Ann: Cuba Block 9 Update, page-137

Estimating the production rates and likelihood of success for the reworked well requires integrating data on reservoir performance, formation properties, and treatment effectiveness. While detailed reservoir modeling would provide the most accurate estimate, a qualitative and semi-quantitative approach can give a reasonable forecast based on the information provided:

---

### **Key Considerations:**
1. **Initial Production Decline:**
- The production fell from **1200 to 200 bopd** during the extended test, indicating potential damage from the drilling mud and/or completion inefficiencies. Overweight mud is known to cause near-wellbore damage, especially in carbonate formations, which could reduce permeability significantly.

2. **Increased Perforated Interval:**
- Initially, only **20% of the net pay (70m)** was perforated. Reworking to perforate the remaining **80% (280m)** increases the open interval by a factor of **4**. In theory, this could proportionally enhance production if permeability and pressure are uniform throughout the formation.

3. **Acid Wash and Squeeze:**
- Acidizing carbonate formations is typically highly effective, as the acid reacts with calcite to dissolve damage and create wormholes, enhancing permeability. This treatment will:
- Remove drilling-induced damage.
- Potentially improve connectivity with the formation.

4. **Formation and Oil Properties:**
- The oil has a **19°API**, suggesting a medium-heavy crude that might have higher viscosity, potentially limiting flow rates.
- Carbonate reservoirs often have heterogeneous permeability, which could influence production enhancement.

5. **Challenges from Cement Behind Liner:**
- Cement presence behind the liner in the lower 20% of the net pay (1850–1920m) might limit acid effectiveness or further restrict flow from this interval. However, the **shallower 80%** is free of this issue, and acid treatment there is expected to yield better results.

---

### **Production Estimate:**
To estimate the post-treatment production rate, we consider:
- **Perforation Factor:** Increasing the perforated interval by 4x could increase flow if all other conditions remain favorable.
- **Damage Removal Factor:** Acidizing can restore or enhance near-wellbore permeability. For damaged carbonate reservoirs, production improvements of **2–10x** are reported depending on damage severity and treatment quality.
- **Decline Factor:** The initial production decline indicates reduced reservoir deliverability or possible depletion of the perforated interval. However, with increased perforations and acid stimulation, this effect might be mitigated.

#### Estimated Post-Treatment Flow Rate:
Assuming:
- 4x increase due to perforation (280m / 70m).
- 2–5x enhancement due to acid treatment (moderate to high success).

The estimated production rate could range from:

\[
\text{Expected Rate} = 1200 \, \text{bopd} \times 4 \times (2 \, \text{to} \, 5) = 9600 \, \text{to} \, 24000 \, \text{bopd}.
\]

Realistically, considering formation heterogeneity and challenges:
- Likely range: **4000–8000 bopd**.

---

### **Likelihood of Success:**
The success depends on:
1. **Acid Treatment Efficiency:**
- High carbonate reactivity suggests good acid effectiveness if properly executed.
- Acid penetration depth might be limited by formation heterogeneity.

2. **Reservoir Pressure and Fluid Mobility:**
- If the reservoir pressure is still sufficient and the oil mobility is not heavily impaired by viscosity, the acid treatment should significantly boost flow.

3. **Uncertainties:**
- Cement behind the liner may hinder flow improvement from the lower 20%.
- Overweight mud might have caused deeper damage that acidizing alone cannot resolve.

**Probability of significant success:** ~70–80%, assuming competent execution and favorable formation properties.

---

### **Conclusion:**
Following the rework, the well could produce between **4000–8000 bopd**, potentially higher if acidizing significantly enhances permeability. The likelihood of a marked improvement is high, provided operational execution is optimal, and formation heterogeneity is managed.