Trends In Unconventional Gas - Halliburton

Trends In 

Unconventional Gas 

• Advances in fracs and fluids improve tight-gas production 

• Custom technology makes shale resources profitable 

• Life-cycle approach improves coalbed methane production

D r i l l i n g & Pr o d u c t i o n 

UNCONVENTIONAL 

GAS TECHNOLOGY—1 

Advances in fracs and fluids 

improve tight-gas production 

Glenda Wylie 

Halliburton Corp. 

Houston 

Mike Eberhard 

Mike Mullen 


Denver 

S p e c i a l 

Only 10 years ago, 

unconventional gas was 

an emerging resource; 

now it’s a core business 

of many large independent 

producers and 

a growing number of 

major operating companies. 

Twenty years ago, it was largely 

overlooked. 

However, 

gas companies 

Trends in 

Unconventional Gas 

Production 

were developing 

“hard 

rock” resources 

in the 

1970s-1990s 

rather than 

tight gas resources. While they needed 

hydraulic fracturing, the resources’ 

permeabilities were higher and we 

focused on the rock. Now we focus on 

unlocking the gas that is tightly bound 

in lower permeability resources. 

Unconventional gas reservoirs are 

found worldwide, including onshore 

US, Canada, Australia, Europe, Nigeria, 

Russia, China, and India. 

Unconventional gas production in 

the US reached a peak of 24 bcfd (8.6 

tcf/year) in 2006, up from 14 bcfd 

(5.0 tcf/year) 10 years ago. With a 43% 

share, it is now the dominant source of 

natural gas production. 1 

Tight-gas reservoirs, shale, and coalbed 

methane assets are the main sources 

of what is generally known as unconventional 

gas. Their flow mechanisms 

increase in complexity from Darcy flow 

to Fick’s diffusion flow mechanisms 

and combinations of a variety of other 

mechanisms. 

Nothing regarding the drilling, 

completion, or production can be 

automatically assumed in these reservoirs. 

They require increased geological 

understanding and precision engineering 

all within a quicker time frame 

and often within a higher well count 

development. 

This three-part series presents 

technologies and methods found to be 

effective in the profitable production of 

unconventional gas. These technologies 

have resulted in production increases 

of up to 100% in some fields, reductions 

in associated costs up to 25%, 

and reduction in nonproductive time 

losses of more than 30%. The second 

part of the series, to be published next 

week, addresses shale gas technologies. 

The concluding part, to be published 

in January, presents technologies to 

produce coalbed methane. 

Tight gas drilling 

Drilling for tight gas requires optimized 

drill bits, horizontal drilling 

equipment, and specialized fluids. 

• Drillbits. Analyses with input from 

seismic data, formation evaluation logs, 

geomechanical studies, and exploratory 

drill cuttings have resulted in specially 

designed bits for the particular unconventional 

resource (tight gas) with a 

new generation of PDC cutters that have 

improved the rates of penetration as 

much as 118% above previously used 

bit technology. 

• Horizontal drilling. Much of the 

unconventional gas resource profitability 

is based on exposing more formation 

through horizontal drilling. Until 

recently, rotary steerables have been 

available primarily to the offshore market 

due to cost. New simplified rotary 

steerable designs allow for a smooth 

borehole making formation evaluation 

acquisition easier and better. 

• Fluids. Drilling in unconventional 

reservoirs often presents lost circulation 

problems that some special technolo- 

Reprinted with revisions to format, from the December 17, 2007 edition of OIL & GAS JOURNAL 

Copyright 2007 by PennWell Corporation

Special Report 

Multizone completion system swellable packer systems isolate various zones of a horizontal, openhole 

wellbore. All zones are stimulated in a single trip of the treating string. In this uncemented, openhole 

example, the ball-drop method was used to operate the completion system (Fig. 1). 

gies can address. For instance, high-performance, 

clay-free invert drilling fluids 

are available that can be formulated 

with a wide variety of base oils, including 

diesel, internal olefin, ester-olefin 

blends, and paraffin or mineral oil. 

The emulsion-based gel structure 

of the fluid helps eliminate barite sag, 

a serious issue often encountered with 

invert clay-based systems. Further, these 

fluids help reduce whole-mud losses 

by 41% on average, decreasing well 

costs and nonproductive time. The wide 

selection of base oils provides operators 

with options for minimizing environmental 

impact, conserving costs, and 

making use of readily available regionally 

acceptable base oils. 

The rheology of this system is managed 

through application of new emulsifiers 

and additives that replace conventional 

organophilic clays and lignite. 

The interaction of components in these 

clay-free systems is a key to providing a 

robust yet fragile gel structure. The gel 

strength develops rapidly to provide excellent 

suspension but is easily disrupted 

when circulation is initiated, even at 

very low pressures. This helps minimize 

or eliminate the pressure spikes that 

typically occur when breaking circulation 

with invert clay-based fluids. 

Other benefits of the clay-free fluid 

systems include: 

• Improved control over equivalent 

circulating density. 

• Increased tolerance to contaminants, 

including solids and water. 

• Smaller footprint on drillsite with 

fewer additives required for maintenance. 

• Real-time response to chemical 

treatments—no waiting for “yield.” 

• Thin filter cake and excellent return 

permeability values. 

Reserves 

optimization 

Optimizing development of tight gas 

sands can be difficult due to characteristically 

low permeability (


erties of the rock, but also its mechanical 

properties. 

These properties may be obtained 

from the following sources: 

• Well tests, logging, and core data. 

• Production analysis of offset well. 

• Stress-field measurements. 

• Understanding of reservoir fluid 

properties. 

• Study of the various completion 

strategies. 

3. Set optimization criterion or 

criteria (may include production and 

economic criteria). 

4. Define parameters that affect the 

optimum design, including reservoir 

properties, and fracture geometry, conductivity, 

and height. 

5. Achieve realistic modeling, a key 

to optimization of completion. 

Fig. 1 illustrates a multizone completion 

featuring swellable-elastomer 

packer systems isolating various zones 

of a horizontal wellbore. 

Hydraulic fracturing 

Unconventional (tight), continuoustype 

reservoirs, such as those in the 

Cretaceous of the northern Great Plains, 

are not well suited for conventional 

formation evaluation. Pay 

zones frequently consist only 

of thinly laminated intervals of 

sandstone, silt, shale stringers, 

and disseminated clay. Potential 

producing intervals are commonly 

unrecognizable on well 

logs and thus are overlooked. 

To aid in the identification 

and selection of potential 

producing intervals, Hester 

developed a calibration system 

that empirically links the gas effect to 

gas production. The calibration system 

combines the effects of porosity, water 

saturation, and clay content into a single 

gas-production index that suggests the 

production potential of different rock 

types. The fundamental method for 

isolating the gas effect for calibration is 

the interpretation of a crossplot of neutron 

porosity minus density porosity vs. 

gamma-ray intensity. 4 

The geomechanical effect on reservoir 

performance should always be 

considered, especially when producing 

from thick formations or creating multiple 

fractures in horizontal wells. 

Recovering fracturing fluids is often 

difficult in underpressured, tight, deep 

formations. CO 2 

, N 2 

, and binary highquality 

foams are widely used in this 

type of reservoir because of their capacity 

to energize the fluid and improve 

total flowback volume and rate. CO 2 

- 

and N 2 

-assisted (foam) fracs are also 

believed to allow less water to reach 

the formation matrix and, with their 

superior proppant-transport properties, 

allow use of far less gel. 

Reducing gel volume decreases the 

amount of gel likely to be left behind 

in the propped fracture; the result is believed 

to be greater conductive fracture 

half-length. The foam fracture fluid is 

full of energy and begins to flow back 

to the surface readily when fracture 

pumping has ceased. The energized 

fluid is especially helpful in promoting 

frac-fluid flowback where formations 

are depleted and have lost significant 

pore pressure due to production. 

Surfactants designed to reduce surface 

and interfacial tension are also key 

“To optimize returns on tight-gas assets, 

the primary objectives should be 

to strive for overall asset efficiency in 

drilling, stimulation, logistics, field surveillance, 

and operations, and to provide 

predictable delivery to maximize 

well rates and ultimate recovery.” 

elements in the design of fluid systems 

to enhance recovery and reduce entrapment 

of fluid barriers within the formation. 

Enhanced fluid recovery improves 

overall completion economics due to 

the lower total treatment cost and shorter 

time required for flowing back fluids. 

The most important benefit is achieving 

a less-damaged proppant pack, resulting 

in higher fracture conductivity. 

Fracturing horizontal wells 

Fracturing horizontal wells is the 

most promising production-enhancement 

technique in some formations. 

Fracturing in general is the more attractive 

completion option. It is even more 

attractive than multilateral completions, 

especially in tight, thick formations. In 

general, horizontal lateral wells have to 

be fractured to improve the economical 

outlook of the well. The geomechanical 

effect on reservoir performance should 

always be considered, especially when 

producing from thick formations or 

creating multiple fractures in horizontal 

wells. 

Hydraulic-fracture stimulation can 

improve the productivity of a well in 

a tight-gas reservoir because a long 

conductive fracture transforms the flow 

path natural gas must take to enter the 

wellbore. 

After a successful fracture stimulation 

treatment, natural gas enters the 

fracture from all points along it in a 

linear fashion. The highly conductive 

fracture transports the gas rapidly to the 

wellbore. Later, the gas in the reservoir 

is flowing toward an elliptical pressure 

sink and most of the gas enters near the 

tip of the fracture. 

Conventional wisdom in 

designing hydraulic-fracture 

treatments for tight-gas 

sands suggests that successful 

stimulation requires creating 

long, conductive fractures 

filled with proppant opposite 

the pay zone interval. This is 

accomplished by pumping 

large volumes of proppant at 

high concentrations into the 

fractures, using fluids that 

can transport and uniformly 

distribute proppant deeply into the 

fracture. 5 

SurgiFrac 

Combined hydrajetting, fracturing, 

and jet-pump (CHF) technology 

is the first known successful method 

to resolve the problem of openhole 

fracture placement control by using 

dynamic diversion techniques. The technique 

(SurgiFrac) is a combination of 

three separate processes: hydrajetting, 

hydraulic fracturing (through tubing),


and coinjection down the annulus (using 

separate pumping equipment). 

One important aspect of this technique 

is the dynamic sealing capability. 

Unlike other techniques that require 

hardware-type packers or plugs, or even 

chemical plugs, this process essentially 

relies upon sealing by using fluid movement. 

Because packers are not used in 

most cases, the existence of passageways 

behind liner or through fractures rarely 

affects the performance of this process. 

The technique is based primarily on 

the Bernoulli principle, which states 

that the energy level of a fluid is generally 

maintained constant. To perform the 

SurgiFrac service, a jetting tool is placed 

near the toe of the well and used to jetperforate 

the casing and the formation 

rock, forming a 4-6-in. deep cavity. 

Based on the Bernoulli equation, as 

pressurized fluid exits the jetting tool 

the pressure energy is transformed into 

kinetic energy or velocity. Since the 

fluid velocity around the jet stream is at 

its greatest, pressure in this area is at its 

lowest, meaning the fluid does not tend 

to “leak” out somewhere. Conversely, 

fluid from the other areas of the well 

will flow into the jetted area. 

The fluid generally contains some 

abrasives to help the fluid penetrate the 

steel liner and the formation rock. As 

cavities are formed by each jet, highvelocity 

fluid impacts the bottom of 

the cavity (e.g., velocity becomes zero, 

an energy change from kinetic back to 

potential energy or pressure), causing 

pressure inside the rock to become high 

enough to create a fracture. Annulus 

pressure is then increased to help extend 

the fracture. 

After the fracturing process is completed, 

the tool is moved to the next 

fracturing position and another fracture 

is placed. 

The conversion of low-pressure, 

high-velocity kinetic energy to highpressure, 

low-velocity potential energy 

is extremely useful for fracture 

initiation and fracture placement. The 

breakdown pressure in a conventional 

treatment requires a tensile failure of 

the rock achieved by pressuring up the 

entire wellbore. 

Because, in most cases, fracture initiation 

pressure is much higher than fracture 

extension pressure, achieving multiple 

fracture initiation points along a horizontal 

wellbore requires achieving multiple 

fracture initiation pressures. This is very 

difficult in practice without some form of 

isolation along the wellbore. 

Since the energy of the jetting fluid 

is converted to pressure inside the 

eroded rock, the tensile failure of the 

rock occurs at the jetting point without 

exposing the wellbore to breakdown 

pressures. This enables precise control of 

the location of fracture initiation in the 

horizontal section. Multiple fractures 

can be created by simply moving the 

jetting tool to another location in the 

lateral and using hydrajet fracturing. 

Another attribute of the hydrajetting 

fracturing process is the creation of a 

dominant fracture through continued 

hydrajetting during fracture extension. 

As the fracture grows in width, the net 

pressure increase resulting from fracture 

extension induces stress normal to the 

direction of the fracture propagation; i.e., 

reopening previous fractures becomes 

more difficult due to the increased stress 

induced by the dominant fracture. 

The SurgiFrac service has been applied 

successfully in a variety of fracturing 

conditions: 

• Multiple propped fractures in open 

hole. 

• Multiple acid fractures in open 

hole. 

• Deviated cased hole. 

• Horizontal slotted liner. 

• Coiled-tubing acid-frac to bypass 

damage. 

• Multiple fractures in a cased horizontal 

wellbore. 

A case history illustrates the utility 

of the multizone fracturing method. 

The first subsea CHF fracture stimulation 

was in 1,000 ft of water in Brazil’s 

Campos basin. Because the stimulated 

well had two branches (abandoned due 

to drilling problems), it behaved like a 

triple lateral for stimulation design. The 

treatment resulted in five acid fractures, 

completed in 2.5 days. 

Production rate for the first 15 production 

days following the treatment was 

almost double the maximum historical 

rate of this well and almost four times 

the monthly production rate during the 

months preceding the SurgiFrac. As a 

result of this treatment and two other 

treatments for proof-of-concept, a major 

international company has approved 

SurgiFrac service for all its scenarios— 

land, offshore, and subsea—worldwide. 

Microemulsion surfactants 

If the formation permits, often 

water-based hydraulic fracturing is carried 

out in tight gas formations. Traditionally, 

they have not been as optimally 

effective as they could be due to water 

blocking. 

A microemulsion surfactant (MS) 

has the potential vastly to increase the 

world’s recoverable reserves of natural 

gas from tight-gas reservoirs by helping 

control fracture-face damage and boosting 

production from these difficult 

formations. 

The special surfactant was designed 

to replace methanol or conventional 

surfactants. Based on new microemulsion 

technology (GasPerm 1000), the 

surfactant helps remove water drawn 

into the formation during the fracturing 

process. Desaturating water and 

removing phase trapping can improve 

inflow of gas from the fracture face and 

help increase gas production. 

Tight-gas reservoirs (as well as 

coalbed methane and shale formations) 

typically have low production due to 

low permeability and-or low reservoir 

pressures. The low permeability 

of these formations creates a capillary 

effect, in which water can be drawn or 

“imbibed” into these tight formations 

during fracturing treatment. 

The low reservoir pressures do 

not create enough flow for the gas to 

displace the liquid from the formation. 

Phase trapping can occur, in which the 

liquid becomes trapped within the lowpermeability 

formation at the fracture 

face, and the gas cannot displace it. This 

trapped liquid can inhibit productiongas 

flows. 

Using a microemulsion surfactant 

can specifically mitigate fracture-face 

damage caused by capillary effects and



phase trapping. 

The surfactant 

can also enhance 

phase displacement 

and spatial flow 

behavior and help 

enhance mobility 

if liquid hydrocarbons 

are present. 

This can help increase recoverable 

gas and improve well economics by: 

1. Increasing actual production rates. 

2. Increasing recoverable reserves. 

3. Extending lifecycle of wells. 

4. Shifting projects above the economic 

threshold. 

The microemulsion additive is more 

effective at much lower concentrations 

than methanol, significantly reducing 

the volume required during fracturing 

treatment. It is a less flammable alternative 

to methanol-based fracturing fluids, 

thus improving safety and reducing 

environmental risk. 

The MS additive is compatible with 

both acidic and basic fluid systems and 

can be used as an acidizing additive or 

a fracturing fluid additive. The range of 

applications for this product continues 

to expand. MS service has been used in 

reservoirs with matrix gas permeability as 

low as the nanodarcy permeability range. 

Two case studies illustrate the effectiveness 

of this technology: 

• Ten horizontal shale wells in 

Oklahoma were recently completed 

with massive slickwater fracturing. Four 

of these wells were fractured with MS 

service and six wells did not have the 

MS treatment. 

Using MS, early load recovery improved 

by 43%. The surfactant reduced 

water saturation and capillary pressures 

along the fracture faces, which improved 

relative permeability to gas. The 

wells treated with MS had initial gas 

production rates comparable to the best 

wells in the field. 

• A Cotton Valley tight-gas sand in 

East Texas was fracture-stimulated with 

microemulsion surfactant. The well produced 

more than 14 times the wellhead 

pressure (100 psi vs. 1,400 psi) and almost 

doubled the initial production rate 

(862 Mcfd vs. 1,432 Mcfd) compared 

“Desaturating water and removing 

phase trapping can improve inflow of 

gas from the fracture face and help increase 

gas production.” 

to a conventionally treated offset well. 

Refracturing 

Hydraulic fracturing, especially in 

a horizontal well, is probably the best 

way to complete a well in a tight-gas 

formation. Fracture performance often 

declines with time, however. 

Reasons for performance degradation 

include: 

• Loss of fracture conductivity near 

the wellbore due to embedment. 

• Degradation of proppant with time 

and stress. 

• Loss of fracture height with time. 

• Loss of fracture length caused by 

degradation of proppant. 

• Loss of fracture conductivity from 

fines migration. 

• Loss of formation permeability 

near the fracture, forming a barrier. 

• Entrapment of liquid around the 

fracture face by capillary force. This 

effect may be aggravated by fluid loss 

during drilling and fracturing and by 

later movement of fines. This may be of 

special importance in tight-gas formations 

where a very high capillary pressure 

may be expected in cases having a 

water phase. 

Refracturing can expose more reservoir 

area to the high-conductivity fractures, 

thus improving well productivity 

and reservoir exploitation. ✦ 

References 

1. Kuuskraa, Vello A., “A Decade 

of Progress in Unconventional Gas,” 

Advanced Resources International, Arlington, 

Va., July 6, 2007. 

2. Tamayo, H.C., Lee, K.J., and Taylor, 

R.S., “Enhanced Aqueous Fracturing 

Fluid Recovery from Tight Gas Formations: 

Foamed CO 2 

Pre-Pad Fracturing 

Fluid and More Effective Surfactant 

Systems,” paper CIPC 2007-112, CIPC 

58th Annual Technical Meeting, Calgary, 

June 12-14, 2007. 

3. Evans, Scot, and Cullick, Stan, 

“Improving Returns on Tight Gas,” Oil 

and Gas Financial Journal, July 2007. 

4. Hester, Timothy C., “Prediction 

of Gas Production Using Well Logs, 

Cretaceous of North-Central Montana,” 

Mountain Geologist, Vol. 36, No. 2, pp. 

85-98, April 1999. 

5. Holditch, Stephen A., and Tschirhart, 

Nicholas R., “Optimal Stimulation 

Treatments in Tight Gas Sands,” 

paper SPE 96104, 2005 SPE Annual 

Technical Conf. and Exhibition, Dallas, 

Oct. 9-12, 2005. 

The author 

Glenda Wylie (Glenda. 

Wylie@Halliburton.com) is 

technical marketing director 

of unconventional resources at 

Halliburton Corp., Houston. 

She has also served as global 

technical marketing manager 

and in other positions in 13 

years at Halliburton. Prior to 

that, she worked with an operating company in 

exploration, engineering, and management. Wylie 

holds a BS (1975) in chemistry from Murray 

State Univ., a BS (1979) in chemical engineering 

from Texas A&M Univ., and an MS (1991) 

in engineering management from the Univ. of 

Alaska-Anchorage. She is also certified in corporate 

governance by Tulane Univ. Law School. Wylie is 

on the advisory board for the Drilling Engineering 

Association and is a member of AADE, API, SPE, 

Business Marketing Assoc., and National Assoc. of 

Female Executives. 

Mike Eberhard (Mike.Eberhard@Halliburton. 

com) is Halliburton’s technical manager for the 

Rockies, based in Denver. He has worked with Halliburton 

nearly 27 years in pumping services, field 

engineering, sales, technical team, and management. 

Eberhard holds a BS in mechanical engineering 

from Montana State University. He is a member 

of SPE, AADE, DWLA, and is on the IAB for 

Montana Tech. Eberhard is a registered professional 

engineer in CO. 

Mike Mullen (Mike.Mullen@Halliburton.com) is 

a technical manager specializing in the integration 

of petrophysics, reservoir simulation, and economic 

stimulation design with Halliburton Energy 

Services in Denver. He began his career as a logging 

field engineer in Hobbs, NM in 1976 and has held 

positions in technical support, sales and formation 

evaluation over the past 31 years. Mullen 

holds a BS in electrical engineering (1976) from 

University of Missouri-Rolla and is a registered 

professional engineer in New Mexico and Colorado. 

He’s a member of SPE and SPWLA.


Low permeability 

shales are unconventional 

gas reservoirs that are 

being more efficiently 

exploited with newly 

developed production 

Production 

technologies. 

This series began 

last week, with an article discussing 

advances in fracture stimulation techniques 

and fluids used to improve tight 

gas production (OGJ, Dec. 17, 2007, p. 

39). 

The final article in this series, to be 

published next month, deals with coalbed 

methane (CBM) production. 

Shales 

There are technical difficulties in 

producing gas from shales, which have 

ultralow permeabilities and vary in 

brittleness. Multilayered shale reservoirs 

have widely varying reservoir characteristics 

and flow mechanism regimes. 

Formations typically have high capillary 

pressures in hydraulic fracturing scenarios. 

Treatment fluids can potentially 

damage shale formations. 

Multilayered shale reservoirs with a 

variety of reservoir characteristics require 

specialized evaluation and drilling 

techniques and “next-well” geological, 

seismic, and production comparisons to 

identify optimum fracturing targets. 

All of these data sources can be fed 

into custom models for a potential 

well’s production design. Combining 

logging systems with next-well and 

field-wide properties, geomechanics, 

and production performance data forms 

the basis of an advanced modeling system. 

The system is tailored for the specific 

shale-production mechanism and 

composition of the proposed new well’s 

drilling and completion design. Placing 

the well’s target location is critical and 

can be done with economical, simplified, 

rotary-steerable drilling assemblies 

in land-based shale wells. 

Determining proper fracture placement 

within shale formations is a key 

to creating large, highly productive 

fracture networks. Logging systems use 

an innovative approach, incorporating 

select mechanical rock properties, 

geomechanics, total organic content, 

and porosity to help locate the best 

fracture-initiation points within shale 

formations. Microseismic methods 

also provide invaluable information on 

the depth and width of the multiple 

fractures that are created during fracture 

stimulation. 

Due to shale’s 

ultralow permeability, 

successful economic 

productivity from a 

shale reservoir depends 

on the capability 

to maximize 

formation exposure through horizontal 

or vertical drilling and fracturing, or 

both. 

Economical rotary-steerable drilling 

assemblies, high-horsepower fracturing 

units, and multifunctional fractureplacement 

techniques provide maximum 

and optimized reservoir exposure. 

A complex reservoir’s brittleness 

must be leveraged through drilling and 

fracturing to create as much fracture 

face as possible to maximize gas migration 

from the producing shale. Brittleness 

can also be leveraged to create 

formation exposure through the use 

of high-horsepower fracture pumping 

units, which have been developed to 

provide maximum fracturing horsepower 

in a reduced environmental 

“footprint.” 

New designs include increased 

horsepower and high-rate pumps and 

offer improved safety, performance, 

reliability, space utilization, operational 

efficiency, real-time automation 

throughout the entire fracturing system, 

and ultimate improved gas recovery. 

Multilayer reservoir characteristics 

and ultralow formation permeability require 

precision fracturing of optimum 

locations along the wellbore, which has 

led to significantly improved production 

results. 

Pinpoint stimulation techniques have 

evolved, making shale more profitable 

as gas prices cycle. Multiple zones can 


GAS TECHNOLOGY—2 

Custom technology makes 

shale resources profitable 

Glenda Wylie 

Ron Hyden 


Houston 

Von Parkey 

Bill Grieser 


Oklahoma City 

Rick Middaugh 


Carrollton, Tex. 

Reprinted from the December 24, 2007 edition of OIL & GAS JOURNAL 



be efficiently fractured independently 

by: 

• Using coiled tubing or tubulars 

with hydrojetting techniques. 

• Using dynamic diversion techniques 

for either vertical or horizontal 

placement. 

• Or, incorporating completion mechanical 

downhole assemblies featuring 

stimulation sleeves and swellable 

elastomer packers to enable stimulation 

of multiple zones without use of bridge 

plugs to isolate intervals to be treated. 

These pinpoint stimulation 

techniques offer operators 

cost-effective methods to 

stimulate multiple zones in 

one rig-up. 

Fluid treatment 

Ultralow permeability 

is the primary challenge in 

shale formations. Fracturing 

fluids that are nondamaging 

and that enhance load 

recovery is essential in shale 

formations with very limited 

permeability. A combination 

of specialized chemistries 

delivers maximum effective 

fractures and preserves the 

formation’s existing permeability 

to gas, contributing 

significantly to the shaleproduction 

success. Components of the 

fracture fluids include: 

• Special friction reducers formulated 

to reduce potential fracture-face 

damage caused by long-chain polymers, 

without compromising their capability 

to reduce friction pressure. 

• Microemulsion surfactant that 

helps reduce capillary pressure, releasing 

imbibed treatment water and 

improving gas permeability. It also 

provides significant safety and environmental 

benefits by replacing methanol 

in water-block treatments. 

• Fracture-cleaning enhancer and 

conductivity enhancer for accelerating 

fracture cleanup and flowback of treatment 

fluids. 

Together, these components create a 

synergistic fluid treatment solution designed 

to help optimize gas production 

from formations with ultralow native 

permeability. The system provides workable, 

cost-efficient solutions for shale 

productivity programs from beginning 

to end—from analysis and planning to 

drilling, fracturing, early production, 

long-term production, and ultimate 

recovery/abandonment. 

The ability rapidly to fracture 

multiple independent zones yields a 

significant decrease in completion time. 

The components of the system work 

Makeup of productive shale formations 

In general, a productive shale formation includes 

these characteristics: 

• Zone thickness >100 ft. 

• Well bounded and containing energy. 

• Maturation in the gas window: R o 

= 1.1 to 

1.4. 

• Good gas content >100 scf/ton. 

• High total organic content (TOC) >3%. 

• Low hydrogen content. 

• Moderate clay content

improves environmental and safety performance 

by replacing methanol; and 

is effective in reservoirs with matrix 

permeability in the nano-Darcy range. 

Formation damage 

A new friction reducer helps reduce 

fracture-face damage from long-chain 

polymers. The maximum horsepower 

can be applied in a shale formation 

rather than being wasted just to get the 

fluid through the mechanical system. 

Because this reducer contains no phenols, 

it provides improved environmental 

performance and exhibits 

less flocculation than conventional 

friction reducers. 

A viscosity-reducing agent 

helps maximize the effectiveness 

of water-fracturing 

treatments by reducing fluid 

viscosity, improving load recovery, 

minimizing frictionreducer 

polymer damage, 

and preventing polymer adsorption 

to the fracture face, 

thereby enabling improved 

production. 

These purpose-focused 

technologies provide a 

holistic and economical 

approach to bringing forth 

energy from unconventional 

shale resources. Two cases demonstrate 

the use of the shale production system 

(SPS): 

• Case 1. A horizontal shale well was 

stimulated at four intervals with stimulation 

sleeves sequentially to isolate 

each interval of interest during treatment. 

The four intervals were fractured 

in 15 hr, placing 1.2 million lb of proppant 

with 2.3 million gal of fluid in a 

continuous operation. 

Normal stimulation practices would 

have required 2 days to run four traditional 

fracturing stages. The operational 

efficiency gained through the use of 

the stimulation-sleeve process reduced 

completion costs by 15-20%. 

• Case 2. Gas sales from six Barnett 

shale wells were compared after three 

of the wells had been treated with SPS 

additives and three were treated without 

additives. First gas production was 

quicker in the three wells treated with 

SPS additives and these wells produced 

100% more gas sales/day. 

The Mississippian Barnett shale 

serves as source, seal, and reservoir in a 

world-class unconventional natural gas 

accumulation in the Fort Worth basin of 

northcentral Texas. The Barnett is lithologically 

complex, with low permeability, 

and requires artificial stimulation to 

produce. 1 

• Case 3. Ten horizontal shale wells 

Shale technologies 

Several production-enhancement processes 

are useful in shale-gas reservoirs: 

• Prospect evaluation and core testing. 

• Shale lithotyping to determine key characteristics 

of productive shale. 

• Log data integration and analysis specific to 

shale. 

• Designing and drilling the vertical and horizontal 

well for stimulation. 

• Proppant size and loading considerations. 

• Optimization and tailoring water-frac fluid 

chemistry to the shale. 

• Remedial treatment processes for obtaining 

long-term sustained production. 

in Oklahoma were recently completed 

with massive slick-water fracturing. 

Four of these wells were fractured with 

microemulsion surfactant (MS) and six 

wells did not have the MS treatment. 

The MS treatment reduced water 

saturation and capillary pressures along 

the fracture faces, which improved relative 

permeability to gas. Wells using the 

MS service had initial gas production 

among the best wells in the field. 

Life-cycle phases 

Operators producing gas from shale 

reservoirs can be more successful by 

following the five life-cycle phases 

of project development and carefully 

choosing technologies appropriate for 

each project phase: 

1. Reservoir assessment. Evaluate shale 

and reservoir potential. 

2. Start-up exploration. Drill experimental 

wells and investigate fracture design 

and production prediction. 

3. Early development (mass production). 

Rapidly develop using an optimized design. 

Develop database and benchmarks. 

4. Mature development (reserve harvesting). 

During this cash-flow cycle, match 

production histories; adjust reservoir 

model; image database. 

5. Declining phase (maintenance and remediation). 

Identify remedial candidates, 

restimulate, initialize lift mechanisms 

and conformance methods. 

(Similar coalbed methane 

life-cycle phases are discussed 

in the final article in this 

series. 2 ) 

Prospect evaluation 

Usually, the first step in 

the design and application 

process is to evaluate the 

shale prospect. Initially, both 

2D and 3D seismic data are 

processed to determine the 

extent of the shale play. The 

volume of shale is estimated 

in tons/acre (ton/acre-ft). 

Gas in place (GIP) is calculated 

from the geochemical 

determination of standard 

cubic feet/ton (scf/ton), as 

follows: GIP = (ρ)(1,359)(scf/ton) = 

scf/acre-ft. 

Shale samples collected from various 

sources help in determination of the 

commercial viability of the project. Factors 

include: 

• Shale hydrocarbon content (scf/ 

ton, bbl/ton, GIP). 

• Shale maturity. 

• Kerogen type (Types I and II, oil; 

Type III, gas). 

• Shale porosity, permeability, oil, 

water, and gas saturations. 

• Shale desorption constant, or gas 

isotherm. 

• Shale bulk density, ρ (g/cu cm). 

Log data requirement 

A triple-combo log can be used to 

obtain density, gamma ray, resistivity, 

neutron, and density porosity.


A wave-sonic log should be run to 

obtain mechanical rock properties. 

An EMI (electromagnetic imaging) 

tool should be run to obtain natural and 

induced fracture direction, followed by 

analysis to identify sweet spots and a 

fracture-initiation site. 

A pulsed spectral gamma (PSG) log 

enhances hydrocarbon recovery by accurately 

measuring hydrocarbon saturations 

over a wide range of properties 

and borehole conditions. The PSG log 

also aids in clay typing, which adds to 

knowledge of the reservoir and is helpful 

information for planning future wells. 

Enhancing production 

Commercial production from shale 

depends largely on the gas content and 

natural storage and deliverability of the 

rock. The prime goal of stimulation is to 

contact and expose the greatest amount 

of rock volume and surface area with 

the least expensive material; in effect, 

“mining” the shale using hydraulic 

horsepower and injected water. This 

hydraulic mining can turn a well in 

nano-Darcy shale into a commercial gas 

producer. 

Restimulation has proven to increase 

recoverable reserves by 50-100%. 

Future vertical and horizontal wells 

are likely to be completed by selectively 

treating, isolating, and retreating 

unstimulated areas along the vertical or 

horizontal wellbore. 

Fracturing fluids and reactive fluids 

should be designed with knowledge of 

the specific shale mineralogy. The overall 

success of any shale play will include 

observation of the resource through its 

life cycle. 

Vertical well stimulation 

Current vertical stimulation designs 

feature: 

• Four or five perforation sites, 2-4 

ft long. 

• 5 shots/ft (spf) and 60° phasing. 

• Pump rates of 1-2 bbl/min per 

perf or 20 bbl/min per initiation site. 

Volumes pumped are about 2,500 

gal/ft, delivering 400 lb/ft of proppant. 

In early phases of the life cycle, 

vertical wells are usually drilled and 

completed to help the operator characterize 

the reservoir. With the experience 

gained from drilling, fracturing, and 

producing the vertical well, more comprehensive 

life cycle phases 3 and 4 can 

be planned and performed profitably. 

Horizontal well stimulation 

Current horizontal stimulation designs 

typically include: 

• Two to eight stages/horizontal 

wellbore. 

• Two to four frac initiation sites/ 

stage. 

• 2-4 ft of perforations/site, with 6 

spf, at 60° phasing. 

• 20-30 bbl/min per frac site or 2-4 

bbl/min per perforation. 

• Volume average 1,800 gal/ft. 

Horizontal completions 

Horizontal well completions can be 

one of three types: 

1. Cased, cemented, multistage with 

composite plugs to separate frac stages. 

2. Multistage, with jetted sand and 

water delivered by coiled or jointed 

tubing to perforate zones. 

3. Mechanical bottomhole assembly. 

The cased, cemented, multistage 

completion with composite plugs is the 

most commonly used type of horizontal 

completion in shale wells. Each 

stage is perforated, fracture-stimulated, 

and isolated with a packer or bridge 

plug, allowing the next stage to be 

treated. The plugs and packers act as a 

well “bottom” for fracturing pressure 

to build up against. This process is the 

most time-consuming, due to the cycle 

time for perforating, plug-setting, and 

drilling out plugs or packers. Use of 

composite plugs reduces drillout times 

drastically. 

Jet-perforated, multistage completions 

eliminate the need to perforate or 

set plugs. This service is run on coiled 

or jointed tubing to the first-stage frac 

site; perforations and a tunnel are eroded 

by pumping through the tubing at 

a high differential pressure, using sand 

and water as the cutting stream. The 

fracture initiates and extends at the jet 

site; packers are not required because 

the jet velocity causes a pressure drop 

at the jet exit. The pressure drop pulls 

fluid from the annulus into the fracture. 

A more detailed discussion is provided 

in Part 1 (OGJ, Dec. 17, 2007, p. 39) 

Mechanical bottomhole assembly 

(BHA)-type completions isolation packers 

have been run in horizontal shale 

wellbores as a new alternative to cementing 

and perforating. These systems 

are deployed as part of the production 

casing and provide mechanical isolation 

and selective injection sites that can 

be opened and, in some cases, closed 

manually. 

Advancements have been made in 

the development of multistage frac-acid 

tools being applied in both openhole 

and cased-hole completions with 

hydraulic-set packers and sliding valves 

opened by pumping balls or shifting 

mechanical devices on jointed or coiled 

tubing. 

Water fracs produce a complex network 

of narrow-aperture fractures that 

can be either induced from extensive 

shear-failures (like shattered safety 

glass) or created from dilation of preexisting, 

incipient fractures or planes 

of weakness in the shale. The frac width 

must be 1.5± times the maximum 

grain diameter of the proppant to provide 

additional propping of the induced 

fractures. 

Because the permeability of the 

matrix rock is usually ultralow 

(0.0001-0.001 md), except possibly 

near the wellbore, the fracture conductivity 

typically does not need to be 

high; 20-50 md-ft is sufficient conductivity 

through the fracture network. The 

exception would be with deeper wells 

with higher closure pressure and rock 

properties that would allow proppant 

embedment. In a few cases, we have not 

seen much correlation between production 

and proppant size. Many created 

fractures remain open and conductive 

even without proppant. 

Many wells have been fractured 

proppant-free or with as little as 5,000 

to 10,000 lb yet achieved commercial

ates. Most Barnett shale well stimulations, 

however, are using proppant 

volumes in the range of hundreds of 

thousands of pounds. Although some 

operators question the value of proppants, 

with advancements 

in proppant 

design, correlating 

volume and type of 

proppant with actual 

production increases 

may be proved. 

Adaptation and 

modification of current 

fracture models 

calibrated to real-time 

microsiesmic mapping 

are being used to help 

in the design of stimulation 

treatments. 

Shale water-frac 

chemistry features 

application of friction 

reducers, surface-modification 

agents (SMA), 

microemulsions, deflocculants, 

and reactive fluids. The SMA 

helps minimize proppant settling, control 

production of fines, and enhance 

propped fracture conductivity. Microemulsion 

additives help remove water 

load and enhance recovery of fracturing 

liquids, resulting in significant uplift in 

recovery factors and estimated ultimate 

recovery (EUR). 

Friction-reducer deflocculants are 

added to prevent the potential negative 

impact friction-reducer polymers can 

have when interacting with formation 

fines and liquid hydrocarbon. Conventional 

friction reducers can essentially 

form damaging, gunk-like material 

within the created fracture system that 

can seal off frac conductivity in the 

narrow-aperture fractures. 

Refracturing 

Vertical shale wells can see production 

increases of 30-80% from reperforating 

the original producing interval 

and pumping a job volume that is at 

least 25% larger than the previous frac. 

There are two obstacles in refracturing 

horizontal: The initial frac sites 

Hydraulic fracturing is a common completion technique in the Barnett shale. Photo from 

Halliburton. 

must be somehow isolated, and new 

frac sites must be created in areas of unstimulated, 

horizontal wellbore. Various 

completion methods such as Halliburton’s 

SurgiFrac and mechanical completions 

with swellable packers eliminate 

the obstacles. 

Shale-reactive fluids 

In general, shale is thought to be 

relatively nonreactive to low pH or 

acidic fluids because the clay, silt, and 

organic materials comprising the major 

components of shale formations exhibit 

insignificant bulk solubility in acid. 

Shale units are highly laminated, however, 

and contain acid-soluble minerals 

homogenized in the shale bulk matrix 

and natural fractures. X-ray diffraction 

analysis and scanning electron microscope 

images of shale samples show 

a great diversity and distribution of 

soluble material in the shale-producing 

unit. 

The amount of gas produced by desorption 

is directly related to the amount 

of surface area exposed, and a shalereactive 

fluid may increase the surface 

area of a newly created hydraulic 

fracture. Gas production from hydraulically 

fractured shale is believed to come 

from desorption and diffusivity from 

microporosity/fractures. Shale-reactive 

fluids may help remove acid-soluble 

minerals in the bulk shale as well as the 

mineral-filled fractures, thereby enhancing 

diffusivity of gas into the fracture 

network. 

The use of reactive 

fluids is a relatively 

new concept in shale 

stimulation, evolving 

from the observation 

that shale lithologies 

contain distributed low 

levels of acid-reactive 

minerals. In experimental 

trials of the use 

of weak-acid reactive 

systems, the unexpected 

pressure-drops that 

occur when the reactive 

fluids contact the shale 

formation inspired 

treatments of 20,000 to 

200,000 gal of reactive 

fluid through the frac 

water. 

Initial production 

has been double that of treatments 

without reactive fluids included. Figs. 

1 and 2 show shales before and after 

being exposed to reactive systems. Early 

field trials are showing excellent production 

improvement results. 

Cementing shale wells 

Constructing a suitable cement 

sheath around the horizontal section of 

a shale well is a key element in the process 

of successful fracture-stimulation 

of shale-gas zones. In recent exploration 

and production activity in Oklahoma’s 

Woodford shale, wells cemented with 

foamed cement produced an average of 

23% more peak gas than wells cemented 

with conventional slurries. 

Conventionally cemented wells did 

not provide adequate zonal isolation 

and allowed fracturing fluid to communicate 

along the horizontal casing. This 

condition caused targeted intervals to 

receive less than the designed volume 

of stimulation fluid and proppant. 

Tensile strengths and mechanical 

properties of foamed cements make 

them ideal for zonal isolation in many


Shale fracture surface (left photo) shown before reactive fluid contact (1,000x magnification on ESEM microscope; Fig. 1). Here is the same shale fracture 

(right photo) surface as shown in Fig. 1 following contact with a reactive fluid. The result is an increase in effective surface area and enhanced flow channels for 

gas to diffuse from shale fracture surface into the created fracture void (Fig. 2). 

hydraulic-fracturing operations. The 

low compressive strengths of these cements, 

however, concern some operators 

that have long considered compressive 

strength to be the leading indicator 

of cement-sheath integrity in highpressure 

fracturing conditions. 

Foamed cement’s relatively low 

compressive strength does not increase 

the risk for fracture initiation 

and propagation in the cement sheath 

during hydraulic-fracturing treatments. 

Stresses induced in the cement sheath 

by increased wellbore pressures during 

casing-pressure tests or fracture 

stimulation treatments are tensile in 

nature. The sheath’s capacity to withstand 

these stresses is predominantly 

determined by the cement’s mechanical 

properties (Young’s modulus and 

Poisson’s ratio) and tensile strength. 

Cement compressive strength is of 

minimal importance. 3 

The durability of foamed cement 

has been demonstrated repeatedly in 

Woodford shale hydraulic-fracturing 

operations, where foamed cement 

outperformed conventional cement 

in withstanding high internal casing 

pressures and high fluid hydrostatic 

pressures. 

Two factors explain this performance: 

1. Mechanical properties of foamed 

cement allow it to withstand greater 

wellbore pressures than conventional 

cement. 

2. The ductile nature of foamed cement 

helps prevent the propagation of 

fractures in the cement sheath, helping 

ensure continued zonal isolation. 

Well-cementing professionals believe 

that the ductile properties of the cement 

allow it to yield to injection pressure 

rather than shattering as is usually 

the case in high-density, more brittle 

cement. Also, the cement-invasion distance 

may be less because of improved 

fluid loss provided by the nitrogen 

bubbles. 

Acid-soluble cement 

Zonal isolation for limited-entry 

stimulation can be provided by acidsoluble 

cements (ASC). 

Because conventional cements have 

a low solubility in acid, perforations 

can be difficult to break down and can 

inhibit fracture initiation and cause 

excess tortuosity during stimulation 

and production. Successful horizontal, 

limited-entry stimulation requires that 

all perforations are open and in communication 

with the formation and the 

designed perforation friction controls 

the fluid distribution along the wellbore. 

Unopened perforations and nearwellbore 

friction resulting from 

tortuosity caused by the conventional 

cement can significantly alter the fluid 

distribution and decrease stimulation 

effectiveness. Conventional high-compressive 

strength cements with a typical 

acid solubility of less than 5% cannot 

be reliably removed so that each perforation 

is openly communicating with 

the formation. 

Instead, acid-soluble cement can be 

used to provide zonal isolation without 

impeding stimulation and production. 

This type of cement has a fast solubility 

rate and is highly soluble (>90%) in 

acid-based stimulation fluids. ASC has 

physical properties much like conventional 

cement. It can be specifically formulated 

to provide the proper weight, 

fluid-loss, free water, compressive 

strengths, and pump times required for 

particular well conditions. Slurry densities 

and yield ratios can range from 

13.0 lb/gal to 15.8 lb/gal and 3.55 cu 

ft/sk to 2.00 cu ft/sk, respectively (sk = 

sack). ASC can also be foamed if lowerdensity 

slurries are needed. 

The easy removal of ASC material 

from the perforation cluster makes it 

especially suitable for limited-entry 

horizontal applications. The highsolubility 

allows the development of 

a larger communication area in the

annulus immediately adjacent to the 

perforations while still providing excellent 

zonal isolation along the wellbore. 

This pocket that is dissolved around the 

casing at the clustered perforation point 

eliminates the tortuosity and fractureentry 

pressure effects that could alter 

the planned limited-entry fluid distribution. 

Also, during production, the 

skin effects, reduced near-wellbore 

conductivity, and perforation-plugging 

problems associated with conventional 

cements are eliminated. 

Cement process 

The following well information is 

used to support an initial design for the 

foam-cementing process: 

• Operator well plan for casing 

strings, drillbit sizes, casing sizes, 

drilling mud systems, and if the well 

is horizontal, a proposed directional 

survey. 

• Depths and thickness of potential 

productive intervals and the fracture 

gradients and pore pressures of these 

intervals. 

• Depths, thicknesses, and fracture 

gradients of potential lost-circulation 

intervals. 

• Desired top of cement. 

Design software aids in developing a 

cementing process tailored for the well, 

and the recommended cement slurries 

are laboratory tested for performance. 

During drilling, the cementing program 

is updated to reflect the influence 

of events that were not expected, for 

example, encountering an unanticipated 

pressure zone. 

When well total depth is reached, 

initial well information is confirmed, 

drilling-mud reports are consulted, and 

drilling-mud and mixing-water samples 

are collected to be tested for compatibility 

with spacers. 

Updated wellbore information is 

entered into the planning program 

to develop a final cementing-process 

design. Several aspects of the design are 

updated in the software program: 

• Total depth. 

• Casing depths. 

• Size and grade of casing. 

• Bit size used for horizontal section. 

• Final directional survey. 

• Last 3 or 4 days’ drilling-mud 

reports. 

• Depths and fracture gradients of 

lost-circulation zones. 

The cementing operation is monitored 

and controlled by operating 

company and service company representatives 

to maximize opportunities to 

make real-time changes to the procedure. 

Other solutions 

In areas where alternatives to foam 

cement may be preferred, recent advances 

in well cementing technology 

have made it possible to provide the 

option of nonfoamed cements with 

the enhanced mechanical properties 

and ductility required to cement shale 

wells that will be fracture stimulated. 

These cements can also be designed to 

expand. The required mechanical modification 

additives can be dry-blended 

with cement and mixed and pumped in 

the field using conventional equipment. 

In practice, combinations of salts in 

cements and spacers and sodium silicates 

in preflushes in cementing fluids 

have provided a simple and proven 

means for managing shale instability 

during the cementing process when 

shale instability is considered to be an 

issue. ✦ 

References 

1. Montgomery, Scott L., Jarvie, Daniel 

M., Bowker, Kent A., and Pollastro, 

Richard M., “Mississipian Barnett Shale, 

Fort Worth basin, north-central Texas: 

Gas-shale play with multi-trillion cubic 

foot potential,” AAPG Bull., Vol. 89, No. 

2 (February, 2005), pp. 155-175. 

2. Blauch, M.E., Weida, D., Mullen, 

M., and McDaniel, B.W., “Matching 

Technical Solutions to the Lifecycle 

Phase is the Key to Developing a CBM 

Project,” SPE 75684, SPE Gas Technology 

Symposium, Calgary, Apr. 30-May 

2, 2002. 

3. Deeg, W.F.J., “High Propagation 

Pressures in Transverse Hydraulic 

Fractures: Cause, Effect, and Remediation,” 

SPE 56598, SPE Annual Technical 

Conf. and Exhibition, Houston, Oct. 

3-6, 1999. 

The authors 

Ron Hyden (Ron.Hyden@Halliburton.com) has 

been group manager for stimulation at Halliburton 

since 2005, based in Houston. He joined the company 

28 years ago, initially working in the East 

Texas and North Louisiana basins, and has since 

held positions in engineering, management, sales, 

and marketing. Hyden received a BS (1979) in 

chemical engineering from Texas A&M University 

and is a member of SPE. 

Von Parkey (Von.Parkey@Halliburton.com) is 

technical manager for the US Midcontinent at 

Halliburton and works in Oklahoma City. He 

has been with the company for 26 years and has 

worked in various pumping services positions; field 

engineering, sales, technical team, management and 

in training at the Halliburton Energy Institute. 

Parkey holds a BS (1981) in agricultural 

engineering from Texas A&M University and is a 

member of SPE. 

Bill Grieser (Bill.Grieser@Halliburton.com) is 

an engineer and a member of the unconventional 

reservoir completions team at Halliburton Energy 

Services in Oklahoma City. He began his career 

with Halliburton in 1978 as a field engineer and 

has 29 years’ experience with fracture stimulation 

in Kansas, Colorado, Texas, and Oklahoma. Grieser 

is currently focused on completing horizontal 

wellbores and designing hydraulic fracture procedures 

in four Midcontinent shale plays (Barnett, 

Woodford, Caney, and Fayetteville). He earned a BS 

(1975) in nuclear engineering and BS (1978) in 

mechanical engineering from the Missouri School 

of Mines-Rolla. Grieser is a member of SPE, API, 

Texas Society of Professional Engineers, Oklahoma 

Society of Professional Engineers, and the National 

Society of Professional Engineers. 

Rick Middaugh (Rick.Middaugh@Halliburton. 

com) is the southeastern US technical manager for 

Halliburton Energy Services, based in Carrollton, 

Tex. Since joining Halliburton in 1977, Middaugh 

has worked in operations, technology, sales, 

and management positions in the Michigan basin, 

Appalachian basin, and Midcontinent. He has also 

worked throughout the US as the business development 

manager and asset manager of Wellnite, a 

Halliburton joint venture involving the use of nitrogen 

and CO 2 

in the oil field. Middaugh holds a 

BS (1977) in agricultural engineering from West 

Virginia University and is registered petroleum 

engineer in West Virginia and Texas. 

Glenda Wylie’s biography was published in Part 1, 

OGJ, Dec. 17, 2007, p. 39.


Life-cycle approach improves coalbed methane production 

Glenda Wylie 


Houston 

Gary Rodvelt 


Charleston, W.Va. 

Matt Blauch 

Richard D. Rickman 


Duncan, Okla. 

John A. Ringhisen 

Halliburton 

Oklahoma City 

Loyd E. East 

Halliburton 

Houston 

Drilling 

This series on unconventional gas 

resources concludes with a discussion 

of technologies used in the recovery of 

coalbed methane and potential future 

research areas. The series has reviewed 

three main types of unconventional 

gas reservoirs: 

tight-gas, shale, 

and coalbed 

methane. The 

flow mechanisms 

of the different 

reservoirs increase 

in complexity 

from Darcy flow 

to Fick’s diffusion flow, and include 

combinations of other mechanisms. 

Many different technologies and 

methods have been effective in producing 

unconventional gas. Part 1 

(OGJ, Dec. 17, 2007, p. 39).discussed 

tight gas reservoirs and included such 

processes as hydrajet fracturing. 3 Part 2 

(OGJ, Dec. 24, 2007, p. 41) discussed 

shale gas and a variety of drilling, logging, 

and fluid treatment technologies. 


GAS TECHNOLOGY— 

Conclusion 

Sorption 

Coal’s unique gas-storage mechanism 

is known as the “sorption” process, 

whereby gas molecules are packed 

tightly within the coal-matrix molecular 

pore system (Fig. 1). Concentration 

gradient causes gas to be released from 

the tens to hundreds of square meter 

surface area per gram of coal. Methane 

and other light gases diffuse (Fick’s 

Law) from the coal matrix toward a 

lower concentration. 

Coal can store many times its equivalent 

volume in gas because the gas 

molecules are packed tightly onto the 

surfaces of the coal. Gas adsorbed onto 

and within the coal macerals diffuses 

through a complex flow path of pores 

and cleats of varying sizes. The physics 

of migration is controlled by diffusion 

or diffusivity at various scales. 

Some coals are diffusion limited, 

while others are not. Water and 

sometimes gas exist at equilibrium 

gas saturation. 

Concentration 

gradients are most 

readily generated 

by removing this 

water or gas from 

the cleat system by 

reducing reservoir 

pressure. 1 

Methane sorption isotherms are used 

to help define a relationship between 

gas storage capacity and reservoir pressure; 

from this, a critical desorption 

pressure can be determined. Conventional 

porous-media fluid-flow concepts, 

such as Darcy’s law, relative permeability, 

and permeability anisotropy 

quantify reservoir mechanics after gas is 

released from the coal matrix. Methane 

extraction then occurs via a concentration 

gradient induced by removal of 

the free water or gas from the cleats as 

referenced above with effective stimulation 

or tailor-made well designs. 

Coalbed methane 

Conventional concepts can quantify 

reservoir mechanics after gas is released 

from the coal matrix, but coalbed 

methane (CBM) projects require earlier 

and more thorough evaluations than 

conventional projects. Therefore, CBM 

technologies, when viewed from a development 

life-cycle perspective, must 

depart from a conventional oil and gas 

approach in order to stack the odds for 

a commercial success. 

Historically, CBM projects include a 

few top-tier wells and many average-tomarginal 

wells. Because CBM prospectors 

rarely understand the up-front 

controlling factors that make a good or 

bad well, an investment in a regional 

view and multiwell approach early in 

the program is necessary so that the 

economically viable wells or acreage can 

be identified during start-up. 

In a technology-play CBM project, 

innovative applications of enabling 

technologies allow prospectors and 

operators to reduce cycle time before 

the first commercial gas sales. They can 

also screen and high-grade potential 

projects, add value to preproduction 

knowledge gathering, and validate economic 

forecasts that often must project 

much further into the future than those 

of conventional oil and gas reservoirs. 

Life-cycle concept 

CBM projects have five distinct lifecycle 

phases: 

1. Regional resource reconnaissance. 

2. Local asset evaluation. 

“Regulations and economics will require more efficiencies to be forthcoming.” 

—Glenda Wylie, technical marketing director of unconventional resources, 


Reprinted with revisions to format, from the January 21, 2008 edition of OIL & GAS JOURNAL 


Free gas and sorbed gas exist in the coal matrix. The model image shows a depiction of a typical subbituminous 

coal at the molecular level (Fig. 1). 

3. Early development. 

4. Mature development. 

5. Declining production. 

A large-scale project may contain 

multiple localized projects, resulting in 

the simultaneous occurrence of all lifecycle 

phases. 

Fig. 2 presents a scenario in which 

an operator has leased several hundred 

thousand continuous acres of coal 

rights. The operator has been developing 

the asset for more than 15 years. 

Several areas in the lease are mature or 

experiencing declining production, but 

other areas have not yet been evaluated 

for production potential. 

In Phase 1, an operator determines 

whether a property has adequate production 

potential to justify an acquisition 

and exploration. 

In Phase 2, evaluations determine 

whether a specific area should be exploited 

and the most economic development 

methodology for exploiting it. 

In frontier exploration plays or 

basins, cycle time and costs must be 

optimized. The economic issues of 

remote operations further drive development 

of innovative strategies to 

help reduce evaluation time and allow 

go/no-go Phase 3 decisions. Inherent 

highly variable coal-seam characteristics 

over short distances cause difficulties 

in extrapolating core hole and single 

test-well results. Consequently, basinwide 

evaluations or localized testing 

should be performed before a multiwell 

production pilot or development phase 

Enabling technologies matched to cbm life-cycle phases Table 1 

–––––––––––––– CBM life-cycle phase ––––––––––––– 

Enabling technologies 1 2.1 2.2 2.3 3 4 5 

Geospatial well-pattern optimization X X 

Core and core analysis X X 

Well logging X X X X X 

Cleat permeability determination X X X X 

Reservoir engineering software tools X X X X X X X 

Prefracture diagnostics X X X 

Hydraulic fracture stimulation X X X X 

Multiseam coiled-tubing hydraulic fracturing X X X X 

Secondary production enhancement X X 

Infill drilling 

X 

activity. 

In Phase 3, initiation of development 

drilling in potential areas and attaining 

targeted project production is critical 

for capital investment. 

Phase 4 involves maintaining project 

production and economic targets 

through development of marginal areas, 

infill drilling, and remediation. 

Phase 5 can result in secondary 

recovery efforts as a means of extending 

economic viability. Declining production 

requires plugging of unproductive 

wells, removing equipment, and restoring 

the site while maintaining a positive 

cash flow. 

Fig. 3 illustrates a conceptual flow 

path for an example project. A phased 

approach may include separation of the 

single-cased well pilot holes as a Phase 

1 effort. This phased approach can be 

further evolved into a “minipilot.” 

Enabling technologies 

Over the years, many technologies 

and operating practices have evolved 

to help make CBM a viable energy 

resource. Ten specific enabling technologies 

may offer the best chance for 

projects to reach their life-cycle potential 

and span multiple life-cycle phases 

(Table 1): 

1. Geospatial well-pattern optimization. 

CBM geospatial well-pattern optimization 

requires an understanding of CBM 

production mechanics and reservoir 

simulation for production and economic 

forecasting. Although well spacing 

is usually a north-south and east-west 

grid, optimized well patterns are determined 

by reservoir characteristics, completion 

effectiveness, well-stimulation 

effects, drilling and completion costs, 

operating costs, and outside factors. 

For minimal cost, virtual simulation 

enables economic assessment, wellpattern 

comparisons, and completion 

options for hundreds of virtual wells. 

2. Core and core analysis. Scientific 

analysis of coal core can be critical to 

the success of Phases 1 and 2. Calculating 

gas in place from direct core 

measurements is a major first step in 

assessing methane gas reserves trapped


in the rock matrix. Gas-content determination 

is largely independent of the 

core porosity and permeability, but is a 

function of methane adsorption within 

the coal macerals. 

Prospectors may tend to rely on 

nonspecific seam lithotypes and assumed 

values for adsorption isotherms. 

Gas contents are calculated with assumed 

isotherms, reservoir pressures, 

and gross seam thickness. Although 

these estimates are appropriate during 

early prospect evaluation, they must be 

validated through direct-core measurement 

in Phase 2. A complete coal-seam 

anatomy can be obtained and applied to 

the macroscale reservoir. 

3. Well logging. Significant technical 

breakthroughs in well logging 

have been developed specific to CBM. 

Perhaps the greatest advances involve 

log-processing methods and core-log 

integration techniques. Table 2 provides 

recommended log suites for projects in 

Phases 2 through 5. 

Electric microimaging (EMI) logging 

may provide the closest thing to a continuous 

core as currently possible. It can 

be integrated with the whole core so 

that grayscale levels can be correlated to 

discrete core lithology. Such integration 

can be performed in one well and applied 

across the field or basin that lacks 

core information. 

4. Cleat permeability determination. Three 

technologies are potentially available 

for cleat permeability determination 

and are applied predominantly through 

Phases 2 and 3: 

• Openhole discrete-seam drillstem 

testing (DST). 

• Interference testing and injection 

fall-off. 

• G-function derivative analysis. 

DST technology can enable the highgrading 

of discrete seams for subsequent 

production during the corehole 

process. Multiwell interference testing 

can enable the acquisition of far-field 

regional cleat permeability and permeability 

anisotropy. G-function analysis, 

primarily used for comparing regional 

variations, can enable near-field qualitative 

cleat permeability information to 

PROJECT LIFE-CYCLE PHASES Fig. 2 

Phase 1— 

Core / single well 

Phase 4— 

60 wells mature 

Phase 1— 

5-spot 

Phase 1—5-spot 

Phase 1—Core / single well 

be obtained in conjunction with the 

hydraulic fracturing parameters. 

5. Primary hydraulic fracture stimulation. 

Very few coal-seam gas reservoirs can 

produce commercial rates of methane 

without some type of primary production 

enhancement. Three primary 

proven stimulation technologies have 

been developed for enhancing CBM 

production: cavitation, underreaming, 

and hydraulic fracture stimulation. Historically, 

the most effective technology 

Phase 1—Core / single well 

Phase 3—22 wells early 

Phase 5—180 wells mature / declining 


Phase 2— Phase 1—Core / single well 

12 wells early 

Phase 2—16 wells early 

Phase 3—40 


wells early 

2 x 2 

Phase 1— 5–spot 

Phase 1— 

Core / single well 

INTEGRATING RESOURCE-ASSESSMENT, SIMULATION DATA Fig. 3 

1 

Core desorption 

2 

Openhole log 

OH test information 

3 

Coal-seam diffusivity 

data 

8 

Multiseam 

production results 

10 

Reservoir 

production model 

and extractable 

reserves 

evaluation 

7 

Geologic and stratigraphic 

information 

2 x 2.5 

9 

Single-seam 

production results 

6 

Coal core study 

information 

4 

Regional permeability/ 

interference test data 

5 

Regional and core-based 

fracture analysis 

appears to be hydraulic fracturing although 

novel stimulated horizontal and 

complex wells are rapidly becoming 

viable alternatives to traditional vertical 

hydraulically fractured wells. 

In the early phases, a technically, 

rather than economically, optimal 

fracturing system is critical to acquire 

valid gas and water producibility data 

for subsequent reservoir simulation 

and sensitivity analysis. Early development 

of fracture-design simulation 

No. z080121OGJdwy02.eps 

No. z080121OGJdwy03.eps

model(s) can match the outcome of the 

development-phase treatments and provide 

dependable predictions for future 

economic fracture treatments. 

Recent technological developments 

have enhanced hydraulic fracturing for 

CBM resource evaluation. Because the 

indiscriminate application of fracturing 

fluids to coal reservoirs 

contributes to production 

performance, identifying an 

optimal fracturing system 

during resource evaluation 

phase is critical. 

Economic constraints 

regarding mobilization and 

logistics, especially in frontier 

regions where little or no 

service infrastructure exists, 

largely drive fracture design 

decisions. If the goal of a 

single test well in a frontier 

region is to demonstrate that free gas 

can be produced to verify gas saturation, 

then a relatively small, low-cost 

hydraulic fracture design may be more 

appropriate than one designed for fullscale 

production. 

6. Secondary production enhancement. 

During the final two life-cycle phases, 

technologies focusing on secondary 

production enhancement are increasingly 

important for extending the life of 

the CBM field. 

Technologies enabling the extension 

of Phases 4 and 5 include the following: 

• Hydraulic refracturing of previously 

fractured wells. 

• Hydraulic fracturing of previously 

cavity-completed wells. 

• Chemical-enhancement additives 

designed to mitigate specific impairment 

mechanisms included as part of 

the hydraulic fracturing system. Such 

remedial “backflush” technologies can 

be economic, repeated on the same 

well, and extend Phase 4 for years. 

7. Infill drilling. Tapping into new 

reservoirs in a development field is 

an enabling technology because it has 

significantly helped extend Phases 4 and 

5 of a mature CBM prospect. Because 

infrastructure investments have been 

capitalized, combining this approach 

with secondary production-enhancement 

methods offers a solution to stopping 

or stabilizing field or basin-wide 

production declines. 

Reservoir modeling and historymatching 

the field’s cumulative production 

can help identify infill-drilling 

candidates. Combined with geospatial 

Recommended log suites for specific phases Table 2 

–––––––– Phase ––––––– 

Log suite 2 3 4 5 

High-resolution spectral density log X X X 

High-resolution gamma ray X X X 

High-resolution dual-spaced neutron X X 

High-resolution induction X X 

Microlog X X X 

Magnetic resonance imaging log (if applicable) X X 

Electric microresistivity imaging log 

Wave sonic tool (dipole sonic) 

Thermal multigate decay pulsed neutron (if 

also evaluating sands) run through casing 

Dual-spaced neutron (if not evaluating 

sands) run through casing 

X 

X 

well-pattern optimization, infill drilling 

can be optimized for a given asset within 

a basin or field. Emerging technology 

involving multilateral and directional 

drilling may eventually replace verticalwell 

infill drilling for CBM. Currently, 

economics are looking more favorable 

for widespread application of innovative 

multilateral and directionally drilled 

well completions in coal. 

8. Treatment selection. Determining an 

optimum stimulation treatment involves 

experimentation, but the following 

guidelines can help operators avoid 

misapplications and decrease the learning 

curve. The following steps can be 

used for planning treatments in areas 

where few or no CBM completions have 

been performed. 

Typically, coalbeds are categorized 

by: 

• Type of coal, coal thickness, and 

stratigraphy. 

• Proppant needs and desired proppant 

concentrations. 

• Field economics, including service 

costs, accessibility and availability, and 

potential gas rates. 

• Cleanup concerns or needs for 

long-term dewatering of well. 

• Job design process, including 

frac-modeling simulation (pressuredependent 

leakoff (PDL) concerns, rate 

effects, etc.). 

When a well contains several coal 

seams that will act as producing zones, 

differences between zones may prevent 

the success of a single fracture design. 

Economics seldom allow operators to 

pump optimum jobs for each zone, 

even when the zones are 

X 

X 

fractured separately. 

9. Optimizing hydraulic 

technology. Helping to define 

hydraulic technology should 

be considered early and 

evolve throughout the entire 

lifecycle, particularly in the 

local asset evaluation, single 

test well, and five-spot subphases. 

Fracturing fluids selection 

and optimization for 

hydraulic-fracturing technology 

is key in the local asset 

evaluation, single test well, and fivespot 

subphases. In these early phases, a 

technically optimal fracturing system is 

critical in acquiring valid gas and water 

producibility data for subsequent reservoir 

simulation and sensitivity analysis. 

Later in the well’s life, emphasis can be 

shifted from technology to efficiency 

optimization. 

Realistically, the time in which an 

optimum fracturing design can be 

achieved depends on several factors, 

including the following: 

• The volume of available information 

about the seam(s) that will be 

fracture stimulated. 

• How this CBM reservoir responds 

to fracturing compared to existing CBM 

reservoirs. Fracturing treatments that 

incorporate the use of fines control and 

surface modification agent (SMA) provide 

both fines and proppant flowback 

control. This allows the operator to 

produce the wells with the pump at or 

below the lowest perforations for optimum 

efficiency. Increased run times 

with fewer workovers improve the dewatering 

efficiency, shortening the time 

to maximum gas desorption. 

• The technical background and 

CBM stimulation experience of the team 

member(s) responsible for developing


the fracturing program. 

10. Multiseam pinpoint hydraulic fracturing. 

One of the most significant enabling 

technologies for CBM in recent years 

involves technologies that enable the hydraulic 

fracturing of multiseam completions. 

Another fracture stimulation option 

for multiseam completions (not involving 

coiled tubing) is the conventional 

“Perf & Plug” method using conventional 

wireline perforating and composite 

bridge plugs that set quickly and 

are easily drilled out at the end of the 

completion. 

Using coiled tubing, there are 

several new methods for isolating and 

fracturing individual coal seams, some 

of which involve hydra-jet perforating 

(Fig. 4). These methods were 

developed to minimize or eliminate 

non-productive time by planning the 

entire completion to be performed in 

a single trip. Coiled tubing fracturing 

technology allows placement of 30,000 

to 100,000 lb/proppant per coal seam 

With pump time of about 1 hr/seam, 

three to seven stages have been successfully 

treated in a single day. For shallow 

CBM wells, as many as 24 intervals in 

two separate wells have been fracture 

stimulated in a single day with the same 

crew and equipment. 

CobraMax fracturing service uses hydra-jet perforating and proppant plug diversion to fracture multiple 

intervals, vertically and horizontally (Fig. 4). 

Defeating coal fines 

A patented fines locking backflush 

service (FLBS) incorporating aqueous 

tackifier technology provides a process 

to help remove wellbore damage while 

locking down formation fines to restrict 

their mobility (CoalStim). It can be 

used during the initial stimulation job 

or in remedial stimulation jobs. FLBS 

chemicals initially act as “clotbusters,” 

breaking apart the internal bridges and 

agglomerates, and then act as “clotformers,” 

imparting a “tacky” surface to 

the coal particle surfaces. 

FLBS has been used to return hundreds 

of CBM wells in the western US to 

their initial production rates and extend 

the life of these highly profitable fields. 

Other key functions of the FLBS 

chemistry are to degrade residual polymer 

remaining from previous gelledfracturing 

operations and dissolve in 

situ geochemical precipitates or carbonate 

scales that may be contributing to 

premature production declines. 

Coal fines tend to collect in both 

proppant and cleat porosity; eventually, 

such plugging may damage permeability 

and conductivity. FLBS causes fines 

to segregate and then adhesively bond 

together in larger groupings that bond 

onto proppant or cleat surfaces while 

keeping flow channels open to flow. 

Benefits of applying FLBS postfracture 

service in mature CBM fields 

include: 

• Extend well productive life. 

• Economically treat wells/field. 

• Accelerate well pay out. 

• Increase success rate. 

• Lower financial risk. 

• Add significant reserves to existing 

assets. 

The fines control technology can be 

applied in both primary stimulation and 

remedial treatment application modes. 

Field case history 

A look-back study was conducted 

from a mature Phase 4 CBM project in 

the western US in which a total of 495 

FLBS treatments were reviewed. The objective 

of the project was to extend the 

life of the field as it was approaching 

Phase 5. Results showed an average per 

well gas increase of 15,696 Mscf/well 

and 312 bbl/well increase in water over 

a 6 month period. This translated to an 

overall 4,500 % increase in gas volume 

and a project ROI of over 2000%. 

Future technologies 

No one individual technology can 

make unconventional assets profitable. A 

comprehensive holistic approach must 

be taken into account beginning with 

seismic and continuing through to last 

stage of production including plug/ 

abandonment. Future exploitation of 

unconventional gas sources will require 

development and-or refinement of several 

technologies: 

• Deformable proppants 

• Partial monolayer proppant designs 

• Proppant transport 

• Improving proppants and fluids 

that are better tailored to formations. 

• Create a better understanding of 

reservoirs by improving reservoir modeling 

and description 

• Better prevention of circulation 

losses while drilling. 

• Recycling and purification of water 

used in well-service functions. 

• Reducing emission to the atmosphere 

• Minimize land use through centrally

located rigs and fixed-plant hydraulic 

fracturing operations serving many wells. 

• Improved efficiency. 

• Increasing simultaneous operations, 

e.g., drilling, stimulation, and 

production at the same time. 

• Improving automation and realtime 

operations for improving learning 

and reducing manpower requirements. 

• Improving recovery processes for 

ultra low pressure reservoirs, including 

improving artificial lift and improved 

recovery processes 

Acknowledgments 

The authors thank Halliburton management 

for their support and permission 

to publish the unconventional 

article series. ✦ 

References 

1. Blauch, M.E., Weida, D., Mullen, M., 

and McDaniel, B.W., “Matching Technical 

Solutions to the Lifecycle Phase is the Key 

to Developing a CBM Project,” SPE 75684, 

SPE Gas Technology Symposium, Calgary, 

Apr. 30-May 2, 2002. 

2. Smith, Michael, Blauch, Matt, 

and Welton, Thomas, “Process increases 

CBM production,” Hart’s E&P, November 

2004. 

3. Surjaatmadja, J.B., Grundmaan, 

S.R., McDaniel, B., Deeg, W.F.J., Brumley, 

J.L., and Swor, L.C., “Hydrajet fracturing: 

An Effective Method for Placing Many 

Fractures in Openhole Horizontal Wells,” 

paper SPE 48856, SPE International Conf. 

& Exhibition, Beijing, Nov. 2-6, 1998. 

4. East Jr., Loyd, Grieser, William, 

McDaniel., B.W., Johnson, Bill, and 

Fisher, Kevin, “Successful Application of 

Hydrajet Fracturing on Horizontal Wells 

Completed in A thick Shale Reservoir,” 

paper SPE 91435, 2004 SPE Eastern 

The authors 

Gary Rodvelt (Gary.Rodvelt@Hallibuton.com) 

began work in the Midcontinent (Illinois) division 

and now works on Applalachian basins –unconventional 

reservoirs. In 28 years, he has worked in 

management, sales/marketing and engineering. 

Rodvelt graduated from Kansas State University 

with nuclear engineering (BS). He is a member of 

Society of Petroleum Engineers and the Appalachian 

Geologic Society and has published numerous 

coalbed methane papers and other unconventional 

reservoir focused papers. 

Matt Blauch (Matt.Blauch@Halliburton.com) is 

a principal technical professional in Halliburton’s 

production enhancement group. He has more than 20 

years’ experience in the industry, including 15 years 

working with unconventional gas, focused on CBM 

and shale gas. He graduated from Juniata College, 

Huntingdon, Penn., with a BS (1982) in geology 

and then earned an MS (1988) in geology from the 

University of Akron. He is a member of the American 

Association of Petroleum Geologists and SPE. 

Richard D. Rickman (Richard.Rickman@Halliburton.com) 

is a senior scientist (chemist) at Halliburton’s 

Duncan Technology Center in Duncan, 

Okla., where he works in both the fracturing and 

sand control groups. Rickman graduated from Texas 

Regional Meeting, Charleston, West 

Virginia, 15-17 September 2004. 

5. Romer, W. C., Phi, M. V., Barber, R. 

C., and Huynh, D. V., “Well Stimulation 

Technology Progression in Horizontal 

Frontier Wells, Tip Top/Hogsback Field, 

Wyoming,” paper SPE 110037, 2007 

SPE Annual Meeting, Anaheim, Nov. 

11-14, 2007. 

A&M University with a PhD (2004) in chemistry. 

He is a member of SPE and the American 

Chemical Society. 

John Ringhisen (John.Ringhisen@Halliburton. 

com) has been with Halliburton for 36 years in 

various field pumping services assignments, sales 

and service line management positions. Based 

in Oklahoma City, he concentrates on cementing 

issues for the midcontinent area. Ringhisen 

received a BS (1969) in petroleum engineering 

from Marietta College, Ohio, and he is a 


Loyd East (Loyd.East@halliburton.com) is currently 

global pinpoint stimulation manager at Halliburton. 

He has been working in the oil and gas 

industry for more than 26 years. East’s most recent 

work is in multiple-interval well completions and 

horizontal well stimulation. His previous assignments 

include engineering positions in technology 

and instructor at the Halliburton Energy Institute. 

East earned his BS (1980) in agricultural 

engineering from Texas A&M University; he is a 


Glenda Wylie’s biography was published in Part 1, 

OGJ, Dec. 17, 2007, p. 45.

H06060 

www.HALLIBURTON.com

Trends In Unconventional Gas - Halliburton

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