Summary
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 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 minimize the scale risk of downhole scale formation, the impact the
degree of fluid mixing will have on the resulting brine (from injection to
production), and the impact the desulfated brine will have on scale control
during produced water reinjection.
The paper draws on a wide range of technical inputs to make scale management
decisions including: computer modeling 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 vs. full sulfate
seawater injection.
Introduction
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 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 Fig.
1.
- For example, before injection, if seawater injection is supplemented by
produced water reinjection (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 reinjection, 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.
© 2008. Society of Petroleum Engineers
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History
- Original manuscript received:
11 January 2006
- Meeting paper published:
15 February 2006
- Revised manuscript received:
14 June 2007
- Manuscript approved:
9 October 2007
- Version of record:
20 May 2008
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