bluuebunny/crossref_metadata_2025 huggingface dataset:
Covalently-Linked Organic Functionalities on Nano-Platelets as a Viscosifier for Oil-Based Muds
Authors: Patel Hasmukh A. , Santra Ashok , Thaemlitz Carl J.
Published: March 2019

Organic functionalities have attached with layered materials through weak ionic bonds in traditional viscosifiers. Since the ionic linkages are weaker than the covalent bonds, ionic organic functionalities tend to detach under high temperature, pressure, shears, presence of other stronger ionic groups and repeated exposures toward alkaline or acidic conditions. To overcome these drawbacks of traditional viscosifiers, we have designed a novel viscosifier with covalently-linked organic moieties on layered materials (COLM). The organic functionalities were linked on the nano-platelets through covalent bonding and thus these linkages provide excellent stability compare to ionic interaction. The synthesis of COLM involves facile synthetic routes that have generated synthetic layered materials of high purity and reproducible chemical composition. The rheological properties of oil-based mud (OBM) containing COLM are characterized under high temperature and high pressure. Unprecedented flat rheology was observed when COLM was blended in OBM and compared with traditional organoclay. The temperature dependent viscoelastic behavior (storage modulus, G' and loss modulus, G") of the OBMs were also studied to establish the effectiveness of COLM compare to traditional organoclay.
Amphiphilic Wax Inhibitor for Tackling Crude Oil Wax Deposit Challenges
Authors: Xiu Zongming , Dufils Pierre-Emmanuel , Zhou Jia , Cadix Arnaud , Hatchman Kevan , Decoster Thomas , Ferlin Patrick
Published: March 2019

As waxy crude oil comes to the surface, it will cool down and causing the waxy fraction to gel. The gelled crude chokes the well, leading to restricted or blocked production and costly downtime for operators. One of the most common chemical solutions to address the wax deposit challenge is the addition of wax inhibitors or pour point depressants (PPDs) to the production stream. However, most of the PPD's used in the field are organic solvent-based polymers, which require large quantities of hazardous organic solvents such as xylene and toluene. To propose an improved solution, a water-based amphiphilic PPD polymer dispersion system, synthesized using controlled radical polymerization technology has recently been developed. This specifically designed block copolymer is synthesized with a hydrophilic polymeric head group and a hydrophobic tail. The macromolecular design was specifically optimized to control particle size to create unique and stable amphiphilic PPD dispersion. The viscosity of the PPD, at high activity of about 40%, is between 200 and 250 cps at room temperature with a milky color, and it remains stable to 200°C under 500psi. Also, the PPD dispersion itself has a pour point of −30°C, and it can be easily formulated to be pumpable under −40°C. For performance evaluation, the water-based PPD dispersion was tested using a standard cold-finger apparatus and a pour point tester on crude oils from various global regions. The results showed that this PPD dispersion not only significantly reduced crude oil wax deposition by nearly 70%, but it also reduced the pour point of the crude by typically 18°C. Overall, the current research performed on macromolecular architecture design shows that this block polymer technology allows polymer adjustment to meet application needs for various crude types, and to tackle this important flow assurance challenges.
Novel Non-Aromatic Non-Ionic Surfactants to Target Deep Carbonate Stimulation
Authors: Sokhanvarian Khatere , Stanciu Cornell , Fernandez Jorge M. , Ibrahim Ahmed , Nasr-El-Din Hisham A.
Published: March 2019

Matrix acidizing is used for permeability and productivity enhancement purposes in oil and gas wells. Hydrochloric acid has been always a first choice due to so many advantages that it can offer. However, HCl in high pressure/high-temperature (HP/HT) wells is a concern because of its high reactivity resulting in face dissolution, high corrosion rates, and high corrosion inhibition costs. There are several alternatives to HCl, among them emulsified acid is a favorable choice due to inherent corrosion inhibition, deeper penetration into the reservoir, less asphaltene/sludge problems, and better acid distribution due to its higher viscosity. Furthermore, the success of the latter system is dependent upon the stability of the emulsion especially at high temperatures. The emulsified acid must be stable until it is properly placed and it also should be compatible with other additives in an acidizing package. This study presents the development of a stable emulsified acid at 300°F through investigating some novel aliphatic non-ionic surfactants.

This paper introduces new non-aromatic non-ionic surfactant to form an emulsified acid for HP/HT wells where the conventional acidizing systems face some shortcomings. The type and quality of the emulsified acid was assessed through conductivity measurements and drop test. Thermal stability of the system was monitored as a function of time through the use of pressure tubes and a preheated oil bath at 300°F. Lumisizer and Turbiscan were used to determine the stability and average particle size of the emulsion, respectively. The viscosity of the emulsified acid was measured at different temperatures up to 200°F as a function of shear rates (0.1-1000 s-1). The microscopy study was used to examine the shape and distribution of acid droplets in diesel. Coreflood studies at low and high flow rates were conducted to determine the performance of the newly developed stable emulsified acid in creating wormholes. Inductively Coupled Plasma (ICP) and Computed Tomography (CT) scan were used to determine dissolved cations and wormhole propagation, respectively.

Superior stimulation results with low pore volume of acid to breakthrough were achieved at 300°F with the newly developed emulsified acid system. The wormhole propagation was narrow and dominant compared to branch wormholes resulted from some of the treatments using conventional emulsified acid systems. The results showed that a non-ionic surfactant with a right chemistry such as suitable hydrophobe chain length and structure can form a stable emulsified acid.

This study will assist in creating a stable emulsified acid system through introducing the new and effective aliphatic non-ionic surfactants, which lead to deeper penetration of acid with low pore volume to breakthrough. This new emulsified acid system efficiently stimulates HP/HT carbonate reservoirs.
Development of a Novel Iron Sulfide Scale Inhibitor for Onshore US Application
Authors: Bhandari Narayan , Bhandari Manoj , Littlehales Ian , Fidoe Julie
Published: March 2019

Iron sulfide scaling can pose a significant threat to flow assurance, especially in sour production systems that yields hydrogen sulfide (H2S). When compared to conventional carbonate and sulfate scales, iron sulfide is difficult to inhibit and various risks (liberation of H2S) are associated with chemical removal. Moreover, efficacy of chemical treatment is poor and often uneconomical; and there is currently no true nucleation inhibitor of iron sulfide identified.

A strictly anoxic static bottle test setup was developed and various traditional scale inhibitors, such as phosphonates, carboxylic acid polymers, as well as new chemistries were screened for iron sulfide nucleation and growth inhibition. Different concentrations of scaling ions (Fe+2 and S2-) were used to mimic the field to field variation in brine composition. The resulting aqueous phases as well as iron sulfide solid products were characterized using various analytical tools including ICP-OES, particle size analyser and Turbiscan.

As expected, conventional scale inhibitors did not show any inhibitory or dispersive effect towards Iron sulfide under tested laboratory conditions. However, a chemistry is identified which can prevent iron sulfide scale deposition at threshold quantities. Specifically, this novel chemistry showed partial iron sulfide nucleation inhibition at early stages and growth inhibition (as high as two orders of magnitude) later. This significant growth inhibition of iron sulfide resulted in excellent dispersion formation that prevents iron sulfide particle aggregation/deposition. Various studies were conducted to understand the chemical-iron sulfide particles interaction and mechanistic aspect of chemical-iron sulfide interaction is identified and discussed. Currently inhibitor packages are being developed for field trials and results will be the subject of future publications.

Efficient mitigation of iron sulfide scaling problem has huge industrial and economic importance in oil and gas production. Based on our current laboratory results, it is anticipated that this chemistry will provide a novel chemical treatment option for iron sulfide scaling control at threshold level whereas orders of magnitude more of conventional scale inhibitors may be required. In addition, this novel chemistry also showed promising outcomes on oil-water partitioning test by making finely dispersed iron sulfide particles water-wet thereby preventing the formation of iron sulfide-crude oil emulsion/pad.
Time Lapse Production Allocation Using Oil Fingerprinting for Production Optimization in Deepwater Gulf Mexico
Authors: Xing Lingbo , Teerman Stan , Descant Frank
Published: March 2019

The variety and sophistication of upstream technologies have been growing fast for imaging the subsurface, modeling reservoir performance and monitoring oil and gas production. Yet there remains a fundamental need to thoroughly sample and analyze the produced reservoir fluids. Reservoir fluid analysis is critical for understanding the nature of produced hydrocarbons and is the key for production optimization. To gain the maximum value from this analysis, reservoir fluid sampling programs need to be well designed and integrated into well testing and reservoir surveillance programs, and not to be developed after.

In one of Chevron's deep-water Gulf of Mexico (DWGOM) sub-salt fields, a robust geochemical sampling plan and production monitoring program has been in place since initial production to estimate the zonal contribution from individually stacked reservoirs.

This surveillance work has been ongoing for 9 commingled wells over a period of 10 years. This paper presents the accuracy of time lapsed production geochemistry allocation and how the results can substantially impact and improve reservoir characterization and trouble shoot completion issues
Insights into Effective Microbial Control Through a Comprehensive Microbiological Audit of Hydraulic Fracturing Operations
Authors: Moore Joseph , Massie-Schuh Ella , Wunch Kenneth , Manna Kathleen , Daly Rebecca , Wilkins Michael , Wrighton Kelly
Published: March 2019

Hydraulic fracturing presents an ideal breeding ground for microbial proliferation due to the use of large volumes of nutrient-rich, water-based process fluids. Bacteria and/or archaea, when left uncontrolled topside or in the reservoir, can produce hydrogen sulfide, causing biogenic souring of hydrocarbons. In addition, microbial populations emerging from the downhole environment during production can colonize production equipment, leading to biofouling, microbially influenced corrosion (MIC), produced fluid separation issues, and HS&E risks. Mitigating these risks requires effective selection and application of biocides during drilling, completion, and production. To this end, a microbiological audit of a well completion operation with the objective of determining the effectiveness of a tandem chlorine dioxide (ClO2) and glutaraldehyde/quaternary ammonium (glut/quat) microbial control program was carried out. This paper describes the rationale behind selection of sampling points for a comprehensive microbiological field audit and provides the resulting critical analysis of biocide efficacy in the field using molecular assays (qPCR, ATP) and complementary culturing techniques (microtiter MPN and culture vials—commonly termed "bug bottles").

Due to the comprehensive nature of sampling and data collection, it was possible to make much more applicable and relevant observations and recommendations than it would have been using laboratory studies alone. First, multiple sources of microbial contamination were identified topside, including source waters, working tanks, hydration units, and guar. Additionally, critical analysis of biocide efficacy revealed that ClO2 treatment of source water was short-lived and ineffective for operational control, whereas glut/quat treatment of fracturing fluids at the blender was effective both topside and downhole. Analysis of the microbial load at all topside sampling points revealed that complete removal of ClO2 treatment could be offset by as little as a 10% increase in glut/quat dosage at the blender. This is a highly resolved microbiological audit of a hydraulic fracturing opration which offers new, highly relevant perspectives on the effectiveness of some biocide programs for operational control. This overview of biocide efficacies in the field will facilitate recommendations for both immediate and long-term microbial control in fractured shale reservoirs.
Microstructural and Flowback Analysis Methodology in Matrix Acidized Carbonate Oil Reservoirs
Authors: Al Moajil Abdullah , AlDakkan Bashayer , Al-Badairy Hameed , Shen Shouwen
Published: March 2019

The success of carbonate acidizing depends on the selection of proper fluid recipes, reservoir formation parameters, job design, and execution. Analysis of flowback spent acid will improve the acidizing process in future treatments, enhance the designed recipes and treatment design. The objective of this paper is to share the flowback analysis methodology following carbonate acidizing treatments with focus on solid analysis.

Microstructural analysis with advanced microscopy and spectroscopy analytical techniques such as high-resolution environmental scanning electron microscopy (ESEM), energy dispersive X-ray microanalysis (EDX) and X-ray diffraction (XRD) techniques were utilized. Flowback samples were filtered through 0.45 µm filter paper. ICP was used to analyze the flowback samples.

The injected acid recipes dissolved significant amount of calcite. The maximum calcium concentrations in flowback samples were 90,000-120,000 mg/L. Moreover, solid precipitates were found in flowback samples associated with pH values of 4.7-5.5. Gypsum was the dominant compound in the samples analyzed while the other compounds such as Lepidocrocite, Magnetite, Quartz, and Barite were detected in a single sample. The iron-based compounds were detected in the beginning of flowback period. Calcium and silicon rich compounds were identified in later flowback periods. The source of iron was identified to be most likely mill scale. Barite and Quartz were found to be associated with iron-based compounds. Gypsum and sodium chloride were detected with varying dominations between CaSO4 and NaCl compounds with a possible correlation as described by Dourba et al. (2017). Particles agglomerations were mainly associated with calcium, chloride and sulfate-based compounds. The rod-like and hexagonally-shaped particles were mainly found to be Si-based particles. Flower particles and dendrite structures were detected and probably associated with Gypsum precipitation amorphous and hemihydrate intermediates. The varying structures and agglomerations of sulfate compounds detected by the SEM indicated they were formed via different mechanisms and environments.
Dissolution Study of Field Deposits for Oilfield Scale Mitigation and Remediation
Authors: Yan Chao , Wang Wei , Wei Wei
Published: March 2019

Formation of scales in near-wellbore reservoir/downhole and production systems can lead to production loss, system integrity and reliability degradation, and fouling of device and equipment. The mitigation and remediation of oilfield depositions can be difficult and costly. Better understanding of the key factors impacting scale dissolution, such as temperature and pH will benefit scale mitigation practices. Most of the research and investigation of silicate dissolution for example are based on low temperature experiences (e.g., <100 °C). Strong acids such as concentrated HCl, HF and aqua regia may not be applicable for field application.

In this study, field depositions with various scale types such as silicates, carbonate, sulfides are characterized and used for studying effects of pH, temperature and solvent on their dissolution. Experiments with oilfield scale deposit samples including silicates were conducted with high temperature thermal aging cells at temperature range >100 °C and pH from 6 – 8. Dissolution test with field scale samples were also conducted under ambient conditions. Various solvents including xylene, HCl and acetic acid were used in the test.

To summarize the results, decreasing temperature has limited effect on dissolution of magnesium silicates, but improves dissolution of calcite and anhydrite which coexist with the field sample. Decreasing pH improves the dissolution of magnesium silicate and calcite. Total amount of dissolved silicates can increase significantly due to appropriate pH decrease. Solution pH is increased dramatically due to the formation of hydroxyl ions during the dissolution process. The reaction for dissolution of metal silicate scale is proposed based on observation and results in the study. More fine particles are produced after dissolution and suspended in solution for at least 15 minutes, which makes solid mitigation possible by applying proper agitation. Oilfield deposits can include a variety of components, and appropriate scale sample characterization should be utilized for selection of mitigation/remediation approaches.

This paper provides novel information of oilfield scale dissolution (including silicate scale) at high temperature by using field applicable treatment approaches. Results lead to better understanding of silicate dissolution at various pHs and temperatures, and required conditions for successful mitigation and remediation of oilfield scale deposits
The Effect of Molecular Composition on the Electro-Deposition of Asphaltene
Authors: Xia Shunxiang , Kostarelos Konstantinos
Published: March 2019

Asphaltene deposition and plugging of pipelines during oil production and transportation is considered a challenging flow assurance issue. Instead of adding dispersants, the concept proposes to remove asphaltenes from the flow stream by means of electro–deposition prior to transportation to prevent later deposition. This study mainly examined the effect of molecular composition on the efficiency of electro-deposition. Two sources of asphaltene, namely asphaltenes from coal tar ("AS-C") and asphaltenes from bitumen ("AS-B") with different molecular composition were collected in this study. Elemental analysis revealed that both AS-B and AS-C possessed transition metals (V and Ni) and heteroatoms (O, N and S). The effect of oil components on the stability of two asphaltenes was studied. After conducting the electro–deposition of both asphaltenes with various oil components and electric field strength, the deposition charge and recover rate was recorded and compared. During stability test, the amount of precipitated AS-B decreased with increasing aromaticity of solvent, while that of AS-C was constant. For electro–deposition, the electro–kinetic behavior of AS-C reveals strong sensitivity to the oil components. Interestingly, both asphaltenes exhibited a change in the net charge, which occurred under 6000 V/cm and 12000 V/cm for AS-B and AS-C respectively, as evidenced by a change in the electrode upon which deposition ocurred. Based on the results, the efficiency of electro–deposition is confirmed to depend upon the metal and heteroatoms of asphaltenes; in addition, and by interaction with these elements, the oil composition and electric field affected the stability, net charge, and electro–kinetic behavior of apshaltene. However, our study is the first to show that the current density plays a role in the net charge of the asphaltene molecule and offers an explanation to the controversy over the polarity or the charge sign of asphaltenes, which gives a clue to understanding the microstructure of asphaltenes. In addition, this is the first study to include the effect of oil components and electric field strength on the performance of deposition, which makes further optimization of the proposed process possible.
A New Up-Scaled Wormhole Model Grounded on Experimental Results and in 2-Scale Continuum Simulations
Authors: Palharini Schwalbert Mateus , Hill A. Daniel , Zhu Ding
Published: March 2019

The optimum design of matrix acidizing treatments in carbonate reservoirs requires accurate modeling of wormhole propagation. While there are several wormhole correlation models available, most are developed based on small core scale experiments, and result in significant deviation when upscaled to field treatment design. There also exists simulation models (e.g. Two-Scale Continuum or Pore Network models). These models are not practical for field design because of the extensive computation effort involved. Large variations in the wormholing behavior are observed in laboratory experiments using different core sizes and geometries (radial flow versus linear flow). This variation is not captured in the previous models. This work proposes a new multiscale wormhole model that represents the physics of wormholing behavior in matrix acidizing of carbonates both at core and field scales.

The derivation of the new semi-empirical model is formulated to represent the experimental data for different core dimensions and flow geometries, as well as field results. In core flooding experiments with different core sizes, the obtained pore volumes to breakthrough and optimal injection velocity are different for each core size. The same behavior is observed in numerical simulations using the Two-Scale Continuum model. That behavior is correctly calculated with the proposed model, which accounts for the dimensions in a function with dependence of the correlation parameters on the wormholed region scale and geometry. Upscaling procedures to linear, radial, elliptical, spherical, and ellipsoidal geometries are presented.

The model's results are validated by the Two-Scale Continuum numerical simulations for both linear and radial flow and verified with experimental results with different core sizes and geometries (both linear and radial flow). We further developed the model for field application, and procedure of using the model is illustrated in the paper. The different flow geometries allow predicting the acidizing behavior in common completions, such as openhole, cased and perforated, and limited entry. The model prediction compares very well to the outcome of field cases.

The new model reproduces the fractal behavior of the dominant wormhole growth above optimal injection rate, and predicts the injection pressure dependence on time as measured experimentally. The model correctly captured the physics of wormhole propagation phenomenon.
Multifunctional Chemical for Simultaneous Dissolution of Iron Sulfide, Corrosion Inhibition, and Scale Inhibition
Authors: Rodgers Patrick , Lundy Brian , Ramachandran Sunder , Ott James , Poelker David , Lee Dong , Stevens Corey , Bounds Christopher , Sullivan Matthew
Published: March 2019

Operators producing hydrocarbons from conventional and unconventional wells often encounter interconnected production-related challenges that exacerbate one another. Challenges during production include the corrosion of steel caused by acid gases, as well as the precipitation and accumulation of iron sulfide, calcium carbonate scale, and barium sulfate scale. The accumulation of solids on pipe walls can facilitate under-deposit corrosion and plugging. Each of these issues can lead to failures and costly workovers. To address these issues, current treatment approaches require multiple chemical applications, frequent batch treatments, mechanical intervention, or a combination of approaches. In certain scenarios, these approaches can be impractical, ineffective, and/or uneconomical. The objective of this study was to develop a solution to overcome the aforementioned production challenges simultaneously and continuously with a single chemical application. The design strategy was to formulate chemicals that included a variety of chemistries to inhibit multiple corrosion mechanisms, as well as an iron sulfide dissolver, and a scale inhibitor to inhibit the formation of calcium carbonate and barium sulfate scales. Laboratory tests were conducted to demonstrate that the formulations could function in the aforementioned areas. One formulation was then applied in the field under different production scenarios: oil wells equipped with either a gas lift mechanism or an electrical submersible pump. Data from those situations are presented to demonstrate the field performance of the new formulation. Compared to the benchmark chemical treatment efforts, application of the formulation improved or maintained similar corrosion control, reduced or eliminated the accumulation of iron sulfide solids in the well, and improved scale control in each of the production scenarios. This paper presents a viable option for effectively treating common production challenges simultaneously and with one chemical application, which is particularly useful when it is impractical or uneconomical to employ multiple chemical treatments.
A New Class of Permanent Clay Stabilizers
Authors: Assem Ahmed I. , Nasr-El-Din Hisham A. , Harper Thomas L.
Published: March 2019

A new class of permanent clay stabilizers has been developed inorganic based on an aluminum/zirconium-based compound. The increased charge density of the molecule allows it to bind more strongly to swelling clays, while its relatively low molecular weight allows it to stabilize the clay permanently without causing formation damage by blocking the pore throats and reducing permeability.

The most commonly used clay stabilizers are organic and inorganic chloride salts including trimethylammonium chloride, potassium chloride, and choline chloride. These salts have been used for years, are effective in most wells, and are both cheap and abundant. However, their high water solubility and the relatively small size of the cation means that these products are highly mobile and thus are quickly washed away during flowback. Several chemical derivatives were made from a tri-functional amine by reacting it with organic and inorganic acids such HCl, acetic acid, and formic acid; as well as alkylating agents, including chloromethane, benzyl chloride, diethyl sulfate, and paraformaldehyde.

Certain cationic polymers have also proven useful as clay stabilizers. These much larger molecules are not as easily washed away due to steric hindrance and a much higher charge density per molecule. These products have proved useful as long-term clay stabilizers, but their high molecular weights can lead to formation damage by causing them to be filtered out on the rock face.

In this research, several laboratory tests were carried out on the new clay stabilizer. These tests included coreflood experiments conducted on Berea sandstone cores to assess the stabilizer at high temperatures and the influence of different acids on its performance. Coreflood effluent samples were analyzed using inductively coupled plasma optical emission spectrometry (ICP-OES) to measure the concentrations of aluminum and zirconium.

This new permanent clay stabilizer improved productivity from formations that have high clay content by minimizing clay swelling and thus preventing formation damage caused by clogged pore throats and subsequent loss of permeability. It worked well at temperatures up to 250°F and with 15 wt% HCl and regular mud acid (12 wt% HCl, 3 wt% HF).
Rducing Backpressure and Enhancing Throughput of Saltwater Disposal Wells with Chlorine Dioxide and Complex Nano Fluids: Optimization and Case Studies
Authors: Pagel Ryan , Tindall Trey , Pursley Tom , Sweeney Tim , Li Zack , Lathrop Tim , Sullivan Bob , Simpson Greg
Published: March 2019

Oilfield produced waters are usually returned to the ground by either reinjecting into underground reservoirs for enhanced oil recovery or injecting in saltwater disposal wells (SWDW) for final disposal. SWDWs often receive waters from production wells with comingled brines. These brines contain residual oils, suspended solids, and additives (such as friction reducers, partially broken gels, biocides, scale and corrosion inhibitors). SWDWs experience declined well injectivity, due to damages from downhole buildup of particles, oils, and biofilms clogging well casing and tubing and plugging a well's perforations and the near wellbore matrix. To fix these problems, chemical treatments are often performed to restore the injectivity of the formations and reduce the injection pressure. Acids and solvents are frequently used to clear blockages of the wells and restore the permeability of the rock formation. Existing chemical treatments of SWDWs still face some challenges, including asphaltene and iron oxide and iron sulfide precipitation, and H2S formation from acid reaction with iron sulfides.

Herein, we report the development and optimization of an innovative field SWDW chemical treatment program. We have successfully developed and optimized the new treatment method including three treating chemicals: hydrochloric acid (HCl), chlorine dioxide (ClO2), and a proprietary Complex nano Fluid (CnF®). Typically, CnF®, HCl, and ClO2 solutions are pumped sequentially downhole into the well formation, with the specific flush volumes of each chemical varying from well to well based on the wellbore configuration. The field application data collected from SWDWs in Haynesville Play and Permian Basin clearly demonstrate remarkable improvement in injectivity and pressure reduction parameters. In all cases, the new treatment combination provides great economic value, with investment payout time within a few weeks. The novel chemical treatment program is expected to have broad application in the treatment of SWDWs across a variety of geological formations in almost all basins.
Effect of Network Parameters of Preformed Particle Gel on Structural Strength for Water Management
Authors: Baghban Salehi Mahsa , Mousavi Moghadam Asefe , Jarrahian Khosro
Published: March 2019

Preformed Particle Gel (PPG) is an appropriate solution for conformance control and managing water production in low permeable reservoirs. Rheological behavior evaluation of these deformable particles is a key factor in designing composition to achieve the best conformance control treatment due to the viscoelastic behavior of these particles along with their swelling. The purpose of this paper is to evaluate the network parameters of PPGs through swelling tests, rheology and determining its role in maintaining their structural strength. Several PPG hydrogels were prepared by varying the concentrations of polyacrylamide and Cr(OAc)3 as copolymer and crosslinker, respectively. The characterization of these hydrogels was performed using Scanning Electron Micrographs (SEM), Electron Dispersion X-ray analysis (EDX), Environmental Scanning Electron Microscopy (ESEM), ThermoGravimetric Analysis (TGA), and Differential ThermoGravimetry (DTG). The correlation between reaction conditions and network parameters of polymer networks such as, molecular weight of the polymer chain between two neighboring crosslinks, crosslink density, and size fraction have been determined. The swelling of the hydrogels was found through the Fickian diffusion mechanism. In this case, the diffusion rate of water in the 3D structure of the hydrogel is less than the relaxation of the polymeric chain, resulting in a significant increase in the PPG particles volume. As PPG was invaded such as in the reservoir by formation water or oil, repeatedly, the sensitivity factor was measured to ensure the swelling in the electrolyte solution. Based on rheological tests, the dynamic modulus of the swelled PPG was strongly dependent on the concentration and consequently network parameters. Also, through the optimization of the network parameters, the appropriate composition from the point of view of strength (complex modulus of 4×104 Pa) and salt sensitivity of 0.5 was presented. In addition, the results of the TGA/DTG test demonstrated the thermal stability of the sample was in temperature range 245 to 340°C. The determination and analysis of the network parameter is the novel technique for predicting the hydrogel performance in porous media and investigating its strength under harsh reservoir conditions. In other words, determination of the network parameter can be a shortcut to ensure the success of the gel performance in porous media.
Relation Between Chemical Composition of a Green Nanofluid and Its Foam Film Stabilization For Robust Foam Injection EOR
Authors: Wei Bing , Wang Yuanyuan , Chen Shengen , Mao Runxue , Ning Jian , Wang Wanlu
Published: March 2019

Foams were introduced to enhanced oil recovery (EOR) for the purpose of improving sweep efficiency via mitigating gas breakthrough. In prior works, well-defined nanocellulose-based nanofluids, which can well stabilize foam film as a green alternative to reduce the environmental impact, were successfully prepared in our group. However, due to the costly manufacturing process, its field scale application is restricted. In order to further simply the manufacturing process and minimize the cost, in this study, we proposed another family of functional nanocellulose, in which lignin fraction was remained as well as carboxyl groups. The primary objective of the present work is to investigate the synergism between the lignin-nanocellulose (L-NC) and surfactant in foam film stabilization. Particular attention was placed on the relation between the chemical composition of L-NC and its stabilizing effect. Direct measurements of foamability, drainage half-time, foam morphology, foam decay, etc., were performed. The results showed that after the contents of lignin and carboxyl group were well tailored, the resultant L-NC can significantly improve the stability of foam either in the absence or presence of crude oil. The flooding dynamics observed in core plugs indicated that the L-NC stabilized foams could properly migrate in porous media and generated larger flow resistance accross the cores than surfactant-only foam.
Development of Structure-Property Relationships for Steam Foam Additives for Heavy Oil Recovery
Authors: Nguyen Thu , Raj Ajay , Rommerskirchen Renke , Fernandez Jorge
Published: March 2019

Low steam viscosity during steam injection can cause steam override and channeling issues for heavy oil recovery, resulting in high operating cost and low oil recovery. One of the common methods to increase the viscosity of steam is by co-injecting surfactants that generate stable foams with steam. The objective of this research is to develop structure-property relationships for surfactants in order to identify surfactant candidates as the steam foam additives for heavy oil recovery.

In this study, alkyl propoxy ethoxy ether carboxylate (alkyl PO EO ECA) surfactants were evaluated. Surfactant solutions at 1 wt% prepared in 1 wt% NaCl were aged at up to 250 °C in Parr reactors for up to 2 weeks. The degradation of the surfactants was quantified based on High Performance Liquid Chromatography profiles of the surfactants before and after the aging process. The foaming performance of the surfactants was evaluated at 1 wt% concentration at varied temperatures from 100 to 250 °C in a high temperature high pressure visual cell. Sand-packed columns were performed to evaluate the ability of the surfactant to increase the apparent viscosity of steam.

The results showed that alkyl PO EO ECA surfactants exhibit excellent chemical stability at up to 250 °C. However, the chemical stability of these surfactants are dependent on the hydrophobe structure as well as the numbers of PO and EO units of the surfactants. Among the studied surfactants, only ECA surfactants with specific structures were able to generate stable foam at 250 °C. It was found that the ECA surfactants with both PO and EO units and a long branched hydrophobe demonstrated to be excellent foaming agents that were able to increase the apparent viscosity of steam by three orders of magnitude at 250 °C in sand-pack columns. In the presence of bitumen, these surfactants were able to increase the steam apparent viscosity by two orders of magnitude. This increase in the steam apparent viscosity is sufficient to overcome the steam override and channeling during steam injection.

Past research has randomly identified some sulfonate and ether carboxylate surfactants as foaming agents for steam EOR processes. This work, however, evaluated these surfactants systematically in order to develop the structure-property relationships that can be used to optimize surfactants as steam foaming agents for thermal EOR processes at up to 250 °C.
Modeling/Forecasting Reservoir Souring in a Field Rajasthan, India with an Extremely Low Indigenous Volatile Fatty Acid VFA Concentration
Authors: Burger Edward , Venkat Panneer Selvam , Mittal Saumya
Published: March 2019

The Rajasthan Field has been undergoing waterflood with produced water reinjection (PWRI) using makeup water with a moderate sulfate (≈500 mg/L) and negligible organic content since 2010. Initial analyses of the formation water indicated that the volatile fatty acid (VFA) content was quite low (≈ 20 mg/L), suggesting a priori that the levels of H2S biogeneration and production would not be problematic. However, after less than four years the H2S production rate from the field was over 1000 kg/day and the H2S concentration in the composite separator gas was about 200 ppmv. Consequently, studies were carried out using the H2S forecasting model previously discussed in four SPE papers to determine the cause for the high level of souring and to estimate future levels and trends of H2S production in the field.

The mechanistic reservoir souring model considers H2S biogeneration due to water-soluble VFAs and/or primarily oil-soluble organics such as BTEX components, the effects of H2S-siderite geochemical reactions within the reservoir to scavenge H2S, flow of H2S (and other components) through the reservoir to the surface, and partitioning of H2S into the oil, water and gas phases within the reservoir and in the surface separators. Also included in the Rajasthan model were the use of power water to lift the well production since it affects partitioning at the surface; and, the effect of chemical H2S scavengers added in selected well flowlines to maintain H2S partial pressures at safe levels.

The model determined that the observed H2S production was not possible even with complete consumption of the indigenous VFAs by sulfate-reducing bacteria and that only with the majority of their organic nutrients being provided by the BTEX-type components were the historical H2S production levels able to be matched. The model results have indicated that H2S production rates have already peaked in the field, primarily due to the reduction in makeup water which provides most of the sulfate being injected into the reservoir. Sulfate is the limiting microbial reactant since the oil-soluble organic supply is essentially infinite.

This study has shown even in non-seawater waterfloods and with minimal organic acids in the formation water that reservoir souring can occur, resulting in the need to handle significant levels of H2S on the surface. The significance of oil-soluble organics as a potential SRB nutrient must be considered when planning a waterflood if sulfate is injected.
Magnesium Depletion and Impact on Produced Brine Compositions in a Waterflooded Reservoir
Authors: Ishkov Oleg , Mackay Eric , Jordan Myles , Blair Sarah
Published: March 2019

Produced water composition analysis provides evidence of what geochemical reactions are taking place in the reservoir. This information can be useful for predicting and managing oilfield mineral scale resulting from brine supersaturation.

This paper presents results of a study of the produced brine compositions from three wells in a field operated in the North Sea, with geochemical modelling complementing the analysis. The findings presented in this work provide evidence of magnesium depletion and sulphate retardation in a sandstone reservoir at 130° C.

This adjusted formation water composition was then used for calculations of the injection water fraction in each of the produced water samples. The Reacting Ions Toolkit was used to plot data in a variety of formats, including ion concentration vs. ion concentration, ion concentration vs. injection water fraction and ion concentration vs. time to identify trends and to examine the extent of involvement of the various ions in geochemical reactions.

The breakthrough of sulphate, a component primarily introduced during seawater flooding, was retarded during injection water breakthrough. Observed sulphate concentrations were lower than predicted for the case of brine/brine interactions only. The implication of this sulphate reduction was lower minimum inhibitor concentration required to control scale formation and longer squeeze treatment lifetimes for the operator.

A brine/rock interaction mechanism was proposed that involves magnesium depletion and is reproduced in the reactive transport model. 1D reactive transport modelling was performed to match possible in situ geochemical reactions (precipitation, dissolution, ion exchange) and account for observed ion trends. The model predicts that the process, which is beneficial in terms of reducing the scale risk, is more pronounced at higher temperatures. It has been observed previously that high temperature (130°C) chalk reservoirs may act as natural sulphate reduction plants during seawater flooding, reducing sulphate scaling and souring risks, and so reducing the operating costs (scale squeeze treatment frequency, chemical volumes) of these fields. This work illustrates new evidence of magnesium depletion and sulphate retardation above levels expected for just brine/brine interactions for a 130° C sandstone reservoir with the implication that the geochemical reactions may lead to reduced operating costs (in terms of squeeze treatment volumes and treatment frequencies) in sandstone reservoirs with low carbonate mineral content that are undergoing seawater flooding.
Green Peptide–nanomaterials; A Friendly Healing Touch for Skin Wound Regeneration
Authors: Nath Debjani , Banerjee Pratyusha , Ray Anugrah , Bairagi Baishakhi
Published: March 2019

The complex phenomenon by which the body responds to any injury of skin or tissue is known as wound healing. A number of phases like exudative, proliferative, and extracellular matrix remodeling are orchestrated events to be occurred involving blood cells, parenchymal cells, and different soluble mediators. Different internal, as well as external factors, regulate the speed and quality of healing. The delay in wound healing process causes the chronic wound or scar formation. At the present moment, the upscale research for identification of agents causing accelerated healing is important. Moreover, the biocompatibility of the accelerators needs to be investigated. Recent biomedical researches for wound care target to provide antimicrobial protection as well as matrix scaffolding for quick repairing of the skin tissue. In recent studies with natural peptides have shown that they are important components in developing the nano-medicines for their usefulness and therapeutic efficiency. New therapeutic formulations can be developed using these natural peptides utilizing different nanoparticle delivery system. This review deals with the developmental study on efficient wound care system where the possible use of natural peptides in combination with nanomaterials has been explored. A trial has also been made on the findings made over the past few years on the use of peptides as tissue regenerating agents through effective wound healing pathway.
The power of choice. Identifying the most autonomy-supportive message frame in digital health communication (Preprint)
Authors: Smit Eline Suzanne , Zeidler Chamoetal , Resnicow Kenneth , de Vries Hein
Published: March 2019

BACKGROUND

Effectiveness of digital health communication may be increased by enhancing autonomy-supportiveness.

OBJECTIVE

Aim of this study was to identify the most autonomy-supportive message frame within an intervention aimed at vegetable intake, by testing the effect of two strategies, i.e. 1) using autonomy-supportive language and 2) providing choice.

METHODS

An online 2 (autonomy-supportive vs. controlling language) x 2 (choice vs. no choice) experiment was conducted among 526 participants, recruited via a research panel. Main outcome measures were perceived autonomy-support (VCCQ; 1-5), perceived relevance (1 item; 1-5) and overall evaluation of the intervention (1 item; 1-10).

RESULTS

Choice had a positive effect on the overall evaluation of the intervention (b = .12, p = .003) and for participants with a high need for autonomy also on perceived relevance (b = .13, p = .017). A trend was observed of choice having positive effects on perceived autonomy-support (b = .07, p = .065). No significant effects on any of the three outcomes were observed for language.

CONCLUSIONS

Results suggest that provision of choice rather than use of autonomy-supportive language can be an easy-to-implement strategy to increase the effectiveness of online computer-tailored health communication, especially for people with a high need for autonomy.
Identification of Informed Consent in Patient Videos on Social Media: Prospective Study (Preprint)
Authors: O'Sullivan Jane , McCarrick Cathleen , Tierney Paul , O'Connor Donal B , Collins Jack , Franklin Robert
Published: March 2019

BACKGROUND

The American Medical Association Code of Medical Ethics states that any clinical image taken for public education forms part of the patient’s records. Hence, a patient’s informed consent is required to collect, share, and distribute their image. Patients must be informed of the intended use of the clinical image and the intended audience as part of the informed consent.

OBJECTIVE

This paper aimed to determine whether a random selection of instructional videos containing footage of central venous catheter insertion on real patients on YouTube (Google LLC) would mention the presence of informed consent to post the video on social media.

METHODS

We performed a prospective evaluation by 2 separate researchers of the first 125 videos on YouTube with the search term “central line insertion.” After duplicates were deleted and exclusion criteria applied, 41 videos of patients undergoing central line insertion were searched for reference to patient consent. In the case of videos of indeterminate consent status, the posters were contacted privately through YouTube to clarify the status of consent to both film and disseminate the video on social media. A period of 2 months was provided to respond to initial contact. Furthermore, YouTube was contacted to clarify company policy. The primary outcome was to determine if videos on YouTube were amended to include details of consent at 2 months postcontact. The secondary outcome was a response to the initial email at 2 months.

RESULTS

The researchers compiled 143 videos. Of 41 videos that contained footage of patient procedures, 41 were of indeterminate consent status and 23 contained identifiable patient footage. From the 41 posters that were contacted, 3 responded to initial contact and none amended the video to document consent status. Response from YouTube is pending.

CONCLUSIONS

There are instructional videos for clinicians on social media that contain footage of patients undergoing medical procedures and do not have any verification of informed consent. While this study investigated a small sample of available videos, the problem appears ubiquitous and should be studied more extensively.