The injection of seawater into oil-bearing reservoirs to maintain reservoir pressure and improve secondary recovery is a well-established, mature operation. Moreover, the degree of risk posed by deposition of mineral scales to the injection and production wells during such operations has been much studied. The current deep water subsea developments offshore West Africa and Brazil have brought into sharp focus the need to manage scale in an effective way. To this end, the challenge of scale control during the lifecycle of water injection, production and onto produced water reinjection has been reviewed for a number of fields by the authors.
This outlines the risk assessment process that should be undertaken to select the most economical and effective scale control methodology (which for sulfate-based scale could be seawater injection with scale inhibitor squeeze treatments to maintain production, or sulfate reduction of the injection water - with or without the need to scale inhibitor squeeze). In the case of sulfate reduction, parameters to be investigated include the degree of desulfation required to minimise the scale risk of downhole scale formation, the impact that the degree of fluid mixing will have on the resulting brine (from injection to production) and the impact that the desulfated brine will have on scale control during produced water reinjection.
The paper draws upon a wide range of technical inputs to make scale management decisions including: computer modelling techniques (e.g., deposition models that incorporate the kinetics of sulfate scale formation at low supersaturation ratios); reservoir simulation of fluid mixing and reaction; the resulting produced brine chemistry; laboratory generated coreflood data to assess chemical selection for scale inhibitor squeeze and produced water application; and field results that will demonstrate the impact of the type of injection water source on the long term manageability of such deepwater projects. Finally, the paper outlines in detail the particular issues associated with the full economic assessment of low-sulfate water injection versus full sulfate seawater injection.
After a brief overview of locations where oilfield scale can form and how it may change in composition throughout the life cycle, this paper discusses the factors that influence the choice of injection water, the impact of sulfate levels on scale control costs and the scale risk assessment process that can be used to select the correct scale management strategy for economic field development.
Where Does Oilfield Scale Form?
The scaling reaction depends on there being sufficient concentrations of sulfate ions in the injected seawater, and barium, strontium and/or calcium divalent cations in the formation brine to generate sulfate scale; or on there being sufficient bicarbonate and calcium ions to allow the formation of carbonate should the physical conditions result in a change in equilibrium. Thus scale precipitation may occur wherever there is mixing of incompatible brines, or there are changes in the physical condition - such as pressure decline. An overview of all the possible scale formation environments for seawater, aquifer, natural depletion and produced water reinjection is presented in Figure 1:
Prior to injection, for example if seawater injection is supplemented by produced water re-injection (PWRI);
Around the injection well, as injected brine enters the reservoir, contacting formation brine;
Deep in the formation, owing to displacement of formation brine by injected brine, or owing to converging flow paths;
As injection and formation brines converge towards the production well, but beyond the radius of a squeeze treatment;
As injection and formation brines converge towards the production well, and within the radius of a squeeze treatment;
In the completed interval of a production well, as one brine enters the completion, while another brine is flowing up the tubing from a lower section, or as fluid pressure decreases;
At the junction of a multilateral well, where one branch is producing a single brine and the other branch is producing incompatible brine;
At a subsea manifold, where one well is producing one brine and another well is producing a different brine;
At the surface facilities, where one production stream is flowing one brine and another production stream is flowing another brine;
During aquifer water production and processing for re-injection, with the possibility of scale formation within a self-scaling brine or mixing with an incompatible formation brine as in b);
During pressure reduction and/or an increase in temperature within any downhole tubing or surface processing equipment, leading to the evolution of CO2 and to the generation of carbonate and sulfide scale if the appropriate ions are present.
Temperature reduction could lead to the formation of halite scales if the brine is close to saturation under reservoir conditions.