1. Introduction and Reservoir Characterization
This case study evaluates the implementation of Polymer-Dispersed System (PDS) technology in a mature oil field characterized by complex carbonate geology and high-viscosity crude oil. The target reservoir is part of a Middle Carboniferous carbonate sequence. The pay zone consists of two primary intervals: an upper reservoir (A1) and a lower reservoir (A2), composed primarily of limestones and dolomites.
The reservoir exhibits significant layer-wise heterogeneity. The A2 layer generally possesses superior reservoir properties compared to the A1 layer, which tends to pinch out into dense, impermeable rock in certain areas. The net pay thickness is highly variable due to lithological complexity and uneven oil saturation, ranging from isolated thin beds of 0.8 m to thicker sections up to 20 m, with an average net thickness of 4.7 m.
Key Reservoir Parameters:
The reservoir is characterized by a wide variation in permeability and porosity, as summarized in Table 1. Core analysis and well log data indicate that permeability is the most variable parameter, with a high coefficient of variation.
Table 1. Reservoir Properties Summary
| Parameter | Data Source | Average Value | Variation Range |
|---|---|---|---|
| Permeability (mD) | Core Analysis | 1194.9 | 0.19 – 7399.0 |
| Well Log Data | 61.3 | 16.0 – 241.0 | |
| Pressure Transient | 55.0 | 6.0 – 900.0 | |
| Porosity (%) | Core Analysis | 14.3 | 2.9 – 27.9 |
| Well Log Data | 14.0 | 9.0 – 19.8 | |
| Initial Oil Saturation (%) | Core Analysis | 77.9 | 35.3 – 96.3 |
| Well Log Data | 70.0 | 45.0 – 89.3 |
Fluid Properties:
The crude oil is classified as heavy and highly viscous, with an in-situ viscosity averaging 874.8 mPa·s and a high content of sulfur (3.85% wt) and asphaltenes (10.0% wt). The formation water is of the calcium-chloride type with high total dissolved solids (TDS), averaging 236 g/L. This high salinity contrasts sharply with the injected water, which is typically of much lower salinity (fresh or low-salinity water).
2. Problem Statement: Waterflooding Inefficiency and Severe Water Breakthrough
Conventional waterflooding in this field was challenged by severe heterogeneity and the presence of natural fractures. The extreme permeability contrast between the A2 (high-permeability) and A1 (low-permeability) layers led to catastrophic early water breakthrough. Analysis of production data showed that injected water channeled rapidly through high-permeability streaks and fractures, resulting in:
- A sudden and dramatic increase in water cut from 10-15% to 98-100% in offset production wells.
- Poor sweep efficiency in the low-permeability A1 matrix, leaving significant bypassed viscous oil behind.
- Rapid dilution of produced formation water salinity due to mixing with injected fresh water.
3. Technology Description: Polymer-Dispersed System (PDS)
The selected EOR method involves the injection of a Polymer-Dispersed System (PDS). This system is formulated using oilfield wastewater combined with a low concentration of polymer (approx. 0.05%) and a suspension of dispersed particles (approx. 1%).
Mechanism: The PDS is designed to increase flow resistance specifically within the high-permeability, water-swept zones (fractures and A2 layer). As the PDS solution enters these thief zones, the dispersed particles and polymer create a stable blockage (increased residual resistance factor). This diverts subsequently injected water into the previously unswept, low-permeability matrix (A1 layer), thereby improving vertical conformance and overall sweep efficiency—crucial for mobilizing the high-viscosity oil.
4. Laboratory Validation
Prior to field deployment, core flood experiments were conducted on heterogeneous composite models designed to simulate the non-communicating layers of the carbonate reservoir. The models consisted of a high-permeability (H) layer and a low-permeability (L) layer.
Experiment Procedure:
- Primary waterflood until 100% water cut in the H-layer.
- Injection of a PDS slug.
- Secondary waterflood to assess incremental oil recovery.
Results:
- Baseline: During primary waterflood, displacement efficiency in the H-layer reached 51-67%, while the L-layer remained virtually unswept (displacement factor < 3%).
- Post-PDS: Following PDS treatment, flow resistance in the H-layer increased (Residual Resistance Factor: 1.31 – 1.84), corresponding to a ~33% reduction in effective permeability.
- Incremental Recovery: Oil displacement from the L-layer increased by 6.5% to 13.9%.
- Water Cut: The overall water cut of the composite model decreased significantly post-treatment.
Figure 1 Description: Oil recovery and water cut curves showing a distinct inflection point upon PDS injection, followed by lower water cut and higher ultimate recovery compared to baseline waterflooding.
5. Field Implementation and Results
The PDS technology was implemented in two injection wells (Well A and Well B) within a specific test area of the carbonate field. Injection volumes of approximately 12,580 bbl and 7,548 bbl of PDS solution were placed, respectively.
Operational Observations:
- Injectivity Modification: Following PDS placement, injectivity decreased approximately 1.5-fold at constant injection pressure. For example, in Well B, the injection rate dropped from approximately 3,397 bbl/day to 1,447 bbl/day. This confirmed successful blockage of high-conductivity thief zones.
- Flow Profile Modification: Injection profile logging (PLT) before and after treatment demonstrated a clear shift in intake. Previously inactive intervals in the upper A1 formation began accepting water, while intake in the dominant A2 intervals was reduced (see Figure 2 description).
Figure 2 Description: Well injectivity profile log showing fluid intake shifting from the lower high-permeability zone (pre-PDS) to the upper previously dormant zone (post-PDS) in Well B.
Production Impact (Six-Year Period Post-Treatment):
| Parameter | Area around Well A | Area around Well B |
|---|---|---|
| Incremental Oil Rate (bbl/day)* | ~9.1 | ~34.4 |
| Total Incremental Oil (bbl)* | ~8,658 | ~28,005 |
| Water Cut Reduction | 3% – 13% | 3% – 13% |
| Pressure Response | Significant pressure redistribution observed across the test area | Significant pressure redistribution observed across the test area |
*Conversion based on crude oil density of 1.041 tonnes/m³. 1 tonne ≈ 6.04 barrels.
6. Conclusions
The application of Polymer-Dispersed System (PDS) technology in this heterogeneous carbonate reservoir with viscous oil proved to be an operationally successful EOR method. The key outcomes included:
- Conformance Improvement: Successful diversion of injected water from high-permeability thief zones into low-permeability matrix rock, addressing the severe water breakthrough issue.
- Incremental Production: The recovery of significant bypassed oil volumes—over 36,600 barrels total from just two injector patterns (Wells A and B)—over a six-year period.
- Water Management: A measurable reduction in produced water cut, lowering operating costs associated with lifting and disposal.
- Reservoir Management: Effective redistribution of formation pressure, indicating a more balanced flood front.
The study confirms that PDS technology is a viable and effective method for enhancing oil recovery in complex carbonate reservoirs suffering from severe heterogeneity, viscous oil, and premature water breakthrough.