Abstract:

The pristane/phytane ratio (Pr/Ph; a geochemical source parameter) and the C7 oil-generation temperature (a geochemical maturity parameter) systematically increase with depth in the petroleum generated by oil-prone Upper Wolfcamp source rocks.  When the values of these parameters are higher or lower in an oil or condensate than in samples produced from nearby wells landed in the same pay zone, it indicates a large amount of oil or wet gas flowed from pay zones shallower or deeper than the landing zone of interest.  We demonstrate this principle using High-Resolution Gas Chromatography (HRGC) data measured on oils and condensates collected from 61 wells landed in the 3rd Bone Spring Sandstone (3BSS) or in Upper Wolfcamp A-D (UWA-UWD) pay zones at a field located in the southern Delaware Sub-Basin.

Seven samples produced from wells landed in UWB or UWC pay zones have significantly lower Pr/Ph and C7 temperatures than expected, while the values of those parameters are significantly higher than expected in samples obtained from six wells landed in UWA or UWB-Lower pay zones.  Most anomalous samples were obtained from wells located on pads where other wells were landed in deeper or shallower reservoirs, which suggests that in some cases child wells interfered with parent wells.  Good production allocation results derived using 280 HRGC peak heights confirm that the anomalous samples contain a large amount of the kind of oil or condensate collected from nearby wells with "normal" source and maturity parameters that were landed in different reservoirs.

For example, samples with anomalously low source and maturity parameters produced from two wells landed in the WCB-Lower pay zone contain >83 wt% of the kind of condensate collected from nearby wells landed in the WCA reservoir.  Similarly, samples with anomalously high source and maturity parameters produced from two wells landed in the WCA reservoir contain >73 wt% of the kind of condensate collected from nearby wells landed in the WCB-Lower reservoir.  Another unexpected observation is that the composition of several pairs of samples collected from different wells are identical (as constrained by the precision of HRGC analyses).  This result indicates each pair of wells produces the same mixture of the same kind of fluid from the same pay zone(s) -- although in some cases the wells were landed in different reservoirs.

Geologists and petroleum engineers can use these geochemical parameters (which are determined using inexpensive HRGC data) to rapidly screen oils and condensates produced from UW pay zones soon after wells are brought on production to establish contributions from unexpected pay zones.  They also can use time-lapse geochemistry technology to monitor how drained rock volumes (DRVs) change over time.

Speaker Biography:

Alan Kornacki has 38 years of experience developing and applying geochemistry technology to help E&P staff discover, appraise, develop, and manage oil and gas pools more efficiently.  He worked at Royal Dutch Shell for 26 years as an exploration geochemist, reservoir geochemist, and the manager of the rock and fluid properties services group in the global technology organization.  Since 2010, Alan has worked as a consultant at Stratum Reservoir (formerly Weatherford Laboratories), where he has focused on developing and implementing new ways of using geochemical data measured on core-plug extracts and oil samples to allocate commingled oils produced from source-rock reservoirs.  Alan earned a B.S in geology from the University of Missouri-Rolla (now Missouri University of Science and Technology), and a PhD in geological sciences from Harvard University.