This paper describes the development of acidizing systems that use several different aldehyde-based sulfide suppression chemicals in conjunction with new acid corrosion inhibitors. Specific combinations of these chemicals have allowed the acid to dissolve FeS, suppress H2S and still enable the acid to be inhibited to industry corrosion standards. Laboratory tests include dissolution of FeS, measurement of H 2S evolved, measurement of acid concentration and chloride ion concentrations. We also determined the effect of FeS and H2S on the corrosion of oilfield steels with these additives. Laboratory measurements covered the temperature range from 75 to 275°F (reservoir temperature). Experimental results were compared with that previously published data.1 The new system enabled the acid to dissolve more FeS than fluids containing previously tested suppressors, while controlling H2S evolution and corrosion. During field testing, samples of the spent acid were captured and were analyzed for [Fe], [S2-] and [HCl]. The data will contribute to an understanding of the corrosion processes and sulfide control during acid treatments. The field acid treatments were accomplished successfully without significant changes in procedures and resulted in large increase in gas production. This system is designed primarily for "tube cleaning" operations prior to acid stimulation (matrix and fracture acidizing), but the control chemicals have also been tested for use in the actual stimulation fluid stages. The new chemicals and procedures will allow the operators to safely remove large amounts of fouling deposits, while controlling the toxic and corrosive effects of H2S much more effectively than previously used products. Introduction In many wells, pipelines, or in the hydrocarbon processing units of refineries, iron-based surfaces may come into contact with sulfur-containing fluids. At the temperatures present in the various sections or reactors, and during long periods of contact, iron sulfide deposits (generally FeS, but sometimes, FeS2) will form. The reduced sulfur minerals with approximately 1:1 Fe/S mol ratios (makinawite, troilite, pyrrhotite) can be dissolved using mineral acids, while pyrite and marcasite (FeS2) have low acid solubility. While scale removal using mineral acids is a very effective procedure, it produces large amounts of hydrogen sulfide. FeS + 2H+ = Fe2+ + H2S (1). Hydrogen sulfide causes severe safety and operational problems once the acid leaves the system being treated, and H2S stimulates corrosion of the base metal. For pipelines or in refinery operations, surface cleaning is the major goal of the operation. Lawson et al.3reviewed the major procedures for safely removing iron sulfide deposits:mineral acids with an acid-gas scrubber;mineral acids with hydrogen sulfide suppression chemicals;multiple stages of oxidizing agents with acids; andalkaline cleaners. Several different suppression technologies have been developed for surface cleaning operations. Frenier and co-workers4–6 and Buske7 developed suppression chemicals that contain aldehydes. The most efficient agent is formaldehyde, which reacts stoichiometrically with hydrogen sulfide to produce trithiane, a very insoluble material.8 In treating sour oil and gas wells, as compared with treating surface equipment, corrosion suppression (not elimination of sulfide gas) and dissolution of FeS are of major concern. The inhibitor package must protect several types of steel at high temperatures in the presence of concentrated acid containing numerous additives. The various additives are required since the purpose of the treatment may include removal of inorganic and organic damage from producing formations (matrix treatments).

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The Canadian Water Network, the Alberta Water Research Institute, and the Ontario Centres of Excellence have collaborated to create the Canadian Municipal Water Management Research Consortium, a new initiative to engage municipal water authorities and allow them to access research capacity to tackle mutually identified, critical issues. The challenge of managing uncertainty in the provision of safe drinking water was selected as one such issue. An international expert panel with scientists from Australia, Canada, the USA and Europe was assembled to work with a steering committee of municipal water providers and drinking water regulators. This group has posed the challenge: How best can drinking water providers address risk and uncertainty to assure safe drinking water? Five key drivers to this challenge were identified: the current large list of drinking water contaminants, the inevitable growth of that list as a result of analytical advances not matched by our ability to assess small, mostly immeasurable health risks, the lack of clarity on public expectations for safe drinking water, misunderstanding of new, small risks and a need to assure aesthetic quality. Promoting the means for achieving a common understanding of risk and uncertainty among water providers and regulators was identified as a priority objective. The project has been initiated by developing, in a Canadian drinking water context, working definitions for safe drinking water, risk and uncertainty, with appropriate illustrative examples. The limitations of sole reliance on compliance monitoring for numerical contaminant limits compared with the merits of a preventive risk management/water safety plan approach were elaborated. Based on the foundations adopted, a toolkit is being developed to assist with issues ranging from a risk hierarchy, various products to promote better understanding of how risk assessment is performed, and products to enhance communications with consumers about drinking water safety.

Matrix acidizing treatments are performed to increase the permeability of oil and gas formations and to remove various types of damage. Mineral acids, organic acids and chelating agents are used to stimulate carbonate formations and to remove damage. Sandstone formations are usually treated with mineral acids (usually containing some HCl and HF) to remove damaging solids or liquids. Usually, stimulation in sandstone is not achieved. While a reactive fluid must be present to dissolve the damage or to remove part of the formation, numerous "additives" can be used to aid the penetration of the fluid or to perform other important tasks. To enable the reactive fluid to be pumped from the surface through the tubing and into the formation, corrosion inhibitors usually will be required to protect the metal from attack by the fluid itself. Surfactants, solvents, iron control agents, non-emulsifiers and several other types of agents also may be present. There is increasing concern and some evidence (H. A. Nasr-El-Din, SPE 56712) that the additives adsorb onto the formation (or scale) and may actually be a cause of increased damage. Stimulation of carbonates frequently results in the formation of highly permeable wormholes, so adsorption of the additive may not be as important as damage caused in sandstone formation where damage removal is the primary goal. However, it is very possible that the additives may alter the surface kinetics during limestone acidizing, and thus change the degree of penetration or the efficiency of wormhole formation. To understand some of the effects of additives on acidizing operations, we have studied some commercial corrosion inhibitors, surfactants and solvents during treatments of simulated sandstone and carbonate formations. The goal of the tests was to determine if the additives are damaging the formations due to adsorption or precipitation or altering the removal of damage or the dissolution mechanisms. Two major techniques were used: linear core flood tests and rotating disk tests. Using these methods, we have determined the effects of selected additives of the effectiveness and kinetics of reaction of HCl and chelating agents on limestone and Berea sandstone. The effects of the additives depend on their individual chemical structure as well as the fluid and the formation being penetrated. In general, additives that are highly soluble in the fluid had less effect than agents that are insoluble or dispersible in the fluid. We have also shown that some additives can change the break-through volume during carbonate stimulation tests, thus altering the effectiveness of the treatment. In the paper, we will describe tests conducted at various temperatures, including tests run at 350°F to evaluate hydroxy chelating agent formulations14,15 for use in matrix stimulation of carbonates. Introduction Acidizing fluids include formulations based on hydrochloric acid (HCl), various hydrochloric acid and hydrofluoric acid (HF) mixtures (i.e., Mud Acids), organic acids and chelating agents. The major function of these fluids is to remove damage by dissolving scales and formation fines and to stimulate the formation. Various acidizing formulations also are used to treat carbonate and silicate formations and to remove scale from tubulars or surface equipment. By definition, these fluids are reactive; therefore, they will react with well tubulars or pumping equipment as well as with the formation. As a result, most of these reactive fluids require addition of a corrosion inhibitor to preferentially protect the metal surfaces from corrosive attack1.

Wellbore cleanup in horizontal, open hole sand control completions has been the subject of many publications in recent years. Although a large majority of horizontal wells have been standalone screen completions, an increasing number of these wells are being gravel-packed, particularly in deep water, sub sea environment where reliability of the sand face completion is of utmost importance due to prohibitively high cost of intervention. In such wells, increased significance of "doing it right the first time" further necessitates an emphasized consideration of wellbore displacement and filter cake removal treatments. Although a substantial amount of laboratory data on filter cake cleanup are available in the literature, a great majority of these data are relevant to non-gravel-pack completions. In field practice to date, cake cleanup in GP completions has almost exclusively been done after gravel packing and typically involved coiled tubing. Although several new methods have recently been proposed and successfully practiced in several applications (e.g., inclusion of cake-breaking chemicals into gravel-pack carrier fluids, post-GP breaker treatments immediately after GP w/o requiring coiled tubing), laboratory data directly applicable to such conditions have been scarce. In this paper, we present laboratory data relevant to gravel-packed completions. We show that the cake removal time scales in the presence of a gravel-pack are longer compared to absence of a gravel-pack on top of the filter cake. The degree of delay is shown to depend primarily on carrier fluid viscosity and whether the breakers are included in the carrier fluid or introduced as a post-GP treatment. It is further shown that including breakers in brine during water packing must be exercised with extreme caution since even slow-reacting breakers can yield premature screen out due to increased losses should external cake erosion occur. Introduction A large fraction of wells drilled in reservoirs requiring sand-control are being completed as horizontal open holes. Although a large fraction of these wells have been completed with screens-only, an increasingly higher number of these wells are being gravel packed, particularly in deep water and sub-sea completion environment where reliability of the sand face completion is of utmost importance due to prohibitively high cost of intervention. Furthermore, because the costs associated with filter cake cleanup treatments are typically marginal compared to potential intervention costs, a thorough cleanup treatment is considered an integral part of the completion in such wells, in order to maximize well productivity and longevity, and provide more uniform production profile and avoid premature water or gas breakthrough, although the actual cleanup methodology, including the type of chemicals and the placement techniques may vary significantly. Cake cleanup in gravel pack completions has traditionally been done after gravel packing, and typically with coiled tubing.1 Several new techniques have recently been proposed.2,3 These involve incorporating breakers into the gravel-pack carrier fluid to place the cake-breaking chemicals into the wellbore during gravel packing, as well as a modified service tool that can be used to displace wellbore fluids and spot breaker solutions by allowing circulation down through the wash pipe and up through the wash-pipe/base-pipe annulus.2