SPECIAL REPORT: UNCONVENTIONAL GAS TECHNOLOGY—1: Advances in fracs and fluids improve tight-gas production

Dec. 17, 2007
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.

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 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 technologies 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 (<0.1 md) and abnormal pressures. The complexities are both technical and economic. Unconventional reservoirs, in general, require higher capital expenditure compared 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 permeability, clay swelling and migration, capillarity effects (capillary action), near-wellbore restrictions, and formation complexity and heterogeneities. These characteristics usually contribute to damage during drilling and cementing operations, water-phase trapping, screenouts, limited proppant advancement into the reservoir, dehydrated polymer, and other problems.2

The performance of tight-gas reservoirs cannot be predicted with traditional reservoir evaluation and stimulation methods. While tight-gas reservoirs do require a high density of wells, drilling 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 maximize 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, including petrophysics, fracturing, production, drilling, scheduling, facilities, and economics. The model provides a complete set of investment scenarios defining better well efficiencies and the means to optimize supply-chain efficiencies.3

Well completions

Optimized well completions in tight gas formations require several steps:

  1. Set realistic expectations. It is important 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 characterization. Reliable optimization of completion requires better knowledge of the reservoir properties. Reservoir properties include not only the physical properties 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.
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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Fig. 1 illustrates a multizone completion featuring swellable-elastomer packer systems isolating various zones of a horizontal wellbore.

Hydraulic fracturing

Unconventional (tight), continuous-type 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. CO2, N2, and binary high-quality foams are widely used in this type of reservoir because of their capacity to energize the fluid and improve total flowback volume and rate. CO2- 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 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 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


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 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 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 high-pressure, 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 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 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. Shifting projects above the economic threshold.
  4. Extending lifecycle of wells.

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 to a conventionally treated offset well.


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.


  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 CO2 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

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Glenda Wylie ([email protected]) 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 ([email protected]) 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 ([email protected]) 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.