Chemical solution improves productivity and sustainability of North Sea produced water re-injection well

By Myles Jordan and Clare Johnston, ChampionX

Evaluation of the demulsifier-type chemical formation was undertaken at the company’s research, development and engineering laboratories in Aberdeen, Scotland
Evaluation of the demulsifier-type chemical formation was undertaken at the company’s research, development and engineering laboratories in Aberdeen, Scotland (photo: ChampionX)

Produced water re-injection (PWRI) is a method for maintaining reservoir pressure and sweeping hydrocarbon towards production wells in which water separated from the produced fluids at the surface facilities is re-injected into the same, or possibly alternative, hydrocarbon bearing formation.

The primary objective is the safe and sustainable disposal of produced water and associated production chemicals with minimal damage to the environment. When correctly selected, implemented and monitored, production chemical applications can improve the total cost of activity. It can also deliver space and weight savings through the optimisation of water treatment facilities and PWRI systems throughout the life of a field.

ChampionX Corporation (ChampionX), a global leader in chemistry solutions and highly engineered equipment and technologies that help companies drill for and product oil and gas safely and efficiently, was contracted by a major operator to address the impact of the continual addition of a low dose polyglycol-type demulsifier chemistry to a PWRI well in the North Sea that had suffered production decline owing to excessive oil carry over within the produced water.

Oil carry-over challenges
Oil carried over with the produced fluids can have a detrimental effect on wells where fluid injection is via matrix flow rather than fracture flow. The suspended oil impact will depend on the amount of oil carried over and the droplet size. In essence, the more oil and the larger the droplet size, the more significant the impact.

Suspended oil droplets can also carry small amounts of solids at the oil/water interface. For example, oil wet solids such as iron sulphides and calcium napthenates.

For sand control completions with produced water injection, there is evidence that oil acts as a binder for suspended solids, reducing the injectivity in wells with screens and gravel packs.1 It is also possible that over time, and with significant volumes of injected produced water, that frequent high oil/water (100s ppm oil not the typical <30 ppm) events can lead to an increase in near wellbore oil saturation within the rock pore space resulting in decreased water flow paths and reducing injectivity. The impact of suspended oil is much less significant in wells where fluid injection is achieved via fractures rather than matrix flow.

Many factors influence PWRI well performance. When applied, production chemistries can improve PWRI effectiveness by reducing the following:

  • Oil in water.
  • Amount of suspended solids.
  • Back pressure induced by frictional drag within injection lines.
  • Formation of inorganic scale and biomass.
  • Microbially Induced Corrosion (MIC).

The application of demulsifier chemicals to produced fluids, for instance, is already an established technology to speed up the separation of oil from water. In terms of PWRI, the lower the amount of oil in the water phase the better, as the oil carried forward can act as a binding agent for reservoir solids, scale and corrosion by-products.

The primary objective of PWRI is the safe and sustainable disposal of produced water and associated production chemicals with minimal damage to the environment
The primary objective of PWRI is the safe and sustainable disposal of produced water and associated production chemicals with minimal damage to the environment (photo: ChampionX)

Evaluation, application and results of production chemical use in the field
During this particular project, due to frequent periods of time where suspended oil had exceeded the recommended concentration of 30 ppm in the produced water injection well in the North Sea, well injectivity had declined. The well was completed in high permeability sandstone (>1 Darcy), and as a result, sand control was required to maintain wellbore stability. Completions that are designed for sand control can suffer very badly owing to the entrapment of suspended solids/oil aggregates. In this case, the completion was a wire wrap screen under matrix flow injection.

The injectivity losses were attributed to the de-oiler not being applied at the optimum rate, resulting in more oil being carried into the injection well. In addition, the demulsifier treatment rate was not optimal for a period of time due to process upsets caused by well tests and well slugging. For instance, an earlier slugging event had resulted in up to 300 ppm oil in water being injected. The cumulative effect of these factors resulted in a reduction in the injection rate of 15,000 BWPD (barrels of water per day).

Reflow of the injection well had only provided temporary improvement. Application of a mud acid stimulation, again, had only shown improvement over 2 to 3 weeks before injectivity declined once again.

ChampionX was tasked with evaluating the performance of a chemical based on a demulsifier-type chemical formation that displayed the ability to reduce surface tension in water and mobilise oil droplets when applied at the ppm range. This was undertaken at the company’s research, development and engineering laboratories in Aberdeen, Scotland.

In other field applications, batch treatment of this type of chemical had shown it was able to remove the build-up of oil-coated solids, thus allowing inorganic solids bound in the oil to pass through the sand control screens. Continual injection of the more dilute chemical was predicted to reduce the build-up rate of oil and solids by preventing the oil droplets from adhering to the inorganic solids and the sand control screen.

It was also predicted that the already accreted oil/suspended solids aggregates would be removed by the mobilisation of the oil binding the solids, therefore allowing improved injection.

The demulsifier was injected into the produced water at concentrations from 10 ppm, 30 ppm and 50 ppm for a period of 7 days at each treatment rate.

The application of the injectivity aid at a concentration between 20-30 ppm clearly enhances injectivity and was able to increase the injectivity due to removal of previously formed oil bound solids from the screens and prevention of additional build-up of these solids as the oil was unable to bind them together to create larger aggregates.

As a result of the project, additional operational processes were put in place to not only ensure chemical injection was carried out to optimise separation, but to also continually evaluate the batch treatment to recover additional damage to injector wells, if required.

In this case, it was possible to increase water injection without the need to batch treat the well, which would have resulted in a potential production shutdown. Due to less resistance to flow, the desired injection rates were achieved at a lower energy requirement. In addition, over a three-week trial period, the volume of demulsifier required is significantly less than the mutual solvent batch application with only four tanks (9,088 litres) of demulsifier compared to ten tanks (23,373 litres) of the conventional mutual solvent chemical solution.

Improving the sustainability profile of PWRI operations
In its efforts to reduce greenhouse gas emissions, minimise waste, conserve operational resources, and shrink carbon footprint, the oil and gas industry is adopting novel or enhanced production chemical technologies to recover damage to PWRI systems that would otherwise have required a well workover, new injector well drilling or vessel intervention to clean flowlines.

The case study in the North Sea demonstrates that the application of remediation programs via continual injection of correctly selected production chemicals presents significant savings in terms of chemical cost/production downtime over batch cleaning chemical applications. More broadly, this will lower the environmental impact of manufacture, shipping, and storage of this innovative and more sustainable chemical application method.

Reference

  1. Mackay, E.J., Collins, I.R., Jordan, M.M. and Feasey, N.: “PWRI: Scale Formation Risk Assessment and Management” paper SPE 80385 presented at the SPE 5th International Symposium on Oilfield Scale, Aberdeen, Scotland, 29-30 January 2003.

Myles Jordon, Director of Marketing, External Technology Group, ChampionXMyles Jordon, Director of Marketing, External Technology Group, ChampionX, has has a BSc in Geology and Chemistry from the University of Glasgow, and a Ph.D. in Sedimentary Geochemistry from Manchester University. Since joining ChampionX in 1997, Myles has been responsible for the development of topside/downhole inorganic scale control programs within the Americas, North Sea, Middle East, and West Africa. He has been an author or co-author of over 185 Society of Petroleum Engineering (SPE), National Association of Corrosion Engineers (NACE) and Royal Society of Chemistry (RSC) papers on deployment challenges of oilfield scale inhibitors.

Clare Johnston, Senior Staff Scientist, Flow Assurance, ChampionXClare Johnston, Senior Staff Scientist, Flow Assurance, ChampionX, has a BSc (Hons) in Applied Chemistry and has worked in technical roles in the upstream oil and gas industry since 1998. Since joining ChampionX in 2002, she has been responsible for the qualification, design, and management of topside/downhole inorganic scale control programs within the Americas, North Sea, Middle East, and Asia Pacific. Clare is the author or co-author of over 20 technical papers and is a frequent contributor to industry technical events on oilfield scale inhibition, including SPE, Tekna and the Royal Society of Chemistry (RSC).