Polymer injection and filtration field tests being carried out inthe East Coalinga field have been used to determine the degree ofin-situ mobility control and to furnish measurements and determine the nature of wellbore impairment. These tests also have been usedto develop criteria for describing solution quality using polyacrylamideand two grades of biopolymer. Introduction Water and polymer field-injection tests are beingconducted to furnish data for a planned pilot projectin the Temblor Zone II reservoir in the East Coalingafield, Calif. The pilot project will evaluate therelative merits of polymer flooding and waterflooding.A waterflood would have an unfavorable mobility ratioof 14.0, but this could be reduced to 1.5 with polymerflooding. Fig. 1 is an index map of the Coalinga fieldshowing the pilot project area.To choose the most suitable polymer for this project, it was necessary to determine the injection characteristicsof both polyacrylamide polymer and biopolymers. Theinjection field tests were supported by field filtrationtests and laboratory studies to define polymer viscosityand filtration properties. The field tests consistedof injecting both polymer solutions and pure water atdifferent times for periods of weeks to generate comparison data for polymer and water for determining thedegree of in-situ mobility control and possible wellboreimpairment. Polyacrylamide Injectivity Test Polyacrylamide polymer (Pusher 700) was originallyselected for field testing at the Coalinga field because, at the time of the test, more was known about thispolymer. To achieve maximum mobility control usingpolyacrylamide, and because it was readily available, afresh-water (300-ppm NACI) source was developed forthe project. This water caused severe wellbore damage (20-fold decrease in permeability) from clay swellingand dispersion during initial water-injection testing;therefore, the test well was chemically treated with theDarley treatment to prevent this damage.The properties of the unconsolidated sand and thefluids involved with the tests are as follows: Property Hx Sand Jv Sand Dept, ft 1,660 1,750Thickness ft 8 17Permeability, md 470 230water at Sor, md 165 80Porosity 0.28 0.28Oil gravity, deg.API 20 20 20Reservoirtemperature, deg.F 100 100Oil viscosityat reservoirtemperature, cp 25.0 25.0Water viscosityat reservoirtemperature, cp 0.64 0.64 The injection system for the polyacrylamide testwas carefully designed to prevent mechanical shear oroxygen degradation of the polymer at the surface. Fig.2 is a plot of water and polymer injectivity vs cumulative injection. JPT P. 586^
Summary Most steamflood operations recycling water will experience silica scales at some location in the field operation. It is usually noticed in the steam generators or heat recovery steam generators (HRSG) used for cogeneration. Whether fresh water or recycled water is used, the hot water, high pH portion of the steam will affect the steam injection wellbore. Silica scaling in the formation around production wells, in the screen of the production wells, and in the pump in the production wells are also noticed due to flashing and deposits of silicates. Some of the silica scales can be controlled, some are beneficial, and some are very costly and difficult or impossible to control. In the formation the silica is in equilibrium with quartz so quartz solubility applies, while the more soluble amorphous silica solubility controls when not in contract with quartz rocks. Introduction Silica is a very complex chemical species with many different forms. In this article we will assume the silica is either the most insoluble quartz, or the more soluble, amorphous silica. The scale formed mostly is silicates—metal ion silicates such as sodium iron silicates or hardness ion silicates. In the oil field, deposits of silica or silica polymers are usually not found due to the long time required for them to form. Much of the literature on silica is concerned with geothermal operations. There are many U.S., German, Russian and Japanese articles that include studies of pH, temperature and total dissolved solids (TDS) waters vs. solubility. Equilibrium The silica in the water from a steamflood operation can be calculated from the bottomhole temperature of the well based on the quartz solubility curve. The solubility of the silica in the formation is thus controlled by the quartz solubility. Once the solution enters the wellbore the more soluble amorphous silica controls the solubility; otherwise the water would be supersaturated with silica as it cooled coming up the wellbore.1 Quartz solubility controls where there is quartz crystal material available. Thus the reservoir formation is all quartz solubility (or mixed solubility when other silica rock is also present but usually just quartz is considered). In the steam generator, the amorphous silica solubility controls and is very soluble at the high pH inside the unit. Once steam is generated and reinjected into the formation, the quartz solubility controls (which also increases in solubility with pH). Silica is only partially soluble in the steam itself. This is very important for steam turbines, but there is ample literature in this important area for those interested. It is important to know which solubility equilibrium on the silica is applicable. There are no really good silicate scale solubility numbers available. Some of the water solubility programs can predicate many of the silicate scales and some can even concentrate the water as if generating steam. Usually those programs associated with the geothermal operations are the best for silicates and steam generation. For amorphous silica, a limit of 75 ppm has evolved from the cooling tower industry. Experience has indicated that with 75 ppm silica in the feedwater only about 4 to 5 cycles or concentration can occur in a cooling tower prior to scaling. This has then been applied to the steam generation. Thus, the scale inhibitors which have been shown to inhibit silicate scale formation are limited to about 75 ppm silica in the feedwater and were developed from the cooling tower work. There are some new polymers on the market but they do not have any data on silicate inhibition at high temperatures and it is doubtful if they are useful at a high inlet water silica concentration. It would be a great benefit if a compound were developed. Steam Generators Internal in a steam generation, the alkalinity will decompose and form carbon dioxide and sodium hydroxide. The steam mixture for 70 to 80% steam quality will be pH of 10 to 11. (If steam is separated, the carbon dioxide goes with the steam and the water will contain the caustic and can indicate even higher pH.) Besides the 10 to 11 pH being beneficial to silica solubility, it is also the lowest point for iron solubility in hot water so iron is not put into solution. Also, it is known that a protective film of magnetite forms on steel when exposed to hot water. Thus pickup of iron, excluding an oxidizing agent such as oxygen, etc., should not occur in a steam generator. However iron contained in the inlet water will be deposited, depending upon the heat flux rate. Boilers have flux rates of about 100,000 Btu/hr/ft2 steam generators about 20,000 and heat recovery steam generators (HRSG's) about 1,000. Therefore boilers are the worst and HRSG's are the least problem on iron deposits from inlet water. Boilers can also develop a problem of caustic embrittlement or "free caustic gouging" but this requires high heat flux and is not normally seen in oil fields. In fact, the problems with the Foster Wheeler boilers at Shell's Mt. Poso field in the late 1970's was sodium iron silicate due to inlet iron and not caustic gouging related. Thus, with or without silica, iron can be deposited in heat equipment. Insoluble iron is usually deposited in the convection section, preheaters, etc. and soluble iron in the radiant section as the concentration of the ion is increased. Silica will not normally deposit in a steam generator. Amorphous silica becomes much more soluble with temperature and especially above pH 9 (Figs. 1 through 3)2 and can remain metastable at nearly twice the concentration for long periods without solid amorphous silica present. However silicates are a problem—mostly sodium iron silicates but also hardness silicates. Therefore the inlet iron must be limited to below 0.4 ppm soluble iron and it is better at 0.2 ppm soluble iron. No sodium iron silicates have occurred with water of low iron and 500 ppm silica, generating 70 to 75% steam quality at 1,000 psi in field tests. Shell, Mobil and Chevron have reported the problems that occur once the sodium iron silicates forms. However, the cause was the iron and/or hardness in the inlet water. Hot shutdowns will usually clean any sodium iron silicates from the tubes of steam equipment and sometimes is done rather than use of fluoride ion, but this can be very stressful mechanically. Preheaters usually need chemical cleaning.
As a result of a steam-injection process that uses the underlying water layer, impressive quantities of oil have been recovered from a reservoir that previously yielded only marginal production. Although many difficulties have reduced the profitability, it is expected that by applying recent technology and field experience, the oil-steam ratio, and hence the economics, will be significantly improved. Introduction and History The Slocum field is in southern Anderson County in northeast Texas. Production of 19 degrees API oil, ranging in viscosity from 1,000 to 3,000 cp is from the shallow Carrizo formation (500 to 600 ft). The oil accumulation is anticlinal bounded on the north by a fault and elsewhere by the oil-water contact. (See Fig. 1.) Although the sand is generally very clean, and has a permeability of about 3,500 md, the viscosity of the oil at the reservoir temperature of 75 degrees F allows only marginal primary recovery. Since the discovery of the field in 1955, numerous exploitation attempts have recovered only 300,000 bbl of oil, or about 1 percent of the original oil in place. A typical primary well produces only 1 to 2 BOPD. primary well produces only 1 to 2 BOPD. The viscosity-temperature behavior of the oil is such that its viscosity is reduced by a factor of more than 100 when the temperature is increased to 350 degrees. (see Fig. 2), which suggests that the oil might be produced successfully with thermal recovery produced successfully with thermal recovery processes. Other favorable conditions for such a process processes. Other favorable conditions for such a process are the shallow depth of the accumulation, the high oil saturation (65 percent), and the availability of high-quality, fresh water for generating steam or hot water. However, the absence of natural reservoir energy eliminates the possibility of a steam soak, and the high viscosity of the oil precludes a direct steam drive in the oil column. Initial reservoir pressure is only 110 psig with no significant gas saturation. Preliminary field tests indicated that although these Preliminary field tests indicated that although these processes would recover additional oil, they would not processes would recover additional oil, they would not be economical. Thus, merely reducing oil viscosity in the reservoir is not sufficient. If the oil is to be successfully unlocked, a more efficient recovery process must be used. process must be used. The reservoir geometry provides the means for such a process. Throughout the field, a water sand underlies the oil sand. (See Fig. 3 for type log.) If steam were injected into this sand, heat would be introduced into the reservoir faster, and would be placed in contact with a much greater portion of the placed in contact with a much greater portion of the oil than by injection into the oil zone. To test this steam-injection process, a 1/4-acre pilot was conducted in 1964–1965. It consisted of a normal five-spot pattern with four injectors, a central producer, and a temperature observation well equipped producer, and a temperature observation well equipped with a thermocouple. Approximately 40 percent of the oil in place within the pilot area was produced. Encouraged by this favorable recovery, Shell Oil Co. started a full-scale 7-pattern project in 1966–1967. Designated as Phase 1, it consisted of 5.65-acre, 13-spot patterns elongated in a NE-SW direction. (See Fig. 4.) The elongation was expected to compensate for a NE-SW preferential flow that had been observed during primary and pilot operations. Both production and injection wells were completed a few production and injection wells were completed a few feet into the water sand. P. 402
An investigation was conducted of the hydraulic characteristics and effectiveness of commonly used oilfield oil-water separators. Measurements were made in a number of separators by injecting a radioactive tracer using a pulse technique. Residence time distributions were calculated to deduce the hydraulic characteristics of the separators, and these were compared with the effectiveness of the separator operations. Introduction The principal method used for separating oil from water in oil production operations is gravity separation. Although simple differences in density are often adequate, gravity commonly is assisted by the use of gas flotation, heat, chemicals, and high-surface-area coalescer sections. These separators come in many different mechanical configurations. Despite this variety in design and configuration, there are remarkably few engineering criteria for properly designing such separators. A notable exception to this is the "API separator," widely used to separate free oil from refinery and chemical-plant waste waters. The design principle's of this separator are based on a 3-year study instituted at the U. of Wisconsin in 1948. A significant part of this study consisted of determining the hydraulic characteristics of the separator by using tracer response techniques. The data obtained from this study, however, apply only to the specific mechanical configuration of the rectangular API separator and free oil (droplet size above 150 microns). A 1956 survey of some circular oil-water separators suggested that, while they often appear to work, "a rational design procedure had not yet been developed." This applies procedure had not yet been developed." This applies even more to the cylindrical oil-water separators so widely used in oilfield separation, particularly to those separators with ratio of width to length approaching unity. As part of our effort to develop a more rational design procedure, the hydraulic characteristics of a number of procedure, the hydraulic characteristics of a number of different oil-water separators used by Shell Oil Co. were measured. These included many different designs and oilfield locations. These measurements were made under operating conditions by injecting a radioactive tracer using a pulse technique. The tracer response was monitored through the walls of the exit pipes by means of suitable detectors. From these data, residence time distributions (RTD's) were obtained, from which the hydraulic characteristics of the separator could be deduced. This paper defines the terms used in these analyses in accordance with current usage. The principles involved are discussed briefly and the necessary equations are given in terms of our applications. The results obtained from field tracer tests in a number of different separators are described. The tracer injection method has been presented fully in a previous paper and only is described presented fully in a previous paper and only is described here. Ref. 4 also included simplified descriptions of the basic terminology. Principles and Terminology Principles and Terminology Tracer response data have been used widely to obtain residence time distributions in nonideal systems. These data then can be used to characterize the hydraulic behavior of a given vessel. A large collection of literature on the interpretation of such data is available. Some examples are given in the figures. A consistent language for expressing hydraulic characteristics in terms of their RTD's first was developed by Danckwerts and extended by Levenspiel, Himmelblau and Bischoff, and others. JPT P. 275
Recycle of high hardness, high TDS(total dissolved solids) waters (hardness>1000 parts per million (ppm) as CaCO3 and TDS>10,000 ppm) water for steam generation or other reuse such as irrigation or drinking water is very expensive. Silica content is usually above 250 ppm in such waters which can cause problems in steam generation and with desalination. Many of the these high hardness waters are oil field produced waters but there are other processes which generate waters which require additional treatment.For those high hardness waters, hot lime or hot caustic, followed with strong acid/weak acid resin or just weak acid resin softeners are used in conjunction with oil field steam generation. Treatment of these waters for irrigation or drinking waters involves thermal desalination or reverse osmotic(RO) treatment with biological control. Silica removal is not required for normal wet steam genera tion. However for desalination operations, whenever the feed water concentrate is to be used for the steam generator feed and the fresh water sold, silica removal is required to aid in scale formation in desalination plus silica level in the concentrate water. The known limits on the concentrate feed water to a wet steam generator are 500 ppm silica and 25,000 – 30,000 ppm TDS of total water ions, based on soluble salts solubility. Silica removal is also required in other waters such as 210,000 ppm TDS water containing sodium carbonate where silica removal is required prior to crystallization of sodium carbonate crystals. In the softening test work, the high solids addition and disposal associated with a hot lime system was not desired so alternatives were investigated. In addition, better silica removal than silica absorption on magnesium hydroxide or alumina or aluminum was required. Steam stripping of the high pH water and removal of the precipitates using a ceramic crossflow filter for which a special crossflow filter back pulse unit for cleaning was developed. Temperature and pH were increased prior to the steam stripping to decrease steam condensation and drive the reaction. When silica removal was required, a bed of alumina or aluminum was used at the high pH and temperature to put aluminum into solution so aluminum silicates were removed with the hardness precipitates. The solids often contain some oil when using oil field waters so an odor chemical was also developed for the microbiological soil remediation site. The steam stripping was tested first in a countercurrent mode in a stainless steel column clad with a Hastelloy C 22, packed with stainless steel packing. The second test was by injecting the steam on the outside circumference of a crossflow ceramic microfilter in a cocurrent mode with flashing in a exit vessel. In the countercurrent tower operation, the control of the equili brium of the carbon dioxide, the carbonate and bicarbonate at the top of the tower was more difficult than when contacting with the microfilter.With the microfilter, the equilibrium approach was not a large concern as fresh steam was contact ing the water and was then flashed. However the exact control of the steam to water ratio was more difficult in the second case. Both thermal desalination and RO were pilot tested with wa ters from 10,000 to 36,000 ppm TDS to produce potable water with a quartz ultraviolet light for biological (disinfection) control. For wet steam generation, the field produced waters(10,000–24,000 TDS) were tested using strong acid/weak acid resin softening with no silica removal in a 1 MM BTU/Hr wet steam generator.1 The overall operational costs were less than normal sequence of processes mentioned in the literature while the capital costs were in the same range. Patents were obtained on the(1) steam stripping softening, (2)silica removal,(3) back pulse on the micro filter and(4) the odor chemical. A patent on the sour gas treatment is pending.
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