An advanced visco-elastic diversion system designed for surface bullhead stimulations in both vertical and horizontal wells. DVG™ temporarily blocks high-permeability pathways, directing stimulation fluids to more damaged or lower-permeability reservoir sections - enhancing acid placement, improving stimulation efficiency, and optimizing hydrocarbon recovery.
Bullhead DVG™ Jobs Since Inception - With Thousands of M³ Pumped
Peak Production Increase - Pierson Field Case Study
Day Flash Payout - 4× Faster Than Mechanical Isolation
In most reservoirs, stimulation fluids follow the path of least resistance - flowing into high-permeability thief zones while bypassing the damaged intervals that require treatment. Solid diverters (rock salt, benzoic flakes, bio-balls) settle by gravity and fail to conform to the liner, leaving gaps in horizontal wells where coverage matters most.
STIMWRX DVG™ eliminates the need for high-rate, high-cost equipment to achieve MAPDIR delta P in bullhead treatments. By viscosifying the fluid itself, DVG™ controls leak-off and enables diversion at lower pump rates without turbulent flow - while also sweeping directional traps in horizontal laterals to prevent sand buildup at the heel.
DVG™ is a true fluid-phase diverter. Unlike solid agents that migrate toward the heel in horizontal wells, DVG™ conforms perfectly to the liner and formation to deliver total, uniform coverage regardless of wellbore orientation.
By blocking the path of least resistance, DVG™ forces stimulation fluids into the most damaged, lowest-permeability intervals deep within the reservoir - addressing the root cause of underperformance.
Engineered to revert to a water-thin state at reservoir temperature. Zero interference with production equipment and no residual formation damage after treatment is complete.
Treatments are performed with pumps, rods, and tubing anchors in place. No workover rig. No coiled tubing unit. Operational cost reduced by up to 75% vs. mechanical isolation.
Head-to-head across the eight performance criteria that directly impact stimulation economics and reservoir coverage.
| Solid Diverters Rock Salt / Benzoic / Bio-Balls |
DVG™ Visco-Elastic System StimWRx Proprietary |
|
|---|---|---|
| Wellbore Conformance | Settles by gravity; limited coverage in horizontal wells | Fluid-phase - total conformance regardless of orientation |
| Pump Rate | High rates required to keep solids in suspension | Effective at low pump rates; no suspension risk |
| Break Mechanism | Solubility-dependent - variable, environment-sensitive | Temperature-triggered; predictable 2-3 hr break at 50-80°C |
| Residual Damage | Undissolved solids can plug pore throats post-treatment | Reverts to water-thin state; zero residual formation damage |
| Rig Requirement | Often requires workover rig or coiled tubing for placement | Fully rigless bullhead application |
| Horizontal Wells | Poor - solids migrate toward heel, leaving toe untreated | Uniform coverage heel-to-toe; conforms to full lateral |
| On-Pad Logistics | Specialized handling and mixing equipment required on site | Pre-mixed, pad-ready - bulk or tote delivery, no mixing equipment |
| Relative Cost | High (rig day rates, coiled tubing mobilization) | Up to 75% lower cost vs. mechanical isolation |
Amaranth Formation - Cemented Liner
A horizontal well experienced declining production, primarily due to near-wellbore scale buildup restricting flow. In 2021, a selective stimulation was performed at the operator's request, but production began to decline again. Two core problems were identified:
Uneven Acid Placement: Stimulation fluids followed the path of least resistance, bypassing damaged and lower-permeability sections.
High Workover Costs: Traditional clean-out methods such as coiled tubing interventions increased operational costs and downtime.
STIMWRX prescribed an annular bullhead treatment using DVG™ to improve acid placement and maximize treatment effectiveness - without the need for a workover rig.
Download DVG™ Brochure →Daily production surged from 3 bbl/d to 44 bbl/d - a 13.7x increase. Peak IP1 of 47 bbl/d outperformed the previous high-cost selective method.
The treatment paid for itself in just 17 days - 4× faster than the traditional mechanical isolation approach that preceded it.
By eliminating the workover rig and coiled tubing unit, the treatment delivered the same result at 75% lower operational cost.
Achieved a peak initial production rate of 47 bbl/d - exceeding the operator's prior best result of 40 bbl/d with high-cost selective stimulation.
Our technical team will review your well's decline profile, formation characteristics, and fluid chemistry to determine whether DVG™ is the right solution - and model the expected payout timeline before a single barrel is pumped.