GreenZyme in Kuwait's Burgan Field: Confirmed Well Treatment Results

In 2019, BTP-GreenZyme was engaged to evaluate and treat candidate wells in the Burgan field, one of the largest oil fields in the world.

The program followed our standard process: systematic well screening and ranking, followed by GreenZyme treatment on the strongest candidates.

Candidate selection

Through mid-to-late 2019, BTP evaluated 11 wells in the Burgan field against production history, water cut trend, and well-log data. Two were screened out — one flagged high-risk after water cut climbed toward 90–100%, the other disqualified on well-log review. The remaining candidates were carried forward, and three were ultimately selected for treatment based on their production potential.

The reservoir problem and well context

All three candidates sit in the Burgan field's sandstone reservoirs. The underlying problem is a familiar one in mature sandstone fields: years of water encroachment and production have left oil bypassed in swept zones, held in place by capillary forces rather than a lack of oil in the ground. Water cut climbing toward 65–70% on these wells is the clearest signal of that — the reservoir has plenty of remaining oil saturation, but conventional lift alone cannot mobilize it. This is precisely the mechanism GreenZyme targets: reducing the capillary forces trapping that bypassed oil so it can flow to the wellbore.

Well and reservoir characteristics, from each well's own candidate-selection data:

• BG-1071 — BGSU sandstone layer, drilled 2005, deviated and cased, total depth 5,100 ft MD with the producing formation at 4,390 ft MD. Porosity 0.5, permeability 200 md, residual oil saturation 0.3, connate water saturation 0.2. Reservoir pressure 1,950 psi and temperature 133°F at initial conditions. Oil viscosity 1.52 cp with a reservoir-condition oil density of 0.767 g/cm³. Pre-treatment water cut of roughly 65%.

• BG-0875 — Producing from the Wara formation (Upper Wara at 4,389 ft MD, Lower Wara at 4,534 ft MD), a vertical, cased and perforated well with a total depth of 4,950 ft MD, on ESP lift. Reservoir temperature 135°F. Its Jan-2019 portable test showed a water cut of roughly 70% ahead of treatment. Porosity and permeability were not captured in this well's candidate-selection sheet, unlike the BGSU-layer wells.

• BG-1122D — Also BGSU sandstone, drilled 2015, deviated and cased, total depth 5,015 ft MD with the producing formation at 4,761 ft MD (perforated across six intervals between 4,761 and 4,854 ft). Porosity 0.5, permeability 600 md — the most permeable of the three — with the same residual oil saturation (0.3) and connate water saturation (0.2) as BG-1071. Reservoir pressure 1,950 psi and temperature 132°F, oil viscosity 1.52 cp, reservoir-condition oil density 0.767 g/cm³. Pre-treatment water cut of roughly 65%.

Oil API gravity: the candidate-selection sheets for these wells did not record a surface (stock-tank) oil density, so no well-specific API figure is available internally. Published field literature puts the Greater Burgan field's crude in the 28° to 35° API range, classifying it as medium-to-light — consistent with the low reservoir-condition oil density (0.767 g/cm³) and low viscosity (1.52 cp) recorded for these wells.

Treatment and results

All three treated wells showed strong production gains:

• BG-1071, treated in December 2019 using the BTP multi-batch injection method — splitting the GreenZyme mixture into portions with produced-water displacement between each batch. Production rose from a baseline of roughly 800 BOPD to a peak of approximately 1,024 BOPD — a 28% increase.

• BG-0875, treated in January 2020 using a huff-and-puff injection and mixing procedure developed by the BTP team specifically for the Burgan field. Production rose from a baseline of roughly 252 BOPD to a peak of approximately 325 BOPD — a 29% incremental gain, equivalent to 73 barrels per day.

• BG-1122D, treated in September 2019 via coiled tubing (1 IBC of GreenZyme mixed to a 5% concentration, roughly 105 barrels total volume, with an optional heat step and a 4-day soak). Production rose from a baseline of roughly 1,191 BOPD to a peak of approximately 1,548 BOPD — a 30% increase.

What this means over time

Applying a standard, conservative production decline curve to each well's confirmed peak, the three treatments together are projected to add roughly 183,000 barrels of incremental oil across a 12-month window — production that would not have been recovered without treatment. This 12-month framing is the standard planning horizon operators use to evaluate a treatment's return, and it's a deliberately conservative one: field observations across GreenZyme applications have shown the treatment's effect on a well can persist considerably longer, in some cases up to 36 months, meaning the true value of a single treatment cycle may extend well beyond the first-year numbers operators typically plan against. This same effect is documented in wells treated in Venezuela, Colombia, Argentina, China to name a few cases.

Why this matters

Burgan is a legacy field with declining, high-water-cut wells — exactly the setting where GreenZyme's enzyme catalyst mechanism (releasing bypassed oil trapped by capillary forces in swept zones) is designed to help. Three independently treated wells in the same Kuwait field program, all landing in the high-20s-to-30% production increase range, is a strong and consistent result for a technology with limited public field documentation anywhere in the world.