▶ Key results: 76,425 bbl incremental oil · 39,940 bbl less water · 5 responding wells · 13 months
Executive Summary
A mature carbonate field with natural fractures and high-permeability zones experienced severe premature water breakthrough from an injection well into five surrounding production wells. Water cut reached as high as 88%, daily oil production collapsed by 280 bbl/day, and the economic viability of the area was threatened.
Conventional water shutoff technologies had already been tested in this field — and they failed to deliver sustainable results.
After two Polymer Dispersed System (PDS) treatments in the injection well, the water conduit was successfully blocked. Oil production increased by up to 450 bbl/day, water cut decreased by 16%, and cumulative incremental oil reached 76,425 bbl over 13 months — reversing a previously negative production trend.
Estimated economic benefit (13 months): ~$5.7 million incremental revenue · ~$0.5 million reduced water handling costs · ROI > 10x
The Problem: Water Breakthrough and Production Collapse
Premature water breakthrough through high-permeability zones, fractures, and cavernous intervals is a common challenge in waterflooded oil fields. In carbonate reservoirs — which are naturally heterogeneous and fractured — this problem is particularly severe. Injected water tends to move almost exclusively through paths of least resistance, bypassing large volumes of oil-saturated rock.
The consequences are well known but worth repeating:
- Production wells water out rapidly
- Large remaining oil reserves become uneconomical to produce
- Water handling costs escalate
- Field abandonment accelerates
In this case study, all of these negative effects were observed before the application of Polymer Dispersed System (PDS) technology.
Reservoir and Geological Summary
The test area is confined to a northeastern deposit of a carbonate field. The development target consists of porous and cavernous limestones alternating with dense, impermeable rocks. The well sequence includes 12 producing members separated by seals ranging from 3 to 28 ft (1.0–8.5 m) in thickness.
Total thickness of the development target is approximately 1,322 ft (403 m), with a net pay of about 262 ft (80 m). The complex structure of carbonate reservoirs, including fractured zones, is a key factor in reservoir development and water breakthrough.
Previous studies in the area have shown that the direction of maximum injected water velocity depends on the orientation of natural fractures, and premature water encroachment in production wells aligns with the dominant fracture pattern. In this field, breakthrough of injected water occurs mainly through fractures and high-permeability layers.
Pre-Treatment Situation: Severe Water Encroachment
The test area includes eight production wells surrounding a single injection well. Before treatment, the situation had become critical:
- Water cut ranged from 2% to 88% across the eight wells
- Five wells showed severe water encroachment (Wells A, B, C, D, and E)
- Other wells produced almost no water due to extreme lateral heterogeneity — meaning injected water was channeling through specific high-permeability pathways rather than sweeping the reservoir evenly
The most alarming indicator: Average daily oil production in the area dropped sharply by 280 bbl/day due to water breakthrough from the injection well. Baseline average oil production fell to 827 bbl/day — a level that threatened the economic viability of the entire area.
In short: the injection well had created a direct water conduit through fractures and high-permeability zones, bypassing oil-saturated rock and flooding production wells prematurely.
Previous Attempts: Conventional Chemical Technologies Failed
Before implementing PDS technology, the operator had already attempted conventional chemical water shutoff methods in this field — including standard polymer gels, silicate-based compositions, and resin systems.
All of them failed to deliver sustainable results:
| Technology | Result |
|---|---|
| Polymer gels | Short-lived effect (weeks), rapid degradation |
| Silicate systems | Poor penetration, unreliable placement |
| Resin treatments | High risk of formation damage, no selective blocking |
Key failure modes:
- Inability to penetrate deep into the fracture network
- Poor selectivity between oil and water zones
- No sustained water cut reduction or incremental oil
After multiple unsuccessful attempts, the operator concluded that a fundamentally different approach was required — leading to the evaluation of Polymer Dispersed System (PDS) technology.
Polymer Dispersed System (PDS) Technology
The PDS technology involves alternating injections of an aqueous polymer solution and a dispersed suspension. These components form polymer dispersed aggregates within the pore space, preferentially in high-permeability layers. The mechanism includes:
- Adsorption of polymer macromolecules onto rock surfaces
- Retention of dispersed particles in large pores
- Formation of stable aggregates that reduce flow in high-permeability zones
- Redistribution of flow to lower-permeability, oil-saturated zones
Unlike conventional gels and resins, PDS is a self-regulating system. As the polymer solution flows deep into the reservoir and polymer is adsorbed by the rock, the solution turns from a stabilizer into a flocculant — ensuring more uniform distribution of dispersed particles in the target zones.
Laboratory studies using NMR confirmed that PDS reduces the volume of large flowing pores and increases flow contribution from small pores, improving sweep efficiency.
Treatment Operations
Two PDS treatments were performed in the same injection well during a single calendar year.
Treatment 1
- Pre-flush: 283 bbl of process water
- Initial injectivity: 2,264 bbl/day at zero pressure
- Five cycles of alternating polymer and dispersed particle batches
- Sixth cycle: polymer + crosslinker, squeezed with 189 bbl of process water
- Total PDS solution volume: 7,000 bbl
- Total injected volume (including water): 8,114 bbl
- Injection pressure increased gradually from 0 to 1,160 psi, then stabilized
- Final injectivity: 2,113 bbl/day at 1,407 psi
Treatment 2
- Pre-flush: 252 bbl of process water
- Initial injectivity: 2,585 bbl/day at zero pressure
- Five cycles of alternating batches
- Squeezed with 189 bbl of process water
- Total PDS solution volume: 6,290 bbl
- Total injected volume: 7,183 bbl
- Injection pressure gradually increased to 1,131 psi
- Final injectivity: 1,811 bbl/day at 1,189 psi
Results: Reversing the Negative Trend
After First Treatment
The first PDS treatment began to reverse the negative trend:
- Oil production rate increased by 129 bbl/day
- Water cut decreased by 14% in the area
- Positive response observed in two highly watered wells (A and B)
Well A (initial water cut 84% — critical condition):
- Water cut reduced to 60.3% (1 month) and 66.3% (2 months)
- Oil rate increased from 33 to 75 bbl/day
Well B (initial water cut 66.9%):
- Water cut reduced to 25.3% (1 month) and 31.8% (2 months)
- Oil rate increased from 160 to 294 bbl/day
- Effect lasted 2–3 months
After Second Treatment
The second treatment delivered an even stronger reversal:
- Oil production rate increased by 450 bbl/day
- Water cut decreased by 16% in the area
- Positive response in all five previously watered wells
Well B:
- Water cut reduced from 61% to 36% (immediate) and 28% (1 month)
- Oil rate increased from 233 to 414 bbl/day, sustained for 3 months
Well C (initial water cut 78.5%):
- Water cut reduced to 70.9% (immediate) and 46.8% (1 month)
- Oil rate increased from 83 to 359 bbl/day, sustained for 3 months
Well D (initial water cut 82%):
- Water cut reduced to 67.3% (2 months) and 24% (3 months)
- Oil rate increased from 17 to 95 bbl/day, sustained for 4 months
Well E (initial water cut 72.9%):
- Water cut reduced to 56% (immediate) and 46.1% (1 month)
- Oil rate increased from 29 to 58 bbl/day, with continued increase over 2 months
Cumulative Benefits
Over a period of 13 months following the first treatment, the test area achieved:
- Incremental oil production: 76,425 bbl
- Reduced water production: 39,940 bbl
These figures represent oil that would otherwise have been left in place — and water that would otherwise have been produced, treated, and reinjected at significant cost.
Economics & Value Created
What Would Have Happened Without Treatment?
Without treatment: water cut in the most affected wells would have remained at 84–88% or deteriorated further, with no mechanism for self-correction.
Value Created After PDS Treatment (13 months)
| Benefit Item | Value |
|---|---|
| Incremental oil revenue (76,425 bbl × $75/bbl) | $5,731,875 |
| Reduced water handling (39,940 bbl × $5/bbl) | $199,700 |
| Total gross benefit | $5,931,575 |
Investment & ROI
| Item | Value |
|---|---|
| Estimated PDS treatment cost (two treatments) | ~$500,000 |
| Net benefit | ~$5,431,575 |
| ROI | ~11.6x (1,160%) |
| Payback period | ~1 month |
Key Takeaways
- Every $1 invested returned nearly $12 in net value
- Payback in the first month after treatment
- Revenue increased AND water handling costs decreased
- Turned a financially threatened asset into a profitable operation
Conclusions
The PDS technology successfully addressed the negative consequences of water breakthrough in this heterogeneous carbonate reservoir — where conventional chemical technologies had previously failed:
- Stopped the water conduit – Reduced injectivity and increased injection pressure, confirming successful reduction of hydraulic conductivity in fractures and high-permeability zones.
- Reversed production decline – Significant water cut reduction from 84–61% down to 66–24% in responding wells.
- Rapid economic response – Typically within 1–2 months after treatment.
- Repeatable and scalable – Stronger effect after the second treatment, with more responding wells and longer-lasting results (up to 5+ months).
- Superior to conventional methods – Unlike polymer gels, silicates, and resins that failed in this field, PDS delivered sustainable, measurable results.
- Exceptional economics – ~$5.9 million gross benefit, ~$5.4 million net benefit, ROI > 1,100%, payback < 1 month.
- Transferred negative to positive – Turned a financially threatening water breakthrough situation into a profitable incremental oil recovery project.
This case study confirms that Polymer Dispersed Systems can effectively and selectively block high-permeability zones and fractures in carbonate reservoirs — directly addressing the root cause of premature water breakthrough where conventional technologies have failed, and delivering exceptional economic returns.