Analysis of the Kansas Hugoton Infill-Drilling Program
Authors: McCoy T.F. , Fetkovich M.J. , Needham R.B. , Reese D.E. 
Published: December 2007

This paper uses official deliverability tests and production histories tocompare the performances of infill wells production histories to compare theperformances of infill wells and companion original wells drilled in the Kansas Hugoton field. In addition, the performance of one of the five Mesa replacementtest wells drilled in 1977 in the Kansas Hugoton is reviewed. Pitfalls in theuse of official deliverability and wellhead shut-in Pitfalls in the use ofofficial deliverability and wellhead shut-in pressure differences betweeninfill wells and companion original pressure differences between infill wellsand companion original wells to indicate additional gas in place (GIP) arepresented. Analysis of the performance of the first 659 infill wells has foundno evidence of additional GIP.

Introduction

We examined more than 12 years of performance data from afive-replacement-well program in the Kansas Hugoton and evaluated the resultsof the Kansas Hugoton infill-drilling program started in 1987. This workfocuses on the pressure, deliverability, and rate-vs. -time relationshipbetween two wells on a 640-acre section with respect to any GIP additions madeby the second well. In 1977, Mesa undertook a five-replacement-well testprogram to determine if increased reserves and improved deliverability could beobtained by drilling an additional well on each of the five 640-acre-spacingunits. One aspect of the five-replacement-well study is that the original wellswere shut in for nearly 10 years and wellhead observation pressures recordedmonthly while the replacement wells were produced. The observed pressures, combined with pressure and flowmeter produced. The observed pressures, combinedwith pressure and flowmeter data taken on each of the four no-cross-flow layersin the productive interval, provide a unique look at the performancerelationship between two wells on the same 640-acre-spacing unit. We found noevidence that the replacement wells encountered any gas that was not alreadybeing drained by the original wells. This paper also examines the performancedata of the first 659 infill wells placed on production in the Kansas Hugoton. In April 1986, the Kansas Corporation Commission (KCC) amended its basicproration order for the Kansas Hugoton gas field to permit a second optionalwell to be drilled on all basic acreage units larger than 480 acres. The KCCbased its decision to allow infill wells on the premise that these wells wouldrecover an additional 3.5 to 5.0 Tscf of gas that could not be recovered byexisting wells. Data used in our analysis include the official deliverabilitytest data and monthly allowable and production history for each infill andcompanion original well. Results indicate that infill wells have notencountered or indicated additional GIP. This conclusion is supported bycompanion papers on the Guymon-Hugoton field. The performance of the fivereplacement wells compared with the companion original wells illustrates therate and pressure vs.-time relationship of a well pair on 640-acre-spacingunits in the Kansas Hugoton. Results obtained from the five-well programprovide a more complete understanding of infill-well performance in the Kansas Hugoton and other similar layered no-crossflow reservoirs.

History

The Hugoton field is the largest gas accumulation in ft Lower 48 states, covering about 6.500 sq. miles in three states. Approximately two-thirds of thefield lies in southwest Kansas on all or portions of nine counties (Fig. 1). In Nov. 1989, there were 4,853 producing gas wells in the Kansas Hugoton, including 659 infill wells. Cumulative production from the Kansas Hugotonthrough Dec. 1989 totaled more than 20 Tscf, with an estimated remaining GIP ofabout 10 Tscf. The Kansas Hugoton field was discovered in 1922; most of thewells were drilled in the 1940's and early 1950's on 640-acre units. The earlywells were completed open hole; later, slotted liners were run over theopenhole interval to avoid cave-in problems. By 1938, operators were treatingthe whole productive problems. By 1938, operators were treating the wholeproductive interval with HC1. In the late 1940's, many operators found thatmaximum deliverability could be obtained by setting casing through the payzones and selectively perforating and acidizing each zone. By the early 1960's, the primary method of stimulation was hydraulic fracturing.

Geology

The Lower Permian section across southwestern Kansas and the Oklahoma and Texas panhandles was deposited in cyclical sequences on a shallow marinecarbonate ramp. Each cycle consists of laterally continuous anhydriticcarbonates and fine-grained clastics capped and separated by shaley redbeds andpaleosols. The Chase group is the major gas pay within the Hugoton field and issubdivided primarily into carbonate units and interlayered shaly units.

JPT

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