Partial Plugging Research Articles

Formation, Effect and Prevention of Asphaltene Sludges During Stimulation Treatments

Abstract Formation of asphaltic sludge during acid stimulation has been a serious problem in many areas for several years. Recent studies have shown that sludge may also affect results in many areas where it has not yet been recognized as such. These studies indicate that: sludge is a precipitate of colloidal materials present in crude oil; the precipitates occur due to changes in environmental conditions of the crude by addition of materials such as, acid, once formed, sludge is insoluble in most treating chemicals; and sludge can be prevented or controlled by use of stabilizing agents in treating fluid or by use of certain solvents as the outer phase of acid-in- oil emulsions. The purpose of this paper will be to show how and why sludge is formed and how it can be prevented or controlled. Simple laboratory tests to determine the probability of sludge formation prior to treatment are discussed. Introduction Formation of sludges by crude oil on contact with acid has been recognized as a serious problem in isolated areas for some time. The problem apparently was first observed in certain California wells. Following acidizing treatments, the wells were very slow to clean up, and often a great deal of asphalt-like material was returned with the treating fluids. In some cases, complete or partial plugging of the well resulted from the treatment. A study of this problem revealed that the crude oils produced from these wells actually formed solid precipitates upon contact with acid. These precipitates were mainly asphaltenes, resins, paraffin waxes, and other high-molecular-weight hydrocarbons. These materials were apparently precipitated from the crude by the reduction in pH as a result of acid contact. Recently, it was found that the formation of crude oil sludge during acidizing is also a serious problem in many other formations throughout the United States. A comprehensive study recently undertaken indicates that these sludges may also be a problem in many areas where it has not been recognized as such. A survey of crude oils from many fields and formations in all the oil- producing areas of the United States and Canada showed that a substantial percentage (28 to 35 per cent) of all naturally occurring oils tested produced precipitates upon contact with acid. Nature of Asphaltic Material in Crude Oil The colloidally dispersed asphaltic and related substances in crude oils which are precipitated upon contact with acid are of such a complex nature that they are classified chiefly on the basis of their physical properties. The most common classification is as follows. Neutral Resins These substances are high-molecular-weight aromatic hydrocarbons, which are insoluble in alkalies and acids and completely miscible with petroleum oils, including light fractions (C fraction). Asphaltenes These materials are similar to the neutral resins, but insoluble in light gasolines and petroleum ether. In contrast to the neutral resins, the asphaltenes are precipitated in the presence of an excess of petroleum ether. Both asphaltenes and neutral resins are completely soluble in benzene, chloroform and carbon disulfide. Asphaltogenic Acids These substances are soluble in alkaline solutions and in such solvents as benzene. Since these are present in petroleum in insignificant quantities, the neutral resins and asphaltenes are the most important asphaltic compounds of petroleum. The asphaltic material present in crude oil is in the form of colloidal particles. Detailed analytical ultracentrifuge studies of several crudes have shown that the asphaltic particles range from 35 to 45 angstroms (A) in diameter. The colloidal range is generally considered to be from 10 to 5,000 A. Other studies have indicated that colloidal particles in crude oil are composed of asphaltic material surrounded by absorbed peptizing materials. These studies have proposed the concept that asphaltenes form the center of the micelles, wth neutral resins absorbed on the surface of the asphaltene particles. JPT P. 1023ˆ

Implosive Shock Treatment of Injection Wells

Abstract The gradual, but continuous increase in pressure required to maintain specific injection rates, with resultant greater operational expense, is a problem common to many injection wells. This problem became critical in the development of the world's largest waterflood project. To combat this problem, new tools and techniques to "shock treat" the injection wells were developed in this field. Extensive use of the shock treatment has proven its effectiveness in improving injection profiles in this field. The treatment has also been effective in other fields in correcting formation interface plugging in both injection and production wells. However, only in injection well applications have there been sufficient jobs to warrant drawing any definite conclusions. Introduction The increase in pressure in an injection well can be due to filling of the reservoir and/or partial plugging of the formation. The causes of formation plugging can be filtrates from original drilling and completion fluids, scales precipitated out of the injection water, bacterial accumulation, injection of incompatible fluids, or the migration of silts from within the formation to form bridges. A new implosive shock treatment has been developed and has proven to be an effective aid in the removal of the plugging caused by filtrates, scales and silts. This paper is a report on a cross section of shock treatments as applied to two different waterflood projects. The following topics pertinent to shock treatments are discussed: remedial efforts leading to the development of shock treatments; mechanics of shock treatments; characteristics required in the tools employed; operational precautions; results of the treatments; and geologic, and general descriptions of the wells in these fields. This can serve as a guide in predicting the applicability of the shock treatment to correct plugging in specific wells in other fields. Conventional Remedial Efforts Formation interface plugging is a problem as old as the oil industry, and several common efforts to correct the condition have evolved over the years. In some areas the following conventional methods are considered to be satisfactory, but in others they have proven to be either ineffective, too costly, or prohibitively time consuming. Acid Washing Acid washing is commonly employed in the attempt to dissolve the plugging materials. Many materials which can cause plugging of the formation interface are not affected by acids and so remain in place. When employed to remove elements that are acid soluble, the treatment does not provide an effective means for flushing the residues. It would certainly be ill advised, in many cases, to force the plugging elements or their residues further back into the formation. Swabbing Swabbing is the most time-honored of the conventional methods, but it is also the most time consuming. Often this method does not create sufficient pressure reduction of fluid velocity to effectively remove an adequate quantity of the plugging materials. Drill-Stem Test Drill-stem test equipment is well known throughout the industry, but is only occasionally employed as a treatment to remove elements plugging the formation interface. By design, the equipment chokes the flow of fluid into the tubing, thereby reducing its effectiveness in removing plugging elements. In the world's largest waterflood project when injection rates began to decline conventional remedial methods were applied; but they proved to be deficient, for the same reasons as outlined previously. Limited but encouraging results with the drill-stem test equipment, under certain conditions, led to the development of the tools necessary to make shock treatments an outstanding success. Shock Treatment Shock treatment is the subjecting of the formation or a portion of a formation to an almost instantaneously applied pressure differential (i.e., implosion) for the purpose of loosening elements plugging that formation and sustaining this differential for a period of time sufficient to cause the plugging elements thus loosened to flow from the formation into the wellbore. JPT P. 128ˆ

STUDIES ON THE INFECTION PROCESS OF CERATOCYSTIS ULMI (BUISM.) C. MOREAU IN AMERICAN ELM TREES

Histological studies of controlled beetle and artificially infected American elm trees (Ulmus americana L.) show that the pathogen of the Dutch elm disease, Ceratocyslis ulmi (Buism.) C. Moreau, grows extensively in all tissues of the xylem. The pathogen produces numerous small spores and hyphae, which pass from cell to cell by means of pits and direct penetration of the walls. This explains the rapid spread of the fungus in the host. Disintegration of bordered pits and of cell walls occurs as infection develops. Acute symptoms of the disease are attributed primarily to complete plugging of the vessels of small branches by the fungus and disintegration products. Gradual or partial plugging of vessels of stems and larger branches and disintegration of cell walls per se are postulated as contributing to the chronic symptoms of the disease. Crossing of the fungus from one growth ring to the next in branches is described.Host reactions to the fungus and seasonal changes in nutrients are discussed in relation to resistance. In beetle-inoculated trees, it was found that wounds extending from the crotch down the sides of the branch were the most favorable for the establishment of infection.

Natural Gas Hydrates

Natural gases under pressure form crystalline hydrates with water.Experimental data are reported on four-phase equilibrium for themethane-propane-water, methane-pentane-water, and methane-hexane-water systems.Temperatures and pressures for equilibrium between gas, water-rich liquid, hydrocarbon-rich liquid, and hydrate were measured, as well as the percentagesof methane and propane in the hydrate. The data indicate that natural gashydrate behaves as a solid solution and that pentanes and heavier hydrocarbonsdo not enter into the solid phase. Vapor-solid equilibrium constants arepresented that permit the approximation of the conditions for hydrateformation, from the composition of a gas. Introduction Natural gas hydrates have been the object of considerable research in recentyears, because of the trouble they have caused in the natural-gas andnatural-gasoline industries. Natural gas hydrates are white crystallinecompounds of water and gas, which, under pressure, exist at temperaturesconsiderably above the freezing point of water. Because of the relatively hightemperatures at which the hydrates exist, they become a nuisance inhigh-pressure gas operations where water is present, since their formationcauses partial or complete plugging of valves and pipes. From a practicalstandpoint, the trouble incident to hydrate formation has been solved bydehydration of the gas before it enters the plant or pipe line, or by otherremedial measures. Extensive work on gas hydrates in the latter part of the nineteenth century, by Villard and others, gave data on methane hydrate and on ethane hydrate.Schroeder summarized these theoretical studies, Hammerschmidt introduced theinformation on gas hydrates to the gas industry, and Deaton and Frost gathereda considerable number of data on the behavior of natural gas hydrates. Recentpapers have extended both the data and the theory of these hydrates. At present, data are available on temperatures and pressures of hydrateformation for pure methane, ethane, propane, n-butane, methane-ethane mixtures, methane-propane mixtures, methane-butane mixtures, and some 15 natural gases, all in the presence of excess water. However, up to the present time no methodhas been available for predicting the temperature at given pressures or thepressure at given temperatures at which natural gases will form hydrates ifsaturated with water. T.P. 1371