Polymer-Flood Field Implementation: Pattern Configuration and Horizontal vs. Vertical Wells
- Martin Sieberer (OMV) | Torsten Clemens (OMV) | Joerg Peisker (OMV) | Solomon Ofori (OMV)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- May 2019
- Document Type
- Journal Paper
- 577 - 596
- 2019.Society of Petroleum Engineers
- economics, field implementation, polymer flooding, injectivity, horizontal wells
- 31 in the last 30 days
- 88 since 2007
- Show more detail
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A polymer pilot in the 8th Torton Horizon (8 TH) Reservoir in Austria showed promising results. The utility factors were 1.8 kg of polymer injected per incremental bbl of oil produced (polymer costs are EUR 1.74 to 3.48/kg). Furthermore, substantial incremental oil was produced, which might result in economic field implementation. The results triggered the planning for field implementation of polymer flooding.
To optimize the economics of field implementation, a work flow was chosen ensuring that known uncertainties were covered. There were 1,200 geological models generated that cover a variety of different geological concepts. These geological models were clustered according to their dynamic response into 100 representative geological realizations, and then used for history matching.
To screen areas of the reservoir that might benefit from polymer injection, probabilistic incremental net-present-value (NPV) maps were generated. Next, the well configuration was investigated using horizontal or vertical wells and the well distances. Afterward, operational parameters, polymer concentration, and duration of polymer injection were optimized for NPV. Finally, full-field simulation was performed to determine the cumulative distribution function (CDF) of incremental NPV.
Applying the work flow to the 8 TH Reservoir in Austria led to the following results:
- Some areas of the reservoir were excluded from polymer injection because the P50 NPV map showed poor economics.
- Horizontal wells might lead to injection under matrix conditions, whereas vertical wells lead to injection under fracturing conditions for the conditions of the 8 TH Reservoir. In particular, the near-wellbore polymer rheology has a meaningful effect on injectivity.
- The NPV per reservoir area is higher for horizontal wells (EUR 43/m2) than for vertical wells (EUR 30/m2) because of the well cost vs. incremental recovery differences of the two configurations.
- The optimal well distance of the horizontal wells in the 8 TH Reservoir is 200 m for operational reasons.
- As operating parameters, a polymer concentration of 2,000 ppm and 8 years of injection were chosen to maximize NPV.
- The resulting CDF of incremental NPV showed a probability of economic success of 91% and an expected monetary value of EUR 73 million.
|File Size||2 MB||Number of Pages||20|
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