Bureau of Mines Report of Investigations/l978 

Foam Stimulation To Enhance 

Production From Degasification Wells 

in the Pittsburgh Coalbed 

UNITED STATES DEPARTMENT OF THE INTERIOR 
UNITED STATES DEPARTMENT OF THE INTERIOR 

Cecil D. Andrus, Secretary 

BUREAU OF MINES 
This pub1 ication has been cataloged as follows : 

Steidl, Peter F 

Foam st imulat ion to enhance product ion from degas if ication wells in the Pittsburgh coalbed / by Peter F. Steidl. 

[Washington] : U.S. Dept. of the Interior, Bureau of Mines, 

1978. 

10 p. ill., map, diagrams ; 27 crn. (Report of investigations - 

Bureau of Mines ; 8286) 

Bibliography: p. 8. 

1. Coal gasification. 2. Mine ventilation. 3. Methane. 4. 

Gas manufacture and works. I. United States. Bureau of Mines. 

11. Title. 111. Series: United States. Bureau of Mines. Report 

of investigations - Bureau of Mines ; 8286. 

TN23.U7 no. 8286 622.06173 

U.S. Dept. of the Int. Library 

I 
CONTENTS 

Page 

Abstract ................................................................. 1 

Introduction ............................................................. 1 

Acknowledgments .......................................................... 3 

Drilling. logging. and completion ........................................ 3 

Design and procedure for foam stimulation ................................ 4 

Production and production data ........................................... 5 

Well spacing .......................................................... 7 

Summary and conclusions ................................................. 7 

References ............................................................... 8 

Appendix A...Approximate costs per well .................................. 9 

Appendix B...Data on stimulation treatments .............................. 10 

ILLUSTRATIONS 

1 . Location of degasification wells ..................................... 2 

2 . Casing and surface equipment for degasification well ................. 4 

3 . Suggested well pattern to degasify part of a blocky coalbed .......... 7 

TABLES 

1 . Gas production data .................................................. 6 

2 . Gas analyses ..............,.......................................... 6 
FOAM STIMULATION TO ENHANCE PRODUCTION FROM DEGASlFlCATlON 

WELLS IN THE PITTSBURGH COALBED 

by 

Peter F. Steidl 1 

ABSTRACT 

Seven degasification wells have been completed in the Pittsburgh coalbed 

at the new Emerald mine near Waynesburg, Pa. Funding was provided by the 

Bureau of Mines to perform stimulation treatments on five of the wells, to 

show that this is a feasible and economical means of degasifying part of a 

coalbed. The seven wells ranged in depth from 590 to 910 feet. Stimulation 

treatments used 25,260 to 42,660 gallons of foam and 7,400 to 12,800 pounds 

of 20/40-mesh prop sand. Pumping rates were 10.8 to 11.6 bbl/min and treating 

pressures were from 1,050 to 1,600 psig. On the day following stimulation,gas 

production ranged from a few hundred cubic feet per day to more than 100,000 

cu ft/day. 

INTRODUCTION 

This project was designed to decrease the hazard of methane, allow 

increased production by reducing downtime, and lower ventilating costs. The 

proposal from Lykes Resources, Inc., suggested the use of foam stimulation, 

which was an innovation to the method being used by the Bureau. 

The Bureau has conducted research on hydraulic stimulation of coalbeds to 

increase gas production and speed degasification. The stimulation treatment 

propagates a fracture which connects many small fractures, thus increasing gas 

production from the coalbed. Degasification prior to mining in gassy coalbeds 

is important to mining safety and efficiency. Degasification wells have been 

completed and hydraulically stimulated with gelled water in the Hartshorne, 

Illinois No. 6, Mary Lee, Pittsburgh, and Pocahontas No. 3 coalbeds (4-5) - - .a 

The highest sustained production from any of these has been about 45,000 

cu ft/day from a well in the Pittsburgh coalbed in Greene County, Pa. 

In 1974, the management of Lykes Resources, Inc., appropriated funds for 

a program for coal degasification prior to mining when it was determined that 

lGeologist, Pittsburgh Mining and Safety Research Center, Bureau of Mines, 

Pittsburgh, Pa. 

2~nderlined numbers in parentheses refer to items in the list of references 

preceding the appendices. 
the Pittsburgh coalbed at the Emerald Mines Corp. property in Greene County 

would average more than 200 cu ft of methane per ton of coal in situ. This 

estimate was based on two coal cores analyzed by the direct method (6-7) - - that 

showed the coalbed to contain 188 to 208 cu ft of methane per ton. Moreover, 

these cores were taken from the part of the property with lowest overburden 

and probably the lowest gas content. A degasification program using 12 wells, 

spaced at about 12 acres per well around the slope and shaft, was proposed to 

reduce emissions of methane into the initial mine development (fig. 1). Lykes 

Resources, Inc., has had some previous experience with foam stimulation of gas 

wells completed in the upper portion of the Devonian shale near Youngstown, 

Ohio. The Bureau contracted with Lykes Resources for foam stimulation treatments on five of the seven wells completed. 

I 

W. Va. 

LEGEND 

0 Degosif icotion we1 1 

0 ,oo'~tructure contour 

0 400 600 1,200 feet 

I 

0 I80 360 mete rs 

FIGURE 1. - Location of degasification wells. 
AC KNOWLE DGME NT S 

The author wishes to thank G. H. Denton, former director of geology, 

Lykes Resources, Inc., and now with the Pittston Co., for setting up this 

project and negotiating the contract with the Bureau. Thanks are also 

extended to R. G. Rahsman, district geologist with Lykes, for providing information and data. 

DRILLING, LOGGING, AND COMPLETION 

Seven wells were rotary drilled to about 40 feet below the Pittsburgh 

coalbed to provide a sump for water accumulation. The 6-1/4-inch-diam wells 

were cased with 4-1/2-inch-OD casing that was set in the shale above the coalbed and cemented to the surface. A drillable, formation-packer shoe was set 

in the shale above the main bench of the Pittsburgh coalbed and below the 

rider coals to keep cement out of the coalbed and sump. This procedure was 

satisfactory except in the case of the deepest well (well 3), in which the 

packer failed and the hole was filled with cement. Another problem was that 

1 to 3 days were required for the service rig to drill out the packers. 

To accurately set the casing, gamma ray and neutron logs were run. These 

logs also provided information on thicknesses and depths of the Pittsburgh 

coalbed, roof shale (draw slate), rider coals, and overlying formations. 

In an attempt to demonstrate that the stimulation treatments did not 

damage the overlying rock, 3-D velocity logs were to be run on four of the 

wells, before and after stimulation. However, owing to gas bubbling through 

the water in two of the wells, the logs were not run after stimulation. In 

another hole, flowback after stimulation carried coal and rock into the bottom 

of the well, which prevented logging of the interval immediately above the 

coal. In the fourth well, the casing-to-cement bond was broken when the formation packer shoe was drilled out, and the rock properties of the roof interval were obscured on the log. 

In preparation for gas production, powerlines were run to all the wells. 

After stimulation and flowback, each well was equipped with 2-3/8-inch-OD production tubing, a rocker arm pump jack, sucker rods, and a downhole pump to 

dewater the coalbed (fig. 2). The pump was set about 10 feet off the bottom 

of the sump to allow for sand and debris accumulation. (See costs in 

appendix A. ) 
rWa ter separator and meter 

Gas to pipeline 

- - 

DESIGN AND PROCEDURE FOR 

FOAM STIMULATION 

A stimulation treatment 

propagates a fracture to 

increase the drainage radius 

of the well. To initiate 

fracture propagation, fluid 

is pumped into the coalbed 

under pressure. The foam 

used in these treatments was 

formed by pumping nitrogen 

into the water, which contained a foaming agent, to 

produce a 75 -percent nitrogen foam. Prop sand is 

added to the foam to keep 

the fracture open after the 

pressure is released, and 

the stimulation fluid is 

allowed to flow back. Compared with other stimulation 

fluids, foam has the advantages of high sand -carrying 

capability, low fluid loss, 

little formation damage, and 

quick fluid recovery (1). - 

Halliburton Services 

FIGURE 2. - Casing and surface equipment for degasifi- and Aircowelr performed 

cation well. the stimulation treatments 

on these wells. Design of 

foam stimulation treatments must take into account such factors as coalbed 

thickness, permeability and porosity of the coal, hydrostatic pressure, viscosity of foam, quality of water, downhole temperature, prop sand size and concentration, well-casing diameter, and others. Each of the seven foam 

treatments used an average of 8,200 gallons of water, 5 gallons of foaming 

agent per 1,000 gallons of water, 10,900 pounds of 10/20- or 20/40-mesh sized 

prop sand, and 300,000 std cu ft of nitrogen. (Details of each treatment are 

given in appendix B. ) 

Treatments started with about 900 gallons of water (water pad) followed 

by 600 gallons of foam pumped into the coalbed. This opens a fracture, 

creates a fluid-filled channel for the propping sand to pass through, and 

helps to prevent a blockage of sand (screenout) when foam, carrying prop sand, 

is pumped into the coalbed. The amount of sand added to the foam was 

increased gradually as an additional precaution against a screenout; the 

injection rate was also increased. Slight formation breaks (drops in pressure 

3Reference to specific manufacturers does not imply endorsement by the Bureau 

of Mines. 
as a fracture is initiated) were observed on some of these treatments. The 

treatments were completed with a flush of foam to push the sand into the 

coalbed. 

There were some exceptions to this procedure on four treatments where 

screenouts occurred. Following screenouts on wells 1 and 3, the wellhead 

valve was opened and treatment fluid was allowed to flow back and flush out 

the sand blockage; then the treatments were completed. Treatments on wells 6 

and 7 were terminated after screenouts occurred, since the treatments were 

almost completed. To avoid loss of treatment fluid into the coalbed and the 

resulting pressure loss, the wells were allowed to flow back as soon as possible. Flowback of the wells,immediately after the treatment, produced enough 

water to account for the treatment fluid plus some formation water. Although 

immediate flowback is advantageous, pieces of coal and underclay that were 

carried into the well caused cleanup problems on two wells. This might have 

been prevented by choking off the wellhead valve during flowback. 

PRODUCTION AND PRODUCT ION DATA 

To dewater the coalbed, the wells have been equipped with 16- and 24- 

inch-stroke Jensen sucker rod pumps with 84- and 100-bbl/day capacities, 

respectively. The 16-inch pumps are on the two wells that are more than 800 

feet deep. 

An attempt was made to use a submersible pump on well 4. It pumped only 

a few minutes and lowered thc hydrostatic pressure in the well. This caused 

the well to unload (gas blew water out through the annulus) and carry propping 

sand into the sump. Submersible pumps are effective for pumping large volumes of water, but a sufficient amount of clean water must be available. 

Water production was not metered since the gas pipeline and water separators were not installed. Gas production was measured several times (table l) 

using an orifice meter. 

Pumping on well 6 began 3 weeks after it was stimulated. On a few occasions over the following 8 weeks, the water level in this well was lowered 

enough that the gas pressure was sufficient to unload the well. Then for 

5 weeks it unloaded in surges. Flow rates of more than 50,000 cu ft/day of 

gas were measured with an orifice meter between water surges. 

The day after well 7 was stimulated, it began flowing more than 100,000 

cu ft/day with some water. Well 6 stopped unloading as water was forced downdip to it by the stimulation treatment performed on well 7. Well 7 flowed 

more than 120,000 cu ft/day for the next 7 weeks until the downhole pump 

failed and the resulting water fill-up in the well stopped gas flow. After 

9 weeks, the well was put back on production and flow returned at the previous 

rate. Orifice meter tests taken before well 7 stopped producing showed a 

total flow of 220,000 cu ft/day from the six wells in production. 
TABLE 1 . . Gas production data in cubic feet per day 

INo pump . "pump down . 

Date tested 

09 -24 -7 6 ........ 10-01-76 ........ 10-29-76 ........ 11.10.76 ........ 12 .14.76 ........ 01.08.77 ........ 01 .26.77 ........ 02 -08 .77 ........ 03.28.77 ........ 03 -29 .77 ........ 08-31-77 ........ 09.07.77 ........ 09.14.77 ........ 09-19 .77 ........ 10.13.77 ........ 10.20.77 ........ 10.27.77 ........- 7 .- 

After all the nitrogen from the treatments was flushed out. recent tests 

showed that the gas averages 91 percent methane (table 2) and has a heating 

value of 900 ~tu/std cu ft . Daily production data is not available because 

pipeline and metering equipment have not been installed . 

TABLE 2 . . Gas analyses. percent 

1 

. 

14. 000 

19. 500 

25. 200 

. 

. 

. 

10. 400 

9. 100 

. 

1. 070 

1. 080 

2. 430 

2. 730 

2. 720 

3. 060 

3. 060 

4 

(I) 

) 

(I) 

(I) 

(I) 

(I) 

40. 000 

. 

. 

16. 000 

7. 090 

7. 470 

8. 840 

. 

3. 510 

3. 510 

(2) 

3 

7, 500 

. 

16. 800 

16. 700 

23. 300 

24. 500 

42. 000 

. 

(') 

(") 

41. 400 

39. 800 

39. 800 

44. 400 

28. 200 

15. 200 

(" ) 

Well 

1 .................... 

1 .................... 

1 .................... 

3 .................... 

3 .................... 

4 .................... 

5 .................... 

5 .................... 

5 .................... 

6 .................... 

6 .................... 

6 .................... 

7 .................... 

7 .................... 

8 .................... 

8 .................... 

Well 

5 

942 

. 

14. 000 

. 

18. 100 

100. 000 

100. 000 

. 

117. 000 

. 

79. 800 

86. 400 

81. 900 

69. 700 

61. 100 

72. 300 

74. 800 

Date 

07-26-76 ............ 09-08-76 ............ 03-28-77 ............ 10-28-76 ............ 04-01-77 ............ 03-31-77 ............ 08-25-76 ............ 10-28-76 ............ 03-28-77 ............ 07-19-76 ............ 08-18-76 ............ 03-28-77 ............ 10-28-76 ............ 03-31-77 ............ 10-28-76 ............ 03-29-77 ............ 

6 

20.30. 000 

2- 8. 000 

10. 000 

100.34. 000 

(" ) 

(" ) 

(" ) 

. 

'800 

(a ) 

(" ) 

110. 000 

86. 400 

69. 700 

64. 100 

61. 100 

61. 100 

C02 

3.0 

4.3 

5.9 

3.3 

2.3 

9.4 

4.6 

5.0 

7.1 

3.9 

5.6 

6.5 

5.2 

4.7 

4.2 

5.9 

0. 

0.5 

. 4 

. 6 

. 1 

1.0 

. 7 

. 3 

. 6 

. 6 

. 6 

. 8 

. 1 

. 0 

. 4 

. 0 

. 4 

7 

120. 000 

122. 000 

140 000 

(') 

(2) 

105. 000 

58. 100 

(2 ) 

(") 

(') 

44. 400 

44. 400 . 

29. 900 

25. 200 

25. 900 

25. 200 

N2 

15.3 

10.2 

1.5 

. 3 

4.9 

2.0 

2.4 

1.2 

1.1 

2.4 

3.5 

. 7 

. 3 

1.4 

. 3 

2.4 

CH4 

80.8 

85.0 

91.7 

96.3 

91.7 

87.7 

92.5 

92.9 

90.9 

92.6 

89.8 

92.5 

94.1 

93.4 

95.3 

91.4 

8 

10. 800 

10. 800 

21. 000 . 

18. 200 

8. 100 

8. 390 

. 

. 

19. 000 

3. 510 

3. 510 

3. 140 

4. 740 

3. 216 

3. 140 

3. 140 

C2H, 

0.3 

. 2 

. 4 

. 1 

. 1 

. 3 

. 2 

. 3 

. 4 

. 4 

. 3 

. 3 

. 6 

. 1 

. 2 

. 1 

Total 

99.9 

100.1 

100.1 

100.1 

100.0 

100.1 

100.0 

100.0 

100.1 

99.9 

100.0 

100.1 

100.2 

100.0 

100.0 

100.2 
WELL SPACING 

Design of an economical 

degasif ication scheme 

depends greatly on proper 

well spacing (2). The 

direction of tEe face cleat 

in the coal should also be 

considered when laying out a 

well pattern (3). If possible, the pattern should be 

so designed that the largest 

spacing between wells is 

parallel to the face cleat 

direction. The well pattern 

shown in figure 3 has a 

LEGEND o 500 1,000 1,500 feet spacing of one well per 12.9 

0 Well location I I 

0 2 25 450 meters acres. This spacing may be 

too close for a longer term - 

FIGURE 3. - Suggested we1 l pattern to degasify part of degasif ication project . a blocky coalbed. 

Layout of a pattern 

should be considered before or during exploration drilling because a substantial reduction in cost can be made by using exploration holes as degasification wells. After they have been undermined, degasification wells can be used 

as rock dust, power drop, or gob degasification holes. 

Well spacing at Emerald mine ranges from 645 to 905 feet and averages 720 

feet or about 12 acres per well (fig. 1). This spacing proved to be satisfactory, except in the case of well 6 and well 1, which lie on a line parallel to 

the trend of the face cleat. Well 6 was stimulated; 6 weeks later, well 1 was 

stimulated and foam came out of well 6. Communication between these two wells 

suggests the well spacing was too close. In such a blocky coalbed with good 

fracture permeability, the well spacing could be increased. 

SUMMARY AND CONCLUSIONS 

Gas production from the treated wells that have low production was 

expected to rise substantially after the coalbed around them was dewatered, 

but has not, owing to mining in the vicinity of the wells, which has slowed 

gas production and will prevent the wells from being economical through gas 

sales alone. For mining companies, the major benefits to be derived are 

hazard reduction, increased coal production, and lowered ventilation costs. 

Continued production rates of 200,000 to 300,000 cu ft/day from the seven 

wells will show that degasification in advance of mining is feasible and 

economical in the Pittsburgh coalbed, considering the increased safety and 

coal production. 
REFERENCE S 

1. Blauer, R. E., and C. A. Kohlhass. Formation Fracturing With Foam. Soc. 

Petrol. Eng., AIME, paper SPE 5003, 1974, 18 pp. 

2. Cervik, J. Behavior of Coal-Gas Reservoirs. BuMines TPR 10, 1969, 10 pp. 

3. Diamond, W. P., C. M. McCulloch, and B. M. Bench. Use of Surface Joint 

and Photolinear Data for Predicting Subsurface Coal Cleat Orientation. 

BuMines RI 8120, 1976, 13 pp. 

4. Elder, C. H., and M. Deul. Degasification of the Mary Lee Coalbed Near 

Oak Grove, Jefferson County, Ala., by Vertical Borehole in Advance of 

Mining. BuMines RI 7968, 1974, 21 pp. 

5. . Hydraulic Stimulation Increases Degasification Rate of Coalbeds. 

BuMines RI 8047, 1975, 17 pp. 

6. McCulloch, C. M., and W. P. Diamond. Inexpensive Method Helps Predict 

Methane Content of Coalbeds. Coal Age, v. 81, No. 6, June 1976, 

pp. 102-106. 

7. McCU~~OC~, C. M., J. R. Levine, F. N. Kissell, and M. Deul. Measuring the 

Methane Content of Bituminous Coalbeds. BuMines RI 8043, 1975, 22 pp. 
APPENDIX A . ..APPROXIMATE COSTS PER WELL 

Service Costs 

Access and site preparation on company property ....................... $8. 500 

Drilling costs (735-foot average depth plus 30-foot sump) ............. 8.800 

Logging : 

Gamma ray and neutron log ........................................... 700 

Three-D velocity log (used on four wells) ........................... 1, 600 

Total ............................................................ 2.300 

Cementing 4-1/2-inch casing: 

Cement (175 sacks 50150 Pozmix and 5 pct salt) ...................... 550 

Other costs ......................................................... 495 

Total ............................................................ 1, 045 

Foam stimulation (30,OO 0- to 40,OO 0-gal treatment with sand proppant): 

Aircowell nitrogen service .......................................... 2, 650 

Halliburton Services ................................................ 4, 400 

Service rig (drill out cement packer and clean well) ................ 6, 000 

Water tank rental (2 tanks at $150 each) ............................ 300 

Water hauling (20. 000 gal at $100 per 15. 000 gal) ................... 140 

Total ........................................................... 13.490 

Powerline to pump ..................................................... 1. 100 

Well hookup (running tubing. rods. and setting pump) .................. 600 

Total for services ............................................... 35. 835 

Material Costs 

Casing. 4-1/2 inches OD (10.5 and 10 -7 lb/ft yellow band. test to 

3. 000 psig. with collars and formation-packer shoe. $2.85/ft) ........ 2. 570 

Tubing. 2-3/8-inches OD (4.6 lb/ft 355. nonupset. 10.round) ........... 500 

Sucker rods (reconditioned No . 1 grade. 5/8 inch with 718-inch box 

and pins). and wellhead (Alten threadless casing head. 4-1/2 inches 

by 2 feet) ........................................................... Pump jack (Jensen 24- and 16-inch-stroke 6.4B 32E24 or 16. 2-hp motor. 

1.800.rev/min. three.phase. 220- or 440-volt) and pump (Continental 

Emsco RWT insert pump. 2 inches by 1-1/2 inches by 7 feet with a 

Baird positive lift valve) ........................................... 2. 000 

Gas pipeline. meters. separators. and installation (not complete) ..... 10. 000 

Total for materials .............................................. 15. 470 

Grand total cost per well ........................................ 51. 305 
APPENDIX B . =.DATA ON STIMULATION TREATMENTS 

Summaries of Fracture Treatments 

*U.S. GOVERNMENT PRINTING OFFICE: 1979-603-002134 lNT.-BU.0 F MIN ES,PGH.,P A . 2294 1 

Foam volume. 

gal 

33. 000 

25. 260 

39. 000 

31. 500 

29. 200 

29. 000 

42. 660 

Well No . 

1 ....... 

3 ....... 

4 ....... 

5 ....... 

6 ....... 

7 ....... 

8 ....... 

Treatment 

date. 

1976 

06-01 

08 -18 

08 -25 

09 -01 

04 -15 

09 -08 

09 -15 

Sand weight. 

pounds 

12. 500 

11. 000 

10. 000 

10. 000 

14. 000 

7. 400 

12. 800 

Depth to base 

of coal. feet 

64 1 

9 08 

84 9 

770 

588 

734 

652 

Treatment 

pressure. 

psig 

1. 400 

1. 600 

1. 300 

1. 375 

1. 500 

1. 400 

1. 050 

Injection 

rate. 

bb l/min 

11.2 

11.2 

10.8 

11.6 

17.7 

10.8 

10.8