Summary
Waterflood optimization by means of rate control is receiving considerable
attention because of increasing deployments of smart well completions and
i-field technology. The use of inflow control valves (ICVs) allows us to
optimize the production/injection rates of various segments along the wellbore,
thereby maximizing sweep efficiency and delaying water breakthrough.
Field-scale rate-optimization problems, however, involve highly complex
reservoir models, production and facility constraints, and a large number of
unknowns. In this paper, we propose an approach that is computationally
efficient and suitable for large field cases. It is based on our previous work
(Alhuthali et al. 2007, 2008), which relies on equalizing arrival time of the
waterfront at all producers to maximize the sweep efficiency. We use
streamlines to efficiently and analytically compute the sensitivity of the
arrival times with respect to well rates. We also account for geologic
uncertainty by means of a stochastic optimization framework using multiple
realizations. Analytical forms for gradients and Hessian of the objective
functions are derived, making our optimization computationally efficient for
large-scale applications. Finally, optimization is performed under operational
and facility constraints using a sequential quadratic programming approach.
We demonstrate our approach using two field-scale examples. The first is a
synthetic example called "Brugge" field, a benchmark case based on a North Sea
Brent-type field. The production optimization of this field is carried out as
part of a closed-loop process where the production history is matched prior to
the production optimization. The production optimization is performed over
multiple realizations for 20 years and involves 30 wells equipped with three
ICVs per well. The second example is a super-giant Middle Eastern field that
has more than 50 years of historical oil production. The optimization is
performed for 20 years on a portion of this field that contains nearly 300
wells consisting of conventional vertical and horizontal wells and smart
horizontal wells. In both examples, multiple field-related constraints are
imposed, such as the maximum well injection and production rates, the maximum
allowable drawdown, restriction on high-water-cut wells, and voidage
replacement for pressure maintenance. The results clearly demonstrate the
viability of our approach and the benefits of optimal rate control, with a
considerable increase in cumulative oil production and a substantial decrease
in the associated water production.
© 2010. Society of Petroleum Engineers
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History
- Original manuscript received:
14 February 2008
- Meeting paper published:
3 February 2009
- Revised manuscript received:
19 June 2009
- Manuscript approved:
30 July 2009
- Published online:
8 June 2010
- Version of record:
22 June 2010
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