What are the key challenges and best practices for well testing in unconventional resources?

1 Challenge 1: Low permeability

Unconventional resources have very low permeability, which means that the fluids flow very slowly and with high resistance through the rock matrix. This makes it difficult to achieve sufficient flow rates and pressures to conduct a conventional well test, such as a drawdown or buildup test, which rely on transient pressure data to estimate reservoir properties. Low permeability also means that the well may not reach a stabilized or pseudo-steady state flow regime, where the pressure changes are proportional to the production rate, even after a long period of testing.

2 Best Practice 1: Rate-transient analysis

One of the best practices for well testing in low permeability reservoirs is to use rate-transient analysis (RTA), which is a technique that uses production rate and flowing pressure data to analyze the well and reservoir behavior. RTA can be applied to both single-phase and multiphase flow systems, and can account for various factors that affect the well performance, such as wellbore storage, skin, fracture geometry, natural fractures, and multi-layered reservoirs. RTA can provide estimates of reservoir properties, such as permeability, porosity, fracture conductivity, and drainage area, as well as forecast the future production and recovery potential of the well.

3 Challenge 2: Complex fracture networks

Unconventional resources are usually stimulated by hydraulic fracturing, which creates artificial fractures in the rock to enhance the permeability and connectivity of the reservoir. However, hydraulic fracturing also creates complex fracture networks, which may not be fully characterized by conventional logging tools, such as gamma ray or resistivity logs. Moreover, the fracture networks may evolve over time due to fluid-rock interactions, stress changes, or production-induced effects, such as fracture closure or proppant embedment. This makes it difficult to understand the fracture geometry, orientation, density, and conductivity, which are crucial for evaluating the well performance and optimizing the fracture design.

4 Best Practice 2: Microseismic monitoring

One of the best practices for well testing in complex fracture networks is to use microseismic monitoring, which is a technique that detects and locates the micro-earthquakes that occur during hydraulic fracturing. Microseismic monitoring can provide insights into the fracture initiation, propagation, and termination, as well as the fracture dimensions, azimuths, and spacing. Microseismic monitoring can also help identify the stimulated reservoir volume (SRV), which is the volume of rock that is effectively connected to the wellbore by the fractures. By comparing the microseismic data with the production data, the fracture effectiveness and efficiency can be evaluated and improved.