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Petroleum Engineering Handbook

Larry W. Lake, Editor-in-Chief

Volume I – General Engineering

John R. Fanchi, Editor

Chapter 10 – Properties of Produced Water

David J. Blumer, ConocoPhillips

Pgs. 465-497

ISBN 978-1-55563-108-6
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History of Produced Water in Oil and Gas Fields

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.[1]

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.[2] 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.[3]

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.[4] Torrey[5] 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,[6] 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.

Two samples from this section were preserved in sealed containers for saturation tests, and both of them, when analyzed, had a water content of approximately 20% pore volume. This well made approximately 10 BOPD and no water after being stimulated with nitroglycerine. Thus, the evidence developed by the core analysis and the productivity test after completion provided a satisfactory indication of the existence of immobile water, indigenous to the Bradford-sand oil reservoir, which was held in its pore system and could not be produced by conventional pumping methods.[5]

Fettke[7] was the first to report the presence of water in oil-producing sand; however, he thought that the drilling process might have introduced it. Munn[8] recognized that moving underground water might be the primary cause of migration and accumulation of oil and gas. However, this theory had little experimental data to back it until Mills[9] conducted several laboratory experiments on the effect of moving water and gas on water/oil/sand and water/oil/gas/sand systems. Mills concluded that "the updip migration of oil and gas under the propulsive force of their buoyancy in water, as well as the migration of oil, either up or down dip, caused by hydraulic currents, are among the primary factors influencing both the accumulation and the recovery of oil and gas." This theory was seriously questioned and completely rejected by many of his contemporaries.

Rich[10] assumed that "hydraulic currents, rather than buoyancy, are effective in causing accumulation of oil or its retention." He did not believe that the hydraulic accumulation and flushing of oil required rapid movement of water, but rather that oil was an integral constituent of the rock fluids, and that it could be carried along with them whether the movement was very slow or relatively rapid.

The effect of water displacing oil during production was not recognized in the early days of the petroleum industry in Pennsylvania. Laws were passed, however, to prevent operators from injecting water into the oil reservoir sands through unplugged wells. In spite of these laws, some operators at Bradford secretly opened the well casing opposite shallow groundwater sands to start a waterflood in the oil sands. Effects of artificial waterfloods were noted in the Bradford field in 1907 and became evident approximately 5 years later in the nearby oil fields of New York.[11] Volumetric calculations of the oil-reservoir volume that were made for engineering studies of the waterflood operations proved that interstitial water was generally present in the oil sands. Garrison[12] and Schilthuis[4] reported on the distribution of oil and water in the pores of porous rocks. They described the relationship between water saturation and formation permeability, while discussing the origin and occurrence of "connate" water in porous rocks.

Lane and Gordon[13] first used the word "connate" to mean interstitial water deposited with the sediments. The processes of rock compaction and mineral diagenesis result in the expulsion of large amounts of water from sediments and movement out of the deposit through the more permeable rocks; therefore, it is highly unlikely that the water now in any pore is the same as when the particles that surround it were deposited. White[14] redefined connate water as "fossil" water because it has been out of contact with the atmosphere for an appreciable part of geologic time period. Thus, connate water is distinguished from "meteoric" water, which entered the rocks in geologically recent times, and from "juvenile" water, which came from deep in the earth’s crust and has never been in contact with the atmosphere.

Meanwhile, petroleum engineers and geologists had learned that waters associated with petroleum could be identified, with regard to the reservoir in which they occurred, by knowledge of their chemical characteristics.[15] Commonly, the waters from different strata differ considerably in their major dissolved chemical constituents, making the identification of water sourced from a particular stratum possible.[16] However, in some areas, the concentrations of dissolved constituents in waters from different strata do not differ significantly, and the identification of such waters is difficult or impossible. Sec. 10.4 describes new techniques to assist in this process, because several new analytical and statistical techniques for trace species apply nicely to this problem.

The enormous quantities of water produced from many fields originally surprised operators and, even today, water-handling costs continue to be significant to company management trying to reduce costs. The amount of water produced with the oil usually increases as the amount of oil produced decreases, even during primary production. At the end of the life of some reservoirs, 100 times (or more) as much water is processed as oil sold.

The history of oil production is replete with operators who decided that the water-handling costs were too high for an older field to be profitable, so they sold the property to another operator. The new operator finds ways of reducing the impacts of that water to produce the smaller oil stream profitably, until they become discouraged and sell to yet another operator, and so on. Very few mature reservoirs, especially those that have undergone secondary and tertiary recovery, have been completely abandoned because new technology and better engineering have made it economical to produce oil at extremely high water cuts or to reduce the water cut by controlling water production in the reservoir and wells. It is the challenge of producers to recover the most oil from the reservoir profitably, which means discovering methods to minimize the impacts of produced water for that particular field.

Produced Water Is Important

As mentioned previously, extraction of oil and gas from underground reservoirs often is accompanied by water or brine, which is referred to as produced water. As reservoirs mature, especially if secondary or tertiary recovery methods are used, the quantity of water climbs and often exceeds the volume of the hydrocarbons before the reservoir is exhausted. The cost of producing, handling, and disposing of the produced water often defines the economic lifetime of a field and the actual hydrocarbon reserves; therefore, understanding and predicting the aspects, behavior, and problems induced by the produced-water flow is important.

Because the produced water is not usually a revenue stream, the emphasis on water-flow prediction, technology development, and engineering application has not traditionally been a major focus of oil- and gas-production engineering. This is complicated by the multidisciplinary nature of produced-water issues, including chemistry; hydrodynamics; surface/interfacial science; materials science; corrosion; mechanical, chemical, and petroleum engineering; as well as environmental regulators. Compared with the advanced knowledge of water and brines, produced water is relatively poorly understood because of its unique aspects.

Produced water is chemically very complex. The process of producing and processing produced water causes changes in temperature and pressure. The addition of treating chemicals, along with the presence of coproduced gas, oil, and likely solids, changes the produced-water properties and behavior. Understanding how production perturbs the chemical state of the produced water is the key to predicting and controlling many problems. Also, the chemical composition is an excellent source of information about the particular reservoir and the reservoir depletion process.

Diagnosing the source of the increased water production from a well is important in deciding whether to pursue water-shutoff options. First, if the field is waterflooded, water must be produced to recover the oil in accordance with relative permeability; only water in excess of this should be a target for remedial treatments. If this is edge water, water shutoff can be difficult, even with polymer-gel technology. Polymer-gel water-shutoff treatments have proved successful in cases in which faults intersect the wellbore, causing a channel for water flow. If excess water production is bottomwater, the well can be plugged back. However, excess water production is often the result of intrusive water from a shallow sand or another aquifer gaining access to the well from a leaky casing or faulty completion. This source of intrusive water can be repaired, depending on the economics.[17]

Waters produced with petroleum are growing in importance from an environmental standpoint. In the past, these waters were considered waste and required disposal. Early on, less attention was paid to the fate of the produced water in the environment, because, after all, it was only water. It later became clear that possible contamination from produced-water disposal practices, especially on the surface, needs to be considered. The bulk of produced water from land-based operations is reinjected. Injection of these waters back into the petroleum reservoir serves three purposes: it produces additional petroleum through secondary recovery (waterflooding), it uses a potential pollutant, and, in some areas, it controls land subsidence.

Secondary and tertiary oil-recovery processes that use water injection result in the production of even more water with the oil. To inject these waters into reservoir rocks, suspended solids and oil must be removed to an appropriate degree to prevent plugging. Most offshore platforms dispose of their produced water directly into the ocean, but have to meet increasingly stringent regulations on the entrained and dissolved oil and other chemicals that are in the produced water. Some offshore operators are considering produced-water reinjection to avoid meeting these expensive ocean-disposal requirements.

Where Does the Water Come From?

As discussed previously, in the original reservoir, the pores in the mineral matrix contain the natural fluids at chemical equilibrium. Because reservoir rock is largely of sedimentary origin, water was present at the time of rock genesis and, therefore, is trapped in the pores of the rock. Water may also move or migrate according to the hydraulic pressures induced by geological processes that also form the reservoirs.

In hydrocarbon reservoirs, some of the water is displaced by the hydrocarbon, but some water always remains. If the rock originated in a sea or ocean, then it will be saline. Rocks deposited in lakes, rivers, or estuaries have fresher water. Originally, the water was in chemical equilibrium with the mineral suite of the rock, but, on invasion of the oil and gas, a new equilibrium with those phases was achieved. Thus, there are both equilibria and chemical-reaction dynamics associated with the inorganic (mineral) phases and the oil and gas phases that are important to understand. Water is an excellent solvent; it will react to dissolve many of the phases it contacts.


Primary Production

When oil or gas is flowed or lifted from a reservoir, some water inevitably accompanies the other phases. This is a consequence of the relative permeability behavior of the rock, as discussed in the chapter on relative permeability in this section of the Handbook. In particular, if the water saturation is above the irreducible water saturation (Swr), then some water will move along with the oil and gas phases present as the fluids flow from the pores of the reservoir rock. This water is in chemical equilibrium with the rock and gas phases under the original temperature and pressure present in the reservoir. Because the pressure and temperature change as a consequence of producing the oil and gas, the chemical equilibrium of the water is perturbed. The perturbation can have severe detrimental effects. The operator must be interested in these effects to mitigate their economic and environmental impacts.

The chemical changes occurring during primary production are largely a result of cooling the water and reducing the pressure as it comes up the tubing into the surface production facilities. However, more-complex behavior can result if multiple zones or reservoirs are coproduced either within the same wellbore downhole or mixed on the surface. The mixing can lead to scale deposition, corrosion, and other effects. Artificial lift can also alter the stability of the water. In particular, gas lift and jet pumps are particular artificial-lift examples in which the chemical composition of the system may change because of the addition of foreign gas or water streams in the wellbore. Another impact of artificial lift is on the pressure profile of the system. Electrical submersible pumps can locally heat the water enough to enter a scaling regime (particularly for calcium carbonate) in the area of the motor, deposit scale on it, and cause the motor to burn out.

During primary production, the water cut may increase as the reservoir is depleted. This is particularly important in reservoirs that have natural waterdrives so that a water aquifer is in both pressure and hydraulic communication with the hydrocarbon reservoir. Thus, as the hydrocarbon is produced, the water from the aquifer is drawn in to fill the void left behind, and the water saturation of the rock is increased. The pressure in the reservoir attempts to stay constant. Depending on the efficiency of the hydraulic connection to the aquifer, the pressure decline over time will be reduced, perhaps to zero in some cases. However, the proportion of water produced will rise until the cost of handling the water exceeds the value of the hydrocarbons produced. Oil and gas reserves of the typical reservoir are limited by this water-handling cost. Clearly, produced-water issues are central, although this may not be immediately apparent because only the hydrocarbons produce revenue.

Economics of Produced Water

Except in the case of gas production from coal seams, water production rates usually start slowly from the initial development of a property. Facility designers may deliberately forestall construction and installation of water-handling equipment at the beginning of a project to reduce upfront capital costs. The eventual appearance of water production requires the addition of the capital investment and operational expense to handle the growing water rates, which do not generate revenue to offset the cost. The natural tendency for companies is to minimize the immediate expense; as a result, companies often underdesign the equipment or fail to budget properly for operational expenses.

Fig. 10.1 demonstrates the impact of rising water cut on the total cost of producing a barrel of oil assuming a constant water-treatment cost of U.S. $0.10 per barrel of water. Actual water costs can be lower or higher. This sobering fact vividly illustrates the importance of improving the technology of water treatment to lower the unit cost over time as reservoirs mature. Most secondary and tertiary oil reserves are produced at high water cuts.

Typically, the connate water (as the original water in the reservoir is called) is more saline than surface water. Many oil and gas reservoirs are in rocks originally lying at the bottom of oceans and were saturated with the seawater present at the time. Of course, the composition of these ancient seawaters may be significantly different than current seawater. Additionally, as the sediments were buried and the temperature and pressure increased, the chemical composition of the water and rock changed to maintain chemical equilibrium. These reactions took place over geologic time, so the aqueous phases of most oil reservoirs are in true chemical equilibrium with the mineral suite with which it is in contact. The converse is not necessarily true; many examples of meta-stable mineral suites are known in hydrocarbon reservoirs, probably because of mass-transfer limitations. Thus, one use of an examination of the water composition by geochemists is to provide insight into the burial history of the sediments in the reservoir. In particular, the isotope ratios of the elements are indicative of the origins of the waters and, in some cases, of the mechanisms by which the hydrocarbons were produced during geologic time.

Besides the commonly thought of species or components in the water such as salts and dissolved minerals, oilfield waters also contain organic species. Much less attention has been allocated to the organic chemical species in the produced water, yet they also have consequences. In particular, new environmental concerns about water and air pollution have required more focus on the dissolved organic species in the water. Some examples of these species include the volatile organic acids like formic, acetic, propionic, and butyric acids; naphthenic acids; and dissolved aromatic compounds like benzene, toluene, and xylenes. The latter species are particularly important for offshore overboard water-disposal operations, because they are often included in the measurements of the oil-in-water carryover, which are limited by law in many areas. The carryover of oil and other hydrocarbons in the produced water is one of the most important issues facing the surface engineer.

How Do We Characterize Produced Water?

Because produced waters are chemically complex systems, compositional computer models are needed to predict their behavior accurately. This technology has advanced steadily since the mid-1970s. One of the first thermodynamics-based water-chemistry computer models was WATEQ, developed by Truesdale and Jones at USGS, along with its database of 522 dissolved species and 192 mineral phases. This computer code was converted to FORTRAN IV in 1974 and became known as WATEQF. It has become the standard against which all future chemistry models are measured. Several major efforts to improve and extend the range of applications of these chemistry models have resulted in sophisticated programs to model water flow and geochemical reactions in reservoirs, production of water to surface, and water-chemistry changes during processing in surface facilities. These changes can have extremely serious impacts through precipitation of scales and corrosion; therefore, the accuracy of these predictions affects the profitability and, sometimes, the viability of many oil and gas projects.

Along with the computer models is the improvement in analytical chemistry technology needed to characterize the individual water in a particular system and provide the fundamental chemical equilibrium and kinetics data that form the basis for the computer models. The analytical instruments now used include inductively coupled plasma spectroscopy (ICP), ion chromatography (IC), capillary electrophoresis (CE), ion selective electrodes, and automatic titrators. In certain special analyses, more advanced techniques are used such as mass spectroscopy, high performance liquid chromatography (HPLC), and various "hyphenated techniques" such as inductively coupled plasma-mass spectroscopy (ICP-MS), gas chromatography-mass spectroscopy, and HPLC-mass spectroscopy. In circumstances in which speciation of the inorganic constituents is particularly of interest, ion chromatography can be used along with ICP or ICP-MS detection. Laser light-scattering instruments are usually used for looking at suspended particles and entrained oil droplets and their size distribution.

One of the most significant produced-water developments during the last two decades has been in the environmental impact and regulatory area. It is no longer a technical issue regarding the composition and fate of the produced water from oil and gas extraction (and transportation and refining, also). In many cases, government regulations limit or change the options available and may define the degree of characterization through sampling and analysis imposed on the operator. In the United States, produced water is still an exempt effluent and need not meet the more stringent requirements of hazardous wastes; however, other regulations impose many other requirements that must be monitored, met, and documented continuously. These regulations, the priority of concerns, and their degree of enforcement differ worldwide. When operating in nondomestic areas, familiarization with these regulations is mandatory, preferably during the conceptual facility- and field-design stages of a new development. These regulations have changed worldwide toward more stringent requirements. When choosing a particular method to handle produced water, that method’s viability for the long term must be considered.

Scale Deposition and Corrosion

The two main detrimental effects encountered during handling produced water are deposition of insoluble scales and corrosion of metal surfaces, which leads to leaks and costly repairs.[18][19] In accordance with the importance of the topics of scale and corrosion, there is an enormous and quickly growing literature, which cannot be reviewed easily here. Scale deposition is predicted through the use of the computer chemistry models mentioned previously. The most common scales are calcium carbonate, calcium sulfate, barium sulfate, iron sulfide, and iron carbonate.

Inhibition of most of these scales is now successful through proper application of particular organic compounds, most of which act to poison the growth sites of the crystals while they are still submicron in size. Two common classes of these inhibitors are the organophosphonates, such as diethylenetriaminepentamethylene phosphonic acid, and low-molecular-weight polyacrylic acid polymers (commonly <1,000 molecular weight). Unfortunately, the computer programs are less useful in predicting precisely which scale inhibitor to select for a particular produced water; therefore, laboratory experiments are needed. These experiments are often done with synthetic waters made to reflect the composition of the actual produced water; however, because minor and trace species are sometimes ignored in formulating these synthetic test waters, the results of the laboratory tests can be incorrect in picking the most effective inhibitor,[20] which can result in ineffective inhibition or much higher treating costs.

Corrosion predictions for produced waters are much less certain than scale-precipitation predictions. The corrosion reactions are much more complex and involve many factors other than the thermodynamics of the obvious chemical reactions of oxidizing and dissolving the metal, such as mass transport, concentration cells, effect of fluid flow and velocity, scale deposition, and microbes. In cases in which H2S levels become high, improperly specified metallurgy or welding procedures can lead to catastrophic and rapid failure from sulfide stress cracking. Loss of life has resulted from this corrosion. Every effort must be taken to measure and predict the water and gas compositions properly, so that the metallurgy will accommodate those levels. If levels approaching 0.05 psia H2S are encountered, National Assn. of Corrosion Engineers (NACE) specifications should be followed carefully.

While there are several computer programs that attempt to predict corrosivity of a produced-water system, these are currently just reasonably good guides. Because of the complexity of real systems, an approach that begins with the water and gas composition inputs to these computer models and then is followed by laboratory testing, field testing, and, finally, an ongoing field-monitoring program is likely to result in successful corrosion control in that particular system. The level of effort applied should be proportional to the aggressiveness of the corrosion, the consequences of failure, and the length of time the system must operate.

Corrosion mitigation typically takes two forms: investment in corrosion-resistant alloys or a chemical corrosion-inhibition/monitoring program. Choosing the best option on a new project should involve a complete life-cycle cost analysis. Existing operations often have already determined that choice, so it is up to the engineers, production chemists, and operators to create the most cost-effective solutions to the corrosion challenges presented by that particular produced water. Like scale inhibitors, corrosion inhibitors must be chosen for each particular area by thorough laboratory and field testing to find the inhibitor with the best combination of cost and performance. Dosage adjustments based on field corrosion-monitoring results can ensure long facility life and few, if any, leaks. An inhibitor mitigation process that incorporates a feedback loop will optimize the dosages of the inhibitor until corrosion-damage/repair cost is minimized, while the amount of inhibitor pumped is no greater than necessary. A similar process can be applied to scale inhibitors and other treating chemicals with modifications with appropriate monitoring techniques.

Sampling and Analyses of Produced Waters

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. The sampling sites should be selected to fit into a comprehensive network to cover an oil-productive basin, in which case the information is of value in both exploration and production.

Water compositions from particular wells change over time, so a periodic sampling program is needed. The sampling frequency needed is not universal. The best guideline is the particular field itself: the faster the composition changes, the more often the water needs sampling. Fields undergoing waterflood or tertiary recovery naturally show water-chemistry changes as the injected water mixes with the formation water. Reservoirs under primary production can show dilution from water moving from adjacent compacting clay beds into the petroleum reservoir as the pressure declines because of the removal of oil, gas, and brine. This can be a detector for possible subsidence of the reservoir and perhaps the surface. The composition of oilfield water can vary with the position within the geologic structure from which it is obtained. In some cases, the salinity will increase upstructure to a maximum at the point of oil/water contact.

Drillstem or Downhole Watering Sampling

Sample Methods

Various techniques and devices are now available for the evaluation of newly drilled wells, but there remain some important factors that must be considered when obtaining these samples and evaluating the results. The primary problem stems from the contamination of the reservoir with the drilling, completion, and stimulation fluids used during the well-construction operation. The contamination is usually easily detected from the analytical results. If one realizes that high concentrations of particular species that were used in those wellbore fluids appear in the water-analysis results, then the sample was likely contaminated and the usefulness of the sample reduced accordingly. Naturally, one must always include these species in the analysis. Unfortunately, if a sample is contaminated there is seldom an opportunity to re-enter the hole and obtain a new sample, except at great cost.

One approach for a standard drillstem test (DST) is to sample the water after each stand of pipe is removed. Normally, the total-dissolved-solids (TDS) content will increase downward, becoming constant when pure formation water is obtained. A test that flows water improves the chances of an uncontaminated sample; otherwise, the best chance is to sample just above the DST tool, because this was the last water to enter the tool. Newer downhole samplers sometimes allow multiple samples to be obtained; therefore, if one first pulls a large volume of water into the tool and then a second (or third) sample from the same interval, there is a chance of getting uncontaminated water in that sample.

For example, analyses of water obtained from a DST of Smackover limestone water in Rains County, Texas, demonstrates the errors caused by improper sampling of DST water. Analyses of top, middle, and bottom samples taken from a 50-ft zone of fluid recovery show an increase in salinity with depth in the drillpipe, indicating that the first water was contaminated by mud filtrate.[20] Thus, the bottom sample was the most representative of Smackover water.

Sample Containing Dissolved Gas. Knowledge of certain dissolved hydrocarbon gases is used in exploration.[21][22] Mapping anomalies of hydrocarbons in both surface water and subsurface aquifer water samples is an extraordinarily powerful geochemical tool.

Sampling at the Flowline. Another method of obtaining a sample for analysis of dissolved gases is to place a sampling device in a flowline, as Fig. 10.2 illustrates. The device is connected to the flowline, and water is allowed to flow into and through the container, which is held above the flowline, until 10 or more volumes of water have flowed through the container. The lower valve on the sample container is closed, and the container removed. If any bubbles are present in the sample, the sample is discarded, and a new one is obtained.

Sampling at the Wellhead. It is common practice to obtain a sample of formation water from a sampling valve at the wellhead. A plastic or rubber tube can be used to transfer the sample from the sample valve into the container (usually plastic). The source and sample container should be flushed to remove any foreign material before a sample is taken. After flushing the system, the end of the tube is inserted into the bottom of the container, and several volumes of fluid are displaced before the tube is removed slowly from the container and the container is sealed. Fig. 10.3 illustrates a method of obtaining a sample at the wellhead. An extension of this method is to place the sample container in a larger container, insert the tube to the bottom of the sample container, allow the brine to overflow both containers, and withdraw the tube and cap the sample under the fluid.

At pumping wellheads, the brine will surge out in heads and be mixed with oil. In such situations, a larger container equipped with a valve at the bottom can be used as a surge tank, an oil/water separator, or both. To use this device, place the sample tube in the bottom of the large container, open the wellhead valve, rinse the large container with the well fluid, allow the large container to fill, and withdraw a sample through the valve at the bottom of the large container. This method obtains samples that are relatively oil free.

Field-Filtered Sample. For some studies, it is necessary to obtain a field-filtered sample. Fig. 10.4 shows a filtering system that has proved to be successful for various applications. This filtering system is simple and economical. It consists of a 50-mL disposable syringe, two check valves, and an inline-disk filter holder. The filter holder takes size 47-mm-diameter, 0.45-μm pore-sized filters, with the option of a prefilter and depth prefilter. After the oilfield brine is separated from the oil, the brine is drawn from the separator into the syringe. With the syringe, it is forced through the filter into the collection bottle. The check valves allow the syringe to be used as a pump for filling the collection bottle. If the filter becomes clogged, it can be replaced in a few minutes. Approximately 2 minutes are required to collect 250 mL of sample. Usually three samples are taken, with one being acidified to pH 3 or less with concentrated HCl or HNO3, and another stabilized with biocide. The system can be cleaned easily or flushed with brine to prevent contamination.

Sample for Stable-Isotope Analysis. Stable isotopes have been used in several research studies to determine the origin of oilfield brines.[23][24][25] The most common isotopes studied are deuterium/hydrogen, 2H/1H; oxygen, 18O/16O; and stable carbon isotopes, 13C/12C. Also, isotopically labeled compounds are sometimes used to trace injection waters or stimulation fluids. The isotopic analyses of the water, gas, and oil phases can be useful to geochemists in determining the sequence of fluid migrations in reservoirs during their genesis.

Sample for Determining Unstable Properties or Species. A mobile analyzer was designed to measure pH, Eh (redox potential), O2, resistivity, S=, HCO3-, CO3=, and CO2 in oilfield water at the wellhead. Portable field kits for chemical analysis are available for these analyses, which provide reasonably accurate on-site results. When oilfield brine samples are collected in the field and transported to the laboratory for analysis, many of the unstable constituents change in concentration. The amount of change depends on the sampling method, sample storage, ambient conditions, and the amounts of the constituents in the original sample. Therefore, an analysis of the brine at the wellhead is necessary to obtain reliable data.[26]

Sample Containers. The types of containers that are used include polyethylene, other plastics, hard rubber, metal cans, and borosilicate glass. Glass will adsorb various ions, such as iron and manganese, and may contribute boron or silica to the aqueous sample. Plastic and hard-rubber containers are not suitable if the sample is to be analyzed to determine its organic content, unless tested and shown otherwise. A metal container is used by some laboratories if the sample is to be analyzed for dissolved hydrocarbons such as benzene. Produced water often will corrode metal containers, unless they are lined. The corrosion will alter the chemical composition of the water by adding metal ions such as iron and manganese and by lowering the pH. The type of container selected depends on the planned use of the analytical data.

Water Sampling and Analysis Specification

This section defines a "standard water analysis" that specifies the complete suite of species and provides suggestions on sampling and analytical techniques. The analysis specifications have been used by the author for two decades and have been used by others, with adaptations for particular needs. The results of this extensive list of analyses are the required input for the various computer multicomponent simultaneous-equilibrium chemistry models that can predict correctly the changes in the water chemistry, scale precipitation, rock/water interactions, water sources and mixing, and corrosion.

While there is always temptation and pressure to limit the range of analyses performed on a sample, analytical technology has reduced dramatically the value of limiting the range of an analysis. Most instruments automatically measure many different species in a single run; therefore, it may cost the same to get one species as it does to get many, depending on the analytical technique. For instance, the commonly used ICP instruments typically measure 10 to 60 elements at a time (depending on the particular instrument) in a few minutes; therefore, adding or subtracting a species on the ICP changes the actual cost very little.

The analytical results should be stored in an electronic database for further analysis and comparison of samples from the same points over time. Certain evaluations can be performed on individual samples, such as scale-deposition predictions or monitoring for corrosion with dissolved manganese and iron. Other evaluations require successive samples, with consistent sample-collection and -analysis procedures, for the data to be meaningful. These results can be mapped to follow the reservoir-area changes over time. They also can provide insight as to potential improvements in reservoir management of a waterflood, because the various ions provide natural tracer data for the injected water. The data are also useful for deciphering casing leaks, conductive (but unmapped) faults, and, in favorable cases, zonal splits of water production. If the data were not collected on each sample consistently or if the analysis suite was minimized to save money in the laboratory, these valuable evaluations are not possible.

Fig. 10.5 illustrates the information that should be obtained for each sample of oilfield water. As much information as possible should be recorded when taking the sample. The following measurements must be taken in the field at the sampling point coincident with taking the sample because these values change quickly once the sample is removed: temperature, pH, Eh (optional), dissolved O2 (Chemet or meter), H2S, CO2, pressure, and bicarbonate (HCO3-) alkalinity titration (recommended).

Example 10.1 Problem. Conduct laboratory analyses to generate the data needed to enter into the computer programs that will predict the stability of water, with respect to precipitation of scales as a function of temperature and pressure.

Solution. Obtain three bottles for each sample: one for cations/metals (Table 10.1), one for anions/etc. (Table 10.2), and one for organic acids (Table 10.3). The bottles should be polyethylene, Teflon, or polycarbonate. Not all polyethylenes are satisfactory because some contain relatively high amounts of metal contributed by catalysts in their manufacture. Fill a bottle with acid solution, let stand for a week, and then analyze the acid for metals to test the bottle’s suitability. Glass should be avoided if the sample can freeze, because it is likely to break. Glass often is reactive with highly saline brines and strongly adsorbs some oils and other organics, including treating chemicals.

Filter a measured portion of the sample taken for the anion analysis through a 0.45-μm filter to measure the total suspended solids. If a large amount of solids is collected, the filter paper should be saved for later X-ray powder diffraction, scanning electron microscopy/energy dispersive X-ray spectroscopy analysis (to identity the solids), and a laser particle-size analysis.

Tables 10.1 and 10.3 specify that the bottles for the cation and organic-acids analyses have additives: 10 mL of ultrapure nitric acid (HNO3) for the ICP analysis and 1 mL of glutaraldehyde for the organic acids. This stabilizes the samples so that precipitation of the metals does not ruin the results for the ICP analysis. In particular, the iron will precipitate as the sample sits and that precipitate removes many of the other species from solution. Also, the naturally present bacteria in the water will quickly eat the organic acids in the samples unless biocide is added to that sample. If no biocide, such as glutaraldehyde, has been added, no organic acids are detected; therefore, adding glutaraldehyde to a bottle used for the organic-acid analysis is highly recommended.

In addition to the water analysis, the gas in contact with the water is important. Taking a gas sample at the same time is recommended, although one taken at a different time can suffice for less critical applications. The main constituents of interest in the gas are the CO2 and H2S. The H2S analysis usually is done at the sampling point. CO2 and H2S are very important in predicting what will happen with the water.

In general, bacterial surveys are recommended, primarily with the serial dilution technique with one medium for sulfate-reducing bacteria (SRB) and another medium for general anaerobic bacteria. Many times, the exact medium composition (and sometimes the incubation temperature) has to be adjusted for a particular field to get that population to grow well. The bacteria have a lot of negative side effects, such as generating H2S, causing a safety and corrosion problem, and making the schmoo (organic/inorganic deposits) formation in the produced-water problem worse. Microbial-induced corrosion can be very severe, especially in deadlegs (stagnant areas in which water and solids are trapped), low-flow areas, and underdeposits.

Physical Properties of Oilfield Waters

This section discusses important physical properties of oilfield waters. As a rule, it is best to have reliable laboratory measurements of the physical properties of oilfield waters. If laboratory measurements are not available, correlations may have to be used. For example, McCain has published some of the most widely used correlations for the physical properties of oilfield waters.[21][22] In addition to defining physical properties of oilfield waters, we present correlations for calculating many of those properties.


The compressibility of formation water at pressures above the bubblepoint is defined as the change in water volume per unit water volume per psi change in pressure. This is expressed mathematically as







cw = water compressibility at the given pressure and temperature, bbl/bbl-psi,
RTENOTITLE = average water compressibility within the given pressure and temperature interval, bbl/bbl-psi,
V = water volume at the given pressure and temperature, bbl,
RTENOTITLE = average water volume within p and T intervals, bbl,
p1 and p2 = pressure at conditions 1 and 2 with p1 > p2, psi,
Bw1 and Bw2 = water formation volume factor (FVF) p1 and p2, bbl/bbl ,
RTENOTITLE = average water FVF corresponding to V, bbl/bbl.

Water compressibility also depends on the salinity. In contrast to the literature, laboratory measurements by Osif[23] show that the effect of gas in solution on compressibility of water with NaCl concentrations up to 200 g/cm3 is essentially negligible. Osif’s results show no effect at gas/water ratios (GWRs) of 13 scf/bbl. At GWRs of 35 scf/bbl, there is probably no effect, but certainly no more than a 5% increase in the compressibility of brine.

Laboratory measurements[20] of water compressibility resulted in linear plots of the reciprocal of compressibility vs. pressure. The plots of l/cw vs. P have a slope of m1 and intercepts linear in salinity and temperature. Data points for the systems tested containing no gas in solution resulted in Eq. 10.2.


where cw = water compressibility, psi−1; p = pressure, psi; C = salinity, g/L of solution; T = temperature, °F; m1 = 7.033; m2 = 541.5; m3 = −537; and m4 = 403.3 × 103. Eq. 10.2 was fit for pressures between 1,000 and 20,000 psi, salinities of 0 to 200 g/L NaCl, and temperatures from 200 to 270°F. Compressibilities were independent of dissolved gas.

When conditions overlap, the agreement with the results reported by both Dorsey[24] and Dotson and Standing[25] is very good. Results from the Rowe and Chou[26] equation agree well up to 5,000 psi (their upper pressure limit) but result in larger deviations with increasing pressure. In almost all cases, the Rowe and Chou compressibilities are less than that of Eq. 10.2.


The density of formation water is a function of pressure, temperature, and dissolved constituents. It is determined most accurately in the laboratory on a representative sample of formation water.[27] The formation-water density is defined as the mass of the formation water per unit volume of the formation water. Electronic densiometers can quickly determine the density with accuracy of +/−0.00001 g/cm3 over a wide range of temperatures, although most oilfield data are reported at a 60°F reference temperature.

In the past, density in metric units (g/cm3) was considered equal to specific gravity; therefore, for most engineering calculations, density and specific gravity were interchangeable in most of the older designs.[16] However, process simulation software used in modern facility design uses the true density or specific gravity of the water to avoid significant cumulative errors, especially when working with low-gravity heavy oils or concentrated brines. Thus, water samples taken for providing input to these programs must have accurate densities determined experimentally. Alternatively, some modern multicomponent chemical equilibrium simulators accurately calculate the densities (and other physical properties) from the complete analysis of the waters within the temperature and pressure range of the thermodynamic database. Experimental verification of the computer predictions should be performed in cases in which any error could have significant impact.

When laboratory data or actual water samples are unavailable, the density of formation water at reservoir conditions can be estimated roughly (usually to within +/−10%) from correlations (Figs. 10.6 through 10.8). The only field datum necessary is the density at standard conditions, which can be obtained from the salt content by use of Fig. 10.6. The salt content can be estimated from the formation resistivity, as measured from electric-log measurements. The density of formation water at reservoir conditions can be calculated in four steps.

  • With the temperature and density at atmospheric pressure, obtain the equivalent weight percent NaCl from Fig. 10.7.
  • Assuming the equivalent weight percent NaCl remains constant, extrapolate the weight percent to reservoir temperature and read the new density.
  • Knowing the density at atmospheric pressure and reservoir temperature, use Fig. 10.8 to find the increase in specific gravity (density) when compressed to reservoir pressure. For oil reservoirs below the bubblepoint, the "saturated-with-gas" curves should be used; for water considered to have no solution gas, the "no-gas-in-solution" curves should be used. These curves were computed from data given by Ashby and Hawkins.[28]
  • The density of formation water (g/cm3) at reservoir conditions is the sum of the values read from Figs. 10.7 and 10.8. They can be added directly because the metric units are referred to the common density base of water (1 g/cm3). The metric units can be changed to customary units (lbm/ft3) by multiplying by 62.37.

Another approach to calculating water density is to first calculate the density of formation water at standard conditions with McCain’s correlation.[21][22]


where density is in lbm/ft3, and S is salinity in weight percent. Then, density at reservoir conditions is calculated by dividing the density in Eq. 10.3 by the brine FVF at the reservoir temperature and pressure of interest.

The specific gravity of formation water can be estimated, if the TDS is known, with


where Csd = concentration of dissolved solids (also known as TDS), mg/L.

Rogers and Pitzer[29] provide precise but very detailed calculations. They tabulated a large number of values of compressibility, expansivity, and specific volume vs. molality, temperature, and pressure. A semiempirical equation of the same type was found to be effective in describing thermal properties of NaCl (0.1 to 5 molality) and was used to reproduce the volumetric data from 0 to 300°C and 1 to 1,000 bars.

Formation Volume Factor

The water FVF, Bw, is defined as the volume at reservoir conditions occupied by 1 STB of formation water plus its dissolved gas. It represents the change in volume of the formation water as it moves from reservoir conditions to surface conditions. Three effects are involved: the liberation of gas from water as pressure is reduced, the expansion of water as pressure is reduced, and the shrinkage of water as temperature is reduced.

Fig. 10.9 is a typical plot of water FVF as a function of pressure. As the pressure is decreased to the bubblepoint, pb, the FVF increases as the liquid expands. At pressures below the bubblepoint, gas is liberated, but, in most cases, the FVF still will increase because the shrinkage of the water resulting from gas liberation is insufficient to counterbalance the expansion of the liquid. This is the effect of the small solubility of natural gas in water.

The most accurate source of the FVF is laboratory data. It also can be calculated from density correlations if the effects of solution gas have been accounted for properly. Eq. 10.5 is used to estimate Bw if solution gas is included in the laboratory measurement or correlation of ρrc.


Vrc = volume occupied by a unit mass of water at reservoir conditions (weight of gas dissolved in water at reservoir or standard conditions is negligible), ft3,
Vsc = volume occupied by a unit mass of water at standard conditions, ft3,
ρsc = density of water at standard conditions, lbm/ ft3,
ρrc = density of water at reservoir conditions, lbm/ ft3.

The density correlations and the methods of estimating ρsc and ρrc were described previously. The FVF of water can be less than one if the increase in volume resulting from dissolved gas is not great enough to overcome the decrease in volume caused by increased pressure. The value of FVF is seldom higher than 1.06.

An alternative expression for the FVF of brine may be calculated from McCain: [21][22]






where p = pressure in psia, and T = temperature in °F. McCain reported that this correlation agrees with a limited set of published experimental data to within 2%. The correlation is considered valid for temperatures to 260°F, and pressures to 5,000 psia. An increase in dissolved solids causes a slight increase in ΔVwT and a slight decrease in ΔVwp, which offset each other to within 1%.


The resistivity of formation water is a measure of the resistance offered by the water to electrical current. It can be measured directly or calculated.[16] The direct-measurement method is essentially the electrical resistance through a l-m2 cross-sectional area of 1 m3 of formation water. Formation-water resistivity, Rwg, is expressed in units of Ω-m. When resistivity of formation water is used in electric-log interpretation, the value is adjusted to formation temperature.

Surface (Interfacial) Tension

Surface tension is a measure of the attractive force acting at a boundary between two phases. If the phase boundary separates a liquid and a gas or a liquid and a solid, the attractive force at the boundary usually is called surface tension; however, the attractive force at the interface between two liquids is called interfacial tension (IFT). The lower the IFT, the smaller the droplet of the internal phase. At very low values of IFT, oil and water become miscible and behave as a single phase. IFT is an important factor in enhanced recovery. Also, the IFT determines the ease of separation of oil from water, because it determines the size of the oil or water droplets, depending on which phase is internal.

Most chemicals added during the course of drilling or production have a major effect on the IFT of the produced water and the hydrocarbons. Indeed, certain corrosion inhibitors added to the three-phase production stream can lower the produced-water IFT enough (<1 to 5 dyne/cm) to cause the droplet size of the entrained oil to be small enough that no injection-well plugging is observed, even at high oil carryover (percent levels) in the reinjected produced water.[29] In attempting to separate the oil from the three-phase production stream, the addition of emulsion breakers changes the IFT and promotes the agglomeration of small droplets into larger ones that separate quickly. Formulating, selecting, testing, and troubleshooting emulsion breakers is the focus of an enormous amount of the effort devoted to the impacts of producing water with hydrocarbons.

Surface tension is measured in the laboratory by a tensiometer, by the drop method, or by a variety of other methods. Descriptions of these methods are found in most physical chemistry texts. The laboratory measurements traditionally have been difficult and done only by specialized facilities. Computerized commercial pendant-drop and falling-drop tensiometers are now available for use by chemists in more general field R&D laboratories. IFT is a critical property of produced water, but is rarely measured because of the analytical difficulties [30]. This new technology promises to improve the ability to troubleshoot problems by directly measuring IFT instead of trial-and-error testing.


The viscosity of formation water, μw, is a function of pressure, temperature, and dissolved solids. In general, brine viscosity increases with increasing pressure, increasing salinity, and decreasing temperature.[31] Dissolved gas in the formation water at reservoir conditions generally results in a negligible effect on water viscosity. There is little information on the actual numerical effect of dissolved gas on water viscosity.

Gas-in-the-water phase behaves entirely differently than gas in hydrocarbons*. In water, the presence of the gas actually causes the water molecules to interact with each other more strongly, thus increasing the rigidity and viscosity of the water. However, this effect is very small and has not been measured to date. In the physical chemistry literature, there is an enormous amount of indirect evidence to support this concept.

For the best estimation of the viscosity of water, refer to Kestin et al.[32] Their correlating equations involve 32 parameters for calculating the numerical effect of pressure, temperature, and concentration of aqueous NaCl solutions on the dynamic and kinematic viscosity of water. The 28 tables generated from the correlating equations cover a temperature range from 20 to 150°C, a pressure range from 0. 1 to 35 mPa, and a concentration range from 0 to 6 molal.

Figs. 10.10 through 10.12 may be used to approximate water viscosity. These figures are calculated from the following correlation presented by McCain[20][21] for water viscosity (in cp) at 1 atm:






McCain reported that this correlation is within 5% of graphical correlations for temperatures between 100 and 400°F, and salinities to 26 wt%.

Water viscosity at reservoir pressure can be obtained from


McCain reported that Eq. 10.12 fits the data to within 4% for pressures below 10,000 psia and temperatures in the range from 86 to 167°F. The fit is within 7% for pressures between 10,000 and 15,000 psia.

Figs. 10.10 through 10.12 show the effects of pressure, temperature, and NaCl content on the viscosity of water. They may be used when the primary contaminant is sodium chloride. Alternatively, the viscosities are calculated and reported by computer chemistry models at the particular temperature, pressure, and gas compositions present in the facilities.[33]

Some engineers assume that reservoir-brine viscosity is equal to that of distilled water at atmospheric pressure and reservoir temperature. In this case, it is assumed that the viscosity of brine is essentially independent of pressure (a valid premise for the pressure ranges usually encountered). In some high-temperature/high-pressure reservoirs recently developed, this assumption breaks down. In those cases, experimental measurements under the relevant temperature/pressure conditions are recommended over attempting to extrapolate the distilled-water viscosities or even the computer models.


Personal communication with J.C. Melrose, Mobil R&D Corp., Dallas (1985).

The pH

Water (H2O) reversibly dissociates into hydrogen ions and hydroxide ions, which is described by the equilibrium constant for this chemical reaction, Keq (H2O) or simply Kw. The acidity or hydrogen ion activity of aqueous solutions controls many of its properties and is commonly expressed as the pH.


is the water dissociation reaction.




where aH+ is known as the activity of hydrogen ion in solution. The hydrogen ion activity is related to the concentration of hydrogen ions [H+] by means of the activity coefficient, γH+, giving


Solutions are known as neutral when the pH = 7, because at that point hydrogen ions and hydroxide ions are present in equal amounts, aH+ = aOH− = 10−7 M. When hydrogen ions predominate, the pH falls below 7, and the solution is described as being acidic. In the opposite case in which hydroxide ions outnumber the hydrogen ions, the pH climbs above 7, and the solution is known as basic or alkaline. The pH is commonly accurately measured with an electrode and meter, while field determinations also may use pH paper strips or colorimetric methods.

When the water is very pure and contains little dissolved salts, the value of γH+ approaches 1.0. The activity and concentration of hydrogen ion are essentially the same, so that the pH definition simplifies to


However, in what must seem to be nature’s perversity, produced water from oil reservoirs usually contains large amounts of dissolved salts. The value of γH+ is < 1.0 as a result, so the more simple form of the pH definition is not correct. Careful, direct pH measurement is the best approach for accurate pH determination, although some of the most sophisticated computer models give reasonable predictions at moderate conditions of brine concentration, temperature, and pressure.

The pH of oilfield waters usually is controlled by the CO2/bicarbonate system. Because the solubility of CO2 is directly proportional to temperature and pressure, the pH measurement should be made in the field if a close-to-natural-conditions value is desired. The pH of the water is not very useful for water identification or correlation purposes, but it does indicate possible scale-forming or corrosion tendencies of a particular water. The pH also may indicate the presence of drilling-mud filtrate or well-treatment chemicals. Organic acids, such as acetic acid, also can control the pH. The following is a typical reaction.


The pH of concentrated brines usually is less than 7.0, and the pH will rise during laboratory storage, indicating that the pH of the water in the reservoir probably is appreciably lower than many published values. In pure water or brines with little buffering capacity, like seawater, the addition of gas containing CO2 at high pressure can depress the pH to less than 2.9, making the water very reactive. This water will dissolve and corrode steel with great rapidity or, if in the reservoir, will dissolve minerals either wholly or partly. This can lead to formation damage and dramatically reduce injection and production because the newly dissolved species reprecipitate as the pressure drops at the producer well.

Addition of the carbonate ion to sodium chloride solutions will raise the pH. If enough calcium is present, calcium carbonate precipitates. The reason the pH of most oilfield waters rises during storage in the laboratory is because of the formation of carbonate ions as a result of bicarbonate decomposition caused by evolution of dissolved CO2 gas. An important consideration of CO2 gas evolution/dissolution is that it is not anything close to instantaneous; a fact that has been underappreciated by many, with very expensive and confusing consequences.

In pure water, the CO2 equilibrium takes on the order of tens of minutes (≈20 min.) to adjust to a change in CO2 pressure and for the pH to stabilize to a new level. However, with large amounts of bicarbonate in an oilfield water, the adjustment is even slower, while the buffering action of the bicarbonate itself will limit how much the pH will eventually change.

Organic acids play an extremely important role in the water chemistry.[34] Because the volatile fatty acids, such as formic, acetic, propionic, and butyric acids, are quite commonly found in the waters, they can control the water chemistry to a large degree, especially the CO2/bicarbonate system. From a historical standpoint, this is important because analytical difficulties prohibited obtaining organic acid compositional data. Thus, much of the confusing behavior that workers observed in scale-deposition predictions based on the analysis of inorganic species compared with the actual field results turns out to be explainable once the organic acids are considered.

Historically, the typical analytical procedure for bicarbonate, the alkalinity titration, also happens to titrate the organic acids because they have Ka values similar to that of bicarbonate. Thus, scale predictions that used those bicarbonate values are somewhat incorrect, with the degree of error depending on the amounts of organic acids that were included with the bicarbonate value. Oilfield waters sometimes will have an unusual odor, which often comes from rather high concentrations of these organic acids. The formic, acetic, propionic, and butyric acids will not precipitate scale under most conditions, but certainly do buffer the water system effectively. Also, they seem to slow down the approach to CO2 equilibrium as well, so that water samples containing several hundred ppm of organic acids will not change their pH significantly when stored for several days. This also means that the dissolved CO2 in the produced water remains high even after the pressure has been reduced in a separator. It still can remain corrosive, even though it would not normally be expected to be very corrosive. One procedure to correct the bicarbonate analysis for the volatile fatty organic acid concentration is to measure the organic acid content by an independent technique, such as IC or CE, calculate the equivalent amounts of the acids, and then subtract those equivalents from the apparent bicarbonate concentration as measured by the alkalinity titration.

Naphthenic acids can precipitate and form scales, in contrast to the volatile fatty acids. Calcium naphthenate scale deposits have been identified recently in several fields that produce high-acid-number crude oils; however, the concentration of naphthenic acids in water is limited by their higher molecular weights and high oil solubility.[35]

TheRedox Potential

The redox potential (often abbreviated as Eh) may be referred to as oxidation potential, oxidation/reduction potential, or pE. It is expressed in volts or millivolts (mV), and, at equilibrium, it is related to the proportions of oxidized and reduced species present. Standard equations of chemical thermodynamics express the relationships.

The Nernst equation expresses the relationship between concentrations of oxidation-reduction couples. For example, a common redox couple involves the dissolved iron species Fe(II) and Fe(III), which can be described thermodynamically as





E = the voltage of the system vs. the standard hydrogen electrode,
Eo = the voltage of the oxidation reaction at standard conditions (1 mole/liter, 298 K, 1 atmosphere pressure),
n = the number of electrons transferred in the reaction,
R = the ideal gas constant,
T = temperature, °K,
F = Faraday’s Constant.

Eh is usually measured with a platinum electrode against a different reference, such as Ag/AgCl or saturated calomel reference electrodes. Knowledge of the redox potential is useful in studies of how compounds such as uranium, iron, sulfur, and other minerals are transported in aqueous systems. The solubility of some elements and compounds depends on the redox potential and the pH of their environment.

Some water associated with petroleum is interstitial (connate) water and has a negative Eh, which has been proved in various field studies. Knowledge of the Eh is useful in determining how to treat a water before it is reinjected into a subsurface formation. For example, the Eh of the water will oxidize if the water is open to the atmosphere, but, if it is kept in a closed system in an oil-production operation, the Eh should not change appreciably as it is brought to the surface and reinjected. In such a situation, the Eh value is useful in determining how much iron will stay in solution and not deposit in the wellbore.

Organisms that consume oxygen lower the Eh. In buried sediments, it is the aerobic bacteria that attract organic constituents that remove the free oxygen from the interstitial water. Sediments laid down in a shoreline environment will differ in degree of oxidation compared with those laid down in a deepwater environment. For example, the Eh of the shoreline sediments may range from −50 to 0 mV, but the Eh of deepwater sediments may range from −150 to −l00 mV.

Aerobic bacteria die when the free oxygen is totally consumed; anaerobic bacteria attack the sulfate ion, which is the second most important anion in the seawater. During this attack, the sulfate reduces to sulfide, the Eh drops to negative potentials (approximately −600 mV), and H2S is liberated. This process is known as reservoir souring and is a major concern to engineers working on fields undergoing waterflood with injected seawater or other sulfate-containing injectant. Most waterfloods have eventually gone sour. Hydrogen sulfide generation causes problems from a health and safety standpoint because it is so poisonous. H2S also causes rapid, nearly instantaneous, failure of steel because of sulfide stress-corrosion cracking, unless the steel has been specified for "sour service." Besides the presence of sulfate ions, dissolved organic acids play a role in feeding the SRB. Predicting and mitigating reservoir souring is an active area of research. SRB and other bacteria often cause a different, much slower type of pitting corrosion on steel, known as microbially induced corrosion (MIC). MIC is commonly seen in low-flow piping areas, under deposits of solids or sludges, or in vessels and tanks.

Dissolved Gases

Large quantities of dissolved gases are contained in oilfield brines. Most of these gases are hydrocarbons; however, other gases such as CO2, N2, and H2S often are present. The solubility of the gases in water generally decreases with increased water salinity and temperature and increases with pressure.

Hundreds of drillstem samples of brine from water-bearing subsurface formations in the U.S. Gulf Coast area were analyzed to determine the amounts and kinds of hydrocarbons.[36] The chief constituent of the dissolved gases usually was methane, with measurable amounts of ethane, propane, and butane. The concentration of the dissolved hydrocarbons generally increased with depth in a given formation and increased basinward with regional and local variations. In close proximity to some oilfields, the waters were enriched in dissolved hydrocarbons. Up to 14 scf dissolved gas/bbl water was observed in some locations.

Organic Constituents

In addition to the simple hydrocarbons, many organic constituents in colloidal, ionic, and molecular form occur in oilfield brines.[36] Because the analytical problems are difficult and very time consuming, many organic constituents present in oilfield brines were not determined. In recent years, some of these organic constituents have been measured quantitatively, because better analytical techniques have been adapted to the difficult produced-water matrix.

Knowledge of the dissolved organic constituents is important because these constituents are related to the origin and/or migration of an oil accumulation, as well as to the disintegration or degradation of an accumulation.[37] The concentrations of organic constituents in oilfield brines vary widely. In general, the more alkaline the water is, the more likely it will contain higher concentrations of organic constituents. The bulk of the organic matter consists of anions and salts of organic acids; however, other compounds also are present. Explorationists can use such data to look for anomalies in these constituents, while environmental scientists can use it to evaluate spills and effluents. The corrosion engineer needs to know how much of the inhibitor added at the well remains in the produced water so that its corrosion can be controlled. Organic-scale-inhibitor compounds are monitored routinely to verify that their concentration exceeds the minimum effective dose.

Knowledge of the concentrations of benzene, toluene, xylenes, and other components in oilfield brines is used in exploration. The solubilities of some of these compounds in water at ambient conditions and in saline waters at elevated temperatures and pressures have been determined.[38][39]

However, the actual concentrations of these and other organic constituents in subsurface oilfield brines are another matter. It has been shown experimentally that the solubilities of some organic compounds found in crude oil increase with temperature and pressure if pressure is maintained on the system. The increased solubilities become significant above 150°C. The solubilities decrease with increasing water salinity. Waters associated with paraffinic oils are likely to contain fatty acids, while those associated with asphaltic oils more likely contain naphthenic acids.

Quantitative recovery of organic constituents from oilfield brines is difficult. Temperature and pressure changes, bacterial actions, adsorption, and the high inorganic/organic-constituents ratio in most oilfield brines are some reasons why quantitative recovery is difficult. The effect of bacteria on the samples is particularly significant.[40] Unless samples are stabilized with an effective dose of biocide, significant or complete depletion of the organic acids is likely before the sample can be analyzed. Total loss of 300 ppm of acetic acid within 24 hours in an unstabilized produced-water sample was observed, while one containing 200 ppm of biocide suffered no loss of acetic acid.

Interpretation of Chemical Analyses

Oilfield waters include all waters or brines found in oil fields. Such waters have certain distinct chemical characteristics.[41][42] Approximately 70% of the world petroleum reserves are associated with waters containing more than 100 g/L of dissolved solids.[43] Water containing dissolved solids in excess of 100 g/L can be classified as brine. Waters associated with the other 30% of petroleum reserves contain less than 100 g/L of dissolved solids. Some of these waters are almost fresh; however, the presence of fresher waters usually is attributed to invasion after the petroleum accumulated in the reservoir trap.

Examples of some of the low-salinity waters can be found in the Rocky Mountain areas in Wyoming fields such as Enos Creek, South Sunshine, and Cottonwood Creek.[44][45] The Douleb oil field in Tunisia is another example. Extremely fresh water was discovered in the Cano Limon, Colombia, oil field with only 300 mg/L TDS, mostly sodium bicarbonate and sodium acetate. The chloride content was only approximately 20 mg/L.

The composition of dissolved solids found in oilfield waters depends on several factors. Some of these factors are the composition of the water in the depositional environment of the sedimentary rock, subsequent changes by rock/water interaction during sediment compaction, changes by rock/water interaction during water migration (if migration occurs), and changes by mixing with other waters, including infiltrating younger waters such as meteoric waters. The following are definitions of some types of water.

Meteoric Water. This is water that recently was involved in atmospheric circulation; furthermore, "the age of meteoric groundwater is slight when compared with the age of the enclosing rocks and is not more than a small part of a geologic period." [14]

Seawater. The composition of seawater varies somewhat but, in general, will have a composition relative to the following (in mg/L): chloride—19,375, bromide—67, sulfate—2,712, potassium—387, sodium—10,760, magnesium—1,294, calcium—413, and strontium—8.

Interstitial Water. Interstitial water is the water contained in the small pores or spaces between the minute grains or units of rock. Interstitial waters are syngenetic (formed at the same time as the enclosing rocks ) or epigenetic (originated by subsequent infiltration into rocks).

Connate Water. The term "connate" implies born, produced, or originated together (connascent); therefore, connate water probably should be considered interstitial water of syngenetic origin. Connate water of this definition is fossil water that has been out with the atmosphere for at least a large part of a geologic period. The implication that connate waters are "born with" the enclosing rocks is an undesirable restriction.[14]

Diagenetic Water. Diagenetic waters are those changed chemically and physically, before, during, and after sediment consolidation. Some of the reactions that occur in or to diagenetic waters include bacteria change, replacement (dolomitization), infiltration by permeation, and membrane filtration.

Formation Water. Formation water, as defined here, is water that occurs naturally in the rocks and is present in them immediately before drilling,

Juvenile Water. Juvenile water is water derived from primary magma.

Condensate Water. Water associated with gas is carried as vapor to the surface of the well, where it condenses and precipitates because of temperature and pressure changes. This water occurs more often in the winter, in colder climates, and in gas-producing wells. This water is easy to recognize because it contains a relatively small amount of dissolved solids, mostly derived from reactions with chemicals in or on the well casing or tubing or carried as a mist in high-rate-gas-flow wells.

Water analyses may be used to identify the water source. In the oil field, one of the prime uses of these analyses is to determine the source of extraneous water in an oil well so that casing can be set and can prevent such water from flooding the oil or gas horizons. In some wells, a leak may develop in the casing or cement, and water analyses are used to identify the water-bearing horizon so that the leaking area can be replaced. With the current emphasis on water pollution prevention, it is very important to locate the source of a brine so that remedial action can be taken.

Historically, comparisons of water-analysis data are tedious and time consuming; therefore, graphical methods were mainly used for positive, rapid identification. A number of systems were developed, all of which have some merit, with the most popular being the Stiff diagram (Fig. 10.13). The new computer chemistry models mentioned previously have largely displaced the manual graphics, but the visual comparisons are still useful in certain situations.

The Mixing-Line Technique

In situations in which two different waters are being mixed, it is desirable to measure the amounts of each in the mixed stream. Also, if that capability exists, it is desirable to look at each constituent to see if it undergoes any phenomenon other than simple mixing. Thus, this can be a powerful technique for detecting water/rock reactions that can lead to formation damage.[46]

The fundamental concept is that mixing two waters should result in the volume-weighted average of each constituent of the two original waters, unless some chemical or biological reaction occurred. This is essentially similar in appearance to a binary phase diagram, with the endpoints of the line defined by the concentrations of the constituent in each of the water streams being mixed. For the technique to be useful, at least one species needs to be found that can act as a tracer for one of the waters. The requirements for this species are that it does not participate in chemical or other reactions under the conditions of interest; it has a relatively large difference in concentration between the two waters; and its analysis is easy and cheap with excellent accuracy.

Candidate species include boron, iodide, bromide, and chloride. The boron species is one that has been valuable in this role for reservoirs in several areas, including the North Sea and the North Slope of Alaska. Seawater is used as the injection water, with a typical boron content of 4.5 mg/L. Boron typically does not undergo any precipitation, dissolution, ion exchange, adsorption, or microbiological reactions and is stable in samples. Boron analysis by ICP is cheap, fast, accurate, and has detection limits of better than 0.05 mg/L with ≈1% relative standard deviation. The formation waters have original boron concentrations ranging from 15 to 160 mg/L; thus, boron can serve as a tracer for the formation water.






Xfm = the fraction of formation water in the mixed produced water,
[B]pw = the measured boron concentration in the produced water sample,
[B]fm = the boron concentration in the original formation water,
[B]inj = the boron concentration in the injection water,
Wi = the percentage of injection water in the mixed produced water,
Wf = the percentage of original formation water in the mixed produced water.

With the use of this calculated index for the amount of formation (or injection) water, the concentrations of each of the species measured in the standard water analysis can be graphed. The pure formation and injection waters define the two endpoints of the mixing line. The analytical data for that species in each of the produced water samples are then plotted and compared with the theoretical mixing line.

Role of Suspended Solids in Produced Water

Solids are almost always present in an oil, gas, and water-producing stream. Unfortunately, the solids are usually ignored until the problems caused by the solids become so onerous that action is required. In some cases, the reservoir sands are known to be unconsolidated, and sand control is part of the project development. However, even if sand control is successful, fine solids will still be produced and end up in the produced-water system. If the volume of water handled is small, the solids issues may never be important. When a lot of water is present, problems such as pump wear, formation of deposits, injection-well plugging, filling vessels, corrosion, and oil carryover begin to appear. Water intended to be injected is often specified to meet certain levels of particulates with a maximum size.

The solids can be produced from the reservoir rock (e.g., clays, quartz) or from hydraulic fractures (proppant flowback), or it can precipitate from the produced water (e.g., iron sulfide). Particle sizes cover a wide range. In the hydraulic-fracture case, the proppant size may be 1 mm or larger, while iron sulfide precipitate can be < 0.1 μm.

Because the solids are denser than either the oil or the produced water, they tend to sink to the bottom of the pipes, vessels, or tanks. Systems with low flow rates usually build stagnant deposits of the solids. A rule of thumb that can be used is < 3 ft/sec for lines that will build solids deposits. The solids often are coated with oil and become neutrally buoyant in the water or water/oil interface, so they remain suspended and can travel great distances. Treating chemicals such as corrosion or scale inhibitors or emulsion breakers are surface active, are strongly attracted to the surfaces of the solids, and act to attract oil, paraffins, asphaltenes, and bacteria, so that the once-dense particle is now much larger and less dense. They also are sticky and agglomerate easily, eventually forming what has been termed "schmoo." [47] The resulting schmoo is an organic/inorganic scale that effectively coats the surfaces exposed to the produced water: piping, vessels, meters, tubing, and injector-well perforations. This heterogeneous coating has been observed in produced-water piping more than 1 to 3 in. thick around the full pipe circumference.

Schmoo deposits harbor bacteria implicated in corrosion of the produced-water system.[48] Also, schmoo can plug injector wells, primarily in the perforations and formation face, although occasionally large quantities slough off the tubing and fill the wellbore. Many times, the produced water in the injector-well tubing will build a thick enough layer of schmoo that wireline tools cannot be run. Oiled tubing-fill cleanouts are effective at removing the schmoo and restoring injectivity. Soaking the system with particular surfactant formulations has been effective in removing the schmoo deposits, preventing corrosion, and restoring injectivity.


αH+ = activity of hydrogen ion in solution
αOH- = activity of hydroxide ion in solution
Bw1, Bw2 = water FVF at p1 and p2, bbl/bbl
Bw = water FVF
RTENOTITLE = average water FVF corresponding to V, bbl/bbl
[B]fm = the boron concentration in the original formation water
[B]inj = the boron concentration in the injection water
[B]pw = the measured boron concentration in the produced-water sample
cw = water compressibility at the given pressure and temperature, Lt2/m, bbl/bbl-psi
RTENOTITLE = average water compressibility within the given pressure and temperature interval, Lt2/m, bbl/bbl-psi
C = salinity, g/L of solution
Csd = concentration of dissolved solids (also known as TDS), mg/L
E = the voltage of the system vs. the standard hydrogen electrode
Eo = the voltage of the oxidation reaction at standard conditions (1 mole/liter, 298 K, 1 atmosphere pressure)
F = Faraday’s Constant
Keq = equilibrium constant for water dissociation reaction
Kw = equilibrium constant for water dissociation reaction
m1 = 7.033
m2 = 541.5
m3 = −537
m4 = 403.3 × 10 3
n = the number of electrons transferred in the reaction
p = pressure, M/Lt2, psi
p1, p2 = pressure at conditions 1 and 2 with p1 > p2, M/Lt2, psi
pb = bubblepoint pressure, M/Lt2, psi
R = the ideal gas constant
Rwg = formation-water resistivity
S = salinity in wt%
Swr = irreducible water saturation
T = temperature, T, °F
V = water volume at the given pressure and temperature, L3
RTENOTITLE = average water volume within p and T intervals, L3
Vrc = ft3
Vsc = volume occupied by a unit mass of water at standard conditions, L3, ft3
Wi = the percentage of injection water in the mixed produced water
Wf = the percentage of original formation water in the mixed produced water
Xfm = the fraction of formation water in the mixed produced water
γH = activity coefficient
ρrc = density of water at reservoir conditions, m/L3, lbm/ft3
ρsc = density of water at standard conditions, m/L3, lbm/ft3
ρw = density, m/L3, lbm/ft3


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SI Metric Conversion Factors

atm × 1.013 250* E + 05 = Pa
bar × 1.0* E + 05 = Pa
bbl × 1.589 873 E − 01 = m3
cp × 1.0* E − 03 = Pa•s
dyne × 1.0* E − 02 = mN
ft × 3.048* E − 01 = m
ft3 × 2.831 685 E – 02 = m3
°F (°F−32)/1.8 = °C
in. × 2.54* E + 00 = cm
in.3 × 1.638 706 E + 01 = cm3
lbm × 4.535 924 E − 01 = kg
mL × 1.0* E + 00 = cm3
oz × 2.957 353 E + 01 = cm3
psi × 6.894 757 E + 00 = kPa


Conversion factor is exact.