JNTU B.Tech IV RESERVOIR STIMULATION Previous Question Paper (July - 2021 - R15)

Candidate selection for reservoir stimulation is a systematic process aimed at identifying wells that are underperforming compared to their potential and determining if stimulation can economically enhance their productivity. The process involves two primary phases: identifying low-productivity wells and evaluating potential mechanical or reservoir-related constraints.

The identification phase relies on comparing actual well performance against theoretical potential. This is achieved by analyzing production history, decline curve analysis, and nodal analysis. Wells are flagged if their current inflow performance relationship (IPR) is significantly lower than the expected IPR based on offset well data or reservoir simulation models. Key indicators include a high skin factor, which suggests near-wellbore damage, or a low productivity index compared to the reservoir permeability and thickness.

Once a candidate is identified, the evaluation phase focuses on diagnosing the cause of underperformance. This involves:

• Mechanical Integrity Assessment: Verifying the condition of the casing, tubing, and packers to ensure the well can withstand the pressures and fluids associated with stimulation treatments.
• Damage Diagnosis: Distinguishing between skin damage (e.g., fines migration, scale, or paraffin deposition) and reservoir-scale limitations (e.g., low reservoir pressure or poor connectivity). This is often done using pressure transient analysis (PTA) to determine the skin factor and reservoir permeability.
• Fluid Compatibility: Evaluating whether the proposed stimulation fluids will react negatively with the formation rock or existing fluids, which could lead to further damage.
• Economic Feasibility: Calculating the incremental production gain versus the cost of the stimulation treatment. This requires estimating the post-stimulation productivity increase and the expected payout period.

Ultimately, the goal is to ensure that the stimulation treatment addresses the specific bottleneck—whether it is a restricted flow path near the wellbore or a low-permeability zone—thereby maximizing the return on investment and extending the economic life of the well.

Rock mechanical properties are fundamental parameters that dictate how a reservoir formation responds to hydraulic fracturing and stimulation treatments. These properties determine the stress state, fracture initiation pressure, fracture propagation geometry, and the ability of the formation to contain the fracture.

The primary rock mechanical properties measured include:

• Young's Modulus (E): A measure of the rock's stiffness. Higher values indicate brittle rock that is easier to fracture but harder to keep open, while lower values indicate ductile rock that may require higher pressures for fracture initiation.
• Poisson's Ratio (ν): The ratio of lateral strain to axial strain. It is critical for calculating the minimum horizontal stress, as it influences the stress contrast between layers.
• Unconfined Compressive Strength (UCS): The maximum axial compressive stress a rock can withstand before failure. It is used to predict the breakdown pressure.
• Fracture Toughness (K_Ic): A measure of the rock's resistance to fracture propagation. It defines the energy required to create new fracture surfaces.

These properties are typically measured through laboratory testing of core samples (triaxial compression tests, sonic velocity measurements) or derived from wireline logging data (acoustic logs, density logs). The applications of these measurements in stimulation include:

• Fracture Design and Modeling: Accurate inputs for 3D hydraulic fracturing simulators, allowing for the prediction of fracture height, length, and width.
• Stress Profiling: Determining the minimum horizontal stress (σ_hmin) across different lithological layers to identify potential fracture containment barriers or zones of high stress that might arrest fracture growth.
• Completion Strategy: Assisting in the selection of perforation intervals and the design of proppant schedules. Rocks with high brittleness (high Young's modulus and low Poisson's ratio) are often targeted for stimulation as they tend to create more complex, conductive fracture networks.
• Wellbore Stability: Predicting the risk of sand production or wellbore collapse during the drawdown associated with production following stimulation.

By integrating these mechanical properties, engineers can optimize stimulation treatments to maximize reservoir contact and ensure long-term production efficiency.