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1.0 Introduction On September 1, 1981 the "Memorandum of Agreement between the Government of Canada and the Government of Alberta relating to Energy Pricing and Taxation" was signed. The Energy Agreement contains very complex oil and gas regulations. The purpose of this study is to provide an easy procedure by which Engineers and Corporate Planners could easily determine the economic limit for non-EOR projects in Alberta. The economic limit in this study is defined as the minimum average daily oil production rate needed to break-even on a Before and/or After Income Tax basis. The study utilizes the current, effective January 1, 1983, Canadian Oil and Gas taxes and royalties. The procedure to determine the economic limit is independent of the current taxes and royalty rates and thus can be used at any period of time. The economic limit can be expressed by an easy to use set of equations. These equations are developed in the appendices. The values of the constants in the equations are determined by the tax rates, royalty factors, operating costs and wellhead price. Once the constants are calculated for a given project, it is then very simple to calculate the economic limit as well as perform sensitivity analysis for that project. These equations can be used in both the planning stages as well as in every day use in the area office. The operating costs used in this study are completely arbitrary. They are not representative of any particular field or project. The intent of this paper is to develop and easy method by which a project can be evaluated. paper is to develop and easy method by which a project can be evaluated. It is not the intent of this paper to comment on the economics of any particular project in Alberta. particular project in Alberta. Both single well as well as unit's or project's economic limit can be evaluated by the method outlined below. In calculating the unit's or project's royalty rate an average monthly oil production rate per producer project's royalty rate an average monthly oil production rate per producer must be used.
- North America > Canada > Alberta (1.00)
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
- Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract We have devised a technique for determining chloride in interstitial water of consolidated rocks. Samples of rocks ranging from 5 to 10 g are crushed and sieved under controlled conditions and then ground with distilled water to submicron size in a closed mechanical mill. After ultra-centrifugation, chloride content is determined by coulometric titration. The chloride concentrations and total pore-water concentrations, obtained earlier from the same pore-water concentrations, obtained earlier from the same samples by low-temperature vacuum desiccation, are used to arrive at the "original" pore-water chloride concentrations by a simple iteration procedure. Interstitial chlorinity results obtained from Cretaceous and Jurassic strata in the Gulf of Mexico coastal areas ranged from 20 to 100 g/kg Cl with reproducibility approaching +/- 1%. We have also applied the technique to igneous and metamorphic bedrocks as well as ocean basalts containing 1 % water or less. Chloride values ranging from 6.7 to 20 g/kg with a reproducibility of about 5% were obtained. Introduction This paper outlines a technique for precision analysis of interstitial chloride and water content (porosity) of shales and other consolidated rocks from deep-earth strata. Nearly all the literature on the composition of interstitial water (formation fluid) of deep-earth strata refers to fluids from reservoir rocks or permeable horizons. In many areas, shales or other nonreservoir rocks constitute the bulk of sedimentary sequences. These rocks contain interstitial fluids of generally unknown composition. The paucity of data is caused partly by the lack of access to fresh cores and partly by analytical difficulties in obtaining interstitial water from such materials. Until the late 1960's, much of the analytical literature dealing with pore fluids from deep sedimentary nonreservoir rocks was published in the Soviet Union and in references cited by those authors. Since then, interest in several hydrochemical phenomena relating to nonreservoir rocks has increased among phenomena relating to nonreservoir rocks has increased among scientists in the U.S. and other Western countries: interest in hydrocarbon resources in overpressured strata dominated by undercompacted shales that may have anomalous chloride content; need for knowledge of the proportion of bound water (electrolyte-poor) in porosity proportion of bound water (electrolyte-poor) in porosity during quantitative interpretation of electrical logs for oil and gas saturation in shaly sands; need for better understanding of nonreservoir rocks as sealing beds for deep waste disposal; and, finally, a desire to understand better the hydrochemical history of deeper sedimentary basins. However, only a relatively few field studies are available on the topics in question. Many of these are student theses or work based on them. The basic procedure underlying the studies of interstitial water composition of shales is simply crushing and grinding a rock sample, leaching it with distilled water, and analyzing the leachate. The salt content of the solid is then related to an independent determination of total pore fluid or porosity. Techniques based on this principle were used for shallow groundwater studies, for general rocks, and for studying oilfield drill cores. Comments in the literature and our own experiments suggest that simple approaches to the leaching process may yield accuracies of 10 to 20% for chlorides in rocks with a significant PV fraction. As water contents decrease to 1%, however, an uncontrolled system may easily yield errors of several hundred percent and uncertainties associated with the bound water (see the section called Discussion). Most of the studies of interstitial chlorinity of water composition in deep oilfield strata have been performed on stored, dried, or partly dried materials and/or have used insufficiently documented or quantified techniques. The goal of this study has been to approach a reproducibility and relative accuracy of I % in the values of interstitial chloride, given our definition of mobile water discussed later. Sampling and Handling of Drilling-Core Samples A potential source of error in interstitial fluid analysis is the contamination of cores by drilling fluid. However, experience in the Deep Sea Drilling Project and other drilling studies 11โ15 show that, if external contaminated layers are cut or chipped away from undeformed normal, non-fractured silty-clay cores soon after recovery, virtually unaffected inner sections can be obtained. Even permeable (reservoir-type) rocks sometimes may be sampled successfully for pore-fluid study. During wireline coring by the AMCOR project with the drilling vessel Glomar Conception on the Atlantic Continental Shelf, virtually identical pore-fluid chloride profiles were obtained in repeated drillings performed with seawater and freshwater drilling fluids (Fig. 1). SPEJ P. 704
- North America > United States > Texas (0.95)
- North America > United States > Louisiana (0.94)
- North America > Canada > Alberta > Woodlands County (0.24)
- Phanerozoic > Mesozoic > Cretaceous (0.34)
- Phanerozoic > Mesozoic > Jurassic (0.34)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.30)
- North America > United States > Texas > East Texas Salt Basin > Hawkins Field > Woodbine Formation (0.99)
- North America > United States > Texas > East Texas Salt Basin > Cotton Valley Group Formation (0.99)
- North America > United States > Louisiana > East Texas Salt Basin > Cotton Valley Group Formation (0.99)
- (7 more...)
Introduction Maintaining an effective level of alkalinity during an alkaline flood is of prime importance in design of this EOR process. Alkaline solution can be consumed in the reservoir through interaction with both reservoir rocks and fluids. The rock/alkali interaction can be characterized as either chemical or ion-exchange reaction, and the magnitude of alkalinity consumption and its type must be considered when alkaline floods are designed for specific reservoirs. This is because alkalinity propagation in porous media is directly affected by the type of alkalinity loss. It has been shown previously that kinetically controlled mineral dissolution reactions may cause the produced alkalinity to plateau at a lower concentration than the injected concentration, whereas ion-exchange processes may cause characteristic delay in the produced alkalinity, which in turn delays tertiary oil production. The type and the magnitude of alkalinity loss therefore must be known to design a flood with alkaline concentration maintained at its optimum for the longest possible time. This paper concerns determining alkalinity loss resulting from hydrogen ion exchange. The model describing the release of initially rock-bound hydrogen ions into solution in the presence of alkali has been previously proposed and investigated for California Wilmington and Huntington sands. According to this approach the mechanism for reversible alkalinity uptake is described by the following equation. (1) Since the experiments were carried out with sand fully converted to the sodium form (i.e., sodium form at neutral pH), this implies that additional cation-exchange sites, different from those responsible for the Ca2+ -Na+ exchange, are involved in Na+ -H+ exchange. The number of these sites per unit mass was defined as the hydrogen exchange capacity (HEC) of the rock. The reaction described by Eq. 1 is reversible and implies simultaneous and equal uptake of Na+ and OH- ions. Previous experimental studies of the process described by Eq. 1 consisted of monitoring the effluent hydroxyl ion concentration during NaOH injection into a sandpack. However, mineral dissolution reactions always contribute to OH- loss, especially when minerals of high specific surface area are present. Hence, monitoring only effluent OH- concentration may exaggerate alkalinity loss resulting from hydrogen exchange. This work describes a new approach for determining the alkalinity lost as a result of hydrogen ion exchange during a coreflood. Monitoring sodium rather than hydroxyl ion concentration in the effluent of an alkaline flood circumvents the difficulty in assessing alkalinity consumption caused by hydrogen exchange alone. Effluent hydroxyl ion concentration reflects alkalinity losses resulting from chemical reactions with rock minerals and fluids as well as from any ion-exchange process; the changes in effluent sodium reflect alkalinity loss only from hydrogen exchange. Obviously, the method requires that the rock is converted to a single cationic form (i.e., sodium) before an alkaline flood. Experimental Procedures All experiments presented were carried out with Berea sandstone at 23 deg. C [73 deg. F] in the absence of an oil phase. Two series of coreflooding experiments were performed. The first was designed to ascertain whether the Na+ uptake occurs during an alkaline flood (as suggested by Eq. 1) by performing an alkaline flood in a Berea core completely converted to sodium form and by monitoring the sodium concentration in the effluent. The sodium concentration in the NaCl brine filling the pore space prior to NaOH injection was closely matched to the sodium concentration in the injected NaOH solution to make it possible to measure small changes in the effluent sodium concentration caused by hydrogen ion exchange. The second series was designed to determine the Berea sandstone cation-exchange capacity (CEC) at alkaline pH by Na+ -Ca2 + exchange and to compare its value with that of the HEC. Caustic Floods in Berea Core. Dry and epoxy-coated rectangular Berea cores were evacuated and saturated with either 0.5 or 1.0 N NaCl brine (2.9 or 5.6 wt% NaCl). Several pore volumes (PV) of NaCl brine were injected and the cores were allowed to age for several days to achieve a complete conversion to the sodium form. P. 49^
- North America > United States > West Virginia (0.46)
- North America > United States > Pennsylvania (0.46)
- North America > United States > Ohio (0.46)
- North America > United States > Kentucky (0.46)
- Geology > Mineral (0.96)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.46)
Abstract Evaluation of tight gas reservoirs requires an accurate but rapid and practical method to determine permeability. Such a method is presented for determining both specific and effective gas permeability in the 0.0001- to 0.35-md range for plug-size core samples. Equipment is described that meets the requirements for calculation of nonsteady-state flow and incorporates the capability of simulation, high net overburden pressures by either hydrostatic or triaxial confining pressures with ease of operation. The time required to collect data and calculate Klinkenberg permeability is typically less than 6 minutes per sample. Values normally differ by less than + 5 % from those obtained by steady-state methods. This method is well suited for routine laboratory determinations of permeability on samples from reservoirs with tight or very low gas permeability. Effective gas permeabilities on samples containing nearly irreducible water saturations and the water permeabilities presented are closer to the Klinkenberg permeability values in low-permeability samples than most previously reported. Introduction Substantial price incentives exist in the U.S. to make it attractive for producers to recover gas from tight formations that are less than 15,000 ft 14572 mi deep and have no more than 0.1 md in-situ permeability. This incentive, plus the need for a rapid method to obtain accurate laboratory data on low-permeability samples for well completion and gas reservoir engineering, made it desirable to develop the subject equipment and test method. Various methods used to determine limiting permeability were investigated. The conventional method of determining three specific gas permeabilities and using the Klinkenberg relation to determine a limiting permeability is laborious. Methods involving numerical solutions of one-dimensional (ID) gas-flow equations such as those proposed by Aronofsky and Jenkins and Bruce et al. involve solutions by finite differences. This approach required long calculation times, which made it too cumbersome. Methods such as those proposed by Brace et al. and Walls et al. require pore pressures of the sample to be brought to equilibrium at values close to the reservoir pressure before analysis of the sample, and thus excessive time is required in approaching equilibrium. Jones suggested accounting for the non steady mass flow through the sample during an upstream pressure drawdown test. Such an approach may be used with relatively low mean pore pressures ( - 100 psig ( 690 kPa). The number of calculations was not large, while the reported accuracy was good. The method described in this paper accounts for the nonsteady mass flow through a sample during a downstream pressure-buildup test. The downstream approach allows the smallest possible downstream volumes to be used and ensures flow through the sample. These small downstream volumes allow the detection of very small flow rates in a relatively short time. SPEJ P. 928^
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type (0.70)
Abstract A method has been developed for using nonstatic pressure measurements directly in gas reservoir material balances composed of various energy mechanisms. Applying this method leads to simultaneous determinations of the reservoir p history, gas in place, and other parameters relevant to water influx and effective compressibility. Well-known methods of determining average static pressure, p, have at least two shortcomings:an estimation of reservoir shape and an often-neglected implicit relationship between p and the viscosity-compressibility product. Errors resulting from these deficiencies are minimized by the proposed method through a simple coupling of the well-known pseudo steady-state flow and material-balance equations. The solution of this coupling is obtained through nonlinear regression, and it allows simultaneous evaluations of gas initially in place, static pressure history, and several other reservoir parameters. These parameters can include the initial reservoir pressure, a stabilized gas-deliverability constant, the effective compressibility, aquifer diffusivity, and aquifer volume plus water-influx constants. The results of applying the method to six published cases are presented to illustrate the utility of the method. Introduction Before performing material-balance calculations, separate determinations of the average static reservoir pressure history from available drawdown and buildup tests and shut-in or flowing gradient surveys were required. Well-known methods used for these determinations have been shown by Matthews et al., Odeh and Al-Hussainy, Brons and Miller, and Dietz. All these methods for determining p have one or more undesirable requirements such as a preknowledge of the hydraulic diffusivity in terms of the reservoir area and the reservoir boundary shape plus the assumption of a volumetric depletion-type reservoir-drive mechanism. An additional drawback is found in the implicit relationship between p and the viscosity-compressibility product of the dimensionless time parameter. This product must be evaluated at p in the aforememtioned methods; therefore, the solution of p is implicit. Kazemi has discussed this problem for both oil and gas cases. The proposed method eliminates the intermediate steps in determining a p history before calculating material balances, and it does not require a preknowledge of the hydraulic diffusivity, boundary shape, or reservoir-drive mechanism. Part of the original development work on this problem was presented by Garb et al. This publication showed an iterative method that coupled the functional p terms of the material-balance and the pseudosteady-state flow equations for drawdown and buildup cases. However, the method was limited to determining only gas initially in place for normalpressured, nonwater-drive reservoirs. The new development formulates the problem in a different manner to obtain nonlinear solutions in various reservoir-drive mechanisms. This method eliminates the prerequisite of p determinations, and it provides simultaneous solutions of gas initially in place, p history, water influx, and effective rock and connate water compressibilities. SPEJ P. 209^
Abstract The presence of significant amounts of clay in tight-gas sand formations makes the determination of cation exchange capacities (CEC) important for electric-log, self-potential (SP), and gamma ray log interpretation. In the past, CEC measurements have been difficult and time-consuming to obtain. However, an automated method that avoids many difficulties of other techniques while determining the CEC's of many samples at one time has been described by Worthington . Our work is a modification of the work done by Worthington. Easily assembled commercial equipment instead of specially built equipment is used to agitate rock samples contained in dialysis membrane bags during ion exchange with barium acetate solution and during washing of the samples to remove excess barium ions. Barium acetate is used as the source of barium ions instead of barium chloride, which is used in Worthington's procedure. to avoid corrosion of the stainless steel equipment. The amount of barium ions on the rock samples is then determined by conductometric titration with magnesium sulfate. The titration procedure is not automated. In addition, the use of the barium ion method was extended to samples with CEC values an order of magnitude lower than those determined by Worthington. Most measured CEC's for the western tight-gas sands ranged from 0.5 to 10 meg/100 g with a few to 19 meg/100 g. A comparison of barium acetate, adsorbed water, and ammonium acetate methods for determining CEC's is made. Introduction The highly reactive surfaces of clay, which act as ion exchangers. have a large effect on the physical and chemical behavior of reservoir rocks. The measure of the amount of exchangeable ions on the clay is called the CEC. The CEC describes the amount of reversible exchange occurring between ions in a liquid phase and a solid phase that does not significantly change the structure of the solid. It is measured in terms of the amount of positive ion substituted per unit weight of dry rock or, more often, in terms of the amount of positive ion substituted per 100 g of solid material. Quantitative interpretation of electrical resistivity and SP logs used to evaluate porosity and water saturation of permeable formations is affected by the clay content of the formation. Gamma ray measurements may also be affected by the presence of certain clays. Hill and Milbum studied the conductivity properties of shaly sandstones and derived an empirical relationship to account for deviation from Archie's relationship resulting from the "effective clay content" of the shaly sands. Johnson and Linke described the types of clays found in reservoir rock and the clay's effects on the interpretation of various logs. In general, clays such as kaolinite and chlorite have an insignificant effect on resistivity reduction. Grim reports a low CEC for kaolinite (3 to 10 meg/100 g) and a higher CEC range for chlorite (10 to 40 meg/100 g). However, measurements in our laboratory and by Worthington as reported by Johnson and Linke indicate that chlorite behaves in a manner similar to kaolinite. Montmorillonite and illite, on the other hand, are effective resistivity reducers. Their CEC's range from 80 to 100 meg/g and 10 to 40 meg/g, respectively. SPEJ P. 231^
- North America > United States (1.00)
- Europe > Norway > Norwegian Sea (0.24)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.75)
Abstract An important parameter required for computing heat loss through buried submarine pipelines transporting crude oil is the thermal conductivity of soils. This paper describes an apparatus designed for determination of the thermal conductivity of soils at the desired moisture/ density condition in the laboratory under steady-state conditions. Experimental results on the three soils studied show that thermal conductivity increases as dry density increases at a constant moisture content and that it increases as water content increases at constant dry density. These results confirm the trends isolated earlier by Kersten. The experimental results are compared with the available empirical relationships. Kersten's relation is observed to predict the thermal conductivity of these soils reasonably. The predictions from Makowski and Mochlinski's relation (quoted by Szilas) are not good but improve if the sum of silt and clay fractions is treated as a clay fraction in the computation. Introduction Submarine pipelines are used extensively for transporting crude oil from offshore to other pipelines offshore or onshore. These pipelines usually are steel pipes covered with a coating of concrete. They often are buried some depth below the mudline. The rheological properties of different crude oils vary, and their viscosities increase with a decrease in temperature. Below some temperature, the liquid oil tends to gel. Therefore, for efficient transportation, the crude must be at a relatively high temperature so that it has a low viscosity. The temperature of the soil/water system surrounding a submarine pipeline is usually lower than that of oil. This temperature difference induces heat to flow from the oil to the environment, and the temperature of the oil decreases as it travels along the length of the pipeline. One must ensure that this temperature reduction does not exceed desirable limits dictated by the rheological properties of oil and by the imperatives of efficient economic properties of oil and by the imperatives of efficient economic transportation. Thus the analytical problem is to predict the temperature of crude in the pipeline some distance away from the input station. To do so, knowledge of the overall heat transfer coefficient for the pipeline is required, for which, in turn, it is necessary to know the thermal conductivities of the oil, the pipeline materials and its coating, and the soil. This paper presents thermal conductivities of soils determined in the laboratory under steady-state conditions and also presents a comparison of the test results of three soils with values determined from existing empirical relationships. Literature Review Heat moves spontaneously from higher to lower temperatures. In a completely dry porous body, transmission of heat can take place not only by conduction through the solid framework of the body and the air in the pores but also by convection and radiation between the walls of a pore and by macro- and microdistillation. In soils, however, it can be ascribed essentially to conduction, a molecular phenomenon that can be expressed in terms of experimentally determined coefficients of conductivity or resistivity, although these actually may include microdistillation and other mechanisms. SPEJ p. 558
Summary A new method is described for the determination of the equivalent weight for petroleum sulfonates. The method is based on the direct acidimetric titration of the sulfonate in acetic acid/acetic anhydride solvent using a titrant of perchloric acid in dioxane. From the titration, the moles of perchloric acid required to react with the sulfonate is measured. The equivalent weight is calculated from the grams of sample titrated and the moles of acid used. The potentiometric titration can be carried out in less than 10 minutes and can be done with 10 to 100 mg of sample. The accuracy and precision of the procedure were examined by the titration of sodium salts of p-toleuene sulfonate, 2-naphthalene sulfonate, and petroleum sulfonates. In general, values for the equivalent weight were within 2% of those values determined by the Epton titration, by wet ashing methods, or from the theoretical value. The relative standard deviation (RSD) for the procedure is estimated to be 0.5%. For p-toluene sulfonate, an RSD of 0.15% was calculated. The new method was used to determine the equivalent weights for three fractions of a petroleum sulfonate obtained by the preferential elution from silica gel with alcohol. A series of samples with varying equivalent weight was prepared by proportional combination of the three fractions. Analysis by high-performance liquid chromatography (HPLC) gave a set of data points of peak areas for the series. A plot of equivalent weight as a function of disulfonate to total peak area ratio resulted in a straight line. The slope of this line is descriptive of the molecular weight range for the petroleum sulfonate. Introduction Petroleum sulfonates are used to liberate a residual oil from a porous medium in a tertiary oil-recovery process. One mechanism for the release of oil is the reduction of the interfacial tension between water and oil to values on the order of 10 dyne/cm. The performance of a sulfonate as a surfactant depends on its molecular size and structure. For a pure single-species sulfonate, these properties can be correlated with the alteration of the interfacial tension between water and oil. The same cannot be done for a petroleum sulfonate because the sulfonate is a mixture of molecular species with unknown structures. Previous studies have shown that the overall composition of a petroleum sulfonate is altered by the preferential partitioning of the molecular species to the oil, water, and rock phases. This causes the composition of the sulfonate to change constantly as it flows through the porous media contacting water and oil. To correlate oil-recovery efficiency with a property of the sulfonate, analytical methods are needed to characterize the effluent from core floods. One parameter for characterizing petroleum sulfonates is the average equivalent weight, which is the weight in grams containing 1 mol of sulfonate functional groups. Sufficient sample is often not available for the equivalent weight analysis by the ASTM wet ashing procedure, and the oil in the sample may often interfere with the Epton titrate method. Therefore, a study was initiated to develop a method for the determination of equivalent weight of petroleum sulfonates in the 10- to 100-mg range. Of equal importance is a method to count sulfonate groups and to differentiate mono- and disulfonate molecules. The latter can be achieved by HPLC using an anion exchange column. However, quantification of the effluent from the HPLC column remains a problem. No detector is available that responds specifically to the sulfonate functional group -SO3. Specific ion-electrodes of the liquid- or solid-membrane type show varying response to sulfonates depending on the molecular weight of the sulfonate.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract The classical approach to forecasting hydrocarbon reservoir behavior is through modeling. Traditional models are based on equations describing the physical behavior of the reservoir-plus-aquifer system; usually the parameters describing aquifer behavior are not known beforehand and are evaluated by a trial-and-error procedure based on the best fit of past reservoir performance. This approach leads to models that are intrinsically realistic, as they reflect the physical nature of the phenomena involved. A completely different approach, based on system theory techniques, is presented in this paper. This technique, called identification, consists of the determination of a mathematical model equivalent to the process under test, the word "equivalent" meaning that the process and the model show the same input/output behavior. As a consequence, an identified model of this type can be used to predict the response of an actual reservoir-plus-aquifer system to different inputs - i.e., to different production schedules. Case histories of the application of the identification technique to actual gas storage reservoirs are presented. Introduction As with many other aspects of the world, a gas reservoir can be considered a dynamical system interacting with an external environment by means of inputs and outputs. The exchanges between a reservoir and the rest of the world occur through wells and the measurable attributes at every well are given by the gas production rate and pressure. Thus, it is possible to consider the cumulative gas production of wells as inputs and the well pressures as outputs of this system. Note that when a water drive mechanism is present, the cumulative quantity of water which has entered the reservoir should be considered one of the system's inputs; however, this information is not usually available since wells are drilled where hydrocarbons, rather than water, are expected. In the selection of a suitable model for a reservoir, the choice between linear and nonlinear models must be made. In many cases, linear models are used because of their relative simplicity and of the general theory that has been developed for their treatment. No general theory can be found for nonlinear systems; this explains why clearly nonlinear systems have been studied, designed, built, tested, and operated using only the linear system theory. A gas reservoir, particularly when used for storage purposes, is virtually a linear system; therefore a model of this type is useful to describe its behavior accurately. Another choice regards the time invariance of the model. Gas reservoirs are time invariant; however, if an aquifer is present and no measurements of the cumulative amount of water which has entered the reservoir are available as a system input, the reservoir behavior will change with time and only a time-dependent model could be completely accurate. The selection of a time-invariant model can lead to a lack of accuracy, particularly for water-driven reservoirs when the first production years are considered; the aquifer contribution to time dependency becomes less important in subsequent years. This paper shows that the limits on the use of time-invariant models are no longer valid for reservoirs subjected to injection/production schedules and that models of this kind can be obtained inexpensively and accurately by means of identification procedures performed on the available system history. SPEJ P. 151^
- Europe > Italy > Emilia-Romagna > Po Basin > Cortemaggiore Field (0.99)
- Europe > Italy > Brugherio Field (0.99)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > Natural gas storage (1.00)
- Production and Well Operations (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (0.66)
Abstract Partially hydrolyzed, water-soluble polyacrylamide Partially hydrolyzed, water-soluble polyacrylamide polymers in oilfield brines were determined by polymers in oilfield brines were determined by oxidation with bromine at pH 3.5 to give a product that oxidized iodide ion to iodine. The iodine was measured spectrophotometrically as the starch-triiodide complex.Analyses of samples containing polyacrylamide polymers ranging from 10 to 100 ppm concentration polymers ranging from 10 to 100 ppm concentration gave results with a pooled standard deviation of 0.91 ppm and an average recovery of 104%. Separate ppm and an average recovery of 104%. Separate calibration for each batch of polymer was required because of the nonuniform composition of the product. product. Introduction Water-soluble polymers and copolymers of acrylamide and its derivatives are used to treat water and in oil recovery. These polymers are in the 3 to 15 million number-average molecular weight range and may have up to 50% of the amide groups hydrolyzed. A rapid method for determining less than 100 ppm of these materials in surface water and oilfield brine is described here.Turbidimetric techniques using a quaternary ammonium cation (Hyamine 1622 TM) or the hypochlorite ion as precipitants were applied to both polyacrylic acid and hydrolyzed polyacrylamide polyacrylic acid and hydrolyzed polyacrylamide polymers. While these techniques are rapid and polymers. While these techniques are rapid and sensitive, they are subject to heavy metal ion interference. Measurements used by others but deemed unsatisfactory for our work include total nitrogen, amide nitrogen, solution viscosity, and organic carbon.Post and Reynolds used a hypobromite oxidation-spectrophotometric titration to assay various aliphatic amides. Adapting this technique for analyzing acrylamide-based polymers yielded semiquantitative results. A polymer manufacturer recommended a similar procedure, based on this reaction, to form an N-bromoamide oxidation product. After destroying the excess oxidizing agent product. After destroying the excess oxidizing agent (bromine), the N-bromoamide oxidation product reacted with iodide ion to form iodine. Finally, the iodine was measured as the familiar starch-triiodide complex. Lambert described a superior iodide reagent using a linear A-fraction of potato starch/cadmium iodide solution as both the color reagent and source of iodide ion. We used this reaction to determine water-soluble amides. We have modified the bromine oxidation reaction conditions to make the reaction applicable for samples containing high concentrations of chloride ion. We combined this with the stable Lambert reagent to provide a reliable and sensitive procedure for determining polymers containing the primary amide group. Experimental Reagents and Apparatus Buffer solution was pH 3.5. We dissolved 25 g sodium acetate trihydrate in 0.80 dm3 water, added 0.11 dm3 glacial acetic acid and 0.75 g hydrated aluminum sulfate, adjusted the pH to 3.5 with acetic acid, and diluted the solution to 1 dm3. Starch-CdI2 color reagent was prepared as described in Ref. 7, except that we used J. T. Baker Iodometry Grade potato starch powder. Sodium formate (1 % solution) potato starch powder. Sodium formate (1 % solution) and saturated bromine water were required. Linear starches were obtained from Stein, Hall and Co. Inc. We measured absorbance on a Cary Model 11 spectrophotometer in 1-cm cells. SPEJ P. 151
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Well fluid analysis (0.75)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (0.56)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (0.54)