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Abstract

The Hugoton Field in southwestern Kansas, western Oklahoma and northwestern Texas is the largest gas field in North America. Gas production is from the shallow (2,100+ feet to 2,900+ feet) heterogeneous, multi-layered Chase gas reservoir. This paper analyzes performance of wells in the Kansas Hugoton field. It compares volumetric and performance data from original and more recent infill wells within this field. These comparisons are shown by field, operator grouping, and infilled unit grouping using official deliverability tests and production history. The results are compared against geologic distributions, by producing layer, across the field. A cumulative comparison of the original versus infill well shut-in pressure difference is shown for the first 318 units infilled since infill drilling began in 1987. Some specific case studies are shown comparing monthly and daily well performance surveillance data. This analysis shows:

  1. Some of the pitfalls of estimating initial gas-in-place (IGIP) and recoverable reserves,

  2. The need to look at more than one type of analysis in reaching conclusions, and

  3. Reasons why infill wells have not developed significant fieldwide incremental reserves.

Introduction

The Kansas Corporation Commission (KCC) amended the Kansas Hugoton field Basic Proration Order (BPO) in April, 1986. This amended order allowed a second optional well to be drilled on all basic proration units greater than 479 acres within the Kansas Hugoton field. The KCC based their decision on geologic and engineering evidence presented by Kansas Hugoton field operators suggesting infill drilled wells could recover an additional 3.5 to 5.0 trillion cubic feet (TCF) of gas which could not be recovered by existing wells. Infill drilling commenced in 1987 and the field is approximately 40% (1,666 of 4,177 original wells) infill drilled as of yearend 1993. Numerous infilled units now have over five years of monthly production and annual pressure test performance history. Mobil's producing gas wells in the Hugoton gas area have had electronic gas measurement (EGM) and control capabilities since their installation in 1988. This EGM capability enables the unique ability to monitor and analyze rate and surface pressure data on Mobil's original and infill drilled wells on a daily basis. This historical performance data and extensive EGM data has allowed close monitoring and analysis of the results of the infill drilling program in the Kansas Hugoton field. Detailed numerical simulation studies by Mobil and other operators (Fetkovich 1990) in the Guymon-Hugoton field in 1987 indicated no significant additional reserve potential would be expected from infill drilling in the Guymon-Hugoton field in Oklahoma. Production and pressure performance results of the Kansas Hugoton field infill wells completed through 1989 indicated no significant incremental reserves. Mobil began a fieldwide reservoir characterization project in 1989 using modern logs, sedimentologic and petrographic methods, well performance analysis, and numerical simulation models to address the question of incremental reserve potential. This data and analysis is being used to determine the optimum method of maximizing recovery of the remaining gas reserves in the Kansas Hugoton and Guymon-Hugoton fields. This paper presents some of the well performance and volumetric results from this study.

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