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Abstract This paper describes the development and use of laboratory data to show the impact of multiphase, non-Darcy flow and gel damage upon gas production from hydraulic fractures. In the work, the percent cleanup is related to the molecular weight and concentration of the gel remaining in the proppant pack and the inertial force available from the flow of gas and liquids during cleanup and production. The impact of proppant permeability and multiphase, non-Darcy flow is further combined with inertial force and gel damage to provide a newly developed relationship to predict the degree of cleanup. The new relationship can be used to calculate the effective conductivity for various proppant types, sizes and concentrations vs. closure, temperature, gel and breaker concentration, and prevailing gas/water/oil ratios. The calculated effective conductivities can then be used to predict gas productivity and economics under various conditions of multiphase, non-Darcy flow. The results of the testing show that multiphase, non-Darcy flow dramatically increases the difference between the effective conductivities of various proppants and fracturing fluids with different retained permeabilities. The laboratory data and field observations show that when multiphase flow is taken into account, fracturing fluids with high retained permeabilities and premium high conductivity proppants can produce at as much as twice the gas production rate of fluids with 50% cleanup in gas wells producing as little as 10 barrels of water or condensate per MMCF. Using the developed criteria, proppants and fluids can be selected to optimize gas production from wells based upon prevailing reservoir conditions. Introduction The subject of determining the conductivity of proppants at actual fracture conditions has been a topic of investigation for the last several years. The early work showed that the conductivity of proppant packs could be reduced by a factor of 10 if the impact of time, temperature and embedment are considered. An example of the long-term conductivity of 2 lb/ft 20/40 proppants is shown in Figure 1. Clearly, the conductivity for common products can span from 200 md-ft to 5000 md-ft at 2 lb/ft at 8000 psi closure, which is common in deep, hot reservoirs. These values can then be further discounted by the residual damage caused by the fracturing fluids, which can be from 10 to 90%. Multiphase, non-Darcy flow plays contrasting roles in proppant pack conductivity. The percent cleanup is first related to the amount of energy provided by multiphase, non-Darcy flow. At the same time, multiphase, non-Darcy flow lowers the effective conductivity of the pack by as much as another factor of 10. The impact of non-Darcy flow and multiphase flow are mistakenly not considered in many analyses, because they are not widely understood. Non-Darcy Flow. Non-Darcy flow has a dramatic impact upon the effective permeability of proppant packs. Forchheimer was the first to modify Darcy's law to account for the increases in pressure observed beyond the predicted amount. Cornell and Katz, in 1953, then put forth the common equation used today in whichEquation 1 where dP/L is the pressure drop per unit length, k is the absolute Darcy permeability, ? is the density, and ß is beta factor or the coefficient of inertial resistance. Non-Darcy Flow. Non-Darcy flow has a dramatic impact upon the effective permeability of proppant packs. Forchheimer was the first to modify Darcy's law to account for the increases in pressure observed beyond the predicted amount. Cornell and Katz, in 1953, then put forth the common equation used today in whichEquation 1 where dP/L is the pressure drop per unit length, k is the absolute Darcy permeability, ? is the density, and ß is beta factor or the coefficient of inertial resistance.
Abstract An effective fluid loss control measure that has recently found application in the hydraulic fracturing of gas wells is the addition of an immiscible hydrocarbon phase to aqueous fracturing fluids. In this work the effectiveness and regained permeabilities after employing hydrocarbon and common particulates are assessed. Laboratory studies indicate that reduced hydrocarbon concentrations (less than 5%) may be beneficial in achieving efficient fracture cleanup. A detailed evaluation of the parameters controlling fluid loss of an immiscible hydrocarbon phase in aqueous fluids has led to an optimized hydrocarbon-surfactant system, with which excellent regained permeabilities and efficient fluid loss control are achieved at reduced hydrocarbon concentrations. Introduction A primary role of fluid loss control agents is to maintain adequate injected fluid within the created fracture to achieve desired fracture geometry. At the same time, fluid loss control agents may portray conflicting roles in terms of formation and fracture conductivity damage. Fluid loss additives serve to minimize formation damage by controlling leak-off, thereby limiting matrix fluid invasion and retention; on the other hand, they may impair flow to returning aqueous fluids and hydrocarbons. It has been pointed out by Pye and Smith that the use of particulate fluid loss agents can significantly impair regained permeability to oil in 10 and 250 md formation cores. At an injection pressure of 1000 psi, silica flour brought about a 60% reduction in permeability as determined by regained oil flow at 30 psi on Bandera cores (10 md), and a 90% reduction was reported for Berea cores (250 md) under identical conditions. Regained permeability was improved by increasing the differential pressure. For example, regained permeabilities to oil of 45% and 60% were obtained at differential pressures of 1000 and 2500 psi respectively. psi respectively. The degree of damage to fracture conductivity caused by insoluble particulates has been somewhat controversial. Pye and Smith showed that severe damage can be incurred if the insoluble fluid loss additive plus gelling agent to sand ratio exceeds 0.01. Cooke on the other hand found that the damage from the polymer residue was far greater than that caused by the insoluble particulate matter of the fluid loss agent, except at impractical concentrations (1140 lb/Mgal.). One of the major differences in the two above experiments is the manner in which the fluid loss additive was introduced to the sand pack; Pye and Smith flowed a fluid containing the Pye and Smith flowed a fluid containing the particulate additive into the sand, while Cooke packed particulate additive into the sand, while Cooke packed the sand in a fluid containing the particulate. Particulate bridging was possible in the experiment Particulate bridging was possible in the experiment of Pye and Smith while bridging was less likely in the experiments of Cook. The use of particulate additives in controlling fluid leakoff during the hydraulic fracturing of gas wells can present a more complicated picture in terms of regained permeability. In most cases a limited amount of liquid hydrocarbon and water is produced to dislodge the insoluble particulate matter produced to dislodge the insoluble particulate matter from the fracture surface and/or matrix. Further, the melting points of oil soluble resins are typically exceeded in hot gas well applications resulting in a return of the melted additive to the well bore area where it may solidify on cooling. An alternative to particulate fluid loss control agents has been the introduction of an immiscible liquid phase to aqueous based fluids. Data concerning regained permeability data after treatment with a fluid containing an immiscible liquid is somewhat limited. McAuliffe has noted that once the aqueous permeability of a 1600 md Boise core was reduced permeability of a 1600 md Boise core was reduced some 90% (10 psi) by injecting a 0.5% crude oil in water emulsion, 15 to 19 pore volume of distilled water (10 psi) resulted in a modest 8.5% regain in permeability to water. He points out, however, that permeability to water. He points out, however, that an increasing pressure gradient would eventually displace the droplets that are wedged into pore throat constrictions. No regained permeabilities at lower permeabilities have been reported. P. 9
- North America > United States > Texas (0.46)
- North America > United States > Idaho > Ada County > Boise (0.44)
Abstract This study introduces a method that makes possible the direct monitoring of stimulation fluids for microbial contamination. The procedure is based on the assay of adenosine triphosphate (ATP) with luciferin-luciferase. The accuracy of this method is compared to conventional plate counting and nutrient vial dilution techniques. The effects of stimulation fluid additives such as KCl, biocides, buffers, and gelling agents are assessed, and a procedure for the differentiation of bacterial vs. nonbacterial ATP is examined. Data showing the utility of the assay in monitoring biocide effectiveness and predicting batch mixed gel degradation are presented. Introduction The control of water quality is of prime importance in helping prevent formation damage during the subsurface injection of water based fluids. One of the parameters that can have a serious effect on water quality is microbial (bacterial) contamination. Bacteria play numerous roles in contributing to formation damage. The injection of bacterial cells commonly found in oil field waters into a formation matrix can cause permeability reductions on the order of 90 to 95%. Bacteria can be responsible for the production of substantial quantities of particulate matter that can bring about even more particulate matter that can bring about even more pronounced reductions in the permeability of porous pronounced reductions in the permeability of porous media than bacterial biomass alone. A few examples of particulate generation produced by bacterial corrosion would be the oxidation of iron to ferrous ions producing iron sulfide and iron carbonate in the presence of hydrogen sulfide and carbonate respectively. Ferrous as well as further iron oxidation products such as ferric ions in combination with products such as ferric ions in combination with hydroxyl ions produce iron hydroxides or rust. The direct effects of uncontrolled bacteria are readily seen in holding tanks containing biodegradable polymers for polymer flooding and fracturing operations. polymers for polymer flooding and fracturing operations. Under conditions of suitable pH and temperature, the microbial population can multiply rapidly, utilizing the available polymer, additives such as thiosulfate, and even surfactants, as ready sources of nutrition. Thus, bacteria may also alter the rheological properties of the viscous media to be employed, by fluid degradation, and thus alter the sweep efficiency of a polymer flood or the expected fracture geometry in a hydraulic fracturing treatment. The effective control of microorganisms requires two important procedures –– the application of a suitable biocide and adequate monitoring of the bacterial count within the system. Until recently, monitoring of bacterial populations in the oil field has been accomplished by plate counting (for a review see Buck 1979), and by general growth media vials, which provide total aerobe and anaerobe populations in separate tests. The greatest limitation of plate count and media vial monitoring programs is plate count and media vial monitoring programs is the time required to obtain a reliable count. For example, a week may be required to obtain some plate counts, while 28 days is required for the detection of some anaerobic sulfide producing bacteria. Other less time consuming analyses such as direct microscope counting and epifluorescence enumeration do not distinguish between viable and non-viable cells. Over the past several years ATP analysis has emerged as a valuable tool in monitoring bacteria. The assay first introduced by McElroy in 1947 is based on the release of light on combination of the ATP present in the biomass with the firefly enzyme luciferase and the organic molecule luciferin in the presence of magnesium and oxygen. The light produced presence of magnesium and oxygen. The light produced is proportional to the amount of ATP present. D'Eustachio and Johnson demonstrated that the assay was accurate in determining the number of bacteria in a system since the mean amount of ATP per cell in several species falls in the range of 2.2 to 10.3 × 10(-10) g ATP/organism. To determine the concentration of ATP in a sample, it is necessary to first of all release the ATP from the cells via heating or chemically lysing the cells. p. 273