A Simple Approach Using Standard Mud Gas Data to Distinguish Oil and Gas Zones in Depleted Reservoirs

Abstract

For production wells in depleted reservoirs, identifying the oil and gas zones for completion is a long-lasting challenge. This is not because the conventional logging-while-drilling tools are not working but due to the increased complexity of the reservoir fluids under depleted conditions. In this scenario, the reservoir fluids are no longer in single-phase but in two-phase conditions due to released gas from reservoir oil or displacement of reservoir fluids because of aquifer movement during production. There is a strong business need for an accurate fluid-typing solution without additional data acquisition. We use a field example to demonstrate a new method based on the standard mud gas data. The Troll Field is a giant gas field with a thin oil zone on the Norwegian Continental Shelf. Before gas blowdown, horizontal drilling has been extensively used in the field to produce the thin oil zone. The effort has been a great success story until recent years. A wide density-neutron log porosity separation is often observed in many places along the horizontal sections of the production wells. Following the classic interpretation, these sections are regarded as “gas zones” even if quantifying the amount of gas (free or residual) is challenging. Such interpretation leads to multiple zones of the production well not being completed due to the concern of gas breakthrough. However, are these “gas zones” really filled with free gas, or could most of them be filled with oil? After investigating the reservoir fluid database from the field, we found that the component ratio methane to ethane (C1/C2) has a large difference between reservoir oil samples and reservoir gas samples. Water-based mud was used for the field, and the standard mud gas composition (methane to propane) agrees well with reservoir fluid samples. Therefore, we proposed using the simple ratio of C1/C2 as the reservoir oil or gas indicator. The reservoir fluid database from the field defined the C1/C2 threshold to distinguish reservoir oil from gas. We deployed a compositional reservoir simulation model and cuttings analysis to verify the robustness of the new method. Good agreements were achieved among different methods, supporting the simple ratio approach. After implementing the new method, many questionable “gas zones” are now interpreted as oil zones, which become production candidates. Standard mud gas is widely available for all wells and does not require additional data acquisition costs. The simple approach using standard mud gas data provides a cost-efficient and reliable method to distinguish reservoir oil and gas in depleted reservoirs. The new method is not sensitive to a small amount of released gas or trapped gas in the reservoirs and provides the opportunity to complete more oil zones for production. With increased activities in producing matured fields, the business value of the new method is significant.