Produced water is one of the most handled fluids in the oil and gas industry.  Large volumes of water are used in injection operations, and even larger volumes are a major waste by-product associated with the production of oil and gas worldwide.

What is it?

Produced water is a disparate, distinctive entity, with a different ‘flavour’ in each location. There are no two produced water streams which are identical, even from a central processing facility. Every well has its own unique produced water finger print.

Produced water is essentially oil dispersed in a bulk water stream, where the oil is either free oil or dissolved oil. Free oil is typically the larger component making up 90%+ v/v. That’s the simple definition, however produced water is, and also contains, so much more.

Dispersion Types

Free oil in water dispersions are categorised as either primary dispersions or secondary dispersions, and it’s this free oil component that most treatment systems deal with.

Primary dispersions (or easy separation applications) can be defined as those containing relatively large oil drop sizes, which are typically larger than 40 microns.

Secondary dispersions (or tough, demanding separation applications) contain relatively small oil drop sizes, which are typically less than 20 microns.

As is typically the case with water chemistry, there is a grey area where oil drops sizes (in our case 20 to 40 microns) may be categorised as either primary or secondary dispersions, and are chosen as one or the other, depending on the prevailing process conditions, including temperature and pressure.

It’s important to know your dispersion type, as it will have an impact on treatment approach and equipment selection.

Emulsions

Another term used in describing produced water, is the mysterious ‘emulsion’.  An ‘emulsion’ is a quasi-stable oil in water dispersion, in which the natural tendency for the free oil to coalescence and separate from the water (see Stokes Law) is either prevented or suppressed. This is due to the presence of surface-active agents or chemicals, which may be introduced or naturally occurring chemicals, and occur with great variety in the crude oil or gas reservoir system.

Emulsions result from a reduction in interfacial tension, and/or a stability provided from electrostatic repulsion barriers between the immiscible oil and water liquids.

Emulsions provides a stability or “toughness” dependent on temperature, pH, salinity, viscosity, density of the bulk phase (water), volume fraction, size of the dispersed oil droplets, and the age of the emulsion.

If this isn’t bad enough, a number of oil field ‘conditions’ affect the emulsion stability and provide additional problems for treatment.  These ‘conditions’ include the presence of solids, scale, waxes, asphaltenes, free and dissolved gases, and production chemicals in the produced water.

The dissolved oil component includes hydrocarbons, phenols, organic acids, and low molecular weight aromatic compounds such as benzene and toluene.

Where a stable emulsion is present, any mechanical solution alone will not facilitate the separation process, and other mechanisms, specifically the use of other chemicals or heat, need to be addressed to solve the separation problem.

In their simplest form, if a tough emulsion is encountered one should first take steps to identify the stabilizing causing agent. If it’s an upstream process (high pressure drop), or system input (forward demulsifier dosing), one should look at eliminating this agent, or at the very least look at ways to minimise the effects on the produced water system.

In some instances, where for example the agents are naturally occurring and cannot be removed or minimised, the only solution is a combination of mechanical, chemical, thermal, or electrical treatments. In this case, where we have a more challenging problem, it’s no surprise that we will need a multistep process system solution.

The challenge of adequately identifying whether a produced water system has a dispersion or emulsion, and then addressing the emulsion is not easy. Characterising the water appropriately will be based largely on empirical data and onsite testing.

So, what have you got?

Bibliography:

1. White, L.R., Hilco R&D, “Oily Water Separation: The Characteristics of an Emulsion”, Filtration News, July/August 1995 Issue.
2. Yang, M., et al., UMIST, “Interactions Between Chemical Additives and Their Effects on Emulsion Separation”, SPE 36617, ATCE Denver, October 6-9, 1996.
3. McCain, W.D. Jr., “The Properties of Petroleum Fluids; Chap. 16. Properties of Oilfield Waters”. PennWell, 1990.
4. Becker, J.R., “Crude Oil Waxes, Emulsions and Asphaltenes”, PennWell, 1997.