Abstract. Amoco is producing coalbed methane from several hun- dred wells in both San Juan and Warrior basins. These wel
society of Petr*
*ers
I
SPE 30012 Completions and Stimulations for Coalbed Methane Wells Ian Palmer.* Amoco. Hans Vaziri, Technical University of Nova Scotia, Mohamad Khodaverdian,’ TerraTek, J;hn McLennan,* TerraTek, K. V. K. Prasad,’ Amocoj Paul Edwards,* Amoco, Courtney Brackin, Amoco, Mike Kutas, Amoco, Rhon Fincher, Amoco
* SPE Members
Copydgfit 1SS5, Society of Petrdaum
Engineers, Inc.
Thii paper wee prepared for presentation at the Intemetional #kafing
on Patmfaum Engineering held in Ssdjing, PR China, 14-17 Nwambar
1S95
TM paper wee aa4actad for pmaentation by an SPE Program Cwnmittaafolfcwhg review of informatii mntahad in an amtract submitted by the author(a). Contents of the paper, se pfSWnt8d, have rmt bean reviewed by the Socisty of Patmfaum Engineers and am aub@tad to mrmctmn by the author(s). The material, as pmaantad doaa not nacaaaarity mflaot any poaMn of tha %ciaty of Petmfaum Enginaara, its officers, or mambara. Papers prwentad at SPE maatiis am aubjact to publiitbn review by Editorial Oommittaaa of tha Socialy of Petroleum Engineers. Penmiaaion to COPYis restricted to an atmtracf of not more than 300 words. Illuatrafiia may not be copied. The abstract should oonfain conapicuoua aoknowkrdgmant of wtwm and by whom the paper is pmaantad Wdta Libradan, SPE, P.O. Sox S33S3.S, Richardson. TX 750%3--, U.S.A. [Fs6*ifiik 2$~S=-W%
Abstract Amoco is producing coalbed methane from several hundred wells in both San Juan and Warrior basins. These wells were completed/stimulated in one of two ways: (1) openhole oavity completions, (2) hydraufic fracture stimulations through perforations in casing. Cavity operations are described, and new data from several cavity completions is presented and analyzed. The latest geomechanics modeling of the formation of cavities in coalbeds is presented. The model allows the growth of a cavity as tensile failure occurs, and computes increases in permeability in a stress-relief zone that extends tens of feet from the weii. Critical parameters are given for the success of cavity completions. A pulse interference analysis is discussed: as wefl as intefwell permeability, this can provide information on stressdependent permeability. Finally, some wells which were originally cavitated did not perform up to expectation, and have been reoavitated with remarkable success - these are also examined. Amooo has tried several different kinds of hydraulic fracturing treatments. Results of comparisons between foam fracture, slick water fraoture, and gel fracture treatments are presented. a.-.: al--l -- -.--I -..-.. . . .&.-- *rw r-;~-~ -e thida mf *- f ir. wm~al IWI I= 01 e WJ=I I IUl r ~lwl 1= UUW,VV”, .,A, =MLISWGUI way zone in the San Juan Basin. In the Warrior Basin, water fracture treatments with and without sand have been compared. Lastly, foamed water cleanouts, without sand, have been deployed, and their success is reviewed.
Introduction h-f this paper we present new information on completionaktfmulations of ooalbed methane wells. Specifically, we discuss (1) openhole cavity completions in the fairway (sweet spot) of the San Juan Basin (Colorado and New Mexioo - see Figure 1), and (2) fraoture stimulations in the San Juan Baain and the Warrior Basin (Alabama).
Cavity Operations The openhole cavity completion has been used with tremendous suooess in the San Juan Basin. 1.7,13,14,17some wells produce in excess of 10 MMCFD from only 3,000 ft depth in the
fairway zone (Figure 1). In the cavity operation, a series of injections (or shut-ins) and blowdowns (aotually, a controlled blowout) is performed over typically a two-week period. Coal fails and sloughs into the wellbore, and is ejeoted from the well, leading to creation of a cavity (enlarged wellbore). A plastic or shear failure zone is also formed beyond the cavity, and in this region the permeability is changed. A typical Amoco oavity operation was described previously.”7 Below is an elaboration of certain aspeots of cavity operations in the San Juan Basin fairway 1. The openhole potion oi the weii is generaiiy 200-300 ft hi height, containing usually more than 50 ft of net coal. The coals are divided into the basal coals, which are usually the more productive, and the upper coals. Normally 7-in. casing is topset above the top coal, and TD is only a couple feet below the bottom coal. 2. A typioal cavity operation entails a sequence of(1) cleanout of the well in the evening using air (1,500-2,200 SCFM) and water (20-100 BPH) inj~lons, followed by (2) flow testing lasting typically four houra, followed by (3) cavity operations fCii
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the flow test and CST, the bit ISeither pulled into the casing shoe or to the surface. The sequence is repeated many times over typically 10-20 days. 3. All flow teats are conducted through a 3/4 in. choke, typically for four hours. All pressure surgings are conducted by rapidly opening a surfaoe valve, allowing gas and water and coal fines to be expelled through blooie lines to the pit. 4. The basal seams seem to respond more than the upper seams to the cavity operations, presumably because they are more friable. 5. It is not uncommon to see 0.5-1 in. pieces of coal come to the surface during cavity operations. 6. In flow tests in good wells, flows during the cavity operations often decrease wirn time over i-4 iirs. This may be the transient effect that is predioted by the oavity modelin~ (see later in this paper). This contrasts with flow tests in the
.-
. COMPLETIONS AND STIMULATIONS FOR COALBED METHANE WELLS
2
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Figure 13. Increase In flow rata between drilling and end of surging as a furkctlon of Initial perm. hole is unstable, and the drilling gets sticky due to shale ledges and/or coal fines exiting a cavity into the wellbore. All this seems to imply that coal is continuing to fail under a hydrostatic head of liquid in the wellbore (possibly an underbalanced condtiion since fairway wells were often overpressured initiafly).1 This kind of behavior has been modeled previously, using a failure surface
589
A surface pressure valve is opened very quickly, allowing the pressure to fail to atmospheric within just a few seconds. However, the pressure at the bottom of the well wiii fall more slowfy, probably taking 1-2 min to faii to its equilibrium flowing pressure. Our model, which assumes the bottomhole pressure tracks the surface pressure with no time deiay, therefore overestimates the suddenness of the pressure surges. Consequently, the beet match cohesion should bean upper iimit (i.e., for slower pressure changes at the bottom of the wail, the cohesion would have to be lower in order to achieve the same cavity dimension).
.
.
COMPLETIONS AND STIMULATIONS FOR COALBED METHANE WELLS
8
Reoavitated Wells Several wells have been recavitated a few years after the original cavity operation, using a technique patented by Amoco.s The reasons for this included (1) the well was underperforrning compared with offset wells, (2) to clean out fill in the well, (3) the well was not cavitated for a long enough time originally, and (4) to replace tubing with larger diameter tubing. As the stabilized rates show in Table 1, these recavitations performed by Amoco have been highly successful (note that the wells were producing in the range 100+6,700 MCFD before recavitating). This euccess can be attributed to ●
cleanout of fill in the well
●
reduced friction within larger production tubing improving the original cavity complWlon5 despite substantially lower reservoir pressure at the time of recavitation
●
Pulse Analysis During Cavity Opemtions A well in the fairway of the San Juan Basin was cavity-completed in 1991 and the well was recavitated in 1993. An old Pictured Cliffs well, 242 ft from the cavity well, served as an observation well, and measured pressure interference data. Two sets of cavity surgings were done four days apart, and during both surgings, a rapid response was seen at the observation well. Pulse peak delays were about 16 min (see pulse delays shown in Figure 14). As well as the analysis of the overali pressure interference, a pulse analysis was applied to both sets of surgings.11
Tabie 1. Reoavitated Weiis
Recav #6
1.24 1.44
Recav #8
I
2.60
Recav #1 O
1.85
Recav#11
1.39
Recav #12
7.83
Recav#13
1.57
Average
2.27
I
b. Increased coal failure by surging: results from cavity modeling at the COAL site suggest between initial drilling and the end of six pressure surges, the avera~e cam (between cavity and observation weii 242 ft a~ay) incr&es by a f~or of 1.7.3 This agrees very well with the increase in interwell perm obsewed here between pulse set 1 and pulse set 2 (a factor of 1.74-1 .96). 5. The pulse technique also provides a new way of determining stress/dependent permeability. In every case, the blowdown perms are iower than the buildup perms, presumably because the pore pressure is lower, and the effective stress is higher. However, a strese-permeability function that is stronger than that normally quoted for the San Juan Basin is needed to reproduce this discrepancy.6 6. The fact that perrns measured during buildup exceed those measured during drawdown implies normal stress4ependent permeability, and means that the reservoir pressure of 700-750 psi is not yet low enough that matrix shrinkage dominates.
Comparison of Fraoture Treatments in the San Juan Basin A comparison was made between the various fracture treatments tried on dry coais south of the fairway (Figure 1) in the San Juan Basin. This work buiids on previous comparative studies.’ The coals in this area are typically about 3,000 ft deep, with permeabilities 0.1-1 md and net mal thickness averaging 50 ft.
The main findings of this analysis areas follows: 1.
4. When a comparison is made between pulse set 1 and puise set 2 (either DIowdown or biiilditip vaiues), the inWrwell perm increases by a factor of 1.74-1.96. This can be explained by
A similar pulse analysis has been done at the COAL site in the northwestern pari of the fairway (Figure 1). An observation well, 178 ft away from a cavity well, saw a direct pressure response during six injection/biowdown surgings on Day 8.1113114117 We emphasized the second half of the pulses, as they were more consistent. Our best estimates of time delays varied from 7-16 min. Although there are more uncertainties in thie analysis, we favor an interpretation in which interwell permeabilitiea lie in the range of 6-32 md, which a rees more with inde pendent results that give higher perms13’14r~ 5 than with the result that gave lower perrns18 at the COAL site. Once again, the permeability discrepancies between injection and blowdown reflect a strong stressdependent permeability.
1.47
Recav #9
3. Under non-blowdown conditions, the perm from pulse set 1 agrees with the perm from the preavity pressure match.
a. Drillbit access and cleanout of the bottom seam, which did not cccur until after pulse set 1, or
The last could be due, for example, to lower cohesion due to lower effective stress or lower water saturation or C02 desorption over time, or it could be due to removal of a low perm barrier by fines movement. Unfortunear $hn,“ -eqfitu ,., vQ@Ifie. ,.---, ea~sed -nately, separating the last effect from the first two is difficult, and has not yet been done.
Recav #7
2. Pressure pulses are seen at an obsewation well 242 ft away from the cavity well as a result of “natural” surges at the cavity well (i.e., no air or water injections, only shut-ins followed by blowdowns). AWwater injections are therefore not needed to see a direct pressure response at an observation well 242 ft away. This would seem to imply matrix communication, rather than fracture mmmunication (as hypothesized before).l
The pulse technique is a new application (of an old technique) to calcuiate permeability near a well during openhole cavity operations.
590
The database for the comparison consisted of fracture treatment data from approximately 1,000 wells located south of the fainvay. Several different operators and service companies were represented in the database over a wide geographical area. The wells in the database had production dates ranrairw from April 1989 to September 1993. h&et wells had produ~ofi
*
refxxtad for at least 12 months from the fracturing date and several had production data for up to 34 months. Monthly gas production data were obtained on these wells to evaluate the relative performance of various treatments. For this study, treatment details such as total fluid and sand volumes, pump rates, type of sand, etc., were not considered. The wells were grouped into three broad fracture treatment categories . Slick water fractures (friction reducer added to water). .
Similar comparisons have been carried out north of the fairwav in the San Juan Basin. and these results are shown in Table 3.
Table 3. Comparison of Fraoture Treatments North of the Fairway ) I
[SW) 1
. Croes-lrnked gel fractures.
Foam/SW
XLG/SW
Ratio of av. production over 6 mos.
1.24
1.06
Ratio of av. production over life of wells
1.41
0.94
11
132
Ratio Definition
For comparison purposes, localized areas with interspersed wells subjected to different fracture treatments were chosen. This was done to minimize the impact of geological variations on the fracture treatment response. Two production variables were used to evaluate the efficiency of treatments (1) average production over first six months from the treatment date, and (2) average production based on total cumulative production to date (i.e., average over life of wells). The results of the comparisons are summarized in Table 2.
Table 2. Comparison of Fracture Treatments e-. .+hAcE*:-.. -.. =UULII UI ruuwuy
#of wells These data show that ●
●
Water
(W’)
Foam M* Linear *, (C02LQ
va. Sllck Water
Cross-linked Gel (XLG) va. Foam c#!&kd Gel (XLGF)
Foam with
Llneer Gal(LQF) vs. Sllok
Water
Ratio of av.
C02LW
SW —..
XLGIXLGF
LGFISW
1.07
1.04
1.04
0.65
1.20
1.05
1.07
0.77
N@W
Water Fracture Treatments With and Without Sand in Warrior Basin In tha Wrsrrinr Rndn in Alnhcirna Ic$tu,
wells #of wells
48
27
25
18
.. s
The following can be concluded from these dati. ●
●
Nitrogen foam fractures without gel are better than slick water fractures over the life of the wells. However, there is Iiffle difference when considering only the first six months of production. There is no significant difference between C02 foam fractures and slick water fractures.
s There is no significant difference between foam fractures with cross-linked gel and liquid cross-linked gel fractures. ●
Water Fraoture Versus Foam Fracture Treatments in Arkoma Basin
●
produdon over 6 rnos. Ratioof av. -on over Meof
Overail, wells tilmulated using cross-linked gel do not perform as weli as those stimulated with slick water treatments. The ratios in Table 3 are inflated because of one anomaious area with significantly better cross-linked gei performance.
In southeast Okiahoma, in the Arkoma Basin, the Hartshorne coai (6-12 ft net) has been exploited by a number of operators in recent years. Evidence is that water fractures outperform foam fractures with gei.4 it has been hypothesized that in these coais, which are fairly dry, the foam bubbiee do not break easiiy, :-A- kAI-A J311=L AU-A III 1- tl[iuwlg I:-:*: -.. gutr --- cl-... -“AIU uhA.,. Iur= :w um 4---IUUIII urut.m IIuw mu mu ar hydraulic fracture.4 The observations are reminiscent of a group of coalbed methane welis stimulated ahead of mining in the eastern U.S.A.: anecdotal evidence is that water fractures again outperformed all other fracture treatments, including foam with gel. Note that this result, for fairly dry coals (typicaiiy ~0 bwpd), is the same as that for the dry coals south of the fairway.
(W)
(W) Ratio
Wells stimulated with foam fracturing treatment perform much hatter etimiIldari with elielr ● es., , ,e, ,,. --.. -, than ., ,S, , thnea ., ,-” “.,, ,,“, W...,., , “,, ”,. wdar .. s.”, trnatmant
co~ Nitrogen Foam :~os.
Cross-1inked Gei (XLG) VS. Siick Water (SW)
Foam vs. Siick Water
Foam fractures - these included (1) N2 foam fractures without gel, (2) N2 foam fractures with linear gel, (3) C02 foam fractures with linear gel,and (4) foam fractures with cross-linked gel.
Dafinltlon
9
1.PALMER, H. VAZIRI, M. KHODAVERDIAN, J. MCLENNAN, K. PRASAD, P. EDWARDS, C. BRACKIN, M. KUTAS, R. FINCHER
SPE 30012
Slick water fractures outperform foam fractures with linear gel.
591
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three principal coal groups are produced: the Pratt, the Mary Lee/Blue Creek, and the Black Creek.7 In the western side of the Oak Grove Field, near the Black Warrior River, typicai depths are 1,200 for the Pratt, 1,600 ft for the Mary LeeiBiue Creek, and 1,900 ft for the Black Creek. Note that the Pratt and the Mary Lee probably provide almost 90% of the total gas from the three coal zones. --:-
IIw
Recent AmcrcWaurus fracture treatments were of two --A_ ...!*L -_—J -—J ——— J,-. — &----- .... .. . Z.-A. --- A---A_ wuLur iramuru mrimmerm wwr aana, ana sanawes
t iy~i
water fracture treatments (the latter used baii seaiers to try to open up more pads). Piain water with no additives was used in both cases. In typical water fracture treatments with aand we wmrmd around 70.000 lb of 12/20 sand at concentrations &6 I& at rates of 4&60 bpm. The eandleee water fracture treat-
.
10
COMPLETIONS AND STIMULATIONS FOR COALBED METHANE WELLS
rnents were pwnped at around 60 bpm using ball sealers of SG 1.3 (about 150 balls per zone)? The location of the wells used in this comparison is shown in Figure 15. There are six wells with sendlesa water fracture treatments and eleven wells with water fracture treatments with sand. Some wells further away from the river have undersaturated coals. Because these tend to produce very high water rates, and very low gas rates, they have been excluded from the above comparisons. In only one case was the Pratt seam not f,ed, ,Pn tra tmant) m t$ia ehnt M nnt df6rt ~:m, ,B~*4 I=LIIIIUI=CUU [a ..,eb-~ waLw,,,~“,”, = Uau.gv...,, -.. .“ “..--... ..V. -..-4. the conclusions. Although the distribution of the wells in Figure 15 is not as random as might be desired to rule out any geological variability, we feel that the distribution is random enough to make a valid mmparison, The difference between the two frac types is shown in Figure i 6, and for gas prcdutiion it is clear that the water fracture treatments with aand outperform the aandlass water fracture treatments up to a time of 41 months. The big jump in water rates just after 40 months in Figure 16 is due tQ Qnly a few wells remaining on line after this time, so these data are invalid for comparison. At a time of 41 months after production began, the cum gas production from the water fractured wails exceeds those from the sandless water fractured wells by 1.40:1. This can be compared with gas rates that differed b about a factor of 1.8, in the same dirtilon, reported previously. #
give less water production. This is difficult to rationalize, but may reflect the wide variability in water production (there is much less variability in gas production). Based on a simplistic Calculation,g it can be shown that economically the water fractures with sand, although more expensive, are still better than those without sand, since the difference in average rates (at 41 months) implies a payout time of 76 days. Possible biases in the data include
●
●
●
6/11 of the wells with water fractures with sand were subject to a remedai water-bailout treatment some time later. in several cases this remedal treatment appeared to increase significantly the gas praiuction. The weiis are not entireiy interspersed, but we can wrnpare the two fracture treatment types after removing (1) the group of four water fractures with sand in the iower left of Figure 15, and (2) the three sandiess water fracture treatments in the unoer -rr -. right of Flaure 15, and this gives the resuit in Figure 17. The discrepan~ in gas production is a little greater, but the conclusion remains the same.
—
— -ml~
Figure 16. Discrepancies in gas and water production
—
— .
I
.
—
Figure 17. Same as Figure 16, except outlying weiis are removed. Figure 15. Interspersed wells used to compare different fracture treatments.
Foamed Water Cieanoute in San Juan Basin
The data indicate that while the water fractures with sand give greater gas production than sandless water fractures, they
592
Foamed water cieanouts (FWCOS), a technique patented by Amoco,8 were performed on 19 coalbed methane WOM in thO
. SPE 30012
L PALMER, H. VAZIRI, M. KHODAVERDIAN, J. MCLENNAN, K. PRASAD, P. EDWARDS, C. BRACKIN, M. KUTAS, R. FINCHER
San Juan Basin several years ago. Three treatments were initial completions, and 17 were remedial treatments following cross-linked gel fracture treatments. Fifteen of the wells treated were below average producers, compared to offset wells. Only one of the three initial completions was commercially successful. This is probably because at typical depths in the basin (1,500-3,000 ft) the in-situ stress will close a fracture that is not propped open. The FWCOS were conducted down casing using mostly 70 Q foam pumped at 10-40 bpm. Treatment volumes varied from 3-6 bbl foam/ft of coal. Each treatment was allowed to flow back immediately to the pit, unrestricted, until clean returns were obsemd. Generally the treatment was repeated at each well. Results: About 759f0of these wells experienced increases in gas production, although only about 50% were economical (based on $1.50 per MCF gas price and six-month payout time). Treatments were unsuccessful on two wells that were better than average. Average ratio of postproductiordpreprcduction is 3.0. However, two ratios were much higher than all others (6.2 and 14), and when these are ignored, the average falls to 1.8. Note that initial gas production varied from 10 MCFD to 170 MCFD. Total gas and water production increased by approximately 1,100 MCFD and 600 BPD, or by 629’o and 23% respectively. Note, however, that three FWCOS on two wells account for more than half the incremen@l gas rate increase.
These treatments should not replace sand fracture treatments for initial completions. However, in many cases they do boost production rates significantly as remedial treatments. Since sand is returned during the flowback portion (plus some coal fines), our interpretation is that the FWCO treatments are creating new flow channels in the proppant pack, and thereby increasing the fracture conductivity.
Hydraulic Fracture Geometry This subject was summarized previously.7 Based on extensive observations in both San Juan and Warrior baains, fracture treatments are predominantly of two types
●
vertical fracture strands (each with sand) diverged over a wide angle, seems less likely than the T-shaped fracture geometry. However, unpublished information from water fracture stimulations ahead of mining in an eastern coal field reveal that horizontal fracture components were very rare, and only occurred if the fracturing gradienta (i.e., ISIP) exceeded 1.8 psi/ft. All these wells had very poor performance. The majority of the hydraulic fractures were vertical, extended up to very large distances from the wellbore (half-fengths of 800 ft or more), and some had fracture gradients in excess of 1.0 psi/ft. In the water fracture treatments, sand stages were separated by pad stages, and presumably the pad stages sweep the sand away from the wellbore as the sand banks along the bottom of the fracture. Finally, some mineback statistics from eastern coalbeds of ten fracture treatments with bottomhole pressure >1.0 psi/ft, only five had horizontal fracture components.’ Furthermore, these five were not all >1.8 psi/ft, so the 1.8 psi/ft criterion given above for a horizontal fracture component may only be true for that specific area.
Concluding Remarks 1. Field data on cavity completions: Flow rate increases during cavity operations vary a lot, and can be as high as 8:1. +alv In nnn T1.a -Lb-.-.da. A{ +ha fkm .mta in-r zma vmrlae I I lu u Ial auLOl WI u IG Ilww I U*9 !1W%”.-! !. !“”!,. . . ! “! 0“ area, pressure surging was applied for seven days before significant coal failure. In other cases, flow rate increases markedly, without pressure surghg, during cleanout operations (i.e., the coal is continually failing). Based on nine cases, bottomhole pressure buildups after one hour in natu-
lnj~lon rates of 2040 bpm were the most successful. Results were best when treated wells were flowed back immediately, and at maximum possible rates. One well in the fairway was treatad twice, each with three cycles, and production results were excellent, increasing from 55 to 370 MCFD.
●
11
High pressure treatments in which bottomhole pressures are flat or rising, and ISIP exceeds 1.0 psi/ft. These are fractures confined to a coal seam, and are likely to be T-shaped geometries. Bottomhole pressures that fall with time, with ISIP less than 1.0 psi/ft. These reflect fractures with height growth into bounding zones of lower stress.
Examples of both kinds have been found in minebacks in the Warrior Basin, as reviewad elsewhere.7 No minebacks have been conducted in the San Juan Basin. However, in four out of six cavity recompletion in the fairway of the San Juan Basin, frac sand was returned to the surface during cleanout periods. These were cases in which the original well had been hydraulically fractured with sand, and the well later sidetracked to allow the cavity recompletion - the sidetrack is typically only about 30 ft from the original well. Now if the original fracture were a vertiial fracture, the chances of a typical 10-ft diameter cavity intercepting such a fracture would be far less than 4/6. The simplest interpretation ~. —-—._ of the observation is that the original fracture was T-shaped, and the horizontal component would have intercepted the new CSv~ weii. The o~iy 0ihi3TpOS3ibiitiy, thtii ~ Fiufi&f Of
593
red ““, RI wminrie gwsramn ,-, ~.. l=” “.”,-=”
7A nsi/ft --y-” ... Fnr . -. ~~~ iniactirm ..... . ... . . surainas. --. =...=-,
the average is .45 psi/ft. In all cases, air injection pressures are less than .59 psi/ft, which is lower than any virgin horizontal stresses measured in basal seams. This should imply injection below parting pressure, but the parthg pressure itself may be lowered due to stress relief around the wellbore.2 For air and water injections, bottomhole injection pressures are .80-1.14 psi/ft, and these all exceed the average minimum stress in the basal seams, implying fracture injection. 2. Cavity modeling results have been summarized. A principal benefit of the modeling has been to provide values for large-scale cohesion. The cavity stabilizes fairly quickly in the model, but often not so in the field, perhaps reflecting either lower cohesion coal (i.e., more soil-like) or coal heterogeneity. a. ~dt!~~l ~rarneters for su~essful cavitation: Cohesion is the most critical parameter. However, another important parameter is the pore pressure gradient near the surface of the cavity. This is a consequence of (a) Iarnehpid pressure changes at the wellhead, and (b) formation permeability. A third parameter, the in-situ stress condition, has less importance. A “stress threshold’ effect on cavity performance is not seen in the modeling. Finally, very low cohesion (i.e., soil-like behavior) probably explains cases in which coals are “running; and accompanied by “massive” coal returns at the surface, sometimes in the absence of pressure surging. This suggests cavities in excess of the typical 10-ft diameter measured in the field. 4. The key to coalbed methane success in the fairway maybe the ratio of perm/cohesion. Where this is large, cavity comnidinns.- ShOUI~ work better than fr~dure stimulations, and ~----vice-versa. 5. Recavitations have been very successful, but it is difficult to determine whether cleanout of fill in the well accounts for
COMPLETIONS AND STIMULATIONS FOR COALBED METHANE WELLS
12
this alone, or whether the original cavity completion is actually improved. 6.
7.
Pressure interference has been obsewed on a very shorl time scale at an observation well near a well being cavitated on two occasions. Air/water injections are not needed to see direct pressure response at the observation well, implying matrix communication and not fracture communication. A pulse interference analysis is used to calculate interwell permeekility, which largely agrees with other measurements. The technique appears to provide a new way of determining stressdependent permeability. Comparison of fracture treatments in the San Juan Basin: (1) South of the fairway, nitrogen foam fractures with no gel outperform slick water fractures. Slick water fractures outperform foam fractures with linear gel. (2) North of the fairway, wells stimulated with foam fracturing treatment perform much better than those tiimulated with slick water treatment. Overall, wells stimulated using cross-iinked gei do not perform as well as those stimulated with slick water treatments. The ratios in Table 3 are inflated because of one anomalous area with significantly better cross-linked
2.
Palmer, 1. D. and Vaziri, H., “Modeling of Openhole Cavity Completions in Coaibed Methane W3ii%” W% 28580, Procs. SPE Ann. Tech. Conf., New Orleans, LA, September 1994.
3.
Khodaverdian, M., Vaziri, H. Palmer, l., McLennan, J., “Openhole Cavity Completions in Coalbed Methane Wells Modeling of Field Data; Procs. Intergas ’95 Intl. Uncon. Gas Symp., Tuscaloosa, AL, May 1995.
4a.
Penny, G. S. and Conway, M. W., “Coordinated Studies in Support of Hydraulic Fracturing of Coalbed Methane: Annual Report to GRI, GR1-94/0398, August 1994.
4b.
Conway, M. W., Smith, K., Thomas, T., Schraufnagel, R. A., “The Effect of Surface Active Agents on the Relative Permeability of Brine and Gas in Porous Media; SPE 28982, Procs. SPE Intl. Symp. Oilfield Chemistry, San Antonio, TX, February 1995. Method for Fa!mer, i. ~. am~ gdw~r~e .P . ,A... l~rA~ irnnr~vd ~----.-. ,,” b“...-.-”,
5.
Stimulating a Coal Seam to Enhance the Recovery of Applic. Methane from the Coal Seam; Pat. No. 06/250,561, Pending, May 27, 1994.
flel ~-. oerf~rm~n~e, ~-
&
8.
Water fractures outperform foam fracture treatments with gel in the Arkoma Basin, and apparently in one play in the northeastern U.S.A. This is the same result as south of the fainvay.
s~idl~, J, P,, Jeanaonne, M. J., Erickson, D. J., “Application of Matchstick Geometry to Stress-Dependent Permeability in Coals; SPE 24361, Proos. SPE Rocky Mtn. Reg., p. 433, Casper, WY, 1992.
7.
9.
In the Warrior Basin, water fractures with sand outperform sandless water fractures (in gas prd”utiion) by a factor of
Palmer, L D., Lambert, S. W., Spitter, J. L., “Coalbed Methane Well Completions and Stimulations,” in Hydrocarbons AADR T, ,Ien 1 QO!l 4---e--l \w. l-d Law 1a.., allu en~ 1qlfi~\ II UIII Uual, ,“-,, m, w, , “,”-, .“”-.
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1, .-r, A Q,,“ zind +hau ● ,“,
10.
sw-“ hdtar “, ““..”. ammnqidlv -- ... .. .. . ... .
Foamed water cleanouts in the San Juan Basin boost gas production rates significantly as remedial treatments. The treatments probably create new flow channels in the proppant pack.
11. Hvdraulic fracture mometw: In the San Juan Basin there is new support for T-_haped _fracture geometry. On the other hand, in a play in the northeastern U.S.A., apparently most fractures were vertical, even when frac gradients exceeded 1.0 psi/ft, and horizontal fracture components were very rare. Acknowiedgniems We are grateful to Don Walton of Halliburton for providing assistance in compiling public date that was used to compare different fracture types south of the fairway in the San Juan Basin. Dale Kalcich of Halliburton assisted in compiling the database for fracture comparisons north of the fairway in the San Juan Basin. X. Wang of Technical University of Nova Scotia is acknowledged for performing the numerical analyses of the cavity model. Kent Sauvaugeau, Rudy Candelaria and Pete McNeal of Farmington O.C. are thanked for their support and assistance in acquiring the data for the pulse analysis. Reggie Waiters, Don Morgan, and L. G. Huitt of AITC are thanked for their spreadsheet and plotting analysis. Margie Meyer has been excellent in her desktop publishing support. Gas Research Institute, and Dick Schraufnagei, are acknowledged for their support of a contract to TerraTek under which part of this work was done. They also sup ported, along w“th Amoco, the original research at the COAL site. We thank Amoco for permission to publish this paper.
594
Wamariisl ~~~~~rn~n?for’ ~Qai Deg~S We!!%” M w. ,.,., ! ,“. ..-.-.
C
Pat. No. 4,913,237, April 3,1990. 9.
Palmer, L D., Kinard, C. M., Fryar, R. T., “Sandlees Water Fracture Treatments in Warrior Basin Coalbed%” Procs. 1993 Intl. Coalbed Methane Symp., Birmingham, AL, May 1993.
10. Young, G. B. C., Kelso, B., Paul, G., “Understanding Cavity Well Performance; SPE 26579, Procs. Ann. Tech. Conf., New Orleans, LA, September 1994. 11. Khodaverdian, M. F., McLennan, J. D., Palmer, L D., Vaziri, H. H., “Spalling and the Development of a Hydraulic Frac!~~ng stra?eg)/ for coal: Final ReDort to GRI, 1995. 12.
Muthukumarappan, R., “Analysis of the Success of Openhole Cavity Completions in the Fairway Zone of the San Juan Basin: Ph.D. Thesis, Mississippi State, MS, December 1994.
13. Mavor, M. J., “Coal Gas Resewoir Cavity Completion Well Performance; Procs. 1992 Intl. Gas Research Conf., Orlando, FL, 1992. 14. Logan, T. L., Mavor, M. J., Khodaverdian, M., “Optimization and Evaluation of Openhole Cavity Completion Techniques for Coalbed Methanev SPE 25859, Procs. Rocky Mountain Regional/Low Perm Sym., Denver, CO, 1993. 15. Young, G. B. C., Kelso, B. F., Paul, G. W., “Understanding Cavity Well Performance; SPE 28579, Proca. Ann. Tech. Conf., New Orleans, LA, 1994. 16.
Jochen, V. A. and Lee, W. J., “Reservoir Characterization of an Openhole Cavity Completion Using Production and Well Test Data Analysis; SPE 26917, Procs. Eastern Reg. Conf., Pittsburgh, PA, 1993.
17.
Mavor, M. J. and Logan, T. L., “Recent Advances in Coal Gas-Well Openhole Well Completion Technology” JPT, p. 587, July 1994.
References 1. Palmer, L D., Mavor, M. J., Seidle, J. P., Spitter, J. L., Volz, R. F., “Openhole Cavity Completions in Coalbed Methane Wells,” JPT, Vol. 45, p. 1072, November 1993.
,,”.e”,
1.PALMER, H. VAZIRI, M. KHODAVERDIAN, J. MCLENNAN, K. PRASAD, P. EDWARDS, C. BRACKIN, M. KUTAS, R. FINCHER 18. Soott, A. R. and Kaiser, W. R., “On the Geomeohanioe of Open-hole Cavity Completions in San Juan Basin Coalbed Gas Wefts,” Pres. Nofih American Rook Mechanics Symp., University of Texas at Austin, TX, June 1994. 19. Mavor, M. J., pars. oomm., 1994.
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