Trends InUnconventional 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 & P r o D u c t i o n

Glenda WylieHalliburton Corp.Houston

Mike EberhardMike Mullen Halliburton Corp.Denver

Advances in fracs and fluids improve tight-gas production

Only 10 years ago, unconventional gas was an emerging resource; now it’s a core business of many large inde-pendent producers and a growing number of major operating com-panies. Twenty years ago, it was largely overlooked.

However, gas companies were devel-oping “hard rock” re-sources 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 coal-bed methane assets are the main sources of what is generally known as uncon-

ventional 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 reser-voirs. They require increased geological understanding and precision engineer-ing 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, reduc-tions 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 drillingDrilling for tight gas requires op-

timized 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 uncon-ventional 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 profitabil-ity is based on exposing more forma-tion through horizontal drilling. Until recently, rotary steerables have been available primarily to the offshore mar-ket 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-

S P e c i a l

Trends in Unconventional Gas

Production

Reprinted with revisions to format, from the December 17, 2007 edition of OIL & GAS JOURNALCopyright 2007 by PennWell Corporation

UNCONVENTIONALGAS TECHNOLOGY—1

gies can address. For instance, high-per-formance, clay-free invert drilling fluids are available that can be formulated with a wide variety of base oils, includ-ing 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 environ-mental impact, conserving costs, and making use of readily available region-ally acceptable base oils.

The rheology of this system is man-aged through application of new emul-sifiers and additives that replace con-ventional 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 ex-cellent suspension but is easily disrupt-ed when circulation is initiated, even at very low pressures. This helps minimize or eliminate the pressure spikes that typically occur when breaking circula-

tion with invert clay-based fluids. Other benefits of the clay-free fluid

systems include:•  Improved control over equivalent 

circulating density.•  Increased tolerance to contami-

nants, including solids and water.•  Smaller footprint on drillsite with 

fewer additives required for mainte-nance.

•  Real-time response to chemical treatments—no waiting for “yield.”

• Thin filter cake and excellent re-turn permeability values.

Reserves optimization

Optimizing development of tight gas sands can be difficult due to character-istically low permeability (<0.1 md) and abnormal pressures. The complexi-ties are both technical and economic. Unconventional reservoirs, in general, require higher capital expenditure com-pared with conventional reservoirs, and profitable production rates are in most cases achieved by hydraulic fracturing of pay zones.

The perfect fracturing job consists of an inexpensive, long fracture with infinite conductivity, 100% propped,

100% effective length, and precisely contained in the pay zone with 100% fluid recovery. Realistically, however, we know that a tight, gas-bearing zone faces abnormal pressure, low perme-ability, clay swelling and migration, capillarity effects (capillary action), near-wellbore restrictions, and forma-tion complexity and heterogeneities. These characteristics usually contribute to damage during drilling and cement-ing operations, water-phase trapping, screenouts, limited proppant advance-ment into the reservoir, dehydrated polymer, and other problems.2

The performance of tight-gas reser-voirs cannot be predicted with tradi-tional reservoir evaluation and stimula-tion methods. While tight-gas reservoirs do require a high density of wells, drill-ing may result in a number of marginal or poor-performing wells.

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 maxi-mize well rates and ultimate recovery.

An integrated asset model can help exploration and production companies achieve these objectives by integrating all aspects of tight-gas development, includ-ing petrophysics, fracturing, production, drilling, scheduling, facilities, and eco-nomics. The model provides a complete set of investment scenarios defining better well efficiencies and the means to optimize supply-chain efficiencies.3

Well completionsOptimized well completions in tight

gas formations require several steps:1. Set realistic expectations. It is im-

portant to understand the limitation of a tight-gas formation and its capability to produce. The low permeability of the formation dictates that we increase the flow area deep into the formation to get economical production.

2. Get better reservoir characteriza-tion. Reliable optimization of comple-tion requires better knowledge of the reservoir properties. Reservoir proper-ties include not only the physical prop-

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).

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D r i l l i n g & P r o D u c t i o nerties of the rock, but also its mechani-cal 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, con-ductivity, and height.

5. Achieve realistic modeling, a key to optimization of completion.

Fig. 1 illustrates a multizone comple-tion featuring swellable-elastomer packer systems isolating various zones of a horizontal wellbore.

Hydraulic fracturingUnconventional (tight), continuous-

type reservoirs, such as those in the Cretaceous of the northern Great Plains, are not well suited for conven-tional formation evaluation. Pay zones frequently consist only of thinly laminated intervals of sandstone, silt, shale stringers, and disseminated clay. Potential producing intervals are com-monly unrecognizable on well logs and thus are overlooked.

To aid in the identifica-tion 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 neu-tron porosity minus density porosity vs. gamma-ray intensity.4

The geomechanical effect on res-ervoir performance should always be

considered, especially when producing from thick formations or creating mul-tiple fractures in horizontal wells.

Recovering fracturing fluids is often difficult in underpressured, tight, deep formations. CO

2, N

2, and binary high-

quality foams are widely used in this type of reservoir because of their capac-ity to energize the fluid and improve total flowback volume and rate. CO

2-

and N2-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 be-lieved 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 sur-face and interfacial tension are also key

elements in the design of fluid systems to enhance recovery and reduce entrap-ment of fluid barriers within the forma-tion. Enhanced fluid recovery improves overall completion economics due to the lower total treatment cost and short-er time required for flowing back fluids. The most important benefit is achieving a less-damaged proppant pack, resulting in higher fracture conductivity.

Fracturing horizontal wellsFracturing horizontal wells is the

most promising production-enhance-ment technique in some formations. Fracturing in general is the more attrac-tive 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 stimula-tion 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

SurgiFracCombined hydrajetting, fractur-

ing, 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 tech-nique (SurgiFrac) is a combination of three separate processes: hydrajetting, hydraulic fracturing (through tubing),

“To optimize returns on tight-gas as-sets, the primary objectives should be to strive for overall asset efficiency in drilling, stimulation, logistics, field sur-veillance, and operations, and to pro-vide predictable delivery to maximize well rates and ultimate recovery.”

and coinjection down the annulus (us-ing separate pumping equipment).

One important aspect of this tech-nique 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 move-ment. 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 gener-ally maintained constant. To perform the SurgiFrac service, a jetting tool is placed near the toe of the well and used to jet-perforate 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, high-velocity 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 ex-tend the fracture.

After the fracturing process is com-pleted, the tool is moved to the next fracturing position and another fracture is placed.

The conversion of low-pressure, high-velocity kinetic energy to high-pressure, low-velocity potential en-ergy 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 initia-tion pressure is much higher than fracture extension pressure, achieving multiple fracture initiation points along a horizon-tal 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 ap-plied successfully in a variety of fractur-ing 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 hori-

zontal wellbore.A case history illustrates the utility

of the multizone fracturing method. The first subsea CHF fracture stimula-tion 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 produc-tion 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 surfactantsIf the formation permits, often

water-based hydraulic fracturing is car-ried out in tight gas formations. Tradi-tionally, 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 boost-ing production from these difficult formations.

The special surfactant was designed to replace methanol or conventional surfactants. Based on new microemul-sion technology (GasPerm 1000), the surfactant helps remove water drawn into the formation during the fractur-ing 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 reser-voir 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 low-permeability formation at the fracture face, and the gas cannot displace it. This trapped liquid can inhibit production-gas flows.

Using a microemulsion surfactant can specifically mitigate fracture-face damage caused by capillary effects and

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D r i l l i n g & P r o D u c t i o n Special Report

The authorGlenda 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 engineer-ing 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 Hal-liburton 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 forma-tion 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.

phase trapping. The surfactant can also enhance phase displacement and spatial flow behavior and help enhance mobility if liquid hydrocar-bons 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 eco-

nomic 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 alterna-tive to methanol-based fracturing flu-ids, 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 effec-tiveness 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 im-proved by 43%. The surfactant reduced water saturation and capillary pressures along the fracture faces, which im-proved 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 pro-duced more than 14 times the wellhead pressure (100 psi vs. 1,400 psi) and al-most doubled the initial production rate (862 Mcfd vs. 1,432 Mcfd) compared

to a conventionally treated offset well.

RefracturingHydraulic 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 degrada-tion 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 forma-tions where a very high capillary pres-sure may be expected in cases having a water phase.

Refracturing can expose more reser-voir area to the high-conductivity frac-tures, thus improving well productivity and reservoir exploitation.  ✦

References1.  Kuuskraa, Vello A., “A Decade 

of Progress in Unconventional Gas,” Advanced Resources International, Ar-lington, Va., July 6, 2007.

2. Tamayo, H.C., Lee, K.J., and Taylor, R.S., “Enhanced Aqueous Fracturing Fluid Recovery from Tight Gas Forma-tions: 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 Tsch-irhart, Nicholas R., “Optimal Stimula-tion Treatments in Tight Gas Sands,” paper SPE 96104, 2005 SPE Annual Technical Conf. and Exhibition, Dallas, Oct. 9-12, 2005.

“Desaturating water and removingphase trapping can improve inflow of gas from the fracture face and help in-crease gas production.”

D r i l l i n g & P r o D u c t i o n

Glenda WylieRon HydenHalliburton Corp.Houston

Von ParkeyBill GrieserHalliburton Corp.Oklahoma City

Rick MiddaughHalliburton Corp.Carrollton, Tex.

Custom technology makes shale resources profitable

Low permeability shales are unconventional gas reservoirs that are being more efficiently exploited with newly developed production technologies.

This series began last week, with an article discussing advances in fracture stimulation tech-niques 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 coal-bed methane (CBM) production.

ShalesThere are technical difficulties in

producing gas from shales, which have ultralow permeabilities and vary in brittleness. Multilayered shale reservoirs have widely varying reservoir charac-teristics and flow mechanism regimes. Formations typically have high capillary pressures in hydraulic fracturing sce-narios. Treatment fluids can potentially damage shale formations.

Multilayered shale reservoirs with a variety of reservoir characteristics re-quire 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 sys-tem. The system is tailored for the spe-cific 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, simpli-fied, rotary-steerable drilling assemblies in land-based shale wells.

Determining proper fracture place-ment within shale formations is a key to creating large, highly productive

fracture networks. Logging systems use an innovative approach, incorporat-ing 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 de-pends on the capa-bility to maximize formation exposure through horizontal or vertical drilling and fracturing, or both.

Economical rotary-steerable drilling assemblies, high-horsepower fracturing units, and multifunctional fracture-placement techniques provide maxi-mum 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 migra-tion from the producing shale. Brittle-ness 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 horse-power in a reduced environmental “footprint.”

New designs include increased horsepower and high-rate pumps and offer improved safety, performance, reliability, space utilization, opera-tional efficiency, real-time automation throughout the entire fracturing system, and ultimate improved gas recovery.

Multilayer reservoir characteristics and ultralow formation permeability re-quire precision fracturing of optimum locations along the wellbore, which has led to significantly improved produc-tion results.

Pinpoint stimulation techniques have evolved, making shale more profitable as gas prices cycle. Multiple zones can

Production

UNCONVENTIONALGAS TECHNOLOGY—2

Reprinted from the December 24, 2007 edition of OIL & GAS JOURNALCopyright 2007 by PennWell Corporation

D r i l l i n g & P r o D u c t i o nbe efficiently fractured independently by:

•  Using coiled tubing or tubulars with hydrojetting techniques.

•  Using dynamic diversion tech-niques for either vertical or horizontal placement.

•  Or, incorporating completion me-chanical downhole assemblies featur-ing 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 treatmentUltralow permeability

is the primary challenge in shale formations. Fracturing fluids that are nondamag-ing 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 perme-ability to gas, contributing significantly to the shale-production success. Components of the fracture fluids include:

•  Special friction reducers formu-lated 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, re-leasing imbibed treatment water and improving gas permeability. It also provides significant safety and environ-mental benefits by replacing methanol in water-block treatments.

•  Fracture-cleaning enhancer and conductivity enhancer for accelerating fracture cleanup and flowback of treat-ment fluids.

Together, these components create a synergistic fluid treatment solution de-

signed to help optimize gas production from formations with ultralow native permeability. The system provides work-able, 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

together to provide a synergistic solu-tion targeted specifically at changing a potential resource into an important energy producer.

Multilayer reservoirsMultilayered reservoirs exhibit a

wide range of reservoir characteristics that need to be evaluated, modeled, and monitored.

A shale-specific modeling and analyti-cal system evaluates formation mechani-cal properties, total organic carbon con-tent, shale maturity, vitrinite reflectance, gas content in scf/ton, and free and adsorbed gas content. Specialized shale-logging analyses, reservoir simulation, production history matching, injection test analysis, microseismic, and overall

field characteristics help to inform new well or new field development decisions. (Microseismic applications are “trained” by data from adjunct wells or fields.)

Passive microseismic fracture monitoring (PMM) applications include mapping the extent of fractures dur-ing hydraulic-fracture treatments, fault mapping, and tracking a gas or water front for assisted recovery production. To exploit the benefits of PMM, a re-cently developed technology combines logging and borehole seismic with the

science of microearthquakes to allow the monitoring of fractures while they are cre-ated. With this assist, fractur-ing engineers can obtain the answers they require.

This approach to logging offers:

•  Dipole sonic used for pre-stimulation vertical stress profile modeling.

• Velocity profile for bore-hole seismic modeling.

Fiberoptic monitoring provides temperature profiles over the entire length of the well during the stimula-tion treatment. Comparing and analyzing temperature profiles over time provides direct indications of injec-

tion distribution at various points in the wellbore. The real-time information allows immediate optimization of the treatment and postjob follow-up to aid in future treatment optimization.

Capillary pressureShales often have high capillary

pressures. A unique microemulsion surfactant helps control fluid-induced fracture-face damage during hydraulic fracturing and helps release trapped water and increase production in low-pressure, tight formations. This surfac-tant helps reduce fracture-face damage caused by phase trapping; enhances mobilization of liquid hydrocarbons (including condensate); helps increase regained permeability to gas follow-ing treatment; improves load recovery;

Makeup of productive shale formations

In general, a productive shale formation in-cludes these characteristics:

•  Zone thickness >100 ft.• Well bounded and containing energy.•  Maturation in the gas window: Ro = 1.1 to 

1.4.•  Good gas content >100 scf/ton.•  High total organic content (TOC) >3%.•  Low hydrogen content.•  Moderate clay content <40% with very low 

mixed-layer component.•  Brittle composition, as indicated by a low 

Poisson’s ratio and a high Young’s modulus.•  Combines rock fabric with reservoirs and 

lithology features that enhance gas producibility.

improves environmental and safety per-formance by replacing methanol; and is effective in reservoirs with matrix permeability in the nano-Darcy range.

Formation damageA 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 phe-nols, it provides improved environmen-tal performance and exhibits less flocculation than con-ventional friction reducers.

A viscosity-reducing agent helps maximize the effec-tiveness of water-fracturing treatments by reducing fluid viscosity, improving load re-covery, minimizing friction-reducer polymer damage, and preventing polymer ad-sorption 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 stimu-lation sleeves sequentially to isolate each interval of interest during treat-ment. The four intervals were fractured in 15 hr, placing 1.2 million lb of prop-pant with 2.3 million gal of fluid in a continuous operation.

Normal stimulation practices would have required 2 days to run four tradi-tional 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 with-out 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 litho-logically complex, with low permeabil-ity, and requires artificial stimulation to produce.1

•  Case 3. Ten horizontal shale wells

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 rela-tive permeability to gas. Wells using the MS service had initial gas production among the best wells in the field.

Life-cycle phasesOperators 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 experimen-tal wells and investigate fracture design and production prediction.

3. Early development (mass production). Rapidly develop using an optimized de-sign. 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 reme-diation). 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 evaluationUsually, 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 calcu-lated 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. Fac-tors 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 requirementA triple-combo log can be used to

obtain density, gamma ray, resistivity, neutron, and density porosity.

Shale technologies

Several production-enhancement processes are useful in shale-gas reservoirs:

•  Prospect evaluation and core testing.•  Shale lithotyping to determine key charac-

teristics of productive shale.•  Log data integration and analysis specific to 

shale.•  Designing and drilling the vertical and hori-

zontal 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.

D r i l l i n g & P r o D u c t i o nfracture 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 pack-ers have been run in horizontal shale wellbores as a new alternative to ce-menting and perforating. These systems are deployed as part of the production casing and provide mechanical isola-tion 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 net-work of narrow-aperture fractures that can be either induced from extensive shear-failures (like shattered safety glass) or created from dilation of pre-existing, 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 pro-vide 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 con-ductivity typically does not need to be high; 20-50 md-ft is sufficient conduc-tivity 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 produc-tion 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

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 ac-curately measuring hydrocarbon satura-tions 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 productionCommercial 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 selec-tively 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 over-all success of any shale play will include observation of the resource through its life cycle.

Vertical well stimulationCurrent 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 charac-terize the reservoir. With the experience gained from drilling, fracturing, and producing the vertical well, more com-prehensive life cycle phases 3 and 4 can be planned and performed profitably.

Horizontal well stimulationCurrent horizontal stimulation de-

signs 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 completionsHorizontal 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 hori-zontal 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 comple-tions 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 erod-ed by pumping through the tubing at a high differential pressure, using sand and water as the cutting stream. The

fluids may help remove acid-soluble minerals in the bulk shale as well as the mineral-filled fractures, thereby enhanc-ing 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 experi-mental trials of the use of weak-acid reactive systems, the unexpect-ed 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 pro-duction improvement results.

Cementing shale wellsConstructing a suitable cement

sheath around the horizontal section of a shale well is a key element in the pro-cess 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 cement-ed with conventional slurries.

Conventionally cemented wells did not provide adequate zonal isolation and allowed fracturing fluid to commu-nicate 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

rates. Most Barnett shale well stimula-tions, however, are using proppant volumes in the range of hundreds of thousands of pounds. Although some operators question the value of prop-pants, with advance-ments in proppant design, correlating volume and type of proppant with actual production increases may be proved.

Adaptation and modification of cur-rent fracture models calibrated to real-time microsiesmic mapping are being used to help in the design of stimu-lation treatments.

Shale water-frac chemistry features application of friction reducers, surface-mod-ification agents (SMA), microemulsions, de-flocculants, and reactive fluids. The SMA helps minimize proppant settling, con-trol production of fines, and enhance propped fracture conductivity. Micro-emulsion 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. Conven-tional 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.

RefracturingVertical shale wells can see produc-

tion increases of 30-80% from reper-forating the original producing interval and pumping a job volume that is at least 25% larger than the previous frac.

There are two obstacles in refrac-turing horizontal: The initial frac sites

must be somehow isolated, and new frac sites must be created in areas of un-stimulated, horizontal wellbore. Various completion methods such as Hallibur-ton’s SurgiFrac and mechanical comple-

tions with swellable packers eliminate the obstacles.

Shale-reactive fluidsIn 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, how-ever, and contain acid-soluble minerals homogenized in the shale bulk matrix and natural fractures. X-ray diffraction analysis and scanning electron micro-scope images of shale samples show a great diversity and distribution of soluble material in the shale-producing unit.

The amount of gas produced by des-orption is directly related to the amount of surface area exposed, and a shale-reactive fluid may increase the sur-face area of a newly created hydraulic fracture. Gas production from hydrauli-cally fractured shale is believed to come from desorption and diffusivity from microporosity/fractures. Shale-reactive

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

D r i l l i n g & P r o D u c t i o n

hydraulic-fracturing operations. The low compressive strengths of these ce-ments, however, concern some opera-tors that have long considered compres-sive strength to be the leading indicator of cement-sheath integrity in high-pressure fracturing conditions.

Foamed cement’s relatively low compressive strength does not in-crease 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 dur-ing casing-pressure tests or fracture stimulation treatments are tensile in nature. The sheath’s capacity to with-stand these stresses is predominantly determined by the cement’s mechani-cal 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 perfor-mance:

1. Mechanical properties of foamed

cement allow it to withstand greater wellbore pressures than conventional cement.

2. The ductile nature of foamed ce-ment 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 dis-tance may be less because of improved fluid loss provided by the nitrogen bubbles.

Acid-soluble cementZonal isolation for limited-entry

stimulation can be provided by acid-soluble 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 com-munication with the formation and the designed perforation friction controls the fluid distribution along the well-bore.

Unopened perforations and near-wellbore friction resulting from tortuosity caused by the conventional cement can significantly alter the fluid distribution and decrease stimulation effectiveness. Conventional high-com-pressive strength cements with a typical acid solubility of less than 5% cannot be reliably removed so that each perfo-ration 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 conven-tional cement. It can be specifically for-mulated to provide the proper weight, fluid-loss, free water, compressive strengths, and pump times required for particular well conditions. Slurry densi-ties 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 lower-density slurries are needed.

The easy removal of ASC material from the perforation cluster makes it especially suitable for limited-entry horizontal applications. The high-solubility allows the development of a larger communication area in the

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).

annulus immediately adjacent to the perforations while still providing excel-lent zonal isolation along the wellbore. This pocket that is dissolved around the casing at the clustered perforation point eliminates the tortuosity and fracture-entry pressure effects that could alter the planned limited-entry fluid distri-bution. Also, during production, the skin effects, reduced near-wellbore conductivity, and perforation-plugging problems associated with conventional cements are eliminated.

Cement processThe 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 pro-gram 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 compat-ibility 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 moni-

tored and controlled by operating company and service company repre-sentatives to maximize opportunities to make real-time changes to the proce-dure.

Other solutionsIn areas where alternatives to foam

cement may be preferred, recent ad-vances 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 modi-fication 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 sili-cates 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.  ✦

References1. Montgomery, Scott L., Jarvie, Dan-

iel 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 Technol-ogy Symposium, Calgary, Apr. 30-May 2, 2002.

3. Deeg, W.F.J., “High Propaga-tion Pressures in Transverse Hydraulic Fractures: Cause, Effect, and Remedia-

tion,” SPE 56598, SPE Annual Technical Conf. and Exhibition, Houston, Oct. 3-6, 1999.

The authorsRon Hyden (Ron.Hyden@Halliburton.com) has been group manager for stimulation at Halliburton since 2005, based in Houston. He joined the com-pany 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 Insti-tute. 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 proce-dures 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, Mid-daugh 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 develop-ment manager and asset manager of Wellnite, a Halliburton joint venture involving the use of ni-trogen 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.

D r i l l i n g & P r o D u c t i o n

Reprinted with revisions to format, from the January 21, 2008 edition of OIL & GAS JOURNALCopyright 2008 by PennWell Corporation

Glenda WylieHalliburton Corp.Houston

Gary RodveltHalliburton Corp.Charleston, W.Va.

Matt BlauchRichard D. RickmanHalliburton Corp.Duncan, Okla.

John A. RinghisenHalliburtonOklahoma City

Loyd E. EastHalliburtonHouston

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 pro-ducing 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, log-ging, and fluid treatment technologies.

Life-cycle approach improves coalbed methane production

UNCONVENTIONALGAS TECHNOLOGY—

Conclusion

Drilling

“Regulations and economics will require more efficiencies to be forthcoming.”—Glenda Wylie, technical marketing director of unconventional resources,

Halliburton Corp.

SorptionCoal’s unique gas-storage mecha-

nism is known as the “sorption” pro-cess, whereby gas molecules are packed tightly within the coal-matrix molecu-lar 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 equiva-lent 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 lim-ited, 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 pres-sure; from this, a critical desorption pressure can be determined. Conven-tional porous-media fluid-flow con-cepts, such as Darcy’s law, relative per-meability, and permeability anisotropy quantify reservoir mechanics after gas is released from the coal matrix. Methane extraction then occurs via a concentra-

tion gradient induced by removal of the free water or gas from the cleats as referenced above with effective stimula-tion or tailor-made well designs.

Coalbed methaneConventional 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 de-velopment 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-to-marginal wells. Because CBM prospec-tors 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 eco-nomic forecasts that often must project much further into the future than those of conventional oil and gas reservoirs.

Life-cycle conceptCBM projects have five distinct life-

cycle phases:1. Regional resource reconnaissance.2. Local asset evaluation.

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 proj-ect 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 produc-tion requires plugging of unproductive wells, removing equipment, and restor-ing 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 technologiesOver the years, many technologies

and operating practices have evolved to help make CBM a viable energy resource. Ten specific enabling tech-nologies may offer the best chance for projects to reach their life-cycle poten-tial and span multiple life-cycle phases (Table 1):

1. Geospatial well-pattern optimization. CBM geospatial well-pattern optimiza-tion requires an understanding of CBM production mechanics and reservoir simulation for production and econom-ic forecasting. Although well spacing is usually a north-south and east-west grid, optimized well patterns are deter-mined by reservoir characteristics, com-pletion effectiveness, well-stimulation effects, drilling and completion costs, operating costs, and outside factors.

For minimal cost, virtual simulation enables economic assessment, well-pattern 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. Calcu-lating gas in place from direct core measurements is a major first step in assessing methane gas reserves trapped

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 life-cycle phases.

Fig. 2 presents a scenario in which an operator has leased several hundred thousand continuous acres of coal rights. The operator has been develop-ing 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 pro-duction potential to justify an acquisi-

tion and exploration.In Phase 2, evaluations determine

whether a specific area should be ex-ploited and the most economic devel-opment 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 de-velopment 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, basin-wide evaluations or localized testing should be performed before a multiwell production pilot or development phase

Free gas and sorbed gas exist in the coal matrix. The model image shows a depiction of a typical sub-bituminous coal at the molecular level (Fig. 1).

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  XPrefracture diagnostics       X  X  X      Hydraulic fracture stimulation       X  X  X  X   Multiseam coiled-tubing hydraulic fracturing      X  X  X  X   Secondary production enhancement             X  XInfill drilling                    X

D r i l l i n g & P r o D u c t i o nin the rock matrix. Gas-content deter-mination 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 as-sumed values for adsorption isotherms. Gas contents are calculated with as-sumed isotherms, reservoir pressures, and gross seam thickness. Although these estimates are appropriate during early prospect evaluation, they must be validated through direct-core measure-ment in Phase 2. A complete coal-seam anatomy can be obtained and applied to the macroscale reservoir.

3. Well logging. Significant techni-cal 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 con-tinuous 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 ap-plied 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 high-

grading of discrete seams for subse-quent production during the corehole process. Multiwell interference testing can enable the acquisition of far-field regional cleat permeability and perme-ability anisotropy. G-function analysis, primarily used for comparing regional variations, can enable near-field qualita-tive cleat permeability information to

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 pro-duction enhancement. Three primary proven stimulation technologies have been developed for enhancing CBM production: cavitation, underreaming, and hydraulic fracture stimulation. His-torically, the most effective technology

appears to be hydraulic fracturing al-though 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 develop-ment of fracture-design simulation

Phase 1— 5–spot

Phase 1—5-spot

Phase 1— 5-spot

Phase 1—5-spot

Phase 1— Core / single well

Phase 1—Core / single well

Phase 1—Core / single well

Phase 1— Core / single well

Phase 1—Core / single wellPhase 3—22 wells early

Phase 2— 12 wells earlyPhase 2—16 wells early

Phase 4— 60 wells mature

Phase 5—180 wells mature / declining

Phase 3—40 wells earlyPhase 1—5-spot

PROJECT LIFE-CYCLE PHASES Fig. 2

No

. z08

0121

OG

Jdw

y02.

eps

2 x 2

8Multiseam

production results

9Single-seam

production results

10Reservoir

production modeland extractable

reserves evaluation

7Geologic and stratigraphic

information

6Coal core study

information

4Regional permeability/interference test data

5Regional and core-based

fracture analysis

3Coal-seam diffusivity

data

2Openhole log

OH test information

1Core desorption

INTEGRATING RESOURCE-ASSESSMENT, SIMULATION DATA Fig. 3

No

. z08

0121

OG

Jdw

y03.

eps

2 x 2.5

model(s) can match the outcome of the development-phase treatments and pro-vide dependable predictions for future economic fracture treatments.

Recent technological developments have enhanced hydraulic fracturing for CBM resource evaluation. Because the indiscriminate application of fractur-ing 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 fron-tier 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 satura-tion, then a relatively small, low-cost hydraulic fracture design may be more appropriate than one designed for full-scale production.

6. Secondary production enhancement. During the final two life-cycle phases, technologies focusing on secondary production enhancement are increas-ingly important for extending the life of the CBM field.

Technologies enabling the extension of Phases 4 and 5 include the following:

•  Hydraulic refracturing of previ-ously fractured wells.

•  Hydraulic fracturing of previously cavity-completed wells.

•  Chemical-enhancement additives designed to mitigate specific impair-ment 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-enhance-ment methods offers a solution to stop-ping or stabilizing field or basin-wide production declines.

Reservoir modeling and history-matching the field’s cumulative pro-duction can help identify infill-drilling candidates. Combined with geospatial

well-pattern optimization, infill drilling can be optimized for a given asset with-in a basin or field. Emerging technology involving multilateral and directional drilling may eventually replace vertical-well 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 learn-ing 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 prop-pant 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 (pressure-

dependent 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 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 sub-phases. Fracturing fluids se-lection and optimization for hydraulic-fracturing technol-ogy is key in the local asset

evaluation, single test well, and five-spot subphases. In these early phases, a technically optimal fracturing system is critical in acquiring valid gas and water producibility data for subsequent reser-voir 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 informa-tion 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) pro-vide both fines and proppant flowback control. This allows the operator to produce the wells with the pump at or below the lowest perforations for op-timum efficiency. Increased run times with fewer workovers improve the de-watering efficiency, shortening the time to maximum gas desorption.

• The technical background and CBM stimulation experience of the team member(s) responsible for developing

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  X         Wave sonic tool (dipole sonic)  X         Thermal multigate decay pulsed neutron (if  also evaluating sands) run through casing           XDual-spaced neutron (if not evaluating  sands) run through casing           X

D r i l l i n g & P r o D u c t i o nthe fracturing program.

10. Multiseam pinpoint hydraulic fractur-ing. One of the most significant enabling technologies for CBM in recent years involves technologies that enable the hy-draulic fracturing of multiseam comple-tions.

Another fracture stimulation option for multiseam completions (not involv-ing coiled tubing) is the conventional “Perf & Plug” method using conven-tional wireline perforating and com-posite 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 perforat-ing (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 success-fully 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.

Defeating coal finesA 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 “clot-formers,” imparting a “tacky” surface to the coal particle surfaces.

FLBS has been used to return hun-dreds 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 poly-

mer remaining from previous gelled-fracturing operations and dissolve in situ geochemical precipitates or carbon-ate 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 permeabil-ity 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 post-fracture 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 ob-jective 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 technologiesNo 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 sev-eral technologies:

•  Deformable proppants•  Partial monolayer proppant de-

signs•  Proppant transport •  Improving proppants and fluids 

that are better tailored to formations.•  Create a better understanding of 

reservoirs by improving reservoir mod-eling and description

•  Better prevention of circulation losses while drilling.

•  Recycling and purification of wa-ter used in well-service functions.

•  Reducing emission to the atmo-sphere

•  Minimize land use through centrally 

CobraMax fracturing service uses hydra-jet perforating and proppant plug diversion to fracture multiple intervals, vertically and horizontally (Fig. 4).

located rigs and fixed-plant hydraulic fracturing operations serving many wells.

•  Improved efficiency.•  Increasing simultaneous opera-

tions, e.g., drilling, stimulation, and production at the same time.

•  Improving automation and real-time operations for improving learning and reducing manpower requirements.

•  Improving recovery processes for ultra low pressure reservoirs, including improving artificial lift and improved recovery processes

AcknowledgmentsThe authors thank Halliburton man-

agement for their support and permis-sion to publish the unconventional article series.  ✦

References1. 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, Novem-ber 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

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.

The authorsGary Rodvelt (Gary.Rodvelt@Hallibuton.com) began work in the Midcontinent (Illinois) division and now works on Applalachian basins –uncon-ventional 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 Appala-chian 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@Halli-burton.com) is a senior scientist (chemist) at Hal-liburton’s Duncan Technology Center in Duncan, Okla., where he works in both the fracturing and sand control groups. Rickman graduated from Texas

A&M University with a PhD (2004) in chem-istry. 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 cement-ing issues for the midcontinent area. Ringhisen received a BS (1969) in petroleum engineer-ing from Marietta College, Ohio, and he is a member of SPE. Loyd East (Loyd.East@halliburton.com) is cur-rently global pinpoint stimulation manager at Hal-liburton. 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 assign-ments 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 member of SPE.

Glenda Wylie’s biography was published in Part 1, OGJ, Dec. 17, 2007, p. 45.

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