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ABSTRACT This paper describes an experimental study of water transport through concrete via electroosmosis - the forced movement of water though a porous material due to an external electric field. A basic understanding of this behavior is necessary in order to effectively apply several technologies, such as cathodic protection of rebar in concrete and the ElectroOsmotic Pulse waterproofing technology. The impact of electro-osmosis on the chemistry of concrete was also investigated by observing ion transport within the material. Concrete specimens of various water/cement ratios were prepared and tested. The laboratory experiments demonstrated that the steady-state flow velocity is relatively independent of concrete w/c ratio, in contrast to hydraulic permeability, which is very dependent on the w/c ratio. The study also showed that ion transport in concrete, particularly Calcium ions, due to electro-osmosis can be significant. INTRODUCTION The characteristics of water and ion movement in building materials under the influence of electro-osmosis is gaining importance; electro-osmosis is being used to test concrete for chloride infiltration, to dechlorinate concrete and to prevent water intrusion. For example, a commercial system that uses electro-osmosis within concrete structures is being used as an alternative to traditional waterproofing.1 Additionally, electro-osmosis can be considered to be a by-product of cathodic protection of rebar in concrete. Previous work by Hock et al.1 has shown that Electro-Osmotic Pulse (EOP) technology can eliminate groundwater intrusion in concrete structures and circumvent the need for conventional negative-side waterproofing methods (excavation, tiling, and coatings or membranes) applied to below grade concrete structures. Electro-Osmotic Pulse technology is a new application based on the phenomenon of electro-osmosis - forced movement of an aqueous solution containing a net electric charge due to an applied external electric field. EOP technology extends the basic concept of electro-osmosis to below-grade concrete structures and soil through the novel application of an asymmetric dual polarity pulse and innovative electrode materials. For applications in concrete, EOP technology has outperformed conventional waterproofing technology.1 Studies were undertaken by the Engineer Research and Development Center, Construction Engineering Research Laboratory (ERDC-CERL) to determine the conditions in which EOP technology performs best, specifically, by examining the factors that affect the use of this technology to control water seepage. This paper describes the laboratory evaluation of electroosmosis in concrete - one phase of laboratory experiments that were conducted in order to examine the principle of electro-osmotic transport in various construction materials. The transport rate of water through poured concrete specimens of various water/cement (w/c) ratios was measured in order to characterize the range of performance for EOP technology in concrete. Only pore size and strength of the specimens were varied: all other variables were held constant. The complete study, including the field testing, is published in an ERDC-CERL technical report.2 In 1809, F.F. Reuss3 originally described electro-osmosis in an experiment that showed that water could be forced to flow through a clay-water system when an external electric field was applied to the soil. Research has since shown that flow is initiated by the movement of cations (positively charged ions) present in the pore fluid of clay or similar porous medium such as concrete; the water surrounding the cations moves with them. Electro-osmosis can be used to arrest or cause flow of w
- Research Report > New Finding (0.54)
- Research Report > Experimental Study (0.34)
- Materials > Construction Materials (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Construction & Engineering (1.00)
ABSTRACT The scale control challenges of two North Sea carbonate reservoirs are reviewed in this paper. This paper outlines the mechanism of scale inhibitor retention observed for three different genetic types of chemical (phosphonate, polymer, and vinyl sulfonate co-polymer) within carbonate reservoirs. The methods of chemical placement will also be reviewed with the technical challenges faced when performing scale inhibitor squeeze treatments into fractured chalk reservoirs being detailed. Deployment methods discussed for chemical placement into carbonate reservoirs includes conventional bullhead squeeze and more novel methods such as chemical blending within the fracture fluid and the deployment of scale inhibitor as solids within the fracture proppant. Furthermore, this paper focuses on field results of for over 50 treatments applied in reservoirs E and V where both phosphonate and vinyl sulfonate polymer chemicals have been scale squeezed. The different retention mechanisms suggested by laboratory studies were validated in the field and by changing from a phosphonate to a vinyl sulphate co-polymer scale a significant extension in treatment lifetime was achieved. Field data will also be presented on the deployment of scale inhibitor within fracture fluids and scale inhibitor impregnated proppant packs. It is clear that a complete understanding of scale control during the life cycle of water injection within a carbonate reservoir is vital to select the correct chemical and to apply it effectively to extend treatment life time whilst, moreover, minimising operational downtime and associated cost. To this end novel technologies to enhance conventional chemical placement are vital to economic success during water flood projects. INTRODUCTION The correct selection of scale inhibitor for the control of mineral scales within oil-bearing reservoirs and associated production equipment is vital if economic hydrocarbon production is to be maintained. Whilst the theory and practise of scale inhibitor chemical selection is well documented for sandstone reservoirs 1'~-'3'4 (this is has not until recently been the case for carbonate 5'6'7 fields. The following section will outline the principle differences between carbonates and sandstone reservoirs, which makes scale inhibitor selection and application a technical challenge. What is Carbonate? Carbonate reservoirs are principally composed of carbonate minerals, which include calcite (CaCO3), dolomite (Ca,Mg CO3), ankerite (Ca,Mg,Fe CO3), and siderite (FeCO3). Carbonate reservoirs can be sub-divided into chalk and limestone. Chalk reservoirs are composed of small spherical/plate-like particles (cocoliths) of calcium carbonate from the skeletons of marine organisms, which became compacted and cemented to form rock with a higher primary porosity, Figure 1. Limestone is generally formed by the deposition of fine carbonate mud with associated fragments of biogenetic material (shells, etc) which is compacted to form rock. 8'9 Such a limestone reservoir would generally have a low primary porosity but a high secondary porosity owing to the dissolution of some of the rock caused by reaction of pore fluids during burial. Fluid Flow in Carbonate Reservoirs Fluid flow within carbonate reservoirs generally occurs as a result of fluid motion within both natural and induced fractures (induced fractures include both acid and hydraulic fractures and introduced to enhance production ). The fluid flows first through interconnecting pores and then enters the fracture system finally exiting to the well bore. The pores formed during sediment deposition are generally poorly connected within carbonate reservoirs resulting in a lower permeabil
- North America > United States > Texas (1.00)
- Europe > Norway > North Sea (0.85)
- Europe > United Kingdom > North Sea > Southern North Sea (0.16)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > Block 49/21 > V-Fields > Vulcan Formation (0.99)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > Block 49/16 > V-Fields > Vulcan Formation (0.99)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > Block 48/25b > V-Fields > Vulcan Formation (0.99)
- (22 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
ABSTRACT Oilfield scale formation is dependent upon the production of water and naturally most scale inhibitors are water-soluble and are usually deployed in aqueous media. Squeezing low watercut wells with aqueous and oil miscible inhibitor treatments can cause problems, however for low watercut wells that are water sensitive, squeezing may result in significant and costly damage to the formation. This study describes the development of a range of truly oil soluble scale inhibitors, which precludes any aqueous phases. The products have been screened for use in two fields that are known to exhibit sensitivity to the application of both aqueous and oil miscible scale inhibitor squeeze formulations. The paper describes chemical development and blending issues and also the inhibitor evaluation protocol - which differs significantly from conventional aqueous screening techniques, and includes a new coreflood procedure for oil soluble chemicals. Finally the paper discusses the implications of the test work for field application. INTRODUCTION Oilfield scale is a key issue in the petroleum industry where vast amounts of water are used and co-produced with hydrocarbons. The formation of mineral scale can create a range of problems to production including; reduction in pipe carrying capacity, increase in operational hazards, localization of corrosion attack, impedance of heat transfer and increases in operating costs due to down time and system maintenance. Prevention and control of mineral scale are the aims of water treatment. The mineral ions in water can be divided into three groups; ions in solution, as fine precipitates dispersed in the fluid phase or as precipitate depositing on solid surfaces as scale. Common oilfield scales include calcium carbonate and the sulfates of calcium, barium and strontium. Squeezing is the most common method for scale control downhole. Scale inhibitor, diluted in carrier solvent (usually brine), is propogated out to an optimised radial distance into the oil producing formation where it is retained and then released slowly back into the aqueous phase during normal well production. In water sensitive formations, application of aqueous treatments can result in increased water cut and also formation damage via clay hydrolysis, swelling and subsequent constriction of pore throats. Near wellbore wettability can also be significantly altered resulting in impaired hydrocarbon production that may take weeks or even months to clean-up. Non-aqueous squeeze technologies that allow the active scale inhibitor to readily partition into the aqueous contact phase have been researched and applied with some success1,2,3,4,5,6,7, however the majority of commercially available products feature blends of aqueous based inhibitors with solvent systems or emulsification of aqueous inhibitors in an oil based solvent. This paper describes the next generation in oil soluble technology whereby completely water free, crude oil soluble scale inhibitors are proposed. The novel chemicals comprise a complex blend of non-aqueous scale inhibitor and organic solvents, where the defining property of the package is that it contains absolutely no aqueous phases whatsoever. The following paper details the results of a laboratory test programme specifically designed to examine the key features of a new range of water free crude oil soluble squeeze inhibitors for squeeze application in low water cut and water sensitive wells. The laboratory work focussed on chemical compatibility with production fluids, thermal aging, oil/water partitioning, inhibitor performance and core flood studies to evaluate formation damage potential and retention and release characteristics. The paper also pro
- North America > United States (0.28)
- Europe > Norway > Norwegian Sea (0.24)
- Europe > United Kingdom > Scotland (0.15)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Africa > Middle East > Libya > Murzuq District > Murzuq Basin > Block NC 186 > Field A Field > Silurian Tanezzuft Formation (0.99)
- Africa > Middle East > Libya > Murzuq District > Murzuq Basin > Block NC 115 > Field A Field > Silurian Tanezzuft Formation (0.99)
ABSTRACT This publication examines the issue of hydrogen embrittlement of CRA materials under the cathodic protection conditions often found in the up stream oil and gas industry. The environment in question is thus oxygenated seawater. The different possible mechanisms of hydrogen embrittlement for CRA materials under these conditions are discussed, as are the different factors affecting susceptibility and mitigation of susceptibility. The susceptibility of the different classes of materials is examined, and susceptible materials highlighted. The importance of undertaking a materials/CP review at different stages of a given project is proposed, and two case studies are described. Finally, a flow plan is put forward indicating the procedures that can be followed. INTRODUCTION This publication examines the phenomena of hydrogen embrittlement of corrosion resistant (CRA) alloys under the cathodic protection (CP) conditions present in the upstream oil and gas industry. Here, the flow lines and pipelines themselves are usually organically coated steel. Cathodic protection is employed to protect these structures from external corrosion in the oxygenated sea water environment. This cathodic protection is usually applied in the form of activated aluminium sacrificial anodes. Under deepwater conditions these can induce a potential as low as -1050mV to -1100mV (Ag/AgCl) in the vicinity of the anode. While this potential is excellent for the protection of carbon steel, it is strongly overprotective of corrosion resistant alloys 1. abundantly as bolts and fasteners. In CRA alloys, the aim of cathodic protection is to bring the rest potential of the material to a position substantially below the pitting potential. Because of the passive nature and thus high polarizability of the CRA alloys used this can be achieved with very low currents and at potentials as high as ?700 to ?500 mV (Ag/AgCl) 1. This corresponds to the free corrosion potential of carbon steel in oxygenated sea water environments. In fact, in a number of publications it is claimed that efficient protection of CRA materials against pitting corrosion can be achieved by coupling them to corroding carbon steel. An applied potential of -1050mV (Ag/AgCl) from the activated aluminium sacrificial anodes usually used for flow line CP will thus substantially over protect any CRA components that are not isolated from the CP system. This leads to hydrogen generation on the surface of the CRA components and, as will be described, can lead to embrittlement problems. BASIC MECHANISMS OF HYDROGEN EMBRITTLEMENT Two basic mechanisms of hydrogen embrittlement, under applied CP conditions, exist. These can be attributed to atomic/molecular hydrogen build up and brittle hydride formation 2.
- Materials > Metals & Mining (1.00)
- Energy > Oil & Gas > Upstream (1.00)
ABSTRACT H2S corrosion is controlled by processes occurring across the corrosion product (FeS) layer and by chemical effects which affect the properties of this layer. Laboratory data are reviewed which clearly demonstrate the parabolic nature of the corrosion kinetics. Along with the corrosion rates the film growth rates were experimentally determined. It was postulated that that the permeability was in essence the parabolic rate constant and could be calculated from the differential weight loss corrosion and the associated film weight. The permeability could then be examined as a function ofpH. The difficulty in relating the corrosion rate to the permeability of FeS is the lack of knowledge regarding the actual rate controlling thickness of the film. The semiconducting properties of the film were formulated based on several mechanistic hypotheses. It was found that two of them fit the experimental evidence but no distinction could be made between the two. The corrosion rate was found to vary with flow rate to the 1/6 th power. It had been possible to formulate this dependence on the basis that the corrosion rate was controlled by masstransfer both in solution as well as in the scale. Diagnostic equations had been developed for the action of amine type corrosion inhibitors. It appears that the more basic the amine, the more effective the inhibitor, which seems to have been experimentally comqrmed, however, inhibitor effectiveness also depends on the pH of the solution and as expected the size and hydrophobicity of the inhibitor molecule. INTRODUCTION The corrosion of carbon steel by H2S containing media has been discussed extensively in the literature 1) although perhaps the HzS corrosion phenomena have in recent years ~) The reader is referred to the literature.quoted in the attached references somewhat been neglected in favor of C02 corrosion. The present discussion is by no means intended to review the past literature, nor the many crystalline forms of iron sulfide to which various corrosion phenomena have been attributed. Rather, it is intended to review some old experimental results by the author, previously published in various venues, in order to resurrect a mechanistic concept which appears to have been lost over the years, but which, in the opinion of this author, may help understand, and classify mechanistically, the many manifestations of liES corrosion. No attempt is made to establish a model. It is much too early for this. It is well known and generally accepted, that the kinetics of H2S corrosion are controlled by the presence of a corrosion product film, FeS. Therefore, all the various masstransfer processes across this layer must play, at least under some circumstances, a determining role with respect to the corrosion rate. These processes can occur either via a pore diffusion mechanism or a solid state mechanism. Since in the experience of this author protective FeS layers are usually thin and non-porous, a solid state mechanism is preferred. The questions which then arise pertain to the nature of these transport processes, the chemical effects which destroy the protective nature of the FeS layers, and how these could be counteracted. Unfortunately, many of the questions which might be asked cannot at this time be answered, either qualitatively nor quantitatively, because the experimental support may not be available. In this sense perhaps the following discussion my serve as an incentive or impetus to a newcomer to the field to pursue some "out-of- the-box" thinking. H2S Corrosion Studies in Bench-Top Equipment Kinetics and Inhibition An apparatus was constructed where by corrosive fluids could be circulated over an
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.70)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (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)