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 PDS 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.
Class III: Peripheral Waterflood – Volume Effect
In peripheral injection, wells are at the reservoir edge. Flow is radial; only a fraction η of injected fluid moves toward the oil zone (typically η=0.25–0.5), the rest flows into the external aquifer. To deliver an effective dose Veff to the oil zone, total volume must be Vtotal=Veff/η, i.e., 2–4 times larger than in intra‑pattern floods.
| Treatment phase | Volume per well (bbl) | Effective dose (bbl) | Success rate | Incremental oil |
|---|---|---|---|---|
| First (small) | 12,580 – 23,900 | ~4,000 – 12,000 | 42% (3 of 7) | 0 (failures) |
| Second (large) | 63,000 – 81,700 | ~19,000 – 41,000 | 85% (6 of 7) | 127,700–127,800 |
Threshold: Injectivity declined only after 69,180 bbl – confirming a minimum effective dose.
Class IV: Transition Zone – Hydraulic Access to Saturation Intervals
Success rate: 54.5% (11 injectors across 8 areas)
The critical factor was whether the wellbore had hydraulic access to both the water-saturated interval (water leg) and the oil-saturated interval (oil column).
- Wellbore communicates with both water leg and oil column → PDS injected into the well enters both intervals. Aggregates form in the water leg, increasing its flow resistance. When resistance in the water leg exceeds that in the oil column, subsequent injection water is hydraulically forced into the oil column → success (3 areas).
- Wellbore communicates only with the water leg (oil column not hydraulically connected) → All PDS enters the water leg. Even if aggregates reduce permeability there, the injected water has no path to the oil column. Flow remains confined to the water leg → no incremental oil (5 areas).
Class V: Discontinuous Reservoirs
Highly lenticular, discontinuous sand bodies. Effective only within continuous lenses (where success matches Class I). Not recommended for field‑wide application.
Conclusions
- Heterogeneity is the primary enabler. The highest success (100%) occurs in reservoirs with Dykstra‑Parsons coefficient >0.6, where PDS aggregates can accumulate in thief zones.
- Batch volume is the most controllable factor. Increasing volume from 12–23 kbbl to 63–82 kbbl raised success from 42% to 85% in peripheral floods, compensating for the fraction of injected fluid lost to the external aquifer (η = 0.25–0.5).
- Bottom‑water drives require isolation to achieve 85% success.
- Hydraulic access to both saturation intervals is decisive. PDS diverts flow from the water leg to the oil column only if the wellbore communicates with both intervals. Access to the water leg alone yields zero incremental oil.
- Aggregate field impact: 218 treatments produced 6.51 million bbl of incremental oil, confirming PDS as a cost‑effective EOR technology for mature assets.