Bureau of Mines Report of Investigations/l975 

Hydraulic Stimulation Increases 

Degasification Rate of Coalbeds 

UNITED STATES DEPARTMENT OF THE INTERIOR 
Report of Investigations 8047 

Hydraulic Stimulation Increases 

Degasification Rate of Coalbeds 

By C. H. Elder and Maurice Deul 

Pittsburgh Mining and Safety Research Center, Pittsburgh, Pa. 

UNITED STATES DEPARTMENT OF THE INTERIOR 

Rogers C. B. Morton, Secretary 

Jack W. Carlson, Assistant Secretary-Energy and Minerals 

BUREAU OF MINES 

Thomas V. Falkie, Director 
This publication has been cataloged as follows: 

-$ 

Elder, Curtis H 

Hydraulic stimulation increases degas if icat ion rate of 

coalbeds, by C. H. Elder and Maurice Deul. [Washington] 

U.S. Bureau of Mines [1975] 

17 p., illus., tables. (U.S. Bureau of Mines. Report of investigations 8047) 

Includes bibliography. 

1. Degassing of coal. I. U.S. Bureau of Mines. 11. Deul, 

Maurice, jt. auth. 111. Title. (Series) 

TN23.U7 no. 8047 622.06173 

U.S. Dept. of the Int. Library 

A 
CONTENTS 

Page 

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

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

Description of hydraulic stimulation .................................... 2 

Equipment ............................................................... 2 

Hydraulic stimulation treatment design .................................. 3 

Examples ................................................................ 4 

Pocahontas No . 3 coalbed. Buchanan County. Va ...................... 4 I Mary Lee coalbed. Jefferson County. Ala ............................ 7 

Pittsburgh coalbed. Washington County. Pa .......................... 11 

Observed induced fractures in coalbeds .................................. 14 

Discussion and conclusions ............................................. 15 

References .............................................................. 17 

ILLUSTRATIONS 

Lithology. gamma ray. and density log of strata overlying the 

Pocahontas No . 3 coalbed. Buchanan County. Va .................... 5 

Wellhead pressure and injection rate charts of hydraulic stimulation treatment of Pocahontas No . 3 coalbed ....................... 6 

Hydrafrac of horizontal hole in Pocahontas No . 3 coalbed ........... 7 

Gas and water production rates following hydraulic stimulation 

treatment of Pocahontas No . 3 coalbed ............................ 8 

Lithology. gamma ray. and density log of strata overlying the Mary 

Lee coalbed. Jefferson County. Ala ............................... 9 

Wellhead pressure and injection rate charts of hydraulic stimulation of Mary Lee coalbed ......................................... 11 

Gas and water production rates before and after hydraulic stimulation treatment of Mary Lee coalbed ............................... 12 

Lithology. gamma ray. and density logs of strata overlying the 

Pittsburgh coalbed. Washington County. Pa ........................ 12 

Wellhead pressure and injection rate charts of hydraulic stimulation treatment of Pittsburgh coalbed ............................. 14 

Gas and water production rates before and after hydraulic stimulation treatment of Pittsburgh coalbed ............................. 15 

TABLES 

1 . Hydraulic fracture stimulation plan. site 1. hole 3 SW. Jefferson 

County. Ala ...................................................... 10 

2 . Criteria used in computation of hydraulic fracture stimulation plan. 

site 1. hole 3 SW. Jefferson County. Ala ........................... 10 

3 . Hydraulic fracture stimulation plan. site 3. hole 1 NE. Washington 

County. Pa ........................................................ 13 

4 . Criteria used in computation of hydraulic fracture stimulation plan. 

site 3. hole 1 NE. Washington County. Pa .......................... 13 
HYDRAULIC STIMULATION INCREASES DEGASlFlCATlON 

RATE OF COALBEDS 

by 

C. H. Elder and Maurice Deul2 

ABSTRACT 

Coal degasification boreholes drilled from the surface have been success - fully hydraulically stimulated to increase the flow of gas from the coal. 

This Bureau of Mines report describes the hydraulic stimulation procedure for 

a coalbed, the equipment required, and design criteria for the treatment. 

Three examples of stimulation treatment show from fivefold to twentyfold 

increases in gas production. The tests were conducted in the Pocahontas No. 3 

coalbed, Buchanan County, Va., the Pittsburgh coalbed, Washington County, Pa., 

and the Mary Lee coalbed, Jefferson County, Ala. Two sites where the coal was 

hydraulically stimulated and exposed by subsequent mining show no adverse 

effect on mining operations through the treated zones. The induced vertical 

partings were confined to the coalbed and did not in any way affect either 

roof or floor rock. 

INTRODUCTION 

Drilling degasification holes into the coalbed in advance of mining is 

one method to reduce the formation pressure and to remove a large volume of 

the contained methane. Gasflow into a borehole is dependent upon coalbed 

permeability and formation pressure. A greater rate of degasification can be 

achieved by increasing coalbed permeability in the drainage area and by 

increasing the surface area exposed for more rapid desorption. Hydraulic 

stimulation of a coalbed is designed to accomplish this. 

Twelve test degasification boreholes drilled into coalbeds have been 

hydraulically stimulated. Production has increased in these treated boreholes 

from fivefold to twentyfold. These preliminary production results show that 

this is a valuable stimulation technique and warrants further development. 

This Bureau of Mines report describes the hydraulic stimulation procedure 

and gives examples of the application of this technique in three coalbeds. 

2~esearch supervisor. 
DESCRIPTION OF HYDRAULIC STIMULATION 

Hydraulic stimulation increases fluid flow by inducing or extending a 

vertical parting in a selected section of a formation or coalbed by applying 

hydraulic pressure with controlled injection of gelled water. The parting 

achieved in this way is extended several hundred feet into the coalbed by 

continued pumping of a large volume of the treatment fluid. The length of 

induced parting depends upon the injection rate, formation strength characteristics, volume of treatment fluid, and the flow characteristics of the 

fluid. Sized particles, such as sieved sand, added to the gelled fluid are 

carried into the induced parting and serve as a propping agent to hold the 

parting open after the applied hydraulic pressure is released. The propped 

parting provides a highly permeable path to the borehole. The hydraulic 

fluid is water-gelled with a natural gum and contains chemical additives that 

cause the gel to break down and revert to a fluid of water viscosity after a 

few hours. This allows for the removal of the fluid from the induced parting 

and the borehole after stimulation treatment. The borehole is cleared of 

excess sand and treatment fluid and put on production for degasification of 

the coalbed. 

The hydraulically induced parting should be contained within the coalbed, 

and its orientation should be vertical and my follow the direction of the 

major cleat or joints. Hubbert and Willis (9)s state that hydraulically 

induced fractures should form approximately perpendicular to the least 

principal stress and that in tectonically relaxed areas the least stress will 

be approximately horizontal; therefore, the fracture would be oriented vertically. They state further that not only will the fractures be vertical, 

but they also should have roughly the same direction of strike in all boreholes treated within the immediate area. Fraser and Pettit (g), from a field 

test in the Howard Glasscock field in Howard County, Tex., where impression 

packer tests were run, concluded that the fractures are vertical even at very 

shallow depths and that the theoretical relationships between tectonic stress 

conditions, fracture type, and orientation are valid in their test area. 

Daneshy (2) deduces from his study that in practice, the well bore may contain 

discontinuities in the form of preexisting cracks (cleat and joints in coal) 

and bedding planes, that such features will locally change the stress distribution in their vicinity, and that they are likely placed for fracture orientation. Harrison and Kieschnick (8) from their studies that where a 

consolidated sand is bounded by nonbrittle shales the vertical extent of 

the fractures would be limited by the shales; in west Texas relatively low 

horizontal compressive stresses and already existing fractures offered relatively little resistance to fracture induction and extension. 

EQUIPMENT 

The equipment for hydraulic stimulation consists of truck-mounted highpressure positive-displacement injection pumps, gelled water, a storage tank, 

and a truck-mounted blender and sand proportioner. 

sunderlined numbers in parentheses refer to the list of references at the end 

of this report. 
A typical pump unit is capable of delivering 1,000 hydraulic hp with up 

to 42 bbl/min injection rate at high pressure, although the burst pressure of 

casing or tubing is never exceeded. 

The blending equipment consists of booster pumps, semiautomatic proportioners, and a jet blender for inline mixing of gelled fracturning fluid, 

chemical additives, and a propping agent at the volume capacity matching the 

pump unit. A storage tank for water and fracture fluid equal to the batch 

volume of the hydraulic stimulation treatment is placed on site at a location 

convenient to the pumping, blending units, and the borehole. A hopper truck 

is used for carrying and dispersing the propping agent (10- to 20-mesh sand) 

to the proportioner and jet blender for the fracture treatment. 

Recording flow and pressure meters are used to monitor the mixing of 

chemicals and propping agent, injection rate, and wellhead pressures to 

provide control during the fracture stimulation treatment. 

HYDRAULIC STIMULATION TREATMENT DESIGN 

Procedures in h he Fracbook ~esign/~ata Manual" (l) of Halliburton 

Services, Duncan, Okla., were used to select a hydraulic treatment design. 

The procedures incorporate borehole and formation factors, engineering theory, 

and results of case studies in preparing an effective fracture plan. 

The following criteria are used in developing a stimulation treatment 

design: 

Injection rate 

Assumed fracture height 

Net formation thickness 

young's elastic modulus 

Formation permeability 

Formation porosity 

Bottom hole treatment pressure 

Reservoir pressure 

Fluid loss coefficient 

Spurt loss coefficient 

Type of gel 

Gel concentration 

Well spacing 

Drainage radius 

Well bore radius 

Damage ratio 

Flow behavior index 

Fracture fluid consistency index 

Type and concentration of propping agent 

bbl/min 

feet (coalbed thickness) 

feet (coalbed thickness) 

lb / in2 

md 

lb/1,000 gal 

acreage 

ft 

ft 

mesh size -sand lb/gal 

average 

The values for the design criteria are used in calculating created fracture length, length of propped fracture, height of propper fracture, amount of 

propping agent required, and expected production increase for various volumes 

of treatment. ~roi these calculated results the best treatment plan is selected. 
An injection rate of 10 bbllmin was selected for relatively thin coalbeds 

to contain the propogated fracture within. the cohbed. A greater injection 

rate should tend to create higher fracture heights. A lower injection rate 

could have so low a fluid velocity that the propping sand could settle out, 

plug the created fracture, and effectively stop the hydraulic fracture stimulation procedure. 

A volume of fracture fluid or pad is pumped into the formation to 

initiate and condition the fracture before the propping agent is added. The 

volume used is determined from evaluation of formation factors. Formation 

factors such as coalbed thickness, porosity, permeability, and formation 

pressure were obtained from exploratory core hole drilling records and test 

results obtained during the drilling of the degasification boreholes. Gas 

pressures in the coalbed were measured by bottom-hole pressure buildup tests. 

Permeability was calculated from the bottom-hole pressure buildup curves and 

gas and/or water production data obtained during drill stem test (dst). 

Porosity of the coalbed was obtained from laboratory tests and from estimates 

of inplace porosity related to the joint or cleat spacing of the coalbed as 

observed in nearby mines and from core samples. A value of 0.3 X lo6 for 

Young's modulus of elasticity was used for coal in the design (5). - 

Other design criteria relating to fluid properties and flow properties 

were obtained from tables and charts in the Fracbook (7), developed by experimental research in Halliburton's laboratory. The ~aliiburton Services computer was used in calculations for design of each treatment program. 

EXAMPLES 

Three hydraulic stimulation treatments have been successfully completed 

in the Pocahontas No. 3 coalbed, Buchanan County, Va., the Mary Lee coalbed, 

Jefferson County, Ala., and the Pittsburgh coalbed, Washington Country, Pa. 

Pocahontas No. 3 Coalbed, Buchanan County, Va. (2) 

A test hole was drilled into a projected barrier pillar in an area not 

to be mined for several years. The test site is in central Buchanan County, 

Va. The hole penetrated a series of Pennsylvanian sandstones, shales, and 

coals to test the gassy Pocahontas No. 3 coalbed. The 1,530-foot-deep hole 

was logged with a gamma ray-density logging tool to obtain geophysical data 

on formation density, porosity, and lithology (fig. 1). The 8-inch-diameter 

hole was cased with 4.5-inch steel casing from the surface to the top of the 

coalbed, and the casing was pressure-cemented. 

Monitoring equipment consisting of a flowmeter and pressure gages was 

installed. Waterflow was measured at 1.3 gallhr. The inflowing water 

inhibited the flow of gas and required frequent swabbing to maintain a gasflow. 

The borehole flowed gas at 600 ft3/d with continued swabbing to rid the hole 

of water. 

In July 1970, a hydraulic stimulation procedure designed by the Bureau of 

Mines was attempted. The coalbed was treated successfully with a thickened 
21 22 23 23 25 

/ 

2627 u 

so h I?"-- BULK ---- DENSITY, g/cmS 
water-base fracturing fluid containing 10- to 20-mesh sand as a propping agent 

(fig. 2). The initial fracture in the coalbed occured at 3,200 lb/in2. The 

fractures were propagated into the coalbed with 2,400 to 3,450 lb/in2 pump 

pressure at an average injection rate of 10 bbl/min of gelled-water fracturing 

fluid. Fourteen thousand eight hundred gallons of fracturing fluid and 

4,000 lb of 10- to 20-mesh propping sand were injected into the induced fractures in the coalbed. The high initial fracture at 3,200 lb/in2 is caused 

by complex residual tectonic forces in the area of the test hole (9). - 

An additional factor for the high break pressure may be due to borehole 

damage. Cervik and Cetinbas (L), in research on water infusion for methane 

control, experienced difficulty infusing the friable Pocahontas No. 3 coalbed 

through a horizontal hole drilled into the coalbed from mine workings. An 

experiment was conducted to determine if a zone of reduced permeability surrounded the horizontal borehole. A 1-inch-pipe was grouted to a depth of 

195 feet in a 200-foot hole. Gasflow rate from this 5 feet of hole was 

300 ft3/d. The hole was fractured with water. Break occurred at 1,200 lb/in2 

followed by an abrupt drop in pressure (fig. 3); a secondary fracture occurred 

shortly afterwards. Water injection rate during treatment was 15 gal/min, the 

maximum capacity of the pump. Gasflow after treatment about a month later was 

13,000 ft3/d. 

After stimulation treatment of the vertical borehole, the hole was 

swabbed to remove water and gasflow was monitored. On the first day, waterflow decreased from 120 to 20 gal/hr. Gasflow increased from 2,500 to 

3,500 fts/d (stp) as water was drained from the expanding drainage radius. 

During the second day waterflow averaged 15 gal/hr but flowed in surges; the 

TIME, min 

- I/2 l b/gol sand - 

Resume - 

Flow well bock 

I . 1 I I - 

f 

FIGURE 2. - Wellhead pressure and injection rate charts of hydraulic stimulation treatment of 

Pocahontas No. 3 coalbed. 

w' 

2 

Em- 1 

I I I I I I I . 20 30 40 50 60 70 80 90 100 I0 

1 1 I I I I I I I 1 

- 

Injection rote - 

? 
TIME, min tal degasification of the 

Mary Lee coalbed in advance 

FIGURE 3. - Hydrafrac of horizontal hole in Pocahontas of mining (4). Five holes 

No. 3 coalbed. (1,081 to 1T093 feet total 

depth) were drilled in a 

gasflow increased from 

3,500 to 9,900 ftVd (stp). 

The fourth day, gasflow 

rates increased to 

12,000 fF/d (stp), while 

- the waterflow rate decreased, 

OW flowing an average of 

10 gal/hr during flow 

periods, but with a longer 

flow-nonflow cycle. On the 

fifth day gasflow stabilized, 

. - averaging 12,000 f@/d (stp), 

ul 

a while the waterflow rate 

continued to decline to 

W 

800- - 2.9 gal/hr flowing in cycles 

pattern on a structural nose on the flank of the Sequatchie anticline. The 

holes penetrate Pennsylvanian sandstones, shales, and coalbeds (fig. 5). 

Drilling was completed in July 1971. Hole 3 SW was drilled to the top of the 

of 12 hours of nonflow 

(fig. 4). 

The twentyfold increase 

in gas flow was, indeed, 

encouraging. It was evident, 

however, that a pumping or 

swabbing service must be 

provided to remove the water 

inflow to maintain stable 

gas product ion. 

Mary Lee Coalbed, 

Jefferson County, 

- Ala. 

A test site was located 

in section 23, T 18S, R 6 W 

near Oak Grove, Jefferson 

3 

m 

m 

W 

[L 

a 

600- Secondary - 

W 

I- fracturing a 

3 

400 - - 

200 - a-Fill ing up the water line - and borehole 

b-Occurrence of hydraulic 

f racturing *-a - b 

coalbed at a 1,075-foot depth and cased with 7-inch steel casing. After 

0 10 20 30 40 County, Ala. , for experimenI 

casing the hole, 5 feet of coalbed was cored and the borehole was put on pro1 

duction. Gas production was low at the start but increased as the coalbed was 

dewatered. The maximum production was from borehole 3 SW. After 16 months, 

production from this hole had reached an average of 5,000 f@/d gas with 

6 bbl/d water. A stimulation treatment was then planned to test the effectiveness of stimulation of this coalbed to increase the degasification rate. 
TIME, days 

FIGURE 4. - Gas and water rates following hydraulic stimulation treatment of 
GAMMA RAY, 

API UNITS 
A hydraulic stimulation treatment program was prepared with the aid of a 

design plan of Halliburton Services . Design 2 from a computer calculation 

(tables 1 and 2) selected for the treatment plan provided for 10. 000 gal 

of gelled water. with a 2.50 0.gal water pad to be injected into the coal 

at 10 bbl/min to propagate a fracture or parting . Six thousand pounds of 

10- to 20-mesh sand were mixed with the fracture fluid at the rate of 

314 lb/gal to serve as a propping agent in the induced fracture after 

treatment . 

TABLE 1 . . Hydraulic fracture stimulation plan. site 1. hole 3 SW. 

Jefferson County. Ala . 

Source: Computer computation from Halliburton Services . 

Design 

No . 

1 ..... 

2 ..... 

3 ..... 

4 ..... 

TABLE 2 . . Criteria used in computation of hydraulic fracture stimulation 

plan (7). site 1. hole 3 SW. Jefferson County. Ala . 

Injection rate ........................................... bblldn .. Assumed fracture height ....................................... ft .. Net formation thickness ....................................... ft .. Plastic modulus .......................................... .lb/in 2. . Formation permeability ........................................ md .. Formation porosity ........................................... pct .. Bottom hole treatment pressure ........................... .lb/in2 .. Reservoir pressure ........................................ lb/in2 .. Reservoir fluid vis ........................................... cp .. CW-- Fluid loss coef .................................... f t/minll2 .. Spurt loss ............................................... g al/ft2 .. Type of gel (Halliburton) ......................................... Gel concentration ................................... 1, 00 gal .. n'-Prime .......................................................... k' -prime (slot) ..................................... lbr -secn /ft? .. Well spacing ............................................... acres .. Drainage radius ... .....................*...*..*.**.*...*... ... ft.. 

Wellbore radius . .............................................. ft .. Damage ratio ...................................................... Type and conc prop sand (8-12-mesh) ................... lb/gal avg .. 

Production 

increase 

7.5 

11.7 

15.6 

19.4 

The treatment was done through 2-718-inch high-pressure tubing with a 

tension packer in the string set at 988 feet in the 7-inch casing . The bottom 

of the tubing was at the midpoint of the coalbed . 

Volume. 

1. 000/gal 

Total 

5.0 

10 

15 

20 

Pad 

2.5 

2.5 

2.5 

2.5 

Propped 

fracture. 

feet 

Viscos . 

i ty 

CP 

6 

7 

7 

7 

Length 

105 

255 

377 

437 

Height 

5.2 

5.5 

5.6 

5.7 

Fracture. 

width 

inch 

0.207 

. 242 

. 266 

. 234 

Prop 

sand. 

sacks 

19 

56 

94 

131 

Created 

fracture 

length. 

feet 

233 

758 

1. 040 

1. 007 
The initial fracture of the coal occurred at 800 lb/in2 gage. The fracture was extended into the coalbed at 1,100 to 1,200 lb/in2 pumping pressure 

and a steady 10 bbllmin injection rate. Ten thousand gallons of gelled water 

and 6,000 lb of 10- to 20-mesh propping sand were pqed into the coalbed 

during propogation of the fracture (fig. 6). After treatment, the borehole 

was swabbed free of water, and 30 feet of sand fillup was cleared from the 

borehole. After the water pump was installed, the borehole was returned to 

production. All fracturing fluid was recovered. 

The gasflow increased after treatment from 5,000 ft3/d to a maximum rate 

of 90,000 ft3/d in 11 days (fig. 7). During the next 7 months a normal 

decline in flow occurred. The flow rate stabilized at 50,000 ft3/d. The 

actual tenfold production is very close to the calculated production increase 

of 11.7-fold. 

Pittsburgh coalbed, Washington County, Pa. 

A test site was located near Lone Pine, Washington County, Pa., for 

experimental degasification of the Pittsburgh coalbed in advance of mining. 

Four holes 405 to 552 feet in depth were drilled in a pattern on the flank 

of the Amity anticline. The holes penetrated Pennsylvanian sandstones, 

C 

. - - 

E 

1 Mixing fracture fluid 

,o 20- 

- 1/2 Ib sand /gal 

w - Formation - 

5 break 

34 Ib sand/gal 

- 3 

- 

I I 1 1 Ill11 I I I I 

TIME, min 

4,000 

. - 3,000 

V) 

a 

FIGURE 6. - Wellhead pressure and injection rate charts of hydraulic stimulation of 

Mary Lee coal bed. 

11 I 1 I I 111111 

- Pressure test - 

- - 

- - W 

9 2,000 - -Formation break - m 

m at 800 psi W - Q: 

- 

a 

1,000 - - 

- \ - 

1 I, 

0 4 8 12 16 20 24 28 32 36 40 44 48 
10.000 ------ --------- 

Jan. hh Mor Apr. Mq Jlnr July kpt Oct. Nou D.c &I Flh & Ap W July Aug fpl &I 1973 1974 

FIGURE 7. - Gas and water production rates before and 

after hydraulic stimulation treatment of 

Mary Lee coalbed. 

shales, limestones, and coalbed (f ig. 8). Nine -inchdiameter holes were drilled 

near the top of the coalbed 

and cased with 7-inch steel 

casing. After the holes 

were cased, the 7-foot coalbed was cored and the boreholes put on production. 

Initial gas production 

beginning in June 1972 was 

low but increased as the 

coalbed was dewatered. 

After 18 months, gas produc - 

tion from borehole 1 NE 

stabilized at an average of 

7,000 ft3/d with 4-114 bbl/d 

of water. This borehole was 

fracture-treated to improve 

degasification rate and test 

the effectiveness of stimulation of the Pittsburgh 

coalbed. 

The hydraulic stimulation treatment program was 

FIGURE 8. - Lithology, gamma ray, and density logs of 

strata overlying the Pittsburgh coalbed, 

Washington County, Pa. 

Ti 

- 

- 

- 

< - 

- 

- 

- 

o 200 

GAMMA RAY, ~ULK DENSITY. g/cm3 inch casing. 

API UNITS 

I -=+== - 7f - 

- - 

- - 

- - 

- - 

- - 

- - 

- - 

I 

20 2.5 3.0 

' prepared utilizing a design 

plan of Halliburton Services. 

Design 2 from the computer 

output, selected for the 

treatment plan (tables 3 and 

4), provides for 10,000 gal 

of gelled water with a 

1,600 -gal water pad to be 

injected into the coal of 

10 bbllmin. Six thousand 

pounds of 10- to 20-mesh 

sand were mixed with fratture fluid at the rate of 

112 to 314 lb/gal to serve 

as a propping agent in the 

induced fracture. 

The treatment was done 

through 2-718-inch highpressure tubing with a 

tension packer in the string 

set at 412 feet in the 7- 
TABLE 3 . . Hydraulic fracture stimulation . plan. site 3. hole 1 NEy 

Washington County. Pa . 

Source: Computer computation from Halliburton Services . 

TABLE 4 . . Criteria used in computation of hydraulic fracture stimulation 

plan (7). site 3. hole 1 NE. Washington County. Pa . 

Design 

No . 

1 ...... 

2 ...... 

3 ...... 

4 ...... 

The initial fracture of the coal was achieved at 500 lb/in2 gage . The 

fracture was extended into the coalbed at 1. 200 to 1. 400 lb/in2 pumping pressure and a steady 11.4-bbl/min injection rate . Ten thousand two hundred and 

thirty gallons of gelled water and 6. 000 lb of 10- to 20-mesh propping sand 

were pumped into the coalbed during propagation of fracture (fig . 9) . Midway 

through the pumping. the formation plugged . The system was allowed to backflow to clear the blockage and the treatment was completed . After treatment 

the borehole was swabbed free of water. and a few feet of sand accumulation 

was cleaned from the borehole . With reinstallation of the water pump. the 

borehole was returned to production . All fracturing fluid was recovered . 

Production 

increase 

9.2 

13.2 

15.2 

19.4 

Propped 

fracture. 

feet 

Injection rate ...................................... n .. Assumed fracture height ....................................... ft .. Net formation thickness .... .................................. .ft .. Elastic modulus ........................................... /in2 . Formation permeability ........................................md.. 

Formation porosity ............................................ pct .. Bottom hole treatment pressure ......................... .. .lb/in2 .. Reservoir pressure ........................................ lb/in2 .. Reservoir fluid vis ........................................... cp .. CW-. Fluid loss coef ................. ... ......... .. .... £t/min1I2 .. Spurt loss ............................... ... ............ .gal/£t2 .. Type of gel (Halliburton) ......................................... Gel concentration ................................... b/lOOO gal .. nl-Prime .......................................................... kt-prime (slot) ..................................... lb,-secn/ft2 .. Well spacing ............................................... acres .. Drainage radius ............................................... ft .. Wellbore radius ................................................ ft .. Damage ratio ...................................................... Type and conc prop sand (10 -20 -mesh sand) ............. lb/gal avg .. 

Viscos . 

ity 

C P 

4 

4 

5 

5 

Length 

165 

309 

433 

547 

10.0 

7.0 

6.0 

0.30 X 106 

5.0 

0.04 

722.0 

166.0 

0.02 

0.0031 

0.21 

WG-6 

20.0 

0.728 

0.000898 

30.0 

563.0 

0.25 

3.0 

0.75 

Volume. 

1. 000/gal . 

Height 

4.9 

5.2 

5.3 

5.4 

Fracture. 

width 

inch 

0.221 

. 253 

. 273 

-289 

Total 

5.0 

10 

15 

20 

Pad 

1.0 

1 

1 

1 

Prop 

sand. 

sacks 

30 

68 

105 

143 

Created 

fracture 

length. 

feet 

397 

862 

907 

1. 133 
Start sand 1/4 lb/gal 

1/2 Ib/gal 

r 3/4 Ib/gal 

rC~t sand 

4 ttt t C -m 

1 I Complete flush 7 I 

 for motion break 500 psi I A 

TIME, min 

FIGURE 9. - Wel lhead pressure and iniection rate charts of hydraulic stimulation treatment of 

Pittsburgh coolbed. 

The gasflow increased after treatment from an average of 7,000 ft3/d to 

a rate of 35,750 ft3/d in 3-1/2 months. Gas production had not stabilized 

(fig. 10). 

OBSERVED INDUCED FRACTURES IN COALBEDS 

The No. 6 coalbed in Jefferson County, Ill., was hydraulically stimulated 

in a degasification borehole about 1,500 feet in advance of mining. The stimulation design provided for the injection of 12,000 gal of fracturing fluid and 

6,400 lb of 10- to 20-mesh propping sand. The induced fracture was observed 

in the coalbed where it intercepted development entries in the mine. The sandpropped fracture occurred in the upper part of the coalbed, extending from the 

roof to a 3-inch shale parting 22 inches above the floor. The induced fracture was mapped for 416 feet from the borehole striking in a direction of 

N 76' E. The fracture was a single vertical plane, 1/8 to 114 inch wide, and 

7 feet high. It was filled with propping sand from the roof to a shale 

parting 22 inches above the floor of the coalbed. A hairline crack in the 

roof was exposed where the continuous miner removed a small area of head coal. 

The head coal generally is left in place during mining for roof control. The 

crack extended a few inches into the roof rock. It did not contain sand or 

fluid. The roof rock was dry and sound across the crack and showed no offset 

or weakness. Production data on stimulation effect for this test site showed 

an increase from initial production of 100 to 200 ft3/d to 4,300 ft3/d. 
FIGURE 10. - Gas ond water production rotes before and after hydraulic stimulotion treotment 

of Pittsburgh coalbed. 

A test hole in the Pittsburgh coalbed in Washington County, Pa., was 

drilled 500 feet in advance of mining and hydraulically stimulated to specifically observe the effect of fracturing. The induced fractures were exposed 

during mining; they were vertical, extending from roof rock to floor rock. 

There is no evidence of fractures extending into the roof or floor rock of the 

mine, and the roof and floor of the mine were dry and sound. The induced 

fractures within a few feet of the test hole ranged from 1/8 to 2-1/2 inches 

in width and were filled with 10- to 20-mesh propping sand from floor to roof. 

The fractures were propagated along the butt and face cleat directions in the 

coalbed. The total length of the induced fractures had not been exposed-by 

mining at the time of this writing. 

DISCUSSION AND CONCLUSIONS 

Coalbeds can be successfully hydraulically stimulated from a borehole to 

increase the rates of gas production. The gas production rate after stimulation shows an increase of from fivefold to twentyfold over the production rate 

before stimulation. 
A vertical induced fracture is expected in the coalbed due to the strong 

jointed character of the coalbed and also due to the fact that the injection 

pressures are normally too low to lift the overburden for a horizontal 

fracture. 

Impression packers have shown that vertical fractures were created 

perpendicular to the least in situ pressure in the formation; generally their 

direction is affected by major joints in the formation. 

Vertical induced fractures observed in the No. 6 coalbed of Illinois and 

the Pittsburgh coalbed of Pennsylvania were contained within the coalbed. No 

adverse effect or extension of the induced fractures into the roof or floor 

rock of the mine was evident. The width and length of the induced fractures 

observed in coalbeds correlate closely to the calculated values in the treatment designs. From these observations, it is evident that hydraulic stimulation treatments can be designed to increase degasification rates from a 

coalbed without creating hazardous conditions for mining. 
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Type and Orientation of a Hydraulic Induced Formation Fracture. 

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Halliburton Services. The Fracbook Designl~ata Manual for Hydraulic 

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