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Early U.S. settlements commonly were located near salt lakes that supplied salt to the population. These salt springs were often contaminated with petroleum, and many of the early efforts to acquire salt by digging wells were rewarded by finding unwanted amounts of oil and gas associated with the saline waters. In the Appalachian Mountains, saline water springs commonly occur along the crests of anticlines. In 1855, it was found that petroleum distillation produced light oil that was, as an illuminant, similar to coal oil and better than whale oil. This knowledge spurred the search for saline waters containing oil. With the methods of the salt producers, Colonel Edward Drake drilled a well on Oil Creek, near Titusville, Pennsylvania, in 1859. He struck oil at a depth of 70 ft, and this first oil well produced approximately 35 B/D. Early oil producers did not realize the significance of the oil and saline waters occurring together. In fact, it was not until 1938 that the existence of interstitial water in oil reservoirs was generally recognized. Torrey was convinced by 1928 that dispersed interstitial water existed in oil reservoirs, but his colleagues rejected his belief because most of the producing wells did not produce any water on completion. Occurrences of mixtures of oil and gas with water were recognized by Griswold and Munn, but they believed that there was a definite separation of the oil and water, and that oil, gas, and water mixtures did not occur in the sand before a well tapped a reservoir. It was not until 1928 that the first commercial laboratory for the analysis of rock cores was established, and the first core tested was from the Bradford third sand (Bradford field, McKean County, Pennsylvania). The percent saturation and percent porosity of this core were plotted vs. depth to construct a graphic representation of the oil and water saturation. The soluble mineral salts that were extracted from the core led Torrey to suspect that water was indigenous to the oil-productive sand. Shortly thereafter, a test well was drilled near Custer City, Pennsylvania, that encountered greater than average oil saturation in the lower part of the Bradford sand. This high oil saturation resulted from the action of an unsuspected flood, the existence of which was not known when the location for the test well had been selected. The upper part of the sand was not cored. Toward the end of the cutting of the first core with a cable tool, core barrel oil began to come into the hole so fast that it was not necessary to add water for the cutting of the second section of the sand. Therefore, the lower 3 ft of the Bradford sand was cut with oil in a hole free from water.
Publication Rights Reserved, U.S. Government Publication Rights Reserved, U.S. Government This paper was prepared for the 1977 SPE-AIME International Symposium on Oilfield and Geothermal Chemistry, held in La Jolla, California, June 27-28, 1977. Permission to copy is restricted to an abstract of not more than 300 words, Illustrations may not be copied. The abstract should contain conspicuous acknowledgement of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal, provided agreement to give proper credit is made. Discussion of this paper provided agreement to give proper credit is made. Discussion of this paper is invited.
A survey was made of the types of waters, chemicals, and water-treatment methods used in enhanced-oil-recovery operations. The study indicated that numerous types of waters, chemicals, and water-treatment methods are used. Chemical and biochemical reactions can occur when different types of waters are mixed, or when enhanced-oil-recovery chemicals are added. Stringent quality control is needed in all operational phases related to injection waters in order to produce optimum amounts of oil and to prevent irreparable damage to equipment, wells, and oil reservoirs. Standard methods are needed to assure adequate quality control.
In this report, enhanced oil recovery is defined as the additional production of oil resulting from the introduction of artificial energy into the reservoir. Primary oil recovery is defined as the oil and gas produced by natural reservoir energy or forces. Therefore, by this definition enhanced recovery includes waterflooding, gas injection, and other operations involving fluid or gas injection whether for secondary or tertiary oil recovery. Tertiary recovery is any enhanced-recovery operation applied after secondary recovery. The ERDA research program on enhanced oil recovery does not include waterflooding.
Enhanced recovery is applied to an oil-containing subsurface reservoir for the purpose of dislodging oil from the reservoir rock pores and moving it to a production well. Many subsurface petroleum reservoirs contain sufficient energy because of internal pressures to push oil and gas to the surface when first penetrated by a drill bit. However, as the penetrated by a drill bit. However, as the internal pressures become low because of the removal or production of oil, gas, and water at the wellhead, the residual oil in the reservoir cannot be recovered without the application of external or artificial force.
Secondary recovery is any enhanced-recovery operation first applied to a reservoir. Often it follows primary recovery, but it can be conducted simultaneously with primary recovery. The most common secondary-recovery process is waterflooding.
Producing well water samples from the Prudhoe Bay Eastern Operating Area were evaluated with respect to the fraction of seawater in the sample. The evaluation demonstrated that the previous method of using magnesium or sulfate to determine percent seawater was in error. Because the water contains acetic acid, which was titrated as bicarbonate, scaling calculations overpredicted calcium carbonate scale formation.
The data show that there are at least two different waters in Prudhoe Bay. Additionally, potential reservoir mechanisms driving chemical reactions were identified as cation exchange (fines migration), scale precipitation (calcium carbonate, barium sulfate), formation dissolution and metabolic conversion of sulfate (leading to iron sulfide precipitation).
Water samples from producing wells have been collected at Prudhoe Bay for monitoring purposes since the mid-1980's. In September 1990 the produced water monitoring effort was increased, both in number of samples per year and in the ion constituents analyzed. The increased number allowed for better flood front tracking through seawater fraction determinations in the produced water. The increased ion constituents also allowed for a better understanding of the chemical reactions occurring in the reservoir. The focus was to understand the potential mechanisms that drive the chemical reactions in the reservoir. Knowledge of the reactions leads to a better understanding of the formation damage mechanisms and the produced water chemistry changes. Previous and field studies identified potential damage mechanisms as scales (calcite, siderite, barium/strontium sulfate) and migrating fines.
STATEMENT OF THE PROBLEM
The method used was based on principles of simple mixing of formation water @ and seawater (SW). It also assumes that there will be no dissolution or precipitation when the waters are mixed. Thus, if formation water and seawater are mixed, the calculated ion concentrations are linearly proportional to the percent seawater in the sample on the graphs. This line is designated "calculated mixing based on FW and SW." If precipitation of an ion occurs, then the averaged sample data will fall below the calculated concentration. Barium sulfate is a good example of an ion falling below the mixing line (Figure 1). If dissolution of the formation occurs, then the sample data will be above the calculated concentration.
In order to find the character of any ion sample curve, the data was descretized by averaging the percent seawater in segments: 0.0 to 0.1, 0.1 to 5.0, 5 to 10, 10 to 15, 15 to 20, 20 to 30, etc. The average percent seawater values are then reported as the average of the aforementioned bounds: 0, 2.5, 7.5, 10, 15, 25, 35, 45, 55, 65, 75 and 85 percent, respectively. Few data points existed above 90 percent seawater. Therefore a ninety-five percent seawater average is not reported.
The standard deviation is calculated for each averaged value. The standard deviation of the averaged data is displayed on each plot as dashed lines above and below the averaged line. A consistent standard deviation for the range of averaged values attests to the consistency of the data. Figure 2 is an example of where the points fall in relation to the average value and standard deviation for sulfate ion concentration with respect to seawater fraction.
Determination of the percent seawater was performed using an ion that exhibited no dissolution or precipitation characteristics. To do this, the ion would exhibit linear behavior with respect to percent seawater. The line would have a low standard deviation and would match the calculated straight line determined by the endpoint values. Boron exhibited this quality. Boron, according to Collins, is "useful in identifying the sources of brines intrusive to oil wells, or in fresh water lakes or streams. Consequently, boron was used as the main formation water tracer. Iodide and chloride salts are also very soluble and were used as secondary tracers. Using boron, iodide and chloride led to separating the data into two groups with different formation water compositions: down-structure and up-structure formation water.
The geochemistry of the produced water from the steamflood at the MOCO Monarch anticlinal steamdrive pilot in the South Midway Sunset Field, Kern County, California was evaluated to yield information about reservoir flow patterns, reservoir temperatures and correlation with oil production. Dissolved chloride, bromide, boron and silica concentrations in production waters can be used as natural in situ tracers. Chloride and bromide are inert and their concentrations reflect the mixing of injected and formation waters in the reservoir. Silica and boron are reactive tracers; the concentration of silica reflects the reservoir temperature and boron the extent of reaction with the Monterey diatomite which is thought to form a barrier to steam between the B and C zones.
Analysis of the concentrations of chloride and silica produced from wells perfed in each zone as a function of time and well location was made. The effects of the anticline and structural features controlling communication paths can be clearly seen in the chemical data with some of the variations clearly the result of small scale heterogeneities. Communication paths are well developed in a northeast south-west direction in both zones. Communication has been developed in the south end of the pilot. Silica concentrations indicate that the C zone is hotter than the B zone. Generally the maximum oil production correlates with the wells with high produced chloride concentration and low produced silica concentration (good communication, but locally low temperature). These wells produce significant amounts of oil for some time after both the chloride and silica values have increased. After the producing zone has been swept, oil production drops, and both the chloride and silica concentrations are high. The final decrease of chloride while maintaining high silica values indicates the steam front is near the producer and if it has not already, that oil production will decrease rapidly.
A six month fluid monitoring project was started in March, 1989 at the MOCO Monarch Anticlinal Area Pilot in the South Midway Sunset Field, Kern County, California. The pilot is located in two 200 foot thick reservoirs, the B and C horizons of the Monarch sand. The reservoirs are separated by an impermeable Monterey diatomite barrier. The north portion of the Monarch pilot is situated at the hinge of an anticline plunging 7 degrees SE and the flanks are dipping 20 degrees to the SW. Only the southwest limb of the anticline which is underlain by a waterleg is situated in the pilot; the northeast flank starts to dip north of the pilot.
The composition of subsurface water commonly changes vertically and laterally in the same aquifer. Changes may be brought about by the intrusion of other waters and by discharge from and recharge to the aquifer. As a reservoir is produced, the compositions typically change with time; therefore, it is difficult, but important, to obtain a representative sample of a given subsurface body of water. Any one sample is a very small part of the total mass, which may vary widely in composition; therefore, it is generally necessary to obtain and analyze many samples. Also, the samples themselves may change with time as gases evolve from solution or may precipitate solids when coming to ambient conditions.