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Abstract Flowback aids are usually surfactants or cosolvents added to stimulation treatments—particularly, hydraulic fracturing—to enhance cleanup of the spent fluids and ultimately improve gas or oil recovery when production begins. A range of different flowback additive chemistries have been reported in the literature containing water-wetting nonionic to amphoteric, micro-emulsion, and oil-wet components. Current unconventional reservoir surfactant technology can encounter several major challenges for use in well stimulation processes, including requirements to use nontoxic, environmentally acceptable surfactants; long-term stability at high temperature, pressure, and salinity during the hydraulic fracturing process; and minimum concentration requirements to achieve acceptable performance. The present work focuses on the development of a new class of flowback aids package that can address these challenges. With a low treatment dosage at 1 gal/1,000 gal, they can effectively reduce surface tension and interfacial tension (with synthetic oil or crude oil). They are all "green" products, composed of 100% environmentally acceptable components and have confirmed numeric ranking using the chemistry scoring index (CSI) tool. They also demonstrated superior thermal and chemical stability to formation conditions. Column flow tests confirmed these new packages helped field oil and broken gel flow smoothly through packed formation cuttings obtained from the Permian Basin, indicating they are effective aids for fracturing fluid recovery. With careful investigation of the laboratory performance data, the final product candidate was identified. It was successfully deployed for a field trial in the Permian Basin during a harsh winter season, with positive feedback received at the early stages of production. In addition, this multifunctional additive provided the extra benefit of corrosion inhibition, which can help protect asset integrity for long-term production.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
ABSTRACT Corrosion failures of components in electro-hydraulic control systems can have serious consequences for the operation of an entire subsea oil recovery system. The principal objective of this study is to assess the corrosion behaviour of the main material of construction used for the components in such systems (Stainless Steel 316L) in a range of commercial hydraulic fluids (Oceanic HW443, HW525, HW540, HT, EE1), all of which are water-based and mainly contain ethylene glycol as an antifreeze constituent [1] with some other additives such as sodium sulphonates, fatty acid esters, esters of phosphoric acid, amine salts, carboxylic acids and acid esters up to 10% [2]. These systems are located in deep seawater, and some failures have been suggested to be induced by the ingress of seawater under high pressure. The paper tests this hypothesis. Cyclic potentiodynamic polarization tests were carried out in both pure fluids and 50% seawater-50% fluid solutions under different operating temperatures to assess the role of seawater ingress and, in particular, the effect of chloride ions and the effect of temperature on the function of the organic corrosion inhibitor additives in the hydraulic fluid. The surface of each sample after electrochemical tests was examined under the light microscope to identify the extent and the mechanism of corrosion which occurred during the process and thereby help to understand the mechanisms of passivity breakdown. A comparison of relative ethylene glycol content has indicated that the higher the concentration of ethylene glycol the more corrosive the fluid is to stainless steel 316L and possible reasons for this are discussed in this paper. INTRODUCTION In February 1999, the Schiehallion Oilfield, located 150km West of Shetland was shut down only seven months after production began, which was not the first case of the open loop hydraulic systems failing in deep water due to corrosion of some main components and this failure caused a huge loss of production [3]. Failure of the Subsea Control Module resulted in the pilot stage of the directional control valves being blamed for the high leakage rate of hydraulic fluid [4]. The pilot stage is the electronically operated part of the valve that opens or closes it. The solenoid is energised to deflect a spindle and push a very small ball off its seat. This allows hydraulic fluid to flow past the ball and into a chamber, which in turn pushes the valve into position. The pressure from the function line or the resistance in a spring holds the valve either open or closed once the solenoid is de-energised. Figure 1 [5] shows the directional control valve and the key components blamed for failure are enlarged. The material used for the failed components was Stainless Steel 316L and five types of commercial hydraulic fluids (Oceanic HW443, HW525, HW540, HT, EE1) have been common to the failed system. All of these fluids are aqueous solutions of ethylene glycol [HOCH2CH2OH] with various additives, e.g. corrosion, anti-wear and foam inhibitors. The minimum water content should be 35 % by volume to ensure satisfactory fire-resistance ability.
- North America > United States (1.00)
- Europe > United Kingdom > Atlantic Margin > West of Shetland (0.24)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
ABSTRACT Hydraulic fracturing, used in unconventional shale gas and oil extraction, uses large amounts of water which needs to be treated with biocides to prevent microbial degradation of the fracturing fluids and subsequent microbial contamination of the reservoir. A growing requirement is to deliver an holistic biocide package that can provide protection ‘on-the-fly’ and post fracturing in the reservoir where the newly opened fracture faces, introduction of nutrients and degradable carbon sources provide a favorable environment for microbial growth. Many commonly used fracturing biocides are inactive in the reservoir and therefore biocide chemistries that can retain their activity, have good tolerance to temperature and are not inactivated by hydrogen sulfide may be used. Experimental work has demonstrated that novel combinations of the preservative 1,3-Dimethylol-5,5- dimethylhydantoin and tetrakis hydroxymethyl phosphonium sulfate (THPS).can provide synergistic biocidal performance against commonly found oilfield bacteria. Whilst 1,3-Dimethylol-5,5- dimethylhydantoin can be considered a functional equivalent to biocides such as dimethyl oxazolidine, its controlled release profile appears to supplement and enhance the performance of THPS when either co-applied or co-formulated and results observed over an extended time period. INTRODUCTION Biocide selection for treatment of the fracturing fluids ‘on-the-fly’ is normally based upon rapid speed of kill in the source water and compatibility with the fluid system. However, a growing requirement is to deliver an holistic biocide package that can also provide protection, post fracturing, in the reservoir where the newly opened fracture faces, introduction of nutrients and degradable carbon sources provide a favorable environment for microbial growth. Many of the commonly used fracturing biocides are inactive in the reservoir, either due to adsorption onto surfaces, deactivation by the reservoir temperature or presence of hydrogen sulfide (in the case of sour reservoirs). For these reasons either slower acting preservatives that can retain their activity or formulations of tetrakis hydroxymethyl phosphonium sulphate (THPS), that have good tolerance to temperature and are not inactivated by hydrogen sulfide, may be used. THPS and 1,3-Dimethylol-5,5-dimethylhydantoin (DMDM Hydantoin) are both biocides often used individually, and very effectively, in many industrial applications to control the proliferation of undesired bacteria.
- Europe (0.68)
- North America > United States > Texas (0.52)
- Water & Waste Management > Water Management > Constituents > Treated Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (0.87)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (0.74)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (0.68)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (0.54)
Abstract Fracturing, multiple fracturing and refracturing often create peak loads for well design. The scope of this work is to identify areas of potential damage in older wells being considered for refracturing so that those wells can be flagged for further investigation and repair. Removing damaged well stock from consideration before a well integrity failure can occur protects the environment and also allows time for repairs that protect the future value of the well stock. New and older well conditions and stimulation methods are discussed with a view towards identifying peak-load factors. Laboratory work and literature study results are also cited to document the connection to previous work and relate literature findings to current stress load causes and isolation damage prevention. Well integrity investigation methods include pressure testing, cement evaluation tools (CET), cement and stimulation pump charts, downhole imaging devices (cameras, calipers, electrical logging tools), and other approaches. New well fracturing, and particularly multi-fracturing completions can produce stresses on the cement-to-pipe and cement-to-formation seals, although the damage, depending on specific conditions can be minor to moderate and changes to construction techniques can eliminate or minimize most problems. Re-fracturing of wells opens several new areas of concern including corrosion, erosion, and production related issues such as subsidence that may result in a higher risk to barrier elements. The results of the work illustrate construction methods that can produce wellbores capable of handling significant multi-fracturing stimulation. In addition, risks of re-fracturing damage on damage to older wells are rated with monitoring and remedial operations as part of the discussions. Finally, frac hits (a fracture from one well intersecting and damaging an adjacent well) will be discussed with examples of several factors that are common in frac hits.
- Geology > Geological Subdiscipline > Geomechanics (0.49)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.46)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
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Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to NACE International, Publications Division, 15835 Park Ten Place, Houston, Texas 77084. The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association.
- North America > United States > Florida (0.46)
- North America > United States > Texas > Harris County > Houston (0.26)