Crampin, Tom (Brunei Shell Petroleum Co. Sdn. Bhd.) | Gligorijevic, Aleksandar (Geoservices) | Clarke, Ed (Shell) | Burgess, Jamie (Brunei Shell Petroleum Co. Sdn. Bhd.) | Chung, Shao-Jung (Brunei Shell Petroleum)
Downhole determination of hydrocarbon phase is a significant subsurface challenge in many highly depleted fields. Reservoir production results in fluid compositional changes and variable hydrocarbon saturation distributions. Standard petrophysical techniques such as analysis of density and neutron porosity logs can give misleading results under such conditions. Most commonly, oil reservoirs can display a neutron-density response indicative of gas. There is significant business impact in error of hydrocarbon phase determination. Mistakes can lead to poor completion decisions, incorrect reserves estimation and suboptimal well and reservoir management.
The fluid phase uncertainty resulting from interpretation of standard Logging While Drilling (LWD) datasets can be unacceptably high. Additional tools or techniques are therefore required. Downhole fluid sampling is one such technique. It is routinely and successfully acquired in exploration and appraisal wells and gives robust fluid phase determination. However, it is not economically feasible for frequent acquisition for in-fill production wells where low cost LWD acquisition is the norm. In addition, overbalanced wells drilled through highly depleted reservoirs lead to acquisition risk in stationary openhole logging techniques. Advanced Mud Gas logging (AMG) is an established tool for delivering real-time quantitative fluid composition in exploration, appraisal and early production wells. However, successful applications in highly depleted fields have not been published as AMG analysis can be complicated by compositional changes. In this paper we present a case study calibration of AMG with downhole fluid samples resulting in a robust, cost effective and safe tool for improved hydrocarbon phase determination in depleted reservoirs.
Many techniques are used to determine hydrocarbon phase but all of them can be impacted by production related changes to reservoir fluids. The neutron-density "cross-over?? is the most common gas identification tool (Figure 1). It results from an anomalously low neutron porosity reading in gas, due to low hydrogen index (HI), and an anomalously high density porosity reading, due to low fluid density. A second traditional technique is the neutron near count to far count ratio. The near detector reads largely in the near wellbore invaded zone where high mud filtrate saturation results in a high HI and a relatively low count rate when overlain with the far detector, which reads deeper into the formation, past the invaded zone, resulting in a relatively high count rate if gas is present.