Advanced Mud Gas Logging and the Importance of Biogenic Gas in Fluid Properties: Case Studies From the Gulf of Mexico

Abstract

Since the 1980’s, chromatographic analysis of the C1‐C5 alkane fraction of hydrocarbons released from the mud have been used as the first indication of a reservoir's fluid characteristics (Haworth 1985, Whittaker, 1991). However, developments over the last 15 years have produced a steep change in the quality and utility of mud gas data. Advanced mud gas logging and real time isotopic measurements (C1 to C3) have been introduced to overcome low‐efficiency mud gas extractors and low‐resolution GC‐FID gas analyzers. Several different analytical devices are available on the market from high resolution gas chromatographs (GCs) to mass spectrometers. Advanced mud gas logging is now an established tool for delivering real‐time quantitative fluid composition in exploration wells (McKinney 2007). Understanding reservoir fluid phase and distribution while drilling is one of the critical factors in a successful early evaluation of any oil/gas field. Furthermore, it allows for optimization of future appraisal and development wells. Downhole determination of hydrocarbon phase while drilling is a significant subsurface challenge in many Gulf of Mexico exploration wells. Challenges can be due to multiple variables, such as in situ biogenic gas and pore pressure variations from sand to sand, that can translate to fluid compositional changes and variable hydrocarbon saturation distributions. Interpretation of standard Logging While Drilling (LWD) datasets can give questionable results under such conditions. Mistakes in hydrocarbon phase determination can lead to poor completion decisions, incorrect reserves estimation and suboptimal well and reservoir management. The major question is to what extent can we trust hydrocarbon phase assessment while drilling to provide real time interpretation that can minimize the need to collect samples with more reliable but expensive tools such as downhole fluid sampling. Downhole fluid sampling is routinely and successfully used in exploration wells and in general, gives robust fluid phase determinations. However, depending on the formation properties (porosity, permeability and mobility), and borehole conditions, it might not be economically feasible for the acquisition of enough samples to characterize each productive sand. Furthermore, due to oil‐based mud (OBM) contamination, sometimes it is necessary to pump out fluids for long times (24 h) to get a sample that is truly representative of the formation fluid, incurring high costs. Case histories from the Gulf of Mexico will illustrate how the combination of gas data interpretation coupled with LWD data could provide the best way to assess fluid phase and optimize down hole sampling campaigns.

AAPG Datapages/Search and Discovery Article #90349 © 2019 AAPG Hedberg Conference, The Evolution of Petroleum Systems Analysis: Changing of the Guard from Late Mature Experts to Peak Generating Staff, Houston, Texas, March 4-6, 2019