What are the best practices for managing shale gas reservoir production decline?

Shale reservoirs have different producing and working mechanisms than the conventional reservoirs. Multiple transverse fractures created during fracturing treatment control the wells’ pressure transient response and flow rate. The important parameters influencing this behavior are matrix permeability, cluster spacing, fracture length, conductivity of hydraulic fractures, and permeability of the stimulated zone. The typical average pore-size diameter in unconventional reservoirs changes between 2 to 500 nm, and typical matrix permeability is between 50 and 500 nD

Conventional DCA methods have the inconvenient of interpretation and had showed overestimated results in these reservoirs. Modified forms of DCA (Arps) models and new concepts have been introduced in the last decade to overcome the discrepancy associated with flow mechanisms from conventional reservoirs: - Duong (2010) considered the fracture-dominated flow in the DCA. - Wang et al. (2017) improved Duong's DCA by incorporating time-varying fracture time exponent. Numerical models show that Duong's model and Wang's model best represent the shale gas production behavior. - Gupta et al. (2018) replaced the constant decline rate in the Arp's standard exponential decline function with a power-law function.

DCA is an empirical method that does not take into account the physical and geological characteristics of the reservoir. In shale gas production, understanding the physics of gas flow through ultra-low permeability shale, the impact of natural fractures, and the effectiveness of hydraulic fracturing is essential. Ignoring these can lead to inaccurate forecasts. As new extraction technologies and techniques are developed, DCA, which relies on historical data, may not accurately predict how these innovations could alter future production profiles. DCA is most reliable with a substantial production history. In the early life of a well or in a new play with limited data, DCA predictions can be highly uncertain.

A strong reservoir management team should ideally follow these ideas, in my opinion. Comparison of the performance of different shale gas wells within a field to identify high-performing wells and potential candidates for interventions can help a great deal. This is to be practised only if pressure build up analysis, flow regime identification and type curve matching have been tried on the reservoir under test. Optimization through strategies like in-depth analysis of pressure and rate derivative plots will be helpful. This is to identify key points such as the start of linear flow and boundaries between different flow regimes. Such derivative analysis will always enhance the interpretation of reservoir dynamics.

Production from hydraulically-fractured unconventional formations is determined with well-testing. Rate Transient Analysis (RTA) and Pressure Transient Analysis (PTA) are generally applied to understand the response of the reservoir at different flow characteristics. For instance, drillstring (DST) tool provides information about early-time flow behavior reflecting wellbore storage. Comprehensive information about reservoirs such as permeability value, the volume of the reservoir, and boundaries can be obtained via long-term data from RTA.

Rate Transient Analysis (RTA) is a valuable tool in the evaluation and management of shale gas reservoirs, especially when applied to flow back data following hydraulic fracturing operations. The flow back phase, during which fracturing fluid is recovered from the well following a hydraulic fracturing treatment, provides early-time production data that are rich in information about the reservoir and the effectiveness of the fracturing process. Analyzing this data with RTA techniques can yield insights into reservoir properties, fracture characteristics, and the potential long-term performance of the well.

For shale gas, hydraulic fracturing of a reservoir is the preferred stimulation method. This typically involves injecting pressurized fluids to stimulate or fracture shale formations and release the natural gas. Sand pumped in with the fluids (often water) helps to keep the fractures open. The type, composition and volume of fluids used depend largely on the geologic structure, formation pressure and the specific geologic formation and target for a well. If water is used as the pressurized fluid, as much as 20 percent can return to the surface via the well (known as flowback). This water can be treated and reused,reuse of flowback fluids for subsequent hydraulic fracture treatments can significantly reduce the volumeof wastewater generate.

Optimization techniques for shale gas reservoirs involve processes to enhance recovery and mitigate decline. These include hydraulic fracturing, adjusting well spacing, reservoir simulation, artificial lift methods, and integrating data analytics. These practices aim to maximize production efficiency and optimize the performance of shale gas reservoirs.

To maintain shale gas reservoir production, consistently monitor wells, optimize methods, use artificial lift, conduct proactive maintenance, analyze data comprehensively, manage reservoir effectively, adopt new technologies, assess economics, collaborate, and consider environmental factors for adaptive strategies to maximize recovery.