Summary
Increased oil and particularly gas production may be achieved in
waterflooded reservoirs by stopping further water injection, and depressurizing
the reservoir to release solution gas. Pressure depletion may be
accelerated by backproducing injected brines. However, there is the
possibility that these brines may cause formation damage by mobilizing fines or
deposition of inorganic scales. Scale deposition in production wells may
also occur as a result of pressure depletion, with calcite scales being
precipitated when the system drops below the CO2 bubblepoint
pressure. This paper discusses the assessment and prediction of
scale-related formation damage problems that are likely to occur during
depressurization of a case study field. The potential for the specific
problem arises from the formation of barium sulphate scale as a result of
mixing of injected and formation brines during production. Data used in
this study include well brine chemistries and an existing finite-difference
reservoir simulation model of the field depressurization, which was used to
calculate the mixing of injected and formation brines and the movement of the
mixing and temperature fronts during waterflooding and subsequent
depressurization.
This study has determined that the behavior of the scaling potential for
each well in this field is different. Also, the degree of scaling, both
deep within the reservoir where it does the least damage and around the
wellbore (for both injectors and producers) where it may adversely affect
production, can be predicted by detailed modeling using both conventional and
reaction-flow simulations. Former injectors converted to water production
or infill wells drilled in the aquifer for pressure depletion may experience an
increase in the scaling potential that significantly impacts the economics of
the project because of the need for extensive prevention (inhibition)
treatments. The increased scaling potential in these wells is a result of
the dynamics of brine mixing in the reservoir, the lowering of reservoir
temperature in the vicinity of injection wells during waterflooding, and the
large volumes of water required to be produced to achieve
depressurization. The magnitude of the scaling problem and the economic
impact are lower for the production wells because of lower water production
rates and higher temperatures.
Introduction
A number of mature waterflooded fields are candidates for tertiary recovery
by depressurization, as is currently occurring in the Brent field, North
Sea. Pressure depletion is achieved by stopping water injection and
producing from the aquifer as well as the hydrocarbon-bearing
strata. Solution gas in the residual oil, previously bypassed oil rims,
and attic oil is then released (Mackay et al. 2002). The decision to
implement depressurization in any waterflooded field involves significant
economic considerations. By evaluating the scaling tendency, the
uncertainty and cost resulting from potential losses from scale-related
deferred oil and gas production may be minimized.
This process should involve a thorough review of the current scale
management practice, followed by a detailed study of which parameters will
change as a result of depressurization.
A candidate field for post-waterflood depressurization has been studied to
identify the potential impact of scale damage on production. A predictive
reservoir simulation model, designed specifically to evaluate depressurization
(Drummond et al. 2001), was adapted to study the changes in some of the
parameters that are expected to impact scale precipitation. This paper
describes the application of this model of reservoir depressurization to
evaluate the scaling potential in production wells and in former injection
wells when they are used for backproduction of injection seawater.
The calculations performed using the conventional finite-difference flow
model do not incorporate reaction calculations, although they may be used to
demonstrate the propagation of the mixing zone. To model scale
precipitation, the consequent ion loss, and permeability impairment, a
commercial reaction transport simulator was used.
© 2006. Society of Petroleum Engineers
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History
- Original manuscript received:
23 June 2005
- Revised manuscript received:
29 August 2005
- Manuscript approved:
30 August 2005
- Version of record:
20 May 2006
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