This document discusses using a combination of nanocrystal-enhanced viscoelastic surfactant (VES) fluids and hydrogel-coated self-suspending proppants (SSP) for hydraulic fracturing in high-pressure, high-temperature conditions. The nanocrystals help the VES fluid maintain viscosity at high temperatures while forming a pseudo filter cake to control fluid loss. The hydrogel coating on SSP allows for transport without high viscosity fluids and improves proppant suspension and friction reduction. Laboratory tests show this combination enhances VES performance, controls fluid loss, and achieves high post-fracture conductivity even in brines above 200°F. The integrated technologies reduce additive needs and pumping requirements for
This document discusses non-damaging drilling fluids (NDDF) used to control formation damage during drilling. NDDF was developed using non-degradable and degradable constituents to prevent damage to productive reservoirs. The basic composition of NDDF includes salts, calcium carbonate, polymers, and biocides. Two common types of NDDF are based on micronized calcium carbonate and sodium/potassium formate salts. NDDF provides advantages over conventional drilling fluids like reducing invasion of fines and bridging pore throats to minimize damage during drilling.
The document discusses various factors to consider when selecting drilling fluids, including abnormal pressures, active clays, high temperatures, drilling and hole cleaning efficiency, rate of penetration, cuttings transport, cuttings properties, hydraulics, formation damage, corrosion, lubricity, and gas hydrates. It provides details on each of these factors and how they relate to drilling fluid selection. The document also discusses solid control in drilling fluids, including methods such as settling, dilution, mechanical separation, and chemical treatment to control solids based on particle size.
A drilling fluid, or mud, is circulated during drilling operations to carry cuttings to the surface, control formation pressure and maintain wellbore stability, cool and lubricate the drill bit, and minimize damage to the reservoir. There are three main types of drilling fluid: gaseous (like air), aqueous (water-based fluids containing additives like bentonite or polymers), and non-aqueous (oil- or synthetic-based). Proper handling and cleaning methods are required due to potential health and safety hazards from some drilling fluid components.
This document provides guidelines for hydraulic fracturing operations. It discusses fracture geometry and propagation, noting that fractures are generally planar and oriented perpendicular to the minimum in-situ stress. For horizontal wells, longitudinal or transverse fractures may form depending on well orientation. Near-wellbore fractures can be non-planar and reorient to the far-field direction. The document also outlines factors that control fracture containment and propagation, and introduces basic hydraulic fracturing models, fluid systems, proppants, data acquisition methods, and design considerations.
This document discusses drilling fluids and their properties. It provides an overview of the principal functions of drilling fluids, which include subsurface pressure control, cuttings removal and transport, suspension of solid particles, sealing of permeable formations, stabilizing the wellbore, preventing formation damage, cooling and lubricating the bit, transmitting hydraulic horsepower to the bit, facilitating collection of formation data, partial support of the drill string and casing weights, controlling corrosion, and assisting in cementing and completion. It also discusses drilling fluid classifications, properties such as viscosity and rheology, and key components of drilling fluids.
A Breaker-Free, Non-Damaging Friction Reducer for All-Brine Field ConditionsBill Chang
This document describes a breaker-free, non-damaging nano-composite friction reducer called FR-2 that is effective under various brine conditions. Conventional acrylamide-based friction reducers can cause formation damage and have reduced performance in high-salinity brines. FR-2 is shown to hydrate quickly, reduce friction consistently regardless of brine type, and cause essentially zero formation damage based on core permeability tests. In contrast, conventional friction reducers showed friction reduction dependence on brine composition and severe core damage of up to 99.5%. FR-2 demonstrates advantages over conventional friction reducers for hydraulic fracturing in its breaker-free nature, non-damaging properties, and brine
This document discusses drilling fluids, including their types, functions, properties, and additives. It covers the main types of drilling fluids as water-based and oil-based, and their key functions such as removing cuttings from the wellbore, maintaining wellbore pressure and stability, lubricating and cooling the drill bit. The most common additives are described, including weighting materials to increase mud density, viscosifiers to suspend cuttings and materials, and other additives that control filtration, rheology, alkalinity and other properties. Selection of the appropriate drilling fluid depends on formation data and requirements for each well section.
This document discusses liquid containment and mechanical shaft seals for pumps. It describes the importance of liquid containment to prevent pollution. It then discusses different types of shaft seals including packing, lip seals, single and dual mechanical face seals, and cartridge seals. It provides details on selecting the proper seal based on factors like liquid viscosity, temperature, pressure, and compatibility with elastomers. API specification 682 for mechanical seals in refinery pumps is also summarized.
This document discusses non-damaging drilling fluids (NDDF) used to control formation damage during drilling. NDDF was developed using non-degradable and degradable constituents to prevent damage to productive reservoirs. The basic composition of NDDF includes salts, calcium carbonate, polymers, and biocides. Two common types of NDDF are based on micronized calcium carbonate and sodium/potassium formate salts. NDDF provides advantages over conventional drilling fluids like reducing invasion of fines and bridging pore throats to minimize damage during drilling.
The document discusses various factors to consider when selecting drilling fluids, including abnormal pressures, active clays, high temperatures, drilling and hole cleaning efficiency, rate of penetration, cuttings transport, cuttings properties, hydraulics, formation damage, corrosion, lubricity, and gas hydrates. It provides details on each of these factors and how they relate to drilling fluid selection. The document also discusses solid control in drilling fluids, including methods such as settling, dilution, mechanical separation, and chemical treatment to control solids based on particle size.
A drilling fluid, or mud, is circulated during drilling operations to carry cuttings to the surface, control formation pressure and maintain wellbore stability, cool and lubricate the drill bit, and minimize damage to the reservoir. There are three main types of drilling fluid: gaseous (like air), aqueous (water-based fluids containing additives like bentonite or polymers), and non-aqueous (oil- or synthetic-based). Proper handling and cleaning methods are required due to potential health and safety hazards from some drilling fluid components.
This document provides guidelines for hydraulic fracturing operations. It discusses fracture geometry and propagation, noting that fractures are generally planar and oriented perpendicular to the minimum in-situ stress. For horizontal wells, longitudinal or transverse fractures may form depending on well orientation. Near-wellbore fractures can be non-planar and reorient to the far-field direction. The document also outlines factors that control fracture containment and propagation, and introduces basic hydraulic fracturing models, fluid systems, proppants, data acquisition methods, and design considerations.
This document discusses drilling fluids and their properties. It provides an overview of the principal functions of drilling fluids, which include subsurface pressure control, cuttings removal and transport, suspension of solid particles, sealing of permeable formations, stabilizing the wellbore, preventing formation damage, cooling and lubricating the bit, transmitting hydraulic horsepower to the bit, facilitating collection of formation data, partial support of the drill string and casing weights, controlling corrosion, and assisting in cementing and completion. It also discusses drilling fluid classifications, properties such as viscosity and rheology, and key components of drilling fluids.
A Breaker-Free, Non-Damaging Friction Reducer for All-Brine Field ConditionsBill Chang
This document describes a breaker-free, non-damaging nano-composite friction reducer called FR-2 that is effective under various brine conditions. Conventional acrylamide-based friction reducers can cause formation damage and have reduced performance in high-salinity brines. FR-2 is shown to hydrate quickly, reduce friction consistently regardless of brine type, and cause essentially zero formation damage based on core permeability tests. In contrast, conventional friction reducers showed friction reduction dependence on brine composition and severe core damage of up to 99.5%. FR-2 demonstrates advantages over conventional friction reducers for hydraulic fracturing in its breaker-free nature, non-damaging properties, and brine
This document discusses drilling fluids, including their types, functions, properties, and additives. It covers the main types of drilling fluids as water-based and oil-based, and their key functions such as removing cuttings from the wellbore, maintaining wellbore pressure and stability, lubricating and cooling the drill bit. The most common additives are described, including weighting materials to increase mud density, viscosifiers to suspend cuttings and materials, and other additives that control filtration, rheology, alkalinity and other properties. Selection of the appropriate drilling fluid depends on formation data and requirements for each well section.
This document discusses liquid containment and mechanical shaft seals for pumps. It describes the importance of liquid containment to prevent pollution. It then discusses different types of shaft seals including packing, lip seals, single and dual mechanical face seals, and cartridge seals. It provides details on selecting the proper seal based on factors like liquid viscosity, temperature, pressure, and compatibility with elastomers. API specification 682 for mechanical seals in refinery pumps is also summarized.
it is a benficial slide who wants to know about the drilling fluids and the rhelogical aspects of the drilling fluids. the things are clear and very clear in this slide and this slide is very beneficial for the one who know basics of drilling fluids in a knowledgeable way
Petroleum Production Engineering - PerforationJames Craig
This document provides an overview of perforation for oil and gas wells. It discusses key objectives and components of perforation including shaped charges, explosives, perforating guns, and efficiency factors. It also covers well and reservoir characteristics relevant to perforation and provides equations for calculating perforation skin effects on well performance. The high-level goal of perforation is to establish communication between the wellbore and formation while maintaining reservoir inflow capacity.
This paper discusses a new polymer-coated ultra-fine barite weighting agent that can be used to formulate oil-based drilling fluids with improved resistance to barite sag while maintaining low rheology. The barite particles are coated with a polymer during a wet grinding process which allows for effective dispersion and oil-wetting. Drilling fluids formulated with this barite showed significantly reduced barite sag in both static and dynamic tests compared to fluids with conventional barite, while maintaining lower rheology and improved fluid loss control. Computer simulations demonstrated that use of this barite could reduce equivalent circulating density and pump pressures during drilling.
This document discusses sustainable drilling fluid solutions. It begins with basic terminology used in drilling fluids like mud types, additives, and functions of mud. Water-based mud and oil-based mud are compared, noting that WBM is less toxic and can meet environmental issues but is not stable above 400°F, while OBM is stable above 400°F but more toxic. New developments in bio-polymers are discussed that can viscosify drilling fluids with less toxicity and better stability. In conclusion, water-based muds with bio-polymers are the most sustainable option while also addressing environmental concerns related to drilling fluids.
This document provides information about drilling fluids used in oil and gas drilling operations. It discusses the key components and functions of drilling fluids, including bringing cuttings to the surface, controlling subsurface pressures, lubricating and cooling the drill bit. It also describes various types of drilling fluids like water-based muds, calcium muds, lignosulphonate muds, and KCl/polymer muds. The document discusses the role of clays and colloid chemistry in drilling fluids and outlines the properties and uses of different clay minerals.
This document summarizes a presentation about drilling fluids. It defines drilling fluid as a mixture of clay and chemicals pumped through a drill bit to provide hydrostatic pressure, suspend cuttings, cool and lubricate the bit, and provide information from the wellbore. The presentation covers the types of drilling fluids, their functions, additives used, and rheological properties measured. It also describes the drilling fluid circulation system and discusses drilling fluid considerations and emergency remedies.
Spray Nozzle Engineering developed the Drip-Pro check valve to address issues with nozzle drips during spray drying causing scorched particles. The Drip-Pro valve alleviated dripping problems and proved successful, leading to conversions of many existing plants. The Drip-Pro check valve has since evolved through four generations for improved performance, with the Hi-Flo Gen 4 designed for high solids and long run times without blockages. The document promotes Spray Nozzle Engineering's range of safer nozzle systems incorporating the Drip-Pro check valve.
nFluids Nanoparticle Technology Additives for Drilling Fluids & Oil & Gas Ap...Dr. Jeff Forsyth
An innovative Canadian technology company is commercializing a nanoparticle technology platform to develop drilling fluid additives. Laboratory tests show the company's first product, nForcer, can reduce drilling fluid losses by up to 90%, increase wellbore fracture pressure resistance by up to 60%, and reduce friction by up to 50%. Field tests in Alberta demonstrated up to 30% reduction in mud volume losses. The nanoparticles form stronger, thinner filter cakes and seals in fractures and pores to strengthen the wellbore.
This document discusses the effects of perforating horizontal wells in the Wilmington Oil Field case study. It outlines the objectives of investigating how perforation parameters affect horizontal well productivity. It describes shaped charge perforation technology and the components of perforating guns. It discusses factors that influence well productivity like skin effect and how perforations help reduce skin. Calculations for modeling perforation skin effects are presented. The conclusion recommends future reservoir simulations to improve understanding of complex reservoir structures and well performance.
The document provides guidance on troubleshooting issues that may arise while drilling and maintaining the drilling fluid system. It discusses four key properties (density, viscosity, gel strength, filtration) that must be adequately monitored and controlled. Issues covered include contamination, abnormal pressure, lost circulation, fluid characteristics like high viscosity or fluid loss. For each problem, the summary lists typical symptoms and recommends solutions such as changing the mud weight or viscosity, adding lost circulation materials, or using solids control equipment.
This document summarizes a paper presented at the SPE/IADC Middle East Drilling Technology Conference & Exhibition in 2005. The paper discusses the use of a unique high performance water-based mud system to address drilling challenges in the Middle East, such as shale instability, swelling clays, bit balling, and losses. It describes the system's ability to reduce pressure transmission, inhibit clays, improve cutting encapsulation, minimize differential sticking, and maximize rate of penetration, comparing its performance to conventional water-based and oil-based mud systems.
IRJET- Aphron Drilling Fluids: A Silver Lining for Depleted ReservoirsIRJET Journal
1) Aphron drilling fluids use microbubbles stabilized by polymers and surfactants to form a barrier against fluid losses in permeable rock formations.
2) Both water-based and oil-based aphron fluids have been used successfully to drill depleted reservoirs and non-reactive formations.
3) Aphrons are structured with an inner gas core protected by surfactant layers that give them both hydrophilic and hydrophobic properties, allowing them to resist coalescing while also sealing pores and fractures in formations.
This document summarizes the use of liquid curable resin (LCR) systems to control proppant flowback in hydraulic fracturing operations in Argentina. Various operators applied LCR either during initial fracturing treatments by coating proppant on-site, or as remedial treatments by injecting resin into existing fractures. LCR treatments helped stop proppant flowback while maintaining production rates, reducing cleanout costs compared to untreated wells. Lessons showed resin concentration and additive selection are important to maximize proppant pack strength and conductivity. Field results demonstrated LCR treatments effectively control solids flowback to optimize well productivity.
This document provides a summary of innovative stimulation technologies for shale gas recovery. It discusses various fracturing methods including hydraulic, pneumatic, dynamic loading, and other methods. Specific technologies are described in more detail, including liquid carbon dioxide fracturing, LPG fracturing, energized fluids, HiWAY flow channel fracturing, various perforating technologies like FracGun, StimGun, GasGun, and a proposed Multistage Perforator. The advantages and disadvantages of different methods are presented. The goal is to review these technologies to inspire discussion between industry and academia around developing environmentally friendly and economically viable solutions for Polish shales.
This document provides a summary of innovative stimulation technologies for shale gas recovery. It discusses various fracturing methods including hydraulic, pneumatic, dynamic loading, and other methods. Specific technologies are described in more detail, including liquid carbon dioxide fracturing, LPG fracturing, energized fluids, HiWAY flow channel fracturing, various perforating technologies like FracGun, StimGun, GasGun, and a proposed Multistage Perforator. The advantages and disadvantages of different methods are presented. The goal is to review these technologies to inspire discussion between industry and academia around developing environmentally friendly and economically viable solutions for Polish shales.
1) Total Austral performed trials using high viscosity friction reducer (HVFR) fluid systems as replacements for traditional guar-based fluids in hydraulic fracturing operations in Argentina, beginning in 2017.
2) Initial applications in tight gas wells showed promising results, leading to adoption of HVFR fluids in Vaca Muerta shale wells between 2018-2019, demonstrating reduced wellhead pressures and costs.
3) Challenges in using higher salinity water from new sources were addressed through laboratory testing and field trials, validating the addition of surfactants to maintain HVFR fluid viscosity and performance.
Applications of nanotechnology in enhanced heavy oil recoveryElsayed Raafat
This document discusses applications of nanotechnology in enhanced heavy oil recovery. It begins by defining nanotechnology and describing some key properties of nanoparticles, including large surface area and ability to alter surfaces at the nano-scale. It then discusses several ways nanotechnology can be applied in the oil industry, including developing new materials and sensors. Specifically, it explores three main applications of nanotechnology in enhanced heavy oil recovery: 1) use of nanofluids for wettability alteration, 2) use of nanoemulsions for mobility control, and 3) use of nanocatalysts to enhance steam injection and in-situ upgrading of heavy oil.
Determination of Mud and Rheology of Biodiesel Using Xantan Gum and PAMIRJESJOURNAL
Abstract :- The idea behind the current work is to determining the mud and biodiesel rheology (surface
tension, viscosity) by using Xanthan Gum and PAM (polyacrylamide) (-CH2CHCONH2-).The mud used in this
work is barite and bentonites at different samples to know the difference in their specific gravity, viscosity,
surface tension, and PH of the samples when chemical additives are added. And comparing this value with the
oil based mud’s which is prepared with biodiesel to reduce the impact of toxicity and make the environment
friendly drilling fluids.
Produced water reinjection (PWRI) is one of the most usual ways of produced water reuse in mature fields with high water cut.
The relationship between water quality and injectivity decline in wells is well known and it is particularly important in mature
fields, such as Barrancas, an old field located in Mendoza –Argentina, with more than 40 years of water injection. In this
reservoir significant injectivity losses were recorded when fresh water was replaced by produced water in the 90´s.
Formation Damage mechanism is mainly caused by external cake. Particles are principally, iron sulfide, calcium carbonate,
and oil droplets.
it is a benficial slide who wants to know about the drilling fluids and the rhelogical aspects of the drilling fluids. the things are clear and very clear in this slide and this slide is very beneficial for the one who know basics of drilling fluids in a knowledgeable way
Petroleum Production Engineering - PerforationJames Craig
This document provides an overview of perforation for oil and gas wells. It discusses key objectives and components of perforation including shaped charges, explosives, perforating guns, and efficiency factors. It also covers well and reservoir characteristics relevant to perforation and provides equations for calculating perforation skin effects on well performance. The high-level goal of perforation is to establish communication between the wellbore and formation while maintaining reservoir inflow capacity.
This paper discusses a new polymer-coated ultra-fine barite weighting agent that can be used to formulate oil-based drilling fluids with improved resistance to barite sag while maintaining low rheology. The barite particles are coated with a polymer during a wet grinding process which allows for effective dispersion and oil-wetting. Drilling fluids formulated with this barite showed significantly reduced barite sag in both static and dynamic tests compared to fluids with conventional barite, while maintaining lower rheology and improved fluid loss control. Computer simulations demonstrated that use of this barite could reduce equivalent circulating density and pump pressures during drilling.
This document discusses sustainable drilling fluid solutions. It begins with basic terminology used in drilling fluids like mud types, additives, and functions of mud. Water-based mud and oil-based mud are compared, noting that WBM is less toxic and can meet environmental issues but is not stable above 400°F, while OBM is stable above 400°F but more toxic. New developments in bio-polymers are discussed that can viscosify drilling fluids with less toxicity and better stability. In conclusion, water-based muds with bio-polymers are the most sustainable option while also addressing environmental concerns related to drilling fluids.
This document provides information about drilling fluids used in oil and gas drilling operations. It discusses the key components and functions of drilling fluids, including bringing cuttings to the surface, controlling subsurface pressures, lubricating and cooling the drill bit. It also describes various types of drilling fluids like water-based muds, calcium muds, lignosulphonate muds, and KCl/polymer muds. The document discusses the role of clays and colloid chemistry in drilling fluids and outlines the properties and uses of different clay minerals.
This document summarizes a presentation about drilling fluids. It defines drilling fluid as a mixture of clay and chemicals pumped through a drill bit to provide hydrostatic pressure, suspend cuttings, cool and lubricate the bit, and provide information from the wellbore. The presentation covers the types of drilling fluids, their functions, additives used, and rheological properties measured. It also describes the drilling fluid circulation system and discusses drilling fluid considerations and emergency remedies.
Spray Nozzle Engineering developed the Drip-Pro check valve to address issues with nozzle drips during spray drying causing scorched particles. The Drip-Pro valve alleviated dripping problems and proved successful, leading to conversions of many existing plants. The Drip-Pro check valve has since evolved through four generations for improved performance, with the Hi-Flo Gen 4 designed for high solids and long run times without blockages. The document promotes Spray Nozzle Engineering's range of safer nozzle systems incorporating the Drip-Pro check valve.
nFluids Nanoparticle Technology Additives for Drilling Fluids & Oil & Gas Ap...Dr. Jeff Forsyth
An innovative Canadian technology company is commercializing a nanoparticle technology platform to develop drilling fluid additives. Laboratory tests show the company's first product, nForcer, can reduce drilling fluid losses by up to 90%, increase wellbore fracture pressure resistance by up to 60%, and reduce friction by up to 50%. Field tests in Alberta demonstrated up to 30% reduction in mud volume losses. The nanoparticles form stronger, thinner filter cakes and seals in fractures and pores to strengthen the wellbore.
This document discusses the effects of perforating horizontal wells in the Wilmington Oil Field case study. It outlines the objectives of investigating how perforation parameters affect horizontal well productivity. It describes shaped charge perforation technology and the components of perforating guns. It discusses factors that influence well productivity like skin effect and how perforations help reduce skin. Calculations for modeling perforation skin effects are presented. The conclusion recommends future reservoir simulations to improve understanding of complex reservoir structures and well performance.
The document provides guidance on troubleshooting issues that may arise while drilling and maintaining the drilling fluid system. It discusses four key properties (density, viscosity, gel strength, filtration) that must be adequately monitored and controlled. Issues covered include contamination, abnormal pressure, lost circulation, fluid characteristics like high viscosity or fluid loss. For each problem, the summary lists typical symptoms and recommends solutions such as changing the mud weight or viscosity, adding lost circulation materials, or using solids control equipment.
This document summarizes a paper presented at the SPE/IADC Middle East Drilling Technology Conference & Exhibition in 2005. The paper discusses the use of a unique high performance water-based mud system to address drilling challenges in the Middle East, such as shale instability, swelling clays, bit balling, and losses. It describes the system's ability to reduce pressure transmission, inhibit clays, improve cutting encapsulation, minimize differential sticking, and maximize rate of penetration, comparing its performance to conventional water-based and oil-based mud systems.
IRJET- Aphron Drilling Fluids: A Silver Lining for Depleted ReservoirsIRJET Journal
1) Aphron drilling fluids use microbubbles stabilized by polymers and surfactants to form a barrier against fluid losses in permeable rock formations.
2) Both water-based and oil-based aphron fluids have been used successfully to drill depleted reservoirs and non-reactive formations.
3) Aphrons are structured with an inner gas core protected by surfactant layers that give them both hydrophilic and hydrophobic properties, allowing them to resist coalescing while also sealing pores and fractures in formations.
This document summarizes the use of liquid curable resin (LCR) systems to control proppant flowback in hydraulic fracturing operations in Argentina. Various operators applied LCR either during initial fracturing treatments by coating proppant on-site, or as remedial treatments by injecting resin into existing fractures. LCR treatments helped stop proppant flowback while maintaining production rates, reducing cleanout costs compared to untreated wells. Lessons showed resin concentration and additive selection are important to maximize proppant pack strength and conductivity. Field results demonstrated LCR treatments effectively control solids flowback to optimize well productivity.
This document provides a summary of innovative stimulation technologies for shale gas recovery. It discusses various fracturing methods including hydraulic, pneumatic, dynamic loading, and other methods. Specific technologies are described in more detail, including liquid carbon dioxide fracturing, LPG fracturing, energized fluids, HiWAY flow channel fracturing, various perforating technologies like FracGun, StimGun, GasGun, and a proposed Multistage Perforator. The advantages and disadvantages of different methods are presented. The goal is to review these technologies to inspire discussion between industry and academia around developing environmentally friendly and economically viable solutions for Polish shales.
This document provides a summary of innovative stimulation technologies for shale gas recovery. It discusses various fracturing methods including hydraulic, pneumatic, dynamic loading, and other methods. Specific technologies are described in more detail, including liquid carbon dioxide fracturing, LPG fracturing, energized fluids, HiWAY flow channel fracturing, various perforating technologies like FracGun, StimGun, GasGun, and a proposed Multistage Perforator. The advantages and disadvantages of different methods are presented. The goal is to review these technologies to inspire discussion between industry and academia around developing environmentally friendly and economically viable solutions for Polish shales.
1) Total Austral performed trials using high viscosity friction reducer (HVFR) fluid systems as replacements for traditional guar-based fluids in hydraulic fracturing operations in Argentina, beginning in 2017.
2) Initial applications in tight gas wells showed promising results, leading to adoption of HVFR fluids in Vaca Muerta shale wells between 2018-2019, demonstrating reduced wellhead pressures and costs.
3) Challenges in using higher salinity water from new sources were addressed through laboratory testing and field trials, validating the addition of surfactants to maintain HVFR fluid viscosity and performance.
Applications of nanotechnology in enhanced heavy oil recoveryElsayed Raafat
This document discusses applications of nanotechnology in enhanced heavy oil recovery. It begins by defining nanotechnology and describing some key properties of nanoparticles, including large surface area and ability to alter surfaces at the nano-scale. It then discusses several ways nanotechnology can be applied in the oil industry, including developing new materials and sensors. Specifically, it explores three main applications of nanotechnology in enhanced heavy oil recovery: 1) use of nanofluids for wettability alteration, 2) use of nanoemulsions for mobility control, and 3) use of nanocatalysts to enhance steam injection and in-situ upgrading of heavy oil.
Determination of Mud and Rheology of Biodiesel Using Xantan Gum and PAMIRJESJOURNAL
Abstract :- The idea behind the current work is to determining the mud and biodiesel rheology (surface
tension, viscosity) by using Xanthan Gum and PAM (polyacrylamide) (-CH2CHCONH2-).The mud used in this
work is barite and bentonites at different samples to know the difference in their specific gravity, viscosity,
surface tension, and PH of the samples when chemical additives are added. And comparing this value with the
oil based mud’s which is prepared with biodiesel to reduce the impact of toxicity and make the environment
friendly drilling fluids.
Produced water reinjection (PWRI) is one of the most usual ways of produced water reuse in mature fields with high water cut.
The relationship between water quality and injectivity decline in wells is well known and it is particularly important in mature
fields, such as Barrancas, an old field located in Mendoza –Argentina, with more than 40 years of water injection. In this
reservoir significant injectivity losses were recorded when fresh water was replaced by produced water in the 90´s.
Formation Damage mechanism is mainly caused by external cake. Particles are principally, iron sulfide, calcium carbonate,
and oil droplets.
Foam Assisted Surfactant-Alternating-Gas Injection for Heavy Oil Recovery thr...Antonio B. Mejia Jr.
This document proposes a method for producing heavy oil through permafrost in Alaska's North Slope region. A vertical well will be drilled and completed with two deviated laterals, one for injection and one for production. Carbon dioxide injection will be used to reduce oil viscosity and interfacial tension. Special casing, cementing, and insulation techniques will maintain permafrost integrity. Foam assisted surfactant-alternating gas injection combined with artificial lift will enable heavy oil production while preserving the permafrost layer.
This document provides an introduction to alkaline injection for enhanced oil recovery. It discusses the history of alkaline flooding which dates back to the 1920s. Enhanced oil recovery techniques like alkaline flooding are used to extract additional oil from reservoirs after primary and secondary recovery leave between 30-70% of oil unrecovered. The document outlines different types of EOR including thermal, gas injection, and chemical injection methods. It provides an overview of alkaline flooding and discusses how alkalis work on a chemical level to improve oil recovery through mechanisms like emulsification, wettability alteration, and chemical precipitation. The contents section lists the various topics that will be covered in the document related to alkaline injection characteristics, mechanisms of action, figures, tables, and
This study examines the mechanism of improved oil recovery from bottom water reservoirs through nitrogen foam flooding. Laboratory experiments are conducted using core tube and plate models to analyze fluid migration characteristics during nitrogen foam injection. Results show that foam has higher resistance in water layers, increasing displacement in oil layers by diverting subsequent foam into the oil. Foam also enters the oil layer, defoams and forms a secondary gas cap, improving sweep efficiency and displacing residual oil. The research reveals that nitrogen foam flooding improves oil recovery in bottom water reservoirs by plugging the water layer and enhancing displacement in the oil layer.
Flexible Drilling Fluid Formulation and Applicationjerianasmith
"Generic drilling fluids with well known attributes are used for drilling in many areas. Many times there is a need to enhance these fluids to perform in order to achieve a critical drilling objective. A number of additives are available for specific purposes. An additive which improves shale stability, reduces high temperature-high pressure filtrate, and provides lubricity is a good
example."
This paper investigates formulating solids-free drilling and completion fluids using high density cesium and potassium formate brines viscosified with biopolymers. Previous research showed these "low-solids" formate fluids performed well without requiring filtercake removal. The paper aims to develop similar solids-free fluids that control fluid loss for high-pressure, high-temperature applications. A specially designed radial fluid loss tester was used to test formate brines with xanthan gum and other additives, showing concentrated formate brines can control fluid loss without solids.
This document provides a comprehensive review of foam-enhanced oil recovery (foam-EOR) techniques. It discusses the problems with conventional gas-EOR methods, such as gravity override and poor sweep efficiency. Foam-EOR aims to improve sweep efficiency by generating foam to restrict gas mobility and create a uniform displacement front. The review covers foam characterization, factors impacting foam stability and oil recovery, and mechanisms of foam generation. It analyzes laboratory and field implementations of foam-EOR and highlights recent developments to improve foam generation and stability under reservoir conditions.
This document discusses forward osmosis (FO) desalination technology as an alternative to traditional reverse osmosis (RO) desalination. It provides an overview of FO, including its operating principle using a draw solution to facilitate water flow across a semi-permeable membrane. While FO offers advantages over RO like lower energy usage, it faces challenges related to draw solutions and membranes. Recent research focuses on developing new draw solutes and membrane materials to optimize FO and address its current limitations for large-scale desalination applications. The document also discusses business opportunities for developing FO technology in India.
This paper discusses a single-phase microemulsion technology for cleaning oil- or synthetic-based mud filter cakes in a single step. Laboratory tests showed that microemulsions incorporating oil, surfactants, brine and acid could solubilize oil-based mud, make filter cake solids water-wet, and remove acid-soluble particles in one treatment. Sandpack and filtration cell tests demonstrated the microemulsions restored over 90% of original water injection permeability after cleaning oil-based mud filter cakes. The single-phase microemulsion technology allows efficient filter cake clean-up in a single step compared to traditional multiple step methods.
Self Curing Concrete and Its InherentpropertiesIJERA Editor
Today concrete is most widely used construction material due to its good compressive strength and durability. It is estimated that the present consumption of concrete in the world is of the order of 10 billion tonnes (12 billion tons) every year. Depending upon the nature of work, the cement, fine aggregate, coarse aggregate and water are mixed in specific proportions to produce plain and fresh concrete. The strength and durability of concrete will be fully developed only if it is cured. No action to this end is required, however, when ambient conditions of moisture, humidity, and temperature are sufficiently favorable to curing. Concrete is needed to be provided with moisture for a minimum period of 28 days for good hydration and to attain desired strength. Any laxity in curing will badly affect the strength and durability of concrete. A water/cement ratio of about 0.38 would be required to hydrate all the particles of cement and also to occupy the space in gel pores.
1. SPE 171999
Viscoelastic Surfactants Based Stimulation Fluids with Added Nanocrystals and
Self-Suspending Proppants for HPHT Applications
Avi Aggarwal, SPE, Soham Agarwal, SPE, Indian School of Mines; Shubham Sharma, SPE, Halliburton Logging
Services
Copyright 2014, Society of Petroleum Engineers
This paper was prepared for presentation at the Abu Dhabi International Petroleum Exhibition and Conference held in Abu Dhabi, UAE, 10–13 November 2014.
This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been
reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its
officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to
reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
Abstract
With dwindling resources and mushrooming energy demands worldwide, HPHT field development has come under the
limelight of the industry. Thus for expanding the existing horizons, new frontiers in HPHT stimulation advancements are
being anticipated for economical harnessing of hydrocarbons. From more than a decade, surfactant fluids had been
extensively employed in completion and stimulation operations as the surfactants arrange anatomically to form very long
worm-like micelles, maintaining considerably low formation damage levels, and simultaneously exhibiting brilliant
rheological properties, viscosity and proppant transportability. High fluid leak off and its inability to withstand temperatures
greater than 200°F, have limited its HPHT application. Similar is the case for proppants where significant advancements have
been made to increase its strength, but with better strength it has become heavier, causing early screenout, making it unable
to reach deeper-complex fractures and requiring more viscous fluids.
This paper discusses in detail an extensive review of the application of nanoparticle and hydrogel polymer technology to
enhance fluid – proppant performance in conditions with temperatures nearing 275°F and brine density up to 14.4ppg. This
can be achieved by developing nano-sized crystals, which colligate with VES rod-like micelles to yield a virtual viscous filter
cake that significantly curbs the fluid loss rate, thus demonstrating wall building on the porous media, rather than usual
viscosity dependant leak off control. When internal breakers are applied, VES micelle structures degrade rapidly, leaking off
VES fluid and the pseudo filter cake will then split into brine and nanoparticles, thus producing formations remains intact. To
augment its performance proppants can be encapsulated with a thin hydrogel polymer layer which will hydrate on coming in
contact with water. This layer smoothens the proppant, adsorbs the fines, and makes the proppant self-suspending. This
wonder layer is resilient to high pressure high temperature conditions and exhibits excellent characteristics which are
elucidated in this paper.
When applied, nanotechnology can reduce requirement of VES fluid volume by 60% and permeability range of VES fluid
application is extended upto 2000md. While the incorporation of self-suspending proppants (SSP) can significantly bring
down the requirement of additives and enable fracturing of challenging formations with maximum retained conductivity.
Introduction
Pumping of fluid into the well, at a greater pressure than the fracture pressure, to induce fractures is known as Hydraulic
fracturing. The main objective of the operation is to increase the productivity index of a producing well and/or the injectivity
index of an injection well. It was first used in the industry in Kansas, USA in 1947 when it was found to be more cost
effective compared to acidizing jobs (Gidley et al., 1989). Below enlisted are the fundamental steps employed in a fracturing
job:
Pad fluids are the first stage of the fracturing ‘treatment’ which break down the formation and initiate fractures.
Sufficient depth and width of the fractures is needed to allow the proppant-laden fluids to enter in the later stages.
2. 2 SPE 171999
The Pad fluid is pumped to create enough fracture width to accept proppant particles. Proppant is typically
comprised of size-graded, rounded and nearly spherical white sand, but may also be man-made particles.
Proppant particles are mixed into additional fracturing fluid and the resulting slurry is pumped into the reservoir,
propping open the created fracture(s) so that they will remain open and permeable after pump pressure is relieved.
At the end of placing the slurry, a tubular volume of clean “Flush” fluid is pumped to clear tubulars of proppant and
the pumps are shut down.
Well pressure is then bled off to allow the fracture(s) to close on the proppant.
The final step in a fracturing treatment is to recover the injected fluid by flowing or lifting the well.
Hydraulic fracturing consists of initially injecting a pad fluid to induce fractures in the formation, followed with a propping
agent to keep the induced fractures open once the operation ceases. Varying fluids are employed in fracture initiation and
later for proppant/sand transport. The fluids used have undergone a series of developments with better understanding of the
downhole environment and also the advancements in the field of chemical engineering. Initially, fluids based on a
hydrocarbon phase (kerosene, crude oil or gasoline) were employed. Fatty acids were later used to improve the viscosity of
the oil-based fluids for fracture initiation. The use of water-based fluids such as guar-based polymers emerged as a result of
increasing understanding of the rock-oil interactions. To facilitate the transport of proppant, guar is used as an agent to
increase viscosity. In order to generate more viscosity and minimize leakoff, crosslinked guar-based fluids were introduced.
(Dysart et al., 1969). Breakers are generally used alongside polymer-based fluids to improve retained fracture conductivity
and minimize left-over residue associated damage. (Small et al., 1991).
Synthetic polyacrylamide polymers have been reportedly used in recent years as hydraulic fracturing fluids for high
temperature applications upto 232℃. (Holtsclaw and Funkhouser, 2010).To reduce damage caused by polymer based fluids,
viscoelastic surfactants were introduced. (Small et al., 1991) but were susceptible to high temperature degradation at more
than 115℃.unless used in extremely high concentration, other associated problems being leak-off control and formation
damage. Polymer -based fluids are still the most commonly used type of fracturing fluids. This is due to their versatile
properties and the extensive industry experience associated with their use.
Most of the promising recent discoveries are Tight Oil reservoirs located in deepwater/ultra deepwater High Pressure High
Temperature (HPHT) conditions, so to transform these prospects into projects this paper elucidates a stimulation solution by
integration of two contemporary technologies, namely nanocrystal added viscoelastic surfactants and hydrogel based self-
suspending proppants (SSP).
Nanoparticle Based Viscoelastic Surfactants
Nanoparticle technology has a great potential for a broad range of applications in the oil industry in general and stimulation
fluids in particular. It has been envisaged upon great investigation that nano-fluids have attractive properties for applications
where high temperature-high temperature conditions are encountered. This has led to concentrated research work by
companies to design new-age stimulation fluids which can be used in HPHT conditions, possessing a satisfactory viscous
nature for proppant transportation and causing minimum formation damage as a result of fluid leaf-offs. These nanoparticle
empowered stimulation fluids will hence be useful in those conditions where both cross-linked VES based fluids and polymer
based fluids were found to be having a few shortcomings.
VES based fluids were primarily used to overcome the short comings of the polymer based fluids which left a residue in the
fractures resulting in reduced permeability of the fractures (Crews et al., 2006). This was overcome by usage of VES fluids
which formed micelles. These micelles are stable upto 200℉ providing far superior rheological properties and are compatible
with a vast variety of completion fluids including𝐶𝑎𝐶𝑙1, 𝐶𝑎𝐵𝑟1, 𝐾𝐶𝑙 and crude oils causing no damage to the formation
(McElfresh et al., 2003). The problems associated with these fluids are that they are expensive and are unstable at
temperatures greater than 200℉. Also, these fluids do not form a filter cake on the formation, because the VES fluids are
based on the arrangement of low molecular weight surfactants instead of the high molecular weight polymers like guar,
resulting in greater leak offs (Crews et al., 2006). Hence, VES based fluids can be used for those formations which have low
to moderately low permeability to offset the negative impact of the high fluid loss which may get compounded in case of a
highly porous/permeable formation.
To overcome the drawbacks as presented by VES, (Crews and Huang, 2008) proposed the integration of nanoparticle
technology with VES fluids viz loading of nanoparticles to VES micelles. Huang et al., 2010 showed that the addition of the
above mentioned particles significantly improve the rheological properties. The mechanism behind the working is that with
the usage of cationic worm-like micelles with like charged nanoparticles, a micelle-nanoparticle junction gets formed which
act as physical crosslinks between micelles enhancing the viscosity and elasticity of the dilute and semi-dilute wormlike
micelles (Figure 1). The result showed increase of the surfactant micellar fluid’s zero shear rate viscosity by more than 100
times. Also, 20 to 100% lesser usage of VES was reported at higher temperature by Crews et al., 2006.
3. SPE 171999 3
Self-Suspending Proppants
They are recently introduced modified proppants by Mahoney et al. in 2014, encapsulated with a polymer coating which is
water swellable. This special layer enables proppant to resist settling thus making possible effective transportation into
fracture without the usage of high viscosity fluids. This coating is highly continuous and forms an entangled film. When it
comes in contact with water, the coating impulsively absorbs water leading to the formation of a hydrogel sphere. This
swelling process causes an increase in the volume of particle while reducing the particle density. The anchored coating not
only swells upon interaction with water but this unique activity is restricted to the surface and it doesn’t alter internal
chemistry of the proppant. This special layer turns the proppant into a suspending agent, thus decreasing the fracturing fluid
make-up intricacies.
For a hydrated SSP, the hydrogel layer extends several hundred microns as shown in the picture clicked by Mahoney et al.
his light microscope images of 50/70 SSP (Figure 2). The glowing body in the low brightness image is the sand particle
while the arrows in the high brightness image show the extent of hydration layer around the sand. Moreover to validate the
fact that the thickness of the dry coating layer is very small compared to the hydrated layer, Mahoney et al. took a Scanning
Electron Microscope (SEM) image (Figure 3) of unchanged sand particle and a dry coated sand of the same size. This SEM
image shows that the layer is only around 1 – 3 microns thick sand particle is more rounded-smoothened and there is
significant reduction is fines. Reduction in fines is due to adsorption by polymer coating, thus improves handling and reduces
abrasion.
The dynamic nature of SSP technology encompasses its application to a wide variety of proppants viz. ceramic, sand, or resin
coated sand. Due to the self-suspending nature it when enters the fractures proppants push eacth other to travels deep into
horizontal and vertical fractures creating longer propped fractures. The polymer coating can be modelled to automatically
desorb and degrade when it interacts with formation fluids at reservoir temperature.
Advantages of Proposed Stimulation Solution
The most important components of a successful stimulation job are fluid and proppant. As elucidated earlier it is a complex
process and the HPHT conditions (Figure 4) even make it more difficult to design and place the frac. Thus, to facilitate
economic recovery of hydrocarbons from these challenging scenarios use of nanocrystal added viscoelastic surfactant as
fracturing fluid and hydrogel layer for proppant is recommended. Following discussed are the salient features of the proposed
solution:
1) Fluid Viscosity: Due to the self-suspending nature of SSP, viscosity requirements of fracturing fluids are minimal.
Moreover in an experiment conducted by Gurluk et al. in 2013, where amidoamine oxide surfactant in a 14.2 ppg
brine solution of CaCl2 and CaBr2 with approximately 30nm MgO, 30nm ZnO and without nanocrystals, effectively
reflects the increased stability of nanocrystals added viscoelastic fluids in maintaining viscosity over time at 275°F
and 10 s-1
shear rate. (Figure 5)
2) Friction Reduction: In normal operation friction reducing agents are added to the fluid, but the polymer which gets
desorbed from SSP provides friction reduction benefits. The results of an experiment conducted by Mahoney et al.
shows 65% friction reduction when 1 ppg of SSP was added to 2% KCl (Figure 6), similarly 69% reduction in
friction for 1 ppg SSP in tap water while for 1 gpt friction reducer added to tap water 68.8% reduction was observed.
3) Proppant Suspension: The unique ability of nanoparticles to associate elongated surfactant micelles together to
form a reinforced network which enhances the suspension capability of VES as shown in Figure 1 by Huang and
Crews in 2008. Also the presence of hydrated layer of SSP will augment the suspension capacity by reducing the
overall density of particle and increasing the drag force acting on the proppant (Figure 7).
4) Brine Tolerance: In an experiment by Gurluk et al. when at 275°F concentration CaBr2 (brine) is reduced from
14.2 ppg to 13 ppg, the nanoparticle added VES maintains its viscosity at 200 cp, while the viscosity of VES without
nanoparticle drops to 100 cp. SSP also reflects good brine handling characteristics as the swollen layer acts as an
inert layer.
5) Fluid Loss Control: Due to formation of a pseudo filter cake on the face of fractures by nanoparticle cross-linked
VES micelles, fluid loss is controlled. Huang and Crews in their experiment (Figure 8) showed how with increasing
ppg of nanoparticles at high temperatures fluid loss can be controlled.
6) Regained Conductivity: Due to the small size of nanoparticles during flow-back they cause no damage to the
permeability of formation while the presence of internal breakers inside the VES micelles causes complete
dissolution of pseudo filter cake, leaving no residue after the stimulation job (Figure 9). Similarly is the case for
4. 4 SPE 171999
SSP where almost same conductivity was recorded in the proppant pack after the hydrogel layer breaks off fully in
presence of oxidative internal breakers (magnesium oxide) at reservoir temperature (250°F) and flows back with the
fluid.
Conclusion
The use of self-suspending proppants (SSP) and nanocrystals in viscoelastic surfactants (VES) will offer definite benefits for
inducing propped fractures in high pressure high temperature (HPHT) conditions in comparison to conventional fracturing
practices.
The chemistry of the hydrogel polymer layer and nanocrystals in VES were found to complement each other, thus
enhancing the applicability to challenging environments and increased performance of the combination.
The self-suspending nature of SSP reduces the viscosity requirement in fracturing fluid and the nanocrystals were
able to increase the viscosity of VES by ten times, maintaining the same at HPHT conditions.
The friction reducing characteristic of SSP together with reduced requirement of fluid viscosity will drastically curb
the required pumping power.
Due to the close organization of internal breaker in nanocrystal-VES pseudo filter cake and mangnesium oxide
(nanocrystal in VES) acting as internal breaker for SSP, the system delivers great post-fracture conductivity.
Both the components have exhibit improved brine tolerance thus increasing their capability to induce deeper
propped fractures without getting contaminated with formation fluids.
Better fines handling, smoother proppants, low fluid leak off due to pseudo filter cake formation were some of the
other notable features of the combination.
Due to high level of integration between both the proposed technologies the amount of additives and pumping
capacity required are significantly reduced.
References
1. Gidley, J.L., Holditch, S.A., Nierode, D.E. et al. 1989. An Overview of Hydraulic Fracturing. In Recent Advances in
Hydraulic Fracturing, 12. Chap. 1, 1-38. Richardson, Texas: Monograph Series, SPE
2. Dysart, G.R., Spencer, A.L., and Anderson, A.L. 1969. Blast-fracturing. Paper API 60-068 Drilling and Production
Practice, 1969; Harris, P.C. 1993. Chemistry and Rheology of Borate-Crosslinked Fluids at Temperatures to 300°F.
Journal of Petroleum Technology 45 (3): 264-269
3. Li, L., Ezeokonkwo, C.I., Lin, L., Eliseeva, K., Kallio, W., Boney, C.L., Howard, P., and Small, M.M. 1991. Well
Treatment Fluids Prepared with Oilfield Produced Water: Part II. Paper SPE 133379, SPE Annual Technical
Conference and Exhibition, Florence, Italy, 19-22 September.
4. Funkhouser, G.P., Holtsclaw, J. and Blevins, J. 2010. Hydraulic Fracturing Under Extreme HPHT Conditions:
Successful Application of a New Synthetic Fluid in South Texas Gas Wells, SPE 132173, SPE Deep Gas
Conference and Exhibition, Manama, Bahrain, 24-26 January.
5. Crews, J.B., Huang, T., and Wood, W.R. 2006. New Fluid Technology Improves Performance and Provides a
Method to Treat High-Pressure and Deepwater Wells. SPE-103118-MS, SPE Annual Technical Conference and
Exhibition, San Antonio, Texas, USA. DOI: 10.2118/103118-ms.
6. McElfresh, P., Williams, C. F., Wood, W.R. 2003. A Single Additive Non-ionic System for Frac Packing Offers
Operators a Small Equipment Footprint and High Compatibility with Brines and Crude Oils, SPE 82245, SPE
European Formation Damage Conference, The Hague, The Netherlands.
7. Huang, T. and Crews, J.B. 2008. Do Viscoelastic-Surfactant Diverting Fluids for Acid Treatments Need Internal
Breakers?, SPE-112484-MS, SPE International Symposium and Exhibition on Formation Damage Control,
Lafayette, Louisiana, USA. DOI: 10.2118/112484-ms.
8. Huang, T., Crews, J.B., and Agrawal, G. 2010. Nanoparticle Pseudocrosslinked Micellar Fluids: Optimal Solution
for Fluid-Loss Control with Internal Breaking. Paper presented at the SPE International Symposium and Exhibiton
on Formation Damage Control, Lafayette, Louisiana, USA. SPE-128067-MS. DOI:10.2118/128067-ms.
9. Merve R.G. and Hisham A. Nasr-El-Din. 2013. Enhancing the Performance of Viscoelastic Surfactant Fluids Using
Nanoparticles. SPE 164900, EAGE Annual Conference & Exhibition, London, United Kingdom, 10–13 June.
10. Tianping H. and James B. C. 2007. Nanotechnology Applications in ViscoElastic-Surfactant Stimulation Fluids.
SPE 107728. European Formation Damage Conference, 30 May-1 June.
5. SPE 171999 5
11. DeBruijn, G. Skeates, C. Greenaway, R. Harrison, D. Parris, M. James, S. Muller, F. Ray, S. Riding, M. Temple, L.
and Wutherich, K. 2008. High-Pressure, High-Temperature Technologies, Schlumberger Oilfield Review.
12. Mahoney, R. P. Soane, D. Kincaid, K. P. Herring, M. and Snider, P. M. 2013. Self-Suspending Proppant, SPE
163818, SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, USA, 4 – 6 February.
13. Gurluk, M. R. Hisham, A. Nasr-El-Din and Crews, J. B. 2013. Enhancing the Performance of Viscoelastic
Surfactant Fluids Using Nanoparticles, EAGE Annual Conference & Exhibition, London, United Kingdom, 10– 13
June.
Figure 1: Illustration of a strong network built by nanoparticles associating with VES micelles. (Huang and Crews, 2018)
Figure 2: Light microscope images of 40/70 SSP grain at low and high brightness. (Mahoney et al., 2013)
6. 6 SPE 171999
Figure 3: SEM images of 30/50 proppant sand (left) and 30/50 coated SSP (right) (Mahoney et al., 2013)
Figure 4: HPHT Classification System (DeBruijn et al., 2008)
Figure 5: When the surfactant concentration increases from 2 to 4 vol% VES, the viscosity of the fluid increases. (Gurluk et al., 2013)
7. SPE 171999 7
Figure 6: Friction reducing characteristics of SSP. (Mahoney et al., 2013)
Figure 7: A) Vials of 1.5 ppg 30/50 white sand (left) and two samples of 1.5 ppg 30/50 SSP (middle and right). (Mahoney et al., 2013)
B) Proppant-suspension-test samples after 90 minutes at 80°F. The sample on the left is VES fluid with 0.077% bw nanoparticles,
and sample on the right is VES fluid without nanoparticles. (Huang and Crews, 2008)
8. 8 SPE 171999
Figure 8: Fluid-loss tests to compare VES fluids with and without nanoparticles. Tests with nanoparticles developed a pseudofilter
cake that reduced rate of VES-fluid leakoff substantially. (Huang and Crews, 2008)
Figure 9: Internal breaker dramatically reduces VES fluid viscosity at 250°F. (Huang and Crews, 2008)