Technical case study | 218 well treatments | 12 mature oil fields
Executive Summary
Polymer Dispersed System (PDS) technology was field-tested in 12 mature oil assets with varying geological characteristics. The objectives were to reduce water cut, improve sweep efficiency, and recover incremental oil from reservoirs where water influx had overtaken oil recovery by 30–50%.
Aggregate result: 6,511,000 barrels of incremental oil, averaging approximately 30,000 bbl per treatment. Success rates demonstrated strong dependence on reservoir heterogeneity, injected volume, and hydraulic access to saturation intervals — ranging from 42% in low‑volume peripheral treatments to 100% in highly heterogeneous zones.
This study quantifies the key controlling factors and provides actionable engineering guidelines.
Methodology
Data sources: Injectivity profiles (pre‑ and post‑treatment), production response (oil rate and water cut) in offset producers, reservoir pressure surveys, and displacement characteristics analysis.
Success criterion: A treatment was classified as successful if any of the following conditions were met:
- Incremental oil ≥10,000 bbl per treated area, or
- Sustained water cut reduction ≥10 percentage points, or
- Confirmed positive change in injectivity profile.
Success rate is defined as the ratio of injectors with positive response to total injectors within each reservoir class.
PDS Mechanism and Applicability
Polymer Dispersed System (PDS) increases flow resistance in high‑permeability, water‑swept intervals. Upon injection, the dispersed particles interact with formation water, creating aggregates that partially block thief zones and redirect subsequent injection water into unswept, oil‑saturated layers.
Optimal conditions for PDS application:
- Dykstra‑Parsons permeability heterogeneity coefficient >0.6
- Water cut >60% with evidence of preferential channeling
- Presence of continuous oil‑saturated layers behind thief zones
Suboptimal conditions:
- Highly homogeneous reservoirs (insufficient permeability contrast)
- Bottom‑water drives without mechanical isolation
- Injection into a well that communicates only with the water leg (no hydraulic access to oil-saturated interval)
Class I: High Heterogeneity, Mature Waterflood
Success rate: 100% (9 injectors)
Pre‑treatment water cut: 78–92%. Incremental oil per pattern: up to 160,100 bbl. Response time: 7–8 months.
Example: In one pattern with four injectors and 26 responding producers, water cut in a key producer declined from 92% to 59%, with a sustained oil rate increase.
Class II: Bottom‑Water Drive Reservoirs
Success rate: 85% (7 injectors)
Reservoirs with an underlying active aquifer. Mechanical isolation (packers) was required to prevent PDS migration into the water leg. One area yielded 40,600 bbl of incremental oil.