SPESociety of Petroleum Engineef's

SPE 20756

Analysis of Kansas Hugoton Infill Drilling:Part I-Total Field Resu ItsT.F. McCoy, M.J. Fetkovich, R.B. Needham, and D.E. Reese, Phillips Petroleum CO.

SPE Members

Copyright 1990, Society of Petroleum Engineers Inc.

This paper was prepared for presentation at the 65th Annual Technical Conference and Exhibition of the Society of Petroleum Engineers held in New Orleans, LA, September 23-26,1990.

This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper,as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflectany position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Societyof Petroleum Engineers. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgmentof where and by whom the paper is presented. Write Publications Manager, SPE, P.O. Box 833836, Richardson, TX 75083-3836. Telex, 730989 SPEDAL.

ABSTRACT

This paper compares the performance of infill wellsdrilled in the Kansas Hugoton to the companionoriginal wells - regionally, by operator, and thefield as a whole, using official deliverabilitytests and production history. We present thepitfalls of using official deliverability andwellhead shut-in pressure differences between theinfill wells 'and the companion original wells asindications of additional gas-in-place and suggestmore reliable methods of interpreting infill wellperformance. The results of the first 659 infillwells drilled in the Kansas Hugoton reveal that theinfill wells have not found any evidence ofadditional gas-in-place.

INTRODUCTION

In April 1986, the Kansas Corporation Commission(KCC) amended its basic proration order' for theKansas Hugoton gas field to permit a secondoptional well to be drilled on all basic acreageunits greater than 480 acres. The KCC based theirdeci~ion to allow infill wells on the premise thatthese wells would recover an additional 3.5 to 5.0trillion cubic feet (TCF) of gas that could not berecovered by the existing wells.

This paper is a study of the data publiclyavailable through November 1989 for the first 659infill wells put on production. The data analyzedinclude the official deliverability tests and themonthly allowable and production history for eachinfill and companion original well. The results ofthis study indicate that the infill wells have notencountered nor indicate additional gas-in-place.This conclusion is also supported by the companionpapers on the Guymon-Hugoton2 • 3 • 4 and Part 115 ofthis work.

References and illustrations at end of paper.

403

HISTORY

The Hugoton Field is the largest gas accumulationin the lower 48 states covering approximately 6500square miles in three states. Approximately two­thirds of the field lies in southwest Kansas on allor portions of 11 counties (see Fig. 1). As ofNovember 1989, there were 4853 producing gas wellsin the Kansas Hugoton including 659 infill wells.Cumulative production from the Kansas portion ofthe field through December 1989 totaled over 20TCF, with an estimated remaining gas-in-place ofapproximately 10 TCF.

The Kansas Hugoton discovery wel16 was DefendersPetroleum Company's Boles No.1, Sec. 3, T35S,R34W, completed in December 1922, three miles westof Liberal, Kansas, with an open flow potential of- 1 MMSCFD. Development of the field was delayeduntil 1930 when the first major pipeline wascompleted 1n the area. By the end of 1930,seventy-five wells had been drilled in southwestStevens County. 7 The majority of the remainingwells were drilled in the 1940s and early 1950s on640-acre units.

The early wells in the field were completed openhole with casing to the top of the productiveinterval. In many wells, slotted liners were runover the open hole interval to avoid cave-inproblems. In an attempt to increase the open flowcapacities, operators began to treat the wholeproductive interval with HC1, with the typicaltreatment being 8,000 gallons. This became commonpractice by 1938. In the late 1940s, it wasestablished that maximum deliverability could beobtained by setting casing through the pay zonesand selectively perforating and acidizing eachzone. 8 • 9 .'O In 1947, the very first hydraulicfracturing operation was conducted on the KlepperNo. 1 in the Kansas Hugoton using a gasoline-basednapalm gel fracturing fluid." By the early 1960s,the primary method of stimulation was hydraulic

2ANALYSIS OF KANSAS HUGOTON INFILL DRILLING PART I:

TOTAL FIELD RESULTS SPE 20756

fracturing using large volumes of low-cost, water­based fluid pumped at high rates with 1 ppg ofriver sand. Many successful restimulationworkovers were conducted on the older wells duringthis time. 12

GEOLOGY

The Lower Permian section across the Texas andOklahoma Panhandles and southwestern Kansas wasdeposited in cyclical sequences on a shallow marinecarbonate ramp.2,13 Each cycle consists oflaterally continuous anhydritic carbonates andfine-grained clastics capped and separated byshaley redbeds and paleosols. The Chase Group isthe major gas pay within the Hugoton field and issubdivided into primarily carbonate units andinterlayered shaley units. The carbonate units,including the Upper and Lower Ft. Riley, Winfield,Krider, and Herington Limestones and Dolomites,constitute the potential reservoir intervals withinthe Hugoton field. These reservoir intervals areseparated by shaley units, including the Oketo,Holmesville, Gage, Odell, and Paddock Shales.Based on individual layer pressure data andflowmeter data on five replacement wells in theKansas Hugoton, Carnes15 concluded that the Krider,Winfield, Upper Fort Riley and Lower Fort Riley areseparate and distinct producing horizons within theChase formation, having different pressures anddepleting at different rates. The reservoir andshaley nonreservoir units exhibit characteristiclog signatures recognizable throughout the field.Regional north-south and east-west cross-sections,as demonstrated in Figs. 2 and 3, developed fromlogs by Clausing,14 illustrate the lateralcontinuity of the reservoir layers and shaleybarrier units across the field. Additionalinformation on the geological features in Oklahomacan be found in Ref. 2.

INFILL DRILLING ORDER

Cities Service oil and Gas Corporation (now OXYUSA) filed an application with the KCC on July 31,1984, requesting that an optional well be permittedon each basic proration unit1 of 640-acres in theKansas Hugoton. A hearing on the Citiesapplication began on July 29, 1985, and ended onDecember 5, 1985, before the KCC. One hundred tenwitnesses testified.

In April 1986, the KCC amended the proration orderfor the Kansas Hugoton to permit a second optionalwell. Starting in 1987, the KCC ordered that theinfill drilling be phased in over a 4-year periodin order to avoid a boom-bust race to drill theinfill wells. Each operator would be permitted todrill a maximum of one-quarter of their infilllocations each year with a carry forward of thenumber of undrilled infill locations from theprevious year. In addition, during the four-yearphase-in, the original well would have an acreagefactor of 0.7 and the infill well an acreage factorof 0.3. During the fifth year, the acreage factorsbecome 0.6 and 0.4 respectively for the originaland infill well. Starting in the sixth year, eachwell will receive an acreage factor of 0.5. TheKCC decided that this acreage factor schedule wouldprotect correlative rights during the phase-inperiod.

404

ANALYSIS OF DATA

Infill Drilling Activity

The infill wells analyzed in this study are the 659wells that were assigned allowables and listed inthe November 1989 Monthly Kansas Hugoton Fieldreport. The data analyzed in this study includeall of the official deliverability test data (72 hrflows and shut-ins) published by the KCC throughNovember 1989 and the monthly production andallowables for each well up to November 1989.

Infill drilling in the Kansas Hugoton began in 1987with 260 wells being spudded in the first yearcompared to the 1044 allowed by the KCC. Figure 4compares the actual number of infill wells drilledto the total number of infill wells allowed byyear. As of the end of 1989, only 823 infill wellsof the 3132 allowed (26%) have been drilled. Theoverall infill drilling activity has progressed ata significantly slower pace than was allowed by theKCC.

Fig. 5 summarizes the infill activity throughNovember 1989 by operator as a percentage of theirallotment. The number of infill wells for eachoperator is listed next to the operator name on thex-axis of Fig. 5. Mesa has been, by far, the mostactive, having drilled one-third of all the infillwells in the field representing over 91% of theirallotment of infill wells. The two largestoperators, Mobil with 691 wells and Amoco with 810wells prior to the start of infill drilling, havedrilled only 5% and 7% respectively of theirallotment of infill wells. Although Santa Fe andArco each had less than 100 wells prior to thestart of infill drilling, on a percentage basisthey each have been quite active, drilling 76% and79% respectively of their allotment of infillwells.

Fig. 6 is a map of the Kansas Hugoton with asummary of the infill well locations by operator.Most of the infill wells are located in GrantCounty (258 infill wells) and Stevens County (158infill wells). It appears that some of theoperators such as Amoco, Mobil, OXY USA, Anadarko,and Plains have spread out their infill welllocations over their whole properties. Out of the659 infill wells, approximately 79 (12%) of thewells were unsuccessful deep tests that wereplugged back and completed in the Chase.

The Kansas Hugoton monthly production and wellcountsince 1967 for both the infill and original wellsare presented in Fig. 7. The gas marketcurtailment can be seen in this plot as evidencedby the rate decline in the early 1980s. Theproduction from the infill wells has not had anappreciable effect upon the total production fromthe field. In fact, the increase in demand for gasfrom the Kansas Hugoton between 1987 and 1988 hashad a greater impact on total field production thanthe infill wells.

Infill Well Initial Wellhead Shut-In Pressures

A cumulative frequency and a frequency distributionhistogram of the initial shut-in wellhead pressuresencountered by the infill wells between January

SPE 20756 T. F. McCOY, M. J. FETKOVICH, R. B. NEEDHAM, and D. E. REESE 3

1987 and November 1989 is presented in Fig. 8. Theaverage initial wellhead shut-in pressure is 148.8psia with a most probable value of 143.1 psia. Themost probable value accounts for skewness in thedata. Note the skewness in the upper end of thedistribution in Fig. 8. The average initialwellhead shut-in pressure of 148.8 psia issignificantly lower than the original fielddiscovery pressure of approximately 450 psia. 1

This average reduction in initial pressure of over300 psi in the infill wells drilled in the KansasHugoton is evidence that the existing wells havedrained gas from the reservoir in the areas ofevery new infill well.

The average and most probable initial infillwellhead shut-in pressure for each operator ispresented in Fig. 9. The number of infill wellsfor each operator is listed next to the operatorname. The 1989 field average shut-in pressure of147.6 psia is included on Fig. 9 as a referencepoint. Mesa, Mobil, and Anadarko have drilled amajority of their wells in the most productive areaof the field resulting in their average infillwellhead shut-in pressures being lower than thefield average. The rest of the operators havedrilled many of their wells on the lowerpermeability edges of the field causing theiraverage wellhead shut-in pressures to be higherthan the average.

In a layered, no-cross flow reservoir withcontrasting layer properties such as the KansasHugoton, the shut-in wellhead pressure reflects thepressure of the lowest pressure zone open to thewellbore. This behavior was observed by Carnes15

in the Kansas Hugoton while conducting an in-depthstudy of five replacement wells. Using a two-layerradial reservoir model, Fetkovich et al. 16

demonstrated that the commingled shut-in pressuresin a two layer, no crossflow system follow thepressure in the more permeable layer assuming equalskins on each layer. Although the wellhead shut-inpressure typically reflects the pressure in themost permeable layer, the cumulative productionfrom the well reflects production from all layersalthough each layer is depleting at a differentrate. Using a simple analytical approach, Part 115

presents in detail the basic pressure-rate-timerelationship between each of the layers for atypical Kansas Hugoton well. The shape of thewellhead shut-in pressure vs. Gp plot can reflectthe volume of the more permeable layer. The rateof take also affects the shape of the wellheadshut-in pressure vs. Gp curve. When the fieldproduces wide open from the start, the wellheadshut-in pressure vs. Gp curve basically followsthat of the most permeable layer assuming equalskins on all layers. On the other hand when therate of take approaches zero, all of the layersdeplete at the same rate and the wellhead shut-inpressure vs. Gp plot results in a straight line.Actual production for each well is bounded by thesetwo limiting cases. Reference 4 presentsadditional detailed information relating to thefactors influencing the shape of the wellhead shut­in pressure vs. Gp curve.

Fig. 10 is a bar plot of the averageprobable initial infill wellhead shut-inby county with the number of infill wells

and mostpressuresin each

405

county posted next to the county name. Grant,Stevens, Kearny, and portions of Morton counties,located in the more productive areas of the fieldhave initial wellhead shut-in pressures very closeto or below the 1989 field average wellhead shut-inpressure of 147.6 psia. The other five counties,Finney, Seward, Haskell, Stanton, and Hamilton, allhave average and most probable initial infillwellhead shut-in pressures greater than the 1989field average of 147.6 psia because they aretypically on the edges of the field.

The initial infill wellhead shut-in pressures aregenerally a function of the location of the infillwell. The lower pressures are found in the moreproductive areas of the field and the higherpressures are found on the edges of the field. Thefact that no infill well encountered the initialdiscovery pressure of 450 psia in the KansasHugoton is an indication of lateral continuity ofthe more permeable productive layers and that theexisting wells have drained significant volumes ofgas from these layers in the areas of every newinfill well.

Difference Between Initial Infill and OriginalWellhead Shut-In Pressure

In this section we compare the difference betweenthe initial infill wellhead shut-in pressure andthe original well wellhead shut-in pressure. Thispressure difference is infill wellhead shut-inpressure minus original well wellhead shut-inpressure. Since the infill and original wells arenot always tested at the same time, we used thetest for the original well that was closest in timeto the initial test for the infill well. Theaverage elapsed time between the initial infillwell official deliverability test and the companiontest for the original well was 8~ months. Figure11 is a cumulative frequency and a frequencydistribution histogram of the difference inwellhead shut-in pressure between the infill andoriginal well. The average difference is 13.6 psiwith a most probable value of 10.0 psi. Almostone-quarter of the infill wells had an initialwellhead shut-in pressure that was lower than thewellhead shut-in pressure for the original well.

The average and most probable difference betweeninfill and original well wellhead shut-in pressuresfor each operator is presented in Figure 12. Theaverages range from 1.8 psi (Santa Fe) to 27.5 psi(Kansas Nat). Fig. 13 presents the difference inwellhead shut-in pressure between the infill andoriginal well by county. The highest pressuredifferences are in Stanton Co. (36.4 psi) and thelowest in Morton Co. (7.2 psi).

Since the wellhead shut-in pressure typicallyreflects the pressure of the most permeable layer,these pressure difference variations are basicallya function of the permeability variations in themost permeable layer across the field. Since theinitial wellhead shut-in pressures for the infillwells are much lower than the field discoverypressure, the infill wells must be tapping into theexisting drainage area of the original well. Inorder for gas to flow within this drainage area tothe original well, a pressure drop must exist fromthe drainage area boundary to the original well.

4ANALYSIS OF KANSAS HUGOTON INFILL DRILLING PART I:

TOTAL FIELD RESULTS SPE 20756

(1)

The effect of higher shut-in pressure on officialdeliverability can be shown using the official testdata for a typical infill well as an example, and amore reliable method of presenting well performancewill therefore be introduced. Fig. 16 is awellhead backpressure curve for the Nafzinger #1(original well) and the Nafzinger #2-2 (infillwell) located in Sec. 2 T29S R37W. The solid curverepresents the official 1988 test "backpressure"curve for the original well; the chain-dotted curverepresents the infill well. The initial differencein shut-in pressure for these two wells is 16.7 psiwhich corresponds to a 92 Mscf/day difference inofficial deliverability. The officialdeliverability for each well is marked graphicallyon the plot. The difference in these officialdeliverabilities is a result of the 16.7 psi higherinitial wellhead shut-in pressure for the infil1well. The Nafzinger 2-2 was tested 15 months lateron 1/10/89 with a wellhead shut-in pressure of122.9 psig, corresponding to a 16.4 psi drop overthat time period. The average pressure drop forthe field during the same period was only 7.4 psi.The subsequent official deliverability calculatedfrom the second test was 288 Mscf/day lower thanthe first test while the test rate for the second

The deliverability standard pressure, Pd , is equalto seventy percent of the average wellhead shut-inpressure of all the wells tested in the KansasHugoton that year. Fig. 15 presents the differencein infill and original well officialdeliverabilities (as defined by Eq. 1) used in thedetermination of well allowables. If the wellheadshut-in pressure for either the original well orthe infill well is less than the standarddeliverability pressure, then the well has a zerodeliverability and a minimum allowable of 65Mscf/day is assigned to the well. The initialofficial deliverability for the average infill wellis 380 Mscf/day higher than that for the originalwell with a most probable official deliverabilityof 269 Mscf/day higher for the infill well.However, as demonstrated in the followingdiscussion, official deliverability is not anaccurate measure of the difference between infilland original well performance. For example, theinitial test for the Wagner 1-2 (infill well) on4/13/88 located in Sec. 20 T24S R35W had awellhead shut-in pressure of 93.6 psig and flowed253 Mscf/day at a pressure of 85.4 psig. Using Eq.1, with the 1987 standard deliverability pressureof 102.3 psig, results in an officialdeliverability of zero for the Wagner 1-2 when thewell actually flowed 253 Mscf/day at a pressure of85.4 psig. The official deliverability is simply ameasure of relative productive capacities and anumber used for assigning allowables. The higherinitial wellhead shut-in pressure at the infillwell due to the pressure sink at the original wellis a factor in the official deliverabilityequation.

pressure,

Mscf/dayat the end

official deliverability,observed producing rateof 72 hours, Mscf/day72-hour wellhead shut-in pressure,psiaworking wellhead pressure at rate R,psiadeliverability standardpsia

P

DR

where:

Infill Well Official Deliverability

An infill well drilled anywhere within thisdrainage area should have a higher initial wellheadshut-in pressure due to the pressure sink at theoriginal well. Claims have been made that thehigher pressures observed in the infill wellscompared to the original wells indicate that theoriginal wells were not effectively and efficientlydraining all the existing gas reserves and thatinfill drilling has increased ultimate recoverablereserves. The average initial difference inwellhead shut-in pressure of 13.6 psi between theinfill and original wells. The initial differenceis simply a reflection of the pressure gradienttoward the original well in the most permeablelayer.

In 1977, Mesa conducted a five-well replacementwell program,lS which provides information on thebehavior of the pressure gradient between an infillwell and the corresponding original well. InMesa's study, the original wells were disconnectedand used as pressure observation wells. Mesacollected almost 10 years of monthly wellhead shut­in pressures on these five observation wells. PartII of this paperS presents an updatedinterpretation of the results of the Mesa five wellstudy. Fig. 14 is a plot of wellhead shut-inpressure vs. cumulative production for one of theoriginal and replacement well pairs in Mesa'sstudy. The initial wellhead shut-in pressure forthe replacement well is higher than thecorresponding wellhead shut-in pressure for theoriginal well due to the pressure gradient createdby flow to the original well. However, once thereplacement well begins to produce, the subsequentwellhead shut-in pressures plot on the trend of thewellhead shut-in pressures for the original well.Also, during the same time period, the monthlyobservation pressures for the original wellincrease and follow the trend started by thereplacement well. The exchange of positions on thepressure trends for these two wells is due to apressure gradient caused by flow toward theproducing well in the most permeable layer. Thisdemonstrates that the higher initial wellhead shut­in pressure of 14.4 psi observed in the fivereplacement wells and the higher initial wellheadshut-in pressure of 13.6 psi observed in the infillwells does not by itself reflect any additionalgas-in-place and is due only to the pressuregradient in the most permeable layer encountered bythe replacement well at some distance away from theoriginal well.

The higher initial official deliverabilitiesobserved in the infil1 wells when compared to theoriginal wells have been interpreted as reflectingan increase in ultimate recoverable reserves. Inthe text that follows, we will demonstrate that thehigher official deliverabilities found in theinfill wells over the original wells cannot bereliably used as an indication that the infillwells are encountering additional gas-in-place.The official deliverability of each well in theKansas Hugoton is determined by conducting a onepoint deliverability test. The officialdeliverability, D, is calculated using thefollowing equation:

D = R [::

406

SPE 20756 T. F. McCOY, M. J. FETKOVICH, R. B. NEEDHAM, and D. E. REESE 5

corrected AOFP comparison

test was only 2 Mscf/day lower than that of thefirst.

The average infill well has a corrected AOFP of 457Mscf/day less than that of the original well. Onaverage, this indicates poorer stimulation resultsin the infill wells compared to the original wells.Figure 18 compares the corrected AOFP's by using aratio of corrected AOFP for the infill well to the

Where the corrected AOFP, Mscf/day, is thecalculated absolute open flow potential at thefield average shut-in pressure (Pavg) for 1989equal to 147.6 psia. R, P, and Pw are defined asbefore. Using this method, the corrected AOFP forthe infi1l well in Figure 16 is 1715 Mscf/day lessthan the corrected AOFP for the original well. Theratio of the corrected AOFP's for the infill wellto that of the original well is approximately 0.64.This indicates that the stimulation and/orcompletion procedures for this infill well were notas effective as those used on the original well.

Infill Well Allowables vs. Original Well Allow­abIes

corrected AOFP for the original well. The averageratio is 1.1 with a most probable value of 0.85.The upper skewness in this distribution is thecause of the difference between the average andmost probable values. This ratio is a directmeasure of the difference between the performanceof a typical infill well and the original well.Fig. 18 indicates that over 60% of the infill wellshave corrected AOFP's less than the original well.Since the infill wells were generally stimulatedwith a water-based treatment, the infill wellscould experience some degree of cleaning up overtime as they unload the injected frac water. Thiseffect was investigated by calculating the ratio ofcorrected AOFP between the first and secondofficial deliverability tests for the 261 infillwells with more than one test. The average ratiowas 1.08 with a most probable ratio of 1.04indicating an average increase in productivity of8% between the first and second tests. Although aslight increase in productivity is observed in theinfill wells over time due to clean-up effects,this increase has no appreciable effects upon theresults of this study. Although the calculatedofficial deliverabilities for the infill wellaveraged 380 Mscf/day greater than that for theoriginal well, the corrected AOFP, which representsa better comparison, averaged 457 Mscf/day lessthan that for the original well.

Fig. 20 shows the ratio of corrected AOFP betweenthe infill and original wells by county. Thecounties on the north and some of the edges of thefield including Kearny, Finney, Haskell, Stanton,and Hamilton Counties all have ratios greater than1.28. This indicates on average that in thesecounties the original wells had poor stimulationresults. It is possible that many of theseoriginal wells on the edges of the field were notrestimulated in the early 1960s. The average inthe remaining counties ranges from .89 to 1.08.

Fig. 21 is a plot of allowable vs. time for theoriginal wells, infill wells, the sum of the infilland original wells, and for the original well hadthe infill well not been drilled. The originalwell allowable divided by seventy percent gives usthe original well allowable had the infill well notbeen drilled. The well count vs. time is on theoffset y-axis of Fig. 21. Through the beginningof 1989, the presence of the infill well did notadd significantly to the volumes of gas allowed tobe produced from the infilled proration units. ByNovember 1989, the infill wells accounted for anoverall incremental allowable of approximately 12%from the infilled proration units. Because the

The ratio of corrected AOFP used in Figure 18 ispresented by operator in Fig. 19. Arco, UnionPacific, and the other operators have ratiosgreater than 1.75. The most likely reason for theinfill wells appearing to be so much better thanthe original well is that the original wells hadpoorer stimulation results. The results for theremaining operators range from ratios of 1.18 (OXY)to 0.77 (Anadarko). Since Anadarko has such a lowaverage, it may be an indication of less thanoptimum stimulation results on the infill wells orbetter initial completion results.

(2)- 14.42 Jo. 85

- Pw2[

pa yg2corrected AOFP = R p2

A better method to compare well performance betweenthe infill and original well, designed to avoid theimpact of pressure gradients, is to use the AOFPcalculation corrected to the 1989 average fieldshut-in pressure of 147.6 psia (Eq. 2). Thiscalculation puts all of the wells on the samepressure basis. This method also removes theeffect of testing time between original and infillwell tests. This method presents a bettercomparison of current well productivities anddemonstrates the effectiveness of infill wellcompletion and stimulation techniques relative tothose used on the original wells.

The higher official deliverabilities in the infillwells are generally temporary and are caused byhigher initial wellhead shut-in pressure observedin the infill wells when compared to the originalwells. We have already demonstrated that thehigher initial wellhead shut-in pressure at theinfill wells is a result of the pressure gradient,and as such any increase in official deliverabilityfound in the infill wells over the original wellscaused by this higher initial wellhead shut-inpressure at the infill well does not reflectadditional gas-in-place. This effect isdemonstrated by the historical officialdeliverabilities of the five replacement wellleases in Mesa's study. Fig. 17 is a plot ofofficial deliverability vs. time for the wells inMesa's study. The big increase In officialdeliverability observed in 1969 is a result ofhydraulic fracture restimulations conducted on theoriginal wells. The first official deliverabilitytests for the five replacement wells indicate a 55%increase in official deliverability. After severalyears, the official deliverability for these fivereplacement wells falls back onto the trend startedby the five original wells. This demonstrates thatthe higher official deliverabilities found in anynew well in the Hugoton caused by the pressuregradient will be temporary.

407

6ANALYSIS OF KANSAS HUGOTON INFILL DRILLING PART I:

TOTAL FIELD RESULTS SPE 20756

infill wells are only allowed to produce a fractionof their capacity, some operators appear to beoverproducing their wells which may acceleraterevenue to help defray the cost of the infill well.Once a non-minimum well becomes overproduced by 6times its basic monthly allowable, the KCC shutsthe well in until the overproduction is worked off.For example, in January 1989, 102 (24.5%) of the417 infill wells at that time were overproduced tothe point where the KCC shut them in while only 16(3.8%) of the 417 companion original wells wereshut-in by the KCC.

Cumulative frequency and frequency distributionplots were generated of the difference between thecurrent allowable for the infilled proration unitsand the allowable for that proration unit had theinfill well never been drilled. Distributions ofthis difference were generated for each monthstarting in May 1977 through November 1989. Forthe first 11 months of 1989, the average infilledproration unit had an increase in allowable of only36 Mscf/day due to the presence of the infill well.For this same period, 35% of the infilled prorationunits actually lost allowable because of the infillwell.

CONCLUSIONS

infill wells average 380 Mscf/day greater thanthat for the original well, the correctedAOFP, which represents a better comparison,averaged 476 Mscf/day less than that for theoriginal well. On average, this indicatespoorer stimulation results in the infill wellscompared to the original wells.

5. During the first 11 months of 1989, theaverage infilled proration unit had anincrease in allowable of 36 Mscf/day due tothe presence of the infill well. For the sameperiod, 35% of the infilled proration unitsactually lost allowable because of the infillwell.

6. During the month of November 1989, theallowable of the infill units wasapproximately 12% greater than the allowableof the proration unit if the infill well hadnever been drilled.

7. Through 1989, only 26% of the infill wellsallowed by the KCC have been drilled. Theoverall infill drilling activity hasprogressed at a significantly slower pace thanwas allowed by the Kansas CorporationCommission.

After studying the results of the 659 infill wellsgiven allowables by the KCC through November 1989we have the following conclusions:

1. Based on our engineering analysis of theinfill and companion original well performancedata in the Kansas Hugoton, we conclude thatno evidence of additional gas-in-place wasfound.

2. The infill wells have an average initialwellhead shut-in pressure of 148.8 psia withno infill well encountering the initialdiscovery pressure of 450 psia. The magnitudeof this average reduction in pressure is anindication .of lateral continuity of the morepermeable productive layers and that theexisting wells have drained significantvolumes of gas from these layers in the areasof every new infill well.

NOHENCLATDRE

absolute open flow potential, Mscf/dayofficial deliverability, Mscf/day72-hour wellhead shut-in pressure, psiaaverage field shut-in pressure, psiadeliverability standard pressure, psiaworking wellhead pressure at ratio R, psiaobserved producing rate at the end of 72hours, Mscf/day

ACKNOWLEPGMBRTS

We thank Phillips Petroleum Co. for permission topublish this paper. We also wish to thankM. L. Fraim for his early efforts on this project.The assistance of C. D. Javine and S. A. Baughmanis also gratefully acknowledged and a specialthanks to Kay Patton for the outstanding typing ofthis manuscript.

REFERENCES

1. Kansas Corporation Commission Order Docket No.C-164, July 18, 1986.

3. Ebbs, D. J., Works, A. M., and Fetkovich,M. J.: "A Field Case Study of ReplacementWell Analysis Guymon-Hugoton Field, Oklahoma,"paper SPE 020755 presented at the 1990 AnnualSPE Fall Meeting, New Orleans, September 23­26.

2. Siemers, W. T. and Ahr, W. H.: "ReservoirFacies, Pore Characteristics, and Flow Units ­Lower Permian, Chase Group, Guymon-HugotonField, Oklahoma," paper SPE 020757 presentedat the 1990 Annual SPE Fall Meeting, NewOrleans, September 23-26.

J., and Voelker,MultiWell, Multi­Infill Drilling

Fetkovich, M. J., Ebbs, D.J. J.: "Development of aLayer Model to Evaluate

4.

3. The average infill well's initial wellheadshut-in pressure is 13.6 psi higher than theaverage corresponding shut-in pressure of theoriginal well. We believe this pressuredifference does not reflect additional gas-in­place but is a result of the pressuregradient in the most permeable layer towardthe original well.

4. The higher initial official deliverabilitiesfound in the infill wells over the originalwells cannot be reliably used as an indicationthat the infill wells are encountering addi­tional gas-in-place. To better compareperformance between the infill and correspond­ing original well, a calculation may be madeof the absolute open flow potential correctedto 1989 field average shut-in pressure of147.6 psia. This calculation puts all thewells on the same pressure basis, removing theeffect of the pressure gradient. Although thecalculated official deliverabilities for the

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SPE 20756 T. F. McCOY, M. J. FETKOVICH, R. B. NEEDHAM, and D. E. REESE 7

Potential in the Guymon-Hugoton Field," paperSPE 020778 presented at the 1990 Annual SPEFall Meeting, New Orleans, September 23-26.

7. Pippin, L.: "Panhandle Hugoton Field, Texas­Oklahoma-Kansas The First Fifty Years,"Tulsa Geol Soc Spec Publication No.3, 125­131.

5. Fetkovich, M. J., Needham, R. B., and McCoy,T. F.: "Analysis of Kansas Hugoton InfillDrilling, Part II: Twelve Year PerformanceHistory of Five Replacement Wells," paper SPE020779 presented at the 1990 Annual SPE FallMeeting, New Orleans, September 23-26.

11. Howard, G. C. and Fast, C. R.:HydraulicFracturing, SPE, New York (1970) 8.

KansasC-164,

Testimony,Docket No.

PrefiledCommission

Webb, J. C.:Corporation(1985).

12. Rippetoe, R. M. and Sorenson, M. M.: "HugotonOperators Shoot For Low Cost Workovers," OGJ(September 5, 1960) 173-175.

10. Keplinger, C. H., Wanemacher, M. M., andBurns, K. R.: "Hugoton.. World's LargestDry-Gas Field is Amazing Development," OGJ(January 6, 1949) 86-88.

13.

14. Clausing, R. G.: Prefiled Testimony, KansasCorporation Commission Docket No. C-164,(1985).

Hemsell, C. C.: "Geology of Hugoton Gas Fieldof Southwestern Kansas," Bull of the AAPG(July 1939) 1054-1067.

6.

8 • Mercier , V. J. : "The Hugoton Gas Area, "Tomorrows Tools Today, (October 1946) 29-32.

9. Le Fever, R. B. and Schaefer, H.:"Productivity of Individual Pay Zones Used ForDetermining Completion Efficiencies - HugotonField, Kansas," Drilling and ProductionPractice, API, New York (1948).

15. Carnes, L. M. Jr.: "Replacement Well DrillingResults - Hugoton Gas Field," presented at theKansas Univ. Heart of Amer Drilling & ProdInst meeting, Liberal, February 6-7, 1979.

16. Fetkovich, M. J., Bradley, M. D., Works,A. M., and Thrasher, T. S.: "DepletionPerformance of Layered Reservoirs WithoutCrossflow," paper SPE 18266 presented at the1988 SPE Annual Fall Meeting, New Orleans,October 2-5.

.I I

~

~~ FINNEY

HAMILTON ~ KEARNY t

)I--

II HASTKANSAS S~AN~ON GRANT

HUGOTON ... ...MOtrON

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Fig. 1-Kansas Hugoton location map.

409

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Fig. 2-East-west cross section through the Kansas Hugoton. Fig. 3-North-south cross section through the Kansas Hugoton.

~100

Fig. 4-Actual number of Infill weils drliied compared with the total number of weils a.Jiowed.

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Fig. 11-Histogram of the differences between initial InlUl and original wellhead shut-In pressures.

0-1 ' 1 ' iii ~ ~2; I , iii' 1 ' i ' iii i I-50 -40 -30 -20 -10 0 10 20 30 40 50 60 70 80 90 100 110 120 130 140

Difference between initial infill and original well72 hour wellhead shut-in pressure, psi

SPE 201'55 a; 45100 " ------

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Fig. 13-Dlfference between Inltlallnfill and original wellhead shut-In pressure by county. Fig. 14-Wellhead shut-In pressure VB. cumulative production for one of Mesa's original and replacement well pairs.

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Gas Rate, MSCF/Day

Pw' psig I R. MSCF/DayP. psigWell No.

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~ /2-2 /

/Absolute open flow potential corrected /.to 1989 average shut-in pressure /...........................................................................;( .

/:1987 Official /' :deliverability = 1700 MSCF/Day .........................................................../1987 Official ./. :.~.':~i.~~~~~~I!!y..:':'..1.~.9~.~?~~(!?~Y... ../ .

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___ --------.J.".---" -"

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(AOFP infi!1 / AOFP Original) corrected to 1989 total field averagewellhead shut-in pressure of 147.6 psia

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Fig. 17-Historical official deliverabllity for the wells In Mesa's five-well replacement well study area. Fig. 18-Histogram of the ratio of corrected AOFP.

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