Brine pipelines

Fig. 10-9 Internal cathodic protection to avoid the danger of anodic corrosion behind an insulating joint in a brine pipeline.

The designer of brine pipelines must consider the possibility of deposition of solids. Solids may arise by settling from a slurry or suspension, by precipitation of salt as the brine cools, or by deposition of hardness compoimds (with their reverse solubility characteristics) as the brine is heated. 

Brine pipelines are not long in the sense that oil or natural gas pipelines are long. While booster stations are rare, they are not unknown. These are usually simple affairs, using a single pump provided with a bypass line containing a check valve, to allow the pipeline to function when the booster pump is out of service. 

Brine pipelines H+/General Cast iron, carbon steel, FRP, PVC, PP,... 

Polyurethane (thermocole—a popular name) calcium silicate foam preformed pads (as per pipe diameter) are fixed on chilled watei/brine pipelines at low temperatures by bituminous adhesive. This should, however be avoided in areas handling inflammable vapours, since thermocole itself can bum. 

Buried steel pipelines for the transport of gases (at pressures >4 bars) and of crude oil, brine and chemical products must be cathodically protected against corrosion according to technical regulations [1-4], The cathodic protection process is also used to improve the operational safety and economics of gas distribution networks and in long-distance steel pipelines for water and heat distribution. Special measures are necessary in the region of insulated connections in pipelines that transport electrolytically conducting media. 

Facilities for separating steam from brine and for power generation were designed by mechanical, chemical, and electrical engineers. Dissolved salts in the brine cause severe scaling and corrosion in wells and pipelines. Chemists and chemical engineers developed new production techniques to overcome these problems, as well as pollution control technology for the operation. 

The first oil wells were drilled in China in the fourth century, or perhaps earlier. The wells, as deep as 243 m, were drilled using bits attached to bamboo poles. The oil was burned to produce heat needed in the production of salt from brine evaporation. By the tenth century, extensive bamboo pipelines connected oil wells with salt springs. Ancient Persian tablets also indicate the medicinal and lighting uses of petroleum in the upper echelons of their society. 

A particularly interesting part of the pilot involved the treating of produced emulsions. Over the life of the pilot, 93% of the injected surfactant was produced at the production wells, and this situation led to serious emulsion problems. Heating the emulsion to a specific, but unreported, temperature caused the surfactant to partition completely into the aqueous phase and leave the crude oil with very low levels of surfactant and brine. The resulting oil was suitable for pipeline transportation. The critical separation temperature had to be controlled to within 1 0. At higher temperatures, surfactant partitioned into the oil, and at lower temperatures, significant quantities of oil remained solubilized in the brine. Recovered surfactant was equivalent to the injected surfactant in terms of phase behavior, and had the potential for reuse. 

IONS OR DISPERSIONS OF HEAVY CRUDE OIL in water or brine have been used in several parts of the world for pipeline transportation of both waxy and heavy asphaltic-type crude oils. The hydrodynamically stabilized dispersion transportation concept is described by the Shell Oil Corporation core flow technology (i). The use of surfactants and water to form oil-in-water emulsions with crude oils is the subject of a long series of patents and was proposed for use in transporting Prudhoe Bay crude oil (2). Furthermore, surfactants may be injected into a well bore to effect emulsification in the pump or tubing for the production of heavy crude oils as oil-in-water emulsions (3, 4). 

Whatever the specific formulation used, the final concentration of the surfactant is selected on the basis of the characteristics of the heavy-crude-oil-brine system and the conditions to which the emulsion will be subjected. The principal factor influencing the quantity of surfactant required is the length of the pipeline system in which the emulsion will be pumped. The concentration of surfactant based on the total emulsion may range from 200 to 5000 ppm, depending on specific system characteristics. 

The techniques used in the preparation of a stable oil-in-water emulsion for pipeline transportation are illustrated by the results of a field test in which an Athabasca bitumen was emulsified and pumped through a 3-in. x 4000-ft. pipe-loop system for a total distance of approximately 500 miles. The emulsion in this case comprised 75% by weight of the 8.3 API bitumen and 25% of a synthetic brine containing 1.7% NaCl. (API gravity is defined in the Glossary.) The surfactant used was a mixture of two ethoxylated nonylphenol surfactants the first component contained an average of 40 ethylene oxide units per molecule, and the second component contained 100 units. Approximately 1500 ppm of the surfactant mixture, based on the total... 

Emulsion Pipeline Operations. Prediction of pipeline pressure gradients is required for operation of any pipeline system. Pressure gradients for a transport emulsion flowing in commercial-size pipelines may be estimated via standard techniques because chemically stabilized emulsions exhibit rheological behavior that is nearly Newtonian. The emulsion viscosity must be known to implement these methods. The best way to determine emulsion viscosity for an application is to prepare an emulsion batch conforming to planned specifications and directly measure the pipe viscosity in a pipe loop of at least 1-in. inside diameter. Care must be taken to use the same brine composition, surfactant concentration, droplet size distribution, brine-crude-oil ratio, and temperature as are expected in the field application. In practice, a pilot-plant run may not be feasible, or there may be some disparity between pipe-loop test conditions and anticipated commercial pipeline conditions. In these cases, adjustments may be applied to the best available viscosity data using adjustment factors described later to compensate for disparities in operating parameters between the measurement conditions and the pipeline conditions. 

Sodium hypochlorite and chlorine gas are the most common agents for treating the water supply itself, and the concentration employed depends both upon the dwell time and the chlorine demand of the water. For most purposes a free residual chlorine level of 0.5-5 ppm is adequate. For storage vessels, pipelines, pumps and outlets a higher level of 50-100 ppm may be necessary, but it is usually necessary to use a descaling agent before disinfection in areas where the water is hard. Distilled, deionized and RO systems and pipelines may be treated with sodium hypochlorite or 1% formaldehyde solution. With deionized systems it is usual to exhaust the resin beds with brine before sterilization with formaldehyde to prevent its inactivation to... 

These bacteria have been quoted to have caused corrosion in systans snch as snbsea carbon steel pipelines, natural gas pipelines, and injection systems using produced brine to displace oil from the reservoir they are also a potential problem in closed water systems that conld form anaerobic environments. ... 

As can be seen, pipelines suffer from both internal and external corrosion. Internal corrosion is due to presence of sulfur-bearing gases such as hydrogen sulfide, carbon dioxide, and moisture, which is entrapped as brine from the sea. The usual rule of thumb is that the internal coatings are applied only if the crude/gas is sour in nature (its hydrogen sulfide concentration is more than 500 ppm). Otherwise, the internal corrosion is usually tackled by addition of inhibitors, either continuously or in a batch process. 

Erosion corrosion is a severe problem in transportation underground pipelines. This is because crude transportation occurs at high speed, which can cause cavitation corrosion this, when coupled with a corrosive environment due to retained brine, can cause erosion corrosion, leading to severe hole formation. 

Pipelines are used to transport and distribute Auids such as oil and its derivatives, water, sewage, and brine, and Auids for producAon such as natural gas, hydrogen, and acetylene as well as suspensions of Ane-grained soAds such as canent, coal, or sulfur. It is important to distinguish between Aammable and nonAammable substances, since construction and operating requirements differ considerably between these. 

Laying out the logic of the incident in this manner generates creative thinking. For example, the condition that the truck is a source of ignition may lead to an eventual recommendation to brining in the chemical in a new manner, say by use of a pipeline. 

Many salt deposits contain sulfides and hydrocarbon inclusions. When brine rises from the mine to the surface, noxious or hazardous gases can evolve in the pipeline or at the surface as the pressure decreases. These must be separated and disposed of safely. When temperatures in the mine are higher than those at the surface, dissolved salt may drop from solution. Process design should recognize the possibility of precipitation and accumulation of solids. In this connection, the pressure at the bottom of the well also increases the solubility of other compounds. Frear and Johnston [43] and Brandani et al. [44] have shown that the solubility of calcium species increases when the partial pressure of CO2 increases. A final consideration is on rates of solution. The very long residence time in a brine well allows more of the slower-dissolving materials to enter the brine, which is generally of lower quality than brine prepared at the plant from the same salt. 

Pipelines. This section deals only with off-site pipelines used for the longdistance transfer of brine. Some pipelines, especially among the older ones, are cast iron. Newer lines are more frequently carbon steel or even a resistant plastic. 

To protect a metallic pipeline from corrosion, the brine should first be deaerated. Drawing a vacuum is the most convenient technique (Section 12.6). If the source of brine is remote, there may be no steam available to drive an ejector. A vacuum pump may then be used, or an eductor driven by brine or air. Typical operating pressures for deaeration are 10-20kPa. 

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