Summary Alkaline chemicals in enhanced recovery operations are used (1) as preflush agents, (2) with polymers and surfactants, and (3) as a principal recovery agent. In these chemical flooding techniques, the precipitation reactions of multivalent hardness ions with alkalis are of particular concern. These reactions may be prevented at the injection wells through adequate preflushing and/or the use of good-quality softened water; filtration can remove any precipitates that form at the surface. In the formation, precipitates that form at the surface. In the formation, many reactions occur that alter the injected slug significantly. Those include dissolution, mixing, neutralization, and ion exchange. Such reactions may lead to beneficial fluid diversion as precipitates form and block high-flow channels. At the producing wells, however, precipitation and deposition phenomena are undesirable because scales may form that restrict production and foul well equipment. With the current higher production and foul well equipment. With the current higher concentrations of alkali being used in the field, the development of well scaling has become noticeable and difficult to control by previously accepted practices. This paper describes the progress and experience gained at the Long Beach Unit, Wilmington, CA, alkaline pilot dealing with scales formed in producing wells. These scales have been made up variously of calcium carbonate, magnesium silicate, and amorphous silica. In particular, the reservoir characteristics and chemical conditions leading to the scale formation are discussed in detail, showing what, how, and why the scale forms. For the Wilmington alkaline pilot, the cause appears to be the mixing of very hard waters from one subzone with moderately alkaline water from other subzones. This mixing and the dissolution of formation solids by the alkali have led to scale formation in the producers closest to the injectors. producers closest to the injectors. A few general scale inhibitor formulations, useful for both formation squeeze treatments and continuous sidestream annular injection, have been effective in controlling the carbonate scale under laboratory and field conditions. However, the physical environment and mechanical limitations in the field have resulted in a new deposit, consisting mainly of amorphous silica, against which the current inhibitor systems am ineffective. We suggest field procedures for dealing with such a situation. It is anticipated that the use of appropriate chemicals and methods can lead to cost-effective scale control. Introduction Them is a large body of literature on alkaline flooding and its variations. However, few authors consider associated scale phenomena at the production wells or in laboratory studies, although it is well known that alkaline chemicals react with reservoir rock and fluids to produce precipitates. Mungan mentions briefly that produce precipitates. Mungan mentions briefly that plugging and scaling were noted in some field-test plugging and scaling were noted in some field-test production wells but gives no details. Raimondi et al. production wells but gives no details. Raimondi et al. describing a sodium hydroxide pilot in the North Ward-Estes field, observed increased gypsum scale formation in producers. This reservoir has a high gypsum content. However, no treatment was discussed. The authors also noted an increase in silica content at the producers but did not detect an accompanying increase in pH value or decrease in hardness levels in the produced fluids. The alkaline slug was believed to have been completely consumed by inaction with gypsum. In a field test at the Trekhozernoye deposit in Russia, fluid-flow diversion was reported because of swelling and migrating clays and precipitation of calcium and magnesium carbonates. The produced fluids showed a decrease in Ca++ ion with subsequent increases in HCO3 - ion. In laboratory tests evaluating alkaline flooding for an Alberta reservoir, Novosad and McCaffrey reported a white precipitate in the coreflood effluents that added to the alkali consumption. They also noted that silicates are more effective at precipitation divalent metal ions. Sydansk observed the formation of new, highly hydrated alumina-silicate precipitates in alkaline com tests; these have lower silica/alumina ratios than the original formation clays. Carbonate minerals in the core dissolved first, leading to accelerated alkaline consumption. Significant amounts of silica were dissolved from the rock matrix at elevated temperatures. A number of other studies show that alkalis react strongly with the various reservoir-rock constituents. These inactions can produce very complex ionic effluents downstream in both laboratory com tests and field production wells. Ehrlich and Wygal studied the caustic consumption of a number of clays and minerals in an attempt to quantify the contribution of each to the overall consumption. More recently, this quantification has been extended by Mohnot et al. Holm and Robertson studied the effect of various preflush agents, including alkaline silicates on divalent ion exchange in surfactant flooding. JPT P. 1466
This paper presents a case history of inspecting, cleaning and re-establishing communication in a deepwater pipeline that had plugged because of paraffin deposition over an extended period. Early mitigation attempts did not remove the solid mass causing the blockage but, rather, compounded the problem. A chemical capable of dispersing the wax mass was applied to the plugged pipeline through a snubbing unit. Access to the pipeline and the wax plug was gained by disconnecting the line at the subsea site, lifting the pipeline to a work rig, installing the snubbing unit and applying the chemical solution in sea water at a prescribed dilution ratio. One critical step in dispersing and removing the solid wax mass was selecting the dispersant package. In addition, after the correct chemistry was identified, its application required a complex operation. A snubbing unit inside the pipeline jetted the chemical dispersant and drilled through the wax mass. The dispersed fluid was then returned to the working rig where the paraffins were disposed. The operation was successful and the pipeline was placed back into production. However, it was complicated by the ocean floor topography: The deepwater environment adds a degree of difficulty that is not experienced in shelf waters or on land. The exercise taught several lessons, the most significant being that a slow and consistent effort is ideal. Once the mass is dispersed it is best to continuously remove this fluid. Stop-and-start operations allow the solubilized mass to re-solidify as the solvent drains away from the mass under static conditions. Although operators would like for all operations to proceed according to plan, unforeseen and undesirable situations arise. In the case of a plugged pipeline, several causes need to be investigated in order to prevent future occurrences. Operators need to know that operational experience combined with application chemistry exists to help unplug a deepwater pipeline. Introduction: This paper is about a pipeline plugging problem. The problems were technical, mechanical and chemical. The focus of the paper is selection and application of the correct paraffin dispersant chemistry that was then combined with the right mechanical application to solve the technical problem. Solving problems in the oil field is always a challenge. Solving problems of an unknown or uncertain type complicate the challenge. In this case history a deepwater operator found himself with a pipeline plugging problem. It was not possible to identify the type of plug or its location in the pipeline. For that reason the operator went through a series of fixes using the method most probable to prioritize the sequence of solution operations. This was complicated in that a solution that does not remediate the problem may make a second attempt more complex. We surmise that in the first attempt to fix this particular problem, methanol was added to a hydrocarbon matrix and precipitated a hard wax. In the end, the quick fix approaches served to teach to people what would not work and led them to the right solution. In hindsight, it would be easy to second-guess the unsuccessful steps that were taken. However, it is best to appreciate this effort as a complicated process of elimination. In that type of process, it is best when the negative outcome can be used to better define an improved process that more efficiently results in the desired outcome.
fax 01-972-952-9435. AbstractIt is a well-accepted practice to add production chemicals to a formation through a squeeze process. These are designed to place chemical in the near well area and treat the fluid for scale, paraffin, salt, etc. Now, frac-fluid approved chemicals are added to the fracture in order to place products deeper in the formation. In addition, concentrated solid versions of some chemicals have been formulated to provide prolonged treatment. This paper deals with the application of three production chemicals through the fracture fluid process. These chemicals were used to address the problems of scale deposition, bacteria-related corrosion and oxygen induced corrosion.Fracture fluids are complex blends of chemicals designed to perform specific purposes in a specific order during the fracturing process. The addition of non-frac chemicals adds another level of complexity to the formulation and compatibility processes. Thus, it was necessary to limit the scope of production chemical choices and to seek out the most robust products.To date the following types of production chemicals have been added to a variety of fracture fluids: scale inhibitors, salt inhibitors, oxygen scavengers, biocides, asphaltene dispersants and relative permeability modifiers. Gas hydrate inhibitors and paraffin inhibitors, although not yet applied, have been tested and approved for compatibility. In the future the authors hope to report on the outcome of fracturing and chemical programs that addressed the problems that required the use of these chemistries.The significance of this new area of chemical application falls into two levels. For a land or shallow water well where intervention costs are a major issue then the choice to add production chemicals to the fracture depends on the severity of expected treatment problems, the remoteness of the well and other operational and economic drivers. However, in the case of a deep-water well the application of key production chemicals applied during the initial stimulation could make the difference between a highly profitable well and a well that sees a production decline and requires an expensive intervention.
fax 01-972-952-9435. AbstractIt is a well-accepted practice to add production chemicals to a formation through a squeeze process. These are designed to place chemical in the near well area and treat the fluid for scale, paraffin, salt, etc. Now, frac-fluid approved chemicals are added to the fracture in order to place products deeper in the formation. In addition, concentrated solid versions of some chemicals have been formulated to provide prolonged treatment. This paper deals with the application of three production chemicals through the fracture fluid process. These chemicals were used to address the problems of scale deposition, bacteria-related corrosion and oxygen induced corrosion.Fracture fluids are complex blends of chemicals designed to perform specific purposes in a specific order during the fracturing process. The addition of non-frac chemicals adds another level of complexity to the formulation and compatibility processes. Thus, it was necessary to limit the scope of production chemical choices and to seek out the most robust products.To date the following types of production chemicals have been added to a variety of fracture fluids: scale inhibitors, salt inhibitors, oxygen scavengers, biocides, asphaltene dispersants and relative permeability modifiers. Gas hydrate inhibitors and paraffin inhibitors, although not yet applied, have been tested and approved for compatibility. In the future the authors hope to report on the outcome of fracturing and chemical programs that addressed the problems that required the use of these chemistries.The significance of this new area of chemical application falls into two levels. For a land or shallow water well where intervention costs are a major issue then the choice to add production chemicals to the fracture depends on the severity of expected treatment problems, the remoteness of the well and other operational and economic drivers. However, in the case of a deep-water well the application of key production chemicals applied during the initial stimulation could make the difference between a highly profitable well and a well that sees a production decline and requires an expensive intervention.
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