Geochemical Allocation of Commingled Oil Production or Commingled Gas Production

Abstract

We have made substantial improvements to the previously published methods for geochemical allocation of commingled oil production and/or commingled gas production. This new method has allowed allocation of commingled production from wells at less than 2-5% of the cost of production logging. Four case studies are shown here. In the first two studies, commingling of the wells was subject to approval of the Alaska Oil and Gas Conservation Commission (AOGCC). Before agreeing to the use of geochemical allocation, the AOGCC required the well operator to perform multi-month trial studies in which the wells were monitored both by geochemical allocation and by production logging. The individuals performing the geochemical allocation were kept blind from the results of the production logging until the studies were completed. Close agreement between the geochemistry-based allocation values and the production-logging-based allocation values resulted in AOGCC approval of continued use of the geochemical method for oil production monitoring of these two wells. Two additional case studies presented here illustrate how geochemical allocation can be used to monitor the effects on production of (1) changes in water injection into nearby wells, and (2) closing or opening perforations within a well. Introduction Previous methods for using oil composition differences to allocate commingled production from a single well have been detailed in Kaufman et al. (1987 and 1990). Similar methods for allocating the contribution of multiple fields to commingled pipeline production streams are discussed by Hwang et al. (2000). The methods described in those publications relied on using Whole-Oil Gas Chromatography (GC) peak ratios to quantify the contribution of multiple zones to a commingled production stream. In brief, if two zones were being commingled ("Zone A?? and "Zone B??), then the respective contributions of Zones A and B to a commingled sample were determined, in those publications, by identifying chemical differences between "end-member" oils (with the end members being a pure sample of oil from Zone A and a pure sample of oil from Zone B). Geochemical parameters (GC peak ratios) reflecting these compositional differences were measured in the end member oils, in various artificial mixtures of the end member oils, and in the commingled oil. The data were then used to mathematically express the composition of the commingled oil in terms of contributions from the respective end member oils. Using this simple mixing model, a single geochemical difference between oils from two sands is sufficient to allocate commingled production from those two units. By using data for several peak ratios, independent solutions to the problem could be derived, allowing the accuracy of the allocation to be assessed. This older approach for geochemical allocation had two drawbacks. The first was that it required analysis of artificial mixtures of the end member oils. This necessity existed because ratios of GC peak heights do not necessarily mix linearly: ratios of peak heights only mix linearly when the same absolute value is present in the denominator of the ratio of the two GC peak heights in all of the end member oils being mixed. For example, if the ratio of the height of GC Peak A and GC Peak B is measured in 3 end member oils, and is found to be 7/2 in "Oil X??, 9/2 in "Oil Y??, and 9/3 in "Oil Z??, then the value for the ratio of Peak A/Peak B will mix linearly between Oil X and Oil Y (since Peak B has a value of 2 in both oils), but will not mix linearly between Oil X and Oil Z (since Peak B has a value of 2 in one oil but 3 in the other oil). Therefore, in the older approach, artificial mixes of end member oils had to be prepared to determine the shape of the calibration curve that defines how a given GC ratio changes as one moves from 100% Oil X to 100% Oil Y.