Field Results & Case Studies
Historical results are presented as reported in source records, not as independently verified modern performance. Programs are not pooled statistically because baselines, monitoring methods, geology and treatment designs differ. The 2026 North African pilot is treated separately as the strongest current proof of concept.
2026 Field Validation
North African Sandstone Well
A mature conventional sandstone well produced a 67.9% higher 90-day average oil rate, a 59.2% lower average produced-water rate, and approximately 12,018 incremental barrels of oil during the monitored period. The treatment used existing wellhead and production infrastructure.
Well Parameters
Original Drill Date
November 1964
Total Depth
2,767 ft
Target Reservoir
Oligocene Sandstone
Porosity
~30%
Permeability
~600 md
Oil Gravity
32.1° API
Bottom-Hole Temperature
~121°F
Artificial Lift
ESP
90-Day Production Performance
Metric
Pre-Treatment
90-Day Post-Treatment
Change
Oil Production
196.7 BOPD
330.2 BOPD
+133.5 BOPD / +67.9%
Produced Water
134.7 BWPD
54.9 BWPD
-79.8 BWPD / -59.2%
Total Fluid
331.4 BFPD
385.1 BFPD
+53.7 BFPD / +16.2%
Water Cut
40.6%
14.3%
-26.4 points
Oil-to-Water Ratio
1.46:1
6.01:1
~4.1× improvement
The first post-treatment test came in at 304 BOPD, already about 54% above the accepted baseline average. Oil peaked at 444 BOPD on May 4, then declined toward the pre-treatment range by late June, with a final test of 268 BOPD. The full response curve, not the peak, is what should drive economics and retreatment decisions. Produced water showed a persistent decline through the same period: the final test on June 25 reported 36 BWPD and a 12% water cut, compared with 187 BWPD and 42% water cut in the final pre-treatment test.
Illustrative 90-Day Economics
~12,018 bbl
Incremental Oil
~$901,350
Gross Incremental Revenue at $75/bbl
~$851,350
Net Value Above an Illustrative $50,000 Intervention Cost
~18×
Revenue-to-Cost Multiple
~$4.16/bbl
Intervention Cost per Incremental Barrel
~5 Days
Illustrative Gross Payout (~10 Days at 50% Netback)
The PEMEX, Trinidad, and U.S. field records below are historical and come from the initial work done using the Ultra-MEOR® technology, in the late 1980s–1990s. This is the same technology and protocol that we have successfully reintroduced to the market in 2026. They are evidence for the underlying technology’s track record across different fields and decades.
Historical Program · Mexico
PEMEX Tamaulipas-Constituciones, 20 Wells
At the July 1996 post-treatment measurement snapshot, combined net oil production across 20 wells increased from approximately 446.6 to 874.3 BOPD, a gain of approximately 427.7 BOPD or 95.8%. Fifteen of 20 wells increased oil production, three were unchanged, two declined, and two previously nonproducing wells were restored to oil production.
20
Wells Evaluated
446.6 → 874.3 BOPD
Aggregate Net Oil
+95.8%
Field-Level Oil-Rate Increase
15 of 20
Wells With Increased Oil
3
Unchanged
2
Declined
2 Wells
Reactivated From Zero Net Oil (~132 BOPD Combined)
~ -0.05
Correlation Between Well Depth and Oil-Rate Change (Essentially None)
The response was broad but not uniform: the five largest-gaining wells supplied about 75% of the total field gain, and the top eight supplied about 92.6%. The median well gained about 12.6 BOPD while the mean gain was about 21.4 BOPD, meaning a few strong responders drove much of the value without the program depending on a single well.
This was not a field-wide water-reduction case. Aggregate water cut increased modestly, from about 31.1% to 33.8%, and individual wells behaved differently: some saw water cut fall as oil increased, while others saw both oil and water increase together.
Public depth records and representative field stratigraphy show the 20 wells span a mixed Jurassic reservoir section, including carbonate-rich intervals (Pimienta, San Andrés platform carbonate), sandstone, and basal clastics.
Historical Program · Trinidad
Trinidad, 13 Wells
A historical Trinidad program reported approximately 29,000 incremental barrels across 13 wells over 18 months, a commercially relevant result because it reflects multiwell use rather than a single-well or laboratory experiment.
Later Petrotrin work questioned whether the response could be separated conclusively from stimulation of indigenous reservoir organisms already present in the reservoir. A subsequent Petrotrin MEOR experiment designed to stimulate only the indigenous organisms, using an engineered nutrient package with no Ultra-MEOR consortium, had fewer positive results, with increased oil performance in less than half of its wells. That comparison suggests the Ultra-MEOR program had a more far-reaching impact than indigenous stimulation alone, which highlights the impact of the total Ultra-MEOR package, with all three components plus the validated protocol showing increased response versus using just a portion of the technology.
Historical Program · United States
Additional U.S. Government-Supported Field Applications
Historical work in the U.S. is important because it spans multiple separate field applications rather than one demonstration.
Application
Oil Response
Duration / Other Result
Evidence Note
South Texas Clastic Lease 1
~+27%; 474 bbl incremental
Reportedly persisted at least 15 months
Government-supported historical field record
South Texas Clastic Lease 2
~+22%; 213 bbl incremental
Positive lease response with observed microbial movement
Government-supported historical field record
South Texas Clastic Lease 3
~+27%; 474 bbl incremental
Positive lease response
Source document repeats Lease 1’s figures for this entry; shown as reported
Illinois Modified Waterflood
+41%; 2,212 bbl incremental
~12-13 BOPD above expected for roughly 10 months
Government-supported historical field record
Operators in the South Texas applications also reported reduced paraffin-related maintenance after treatment. That observation was qualitative in the source record and is not represented here as a quantified paraffin-removal result.
What the Combined Record Shows
Positive and negative results occurred even when microbial activity was confirmed present, which makes candidate selection a central technical requirement rather than an optional refinement. The historical and modern record points to a consistent set of predictors worth evaluating before any field application:
- Connected remaining oil
- Completion condition and placement quality
- Injectivity and reservoir connectivity
- Oil and water properties and chemistry compatibility
- Water-flow behavior
- The nature of the production constraint
See the Mechanisms Behind These Results
Review the system and field protocol, or submit a well for a preliminary evaluation.