Silent Fracture Damage: A Case Study from the West Rustavi Field, Georgia
WR-B01A, a horizontal sidetrack targeting the Middle Eocene naturally fractured reservoir in the West Rustavi field, Georgia, produced significantly less than expected after drilling was complete. The drilling logs showed no significant circulation losses. The mud programme was considered conventional. A post-drilling acid treatment with 15% HCl failed to restore productivity. By the time the well was tested, the damage was irreversible and its cause unexplained.
Block Energy PLC engaged WellSoft to find out why.
The Formation
The Middle Eocene at West Rustavi is a tuffaceous volcanic formation with virtually no matrix permeability. Every barrel of production comes from natural fractures. In reservoirs like this, protecting fracture conductivity during drilling is not a best practice. It is the entire game. Once a fracture is plugged by drilling fluid, it does not produce, regardless of what the reservoir engineer plans for it.
What the Mud Programme Looked Like
The sidetrack used a fresh water and polymer-based system. Calcium carbonate (Calcarb grades) was the primary weighting material, raising mud density from 1.15 to 1.20 sg. Because CaCO₃ also functions as a bridging agent, WellSoft modelled this secondary role in the simulation. However, the Calcarb 25 and 50 grades used for weighting bridge only the smallest fractures (0.05 to 0.15 mm aperture). Fractures wider than approximately 0.20 mm, which includes the most productive fractures in the reservoir, received no coverage.
There was also a deliberate operational decision: CaCO₃ concentration was kept low in order to monitor circulation losses at surface and identify where the productive fractures were. It is a logical concept. The simulation shows it was, in practice, impossible to execute without damaging the reservoir in the process.
If There Was No Barite, What Damaged the Fractures?
This is the question reservoir and drilling engineers most frequently ask when they encounter a case like WR-B01A. If the mud contained only fresh water and polymers, what actually plugged the fractures?
The answer is the drilling cuttings. As the bit grinds through tuffaceous volcanic rock, it continuously generates fine particles. Baker Hughes, the drilling fluids contractor on this well, documented a measured solids removal efficiency of only 62% for the WR-B01A section. This means 38% of generated cuttings were not removed at surface and were instead recirculated downhole. Each recirculation pass through the bit, pump impellers, and drill string reduces particle size further.
When these fine recirculated cuttings encounter a natural fracture, they are forced into it by the overbalance pressure gradient. Inside the fracture, they combine with the polymer additives in the mud to form a composite filter cake. Unlike a CaCO₃ bridge, which is fully soluble in hydrochloric acid, this cuttings-polymer composite is not acid-soluble and cannot be displaced by flow reversal. WellSoft presents this as the most plausible mechanism explaining both the severity of the formation damage and the failure of the acid treatment. The fractures were not bridged with material that could be dissolved. They were filled with material that could not.
The Silent Damage Problem
Perhaps the most important finding from the simulation is this: the worst damage left no surface signal at all.
WellSoft’s analysis shows that micro-fractures with apertures of 0.01 to 0.10 mm sealed within a median of 9.9 seconds of being opened by the drill bit. These events generated no measurable change in pit volume, no flow rate anomaly, and no visible loss event at surface. The reservoir was being damaged continuously and silently throughout drilling.
By the time the 3 m³ loss event appeared at 2,426 m MD and CaCO₃ was reactively added, the bulk of the micro-fracture population had already been permanently plugged. The reactive LCM protected the fractures encountered after that depth, but could not recover the damage already sustained. The monitoring strategy intended to find the productive zones actually ensured that protection arrived after most of the damage was done.
What the Simulation Found
WellSoft modelled three scenarios using the WDS Naturally Fractured Reservoir (NFR) simulator: the initial drilling phase with no bridging LCM active (Section 1), the reactive Calcarb 25/50 phase following the detected loss event (Section 2, base case), and the fully optimised WellSoft programme. Monte Carlo analysis across 4,000 realisations per scenario propagated geological and operational uncertainty through the physics to produce full probability distributions for Productivity Index (PI).
| Metric | Base Case (Section 2) | WellSoft Optimised |
|---|---|---|
| P50 PI (median outcome) | 0.43 bbl/d/psi | 0.50 bbl/d/psi (+16%) |
| P90 PI (high upside case) | 13.79 bbl/d/psi | 54.70 bbl/d/psi (+4×) |
| Blockage success, fractures > 0.50 mm | 0% (Sections 1 and 2) | 80% |
| Max invasion depth (Section 1) | 39.7 cm | 0.01 cm |
The numbers tell a precise story. The wide fractures, those with apertures above 0.50 mm, received zero protection from the as-drilled programme in both Section 1 and Section 2. These are the highest-conductivity fractures in the reservoir, and they were left completely undefended. The optimised programme bridges 80% of them. At the P90 level, where those fractures dominate the PI outcome, the improvement is a factor of four.
What Good Looks Like
The optimised programme requires four changes, all within standard drilling practice:
- Proactive four-grade CaCO₃ LCM from first reservoir contact: Fine (20%, 25 to 75 μm), Medium (30%, 75 to 250 μm), Coarse (35%, 250 to 600 μm), and Extra-Coarse (15%, 600 to 1,000 μm). This covers fracture apertures from 0.05 mm to 1.0 mm and replaces the loss-monitoring strategy with a proactive protection strategy.
- Optimised rheology: Plastic Viscosity maintained at 10 to 15 cP at downhole temperature, and Yield Point kept within 10 to 15 lb/100 ft². The WR-B01A sidetrack recorded Yield Points up to 45 lb/100 ft² at peak. High fluid viscosity amplifies fracture damage once invasion begins, as confirmed by the sensitivity analysis. Irreversible polymer additives such as Him-PAC LV should not be used in the reservoir section.
- LWD-based reservoir identification: High-definition borehole imaging, real-time formation pressure measurement, and advanced sonic analysis identify productive zones with precision, without requiring surface loss events and without sacrificing reservoir protection.
- Controlled overbalance: Static overbalance of 3 to 5% above pore pressure, with a hard ceiling of 8% under circulating conditions. Overbalance is the driving force for all fracture invasion. Controlling it tightly, combined with the proactive LCM programme, eliminates most of the damage risk.
The Broader Implication
The WR-B01A case is not an outlier. It is a well-documented example of a damage pattern that affects naturally fractured reservoirs across multiple basins and lithologies. The combination of polymer-based fluids, inadequate solids control, overbalance, and reactive LCM strategy is common. The resulting damage, characterised by silent micro-fracture plugging followed by limited response to acid treatment, is also common. What is less common is having a quantitative model that explains it.
WellSoft worked with Block Energy PLC to deliver this analysis for the West Rustavi field. The simulation is now calibrated to the Middle Eocene fracture network and will improve in precision with every additional well drilled in this structure.
Work With WellSoft
If you are planning a well in a naturally fractured reservoir and want to understand the formation damage risk before the bit enters the reservoir, we welcome a conversation. Physics-based simulation runs before the well is drilled, not after productivity is lost.