Why High BHP Drawdown Is Not Always Good?

First of all, it is better to have a review of the concept of skin and formation damage and then move on to examining bottomhole pressure (BHP) drawdown.

Differences Between Skin and Formation Damage

“Skin” and “Formation Damage” are related but different concepts in well performance analysis. Here’s a clear breakdown of their differences, effects on well productivity, and impact on bottomhole pressure (BHP) drawdown.

1. Definition and Causes

Skin: A dimensionless number representing near-wellbore flow resistance.

Formation damage: A physical or chemical impairment of the formation near the wellbore.

Skin is derived from pressure transient analysis (PTA) and formation damage is inferred from skin and core/log data.

Causes of skin (most common):

• Partial penetration
• Incomplete perforations
• Turbulence (gas wells)
• Well geometry effects

Causes of formation damage (most common):

• Fines migration
• Mud invasion
• Clay swelling
• Scale deposition
• Asphaltene/wax buildup

PTA Interpretation:

• S < 0 → Stimulated well (e.g., acidizing, fracturing).
• S = 0 → No damage/stimulation.
• S > 0 → Formation damage or completion issues.

2. Impact on Well Performance

q = (k*h*dp) / [Bo*muo*(ln(re/rw)-0.75+S)]

PI = q / (Pres – Pwf) = (k*h) / [Bo*muo*(ln(re/rw)-0.75+S)]

Identifying wells with (+) skin due to damage is the first step to improving well deliverability.

2.1. Effect on Productivity Index (PI):

• Higher (+) skin → Lower PI
• Negative (-) skin → Higher PI
• Formation damage reduces PI due to permeability impairment

2.2. Effect on BHP Drawdown (ΔP):

Drawdown is the pressure difference needed to sustain production.

• Higher skin → More ΔP needed for same flow rate
• Formation damage increases ΔP due to restricted flow

According to Darcy’s Law, increasing pressure drawdown increases the flow rate (For example, when we increase the choke size, we are actually increasing the flow rate by increasing the bottomhole pressure drop). But here’s the engineering insight: Why high drawdown is not always good?

• Risk of Formation Damage (Near-wellbore): High drawdown can pull fine particles, water, or gas from the formation into the wellbore.
• Reservoir Depletion Acceleration: High drawdown can deplete the reservoir locally near the wellbore faster than oil can flow in from farther away.
• Sand Production Risk: In unconsolidated or weak formations, high drawdown can cause sand production.
• Efficiency and Economic Tradeoff: High flow rates = higher short-term cash flow, but optimizing drawdown is essential to maximize cumulative production, not just initial rates.

Instead of maximizing drawdown (Drawdown Management):

• Monitor PI trends over time
• Apply controlled drawdown strategy: Gradual ramp-up of production / Monitor water and gas breakthrough / Maintain pressure support (e.g., water injection)
• Use nodal analysis to find the optimum drawdown for each well

High BHP Drawdown in Some Wells

Some wells in the Middle East are experiencing high drawdown (1500 to 3500 psi). Below are the key reasons for such high drawdowns, along with diagnostic methods and potential solutions.

1. Main Causes of High Drawdown:

A. Formation Damage (High Positive Skin, S > 0): It is the major contributor to excessive ΔP in many carbonate reservoirs.

Causes:

• Mud invasion during drilling/completion.
• Fines migration (clay swelling, particle plugging).
• Scale deposition (CaCO₃, CaSO₄, BaSO₄).
• Asphaltene/wax precipitation (common in heavy oilfields).

Effect: Reduces near-wellbore permeability → higher ΔP needed to sustain flow.

B. Low Reservoir Permeability (Tight Carbonates)

Low k → Higher ΔP required for same flow rate.

C. Partial Perforation or Poor Completion

• Partial perforation (not all zones open).
• Inadequate perforation density (few shot per foot, about 6 SPF).

Effect: Increases mechanical skin (S) → Extra ΔP needed.

D. High-Viscosity Oil (Heavy Crude)

Some fields produce heavy oil (high μ). Higher viscosity oil → More resistance to flow → Higher ΔP.

E. Turbulence in High-Rate Wells (Gas or High-GOR Oil)

• For gas wells or high-GOR oil producers, turbulence near wellbore adds non-Darcy skin (Dq).
• S_total = S + Dq : High rates → Dq dominates → Extreme ΔP.

2. Diagnosing the Root Cause of High Drawdown

Step 1: Pressure Transient Analysis (PTA)

• Buildup/drawdown tests → Estimate skin (S) and permeability (k).
• High S (>10) → Formation damage.
• Low k (<10 mD) → Tight reservoir.

Step 2: Production Logging (PLT)

• Identifies which zones are contributing.
• Detects partial perforation or uneven flow.

Step 3: Fluid & Core Analysis

• Scale/wax/asphaltene lab tests.
• Core permeability vs. well test permeability (damage assessment).

Step 4: Compare Historical Data

• Increasing ΔP over time? → Growing damage.
• Sudden ΔP jump? → Scale, asphaltene, or water breakthrough.

3. Solutions to Reduce Drawdown