Polymer-Free Fracturing Fluid Exhibits Improved Cleanup for Unconventional 
Natural Gas Well Applications

Fredd, C.N.; Olsen, T.N.; Brenize, Galen; Quintero, B.W.; Bui, Thang; Glenn, S.; Boney, C.L.

doi:10.2523/91433-ms

Cited by 5 publications

(5 citation statements)

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“…A nitrogen-foamed viscoelastic surfactant-based system for use in unconventional natural gas wells has been developed that is a coal/carboniferous shale-compatible solids-free (CCSF) fluid (Fredd et al 2004). The CCSF fluid showed greater than 70% retained permeability and cleanup factors less than 100 psi-min-K with formation coal samples from seven different basins in North America.…”

Section: A4 Foamed and Emulsified Vesmentioning

confidence: 99%

Recent Advances in Viscoelastic Surfactants for Improved Production from Hydrocarbon Reservoirs

Hull

Sayed

Al-Muntasheri

2015

Day 2 Tue, April 14, 2015

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Viscoelastic surfactants (VES) are used in upstream oil and gas applications, particularly hydraulic fracturing and matrix acidizing. A description of surfactant types is introduced along with a theoretical description of how they assemble into micelles, what sizes and shapes of micelles can be formed under different conditions, and finally how specific structures can lead to bulk viscoelastic solution properties. This theoretical discussion leads into a description of the specific VES systems that have been used over the last twenty years or so in improved oil recovery for upstream applications.VES-based fluids have been used most extensively for hydraulic fracturing. They are preferred over conventional polymer-based fracturing fluid systems because they are essentially solids-free systems which have demonstrated less damage to the reservoir rock formation. Important advancements in VES have been made by introducing "pseudo-crosslinking agents" such as nanoparticles to enhance the viscosity. Fracturing fluid systems based on VES have also been improved recently by developing internal breakers to lower their viscosity in order to flow back the well. The flexibility of VES-based fluids has been demonstrated by their application as foamed fluids as well as their incorporation with brine systems such as produced water.A second key area that has benefited from VES-based systems is matrix acidizing carbonated-based reservoirs. The viscosity of these VES-based fluids is mostly controlled by pH where, at low pH (low viscosity), the acid system flows easily and invades pore spaces in the formation. During acidizing, the acid is spent, and the pH and viscosity increase. Because the spent acid has higher viscosity, fresh acid is diverted to low permeability un-contacted zones and penetrates the rocks to form wormholes. A number of experimental studies and field applications to these effects have been performed and will be described here.In order for VES-based fluids to play a more prominent role in the field, inherent limitations such as cost, applicable temperature range, and leak-off characteristics will need to continue to be addressed. If we can efficiently and economically overcome these issues, VES-based fluids offer the industry an excellent clean, non-damaging alternative to conventional polymer-based fluids.

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Section: A4 Foamed and Emulsified Vesmentioning

confidence: 99%

Recent Advances in Viscoelastic Surfactants for Improved Production from Hydrocarbon Reservoirs

Hull

Sayed

Al-Muntasheri

2015

Day 2 Tue, April 14, 2015

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“…These relatively large natural fractures can be prone to fluid and particulate invasion from drilling fluids cements and whole polymer fracturing gels. Previous publications have demonstrated how frac gel can invade tens of feet into natural fractures adjacent to induced hydraulic fractures, and how this can greatly temper the stimulation effect from fractures 4,5 . For years gelled fluids were used to fracture stimulate natural fractured formations.…”

Section: Natural Fractures and Modern Stressmentioning

confidence: 99%

Quantifying Proppant Transport for Complex Fractures in Unconventional Formations

2009

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Since the widespread proliferation micro-seismic fracture mapping, it has been observed that some naturally fractured formations exhibit a non planar or complex set of micro seismic events. This fracture mapping technique has provided some valuable insight into the nature of this complex fracturing. However, this mapping is not necessarily a direct measurement of hydraulic fracturing. Instead the microseisms are small shear failures in the rock that can be caused by changes in pressure and temperature of the formation. Therefore we cannot know with certainty if these events are directly showing us where the proppant or even the frac fluid is going. None the less, this insight to complex fracturing, has been key to improving economic recovery of many unconventional plays over the past 8 years. However much of the improvements, have been through empirical trial and error and qualitative techniques. For example it had been observed that thin fracturing fluids tended to create more complex fracturing than viscous fluids. More recently it has been observed that smaller mesh proppant may be more successful at being transported out into the multiple fracture planes of the formation than larger mesh proppant. Although this trial and error technique has been useful, it is often very slow and can be expensive, it took many years to optimize the Barnett play in the Ft. Worth basin. But even more detrimental is when a success from one basin is applied in another basin without fully understanding the underlying mechanics. This can often lead to costly disappointment. This paper reviews the key parameters that need to exist to enable complex fracturing such as:○Nature and genesis of the natural fractures.○Orientation of the minimum and maximum horizontal stress.○The juxtaposition of the natural fractures to the stresses.○Magnitude of the difference between the minimum and maximum horizontal stress.○Poisson's ratio and Young's modulus of the rock being stimulated. From this information we attempt to quantify the dilation pressure of natural fracture systems which precede complex fracturing. But in particular we attempt to investigate the mechanics of the critical intersection of these transverse fractures and how they can interfere with each other and create pinch points that can inhibit non planar proppant transport. The ultimate goal of this paper is to demonstrate a methodology for quantifying the width relationship of these intersecting fracture systems, which can be used to determine if multi planar proppant placement is possible and help design the optimum mesh size and net pressure required to enable successful placement. Introduction: As conventional resources for natural gas become depleted, unconventional resources become more and more important for meeting our natural gas energy needs. It is estimated that currently more than 7 tcf of natural gas production per year come from unconventional tight gas, coalbed methane, and shale gas1. With extremely low matrix permeability formations, natural fracture enhancement of the formation permeability becomes important and many times essential for economic exploitation. The degree of influence natural fractures have upon reservoir formation permeability, storativity and completion effectiveness varies greatly and depends upon many parameters such as the origin of the fractures, fracture digenesis, the stress on the natural fractures, and stress orientation. Unfortunately many of these parameters are not always well understood when completion and stimulation decisions are made.

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“…There have been multiple evolutions of the VES technology such as making it more environmental friendly, extensions for applications with higher bottomhole static temperatures, as well as tailoring it to specific application requirements. 3,4 The unique rheological behavior of the solids-free VES fluid is derived from the dynamic nature of the 3D network of worm-like micelles. 2 These micelles form through the aggregation of surfactant molecules in which the hydrophobic tails orient towards the interior of the micelles, away from polar media (water).…”

Section: Viscoelastic Surfactant Based Fracturing Fluidsmentioning

confidence: 99%

“…Such test was were used to evaluate clean up factors for different fluids in coal samples. 3 The experimental set up and rock sample preparation procedures are described below.…”

Section: Shown Inmentioning

confidence: 99%

Case Study: Application of a Viscoelastic Surfactant-Based CO2 Compatible Fracturing Fluid in the Frontier Formation, Big Horn Basin, Wyoming

Bustos¹,

Heiken²,

Stewart³

et al. 2007

Proceedings of Rocky Mountain Oil &Amp; Gas Technology Symposium

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fax 01-972-952-9435.Abstract CO2 based fluids are commonly used to fracture stimulate formations with low reservoir pressure as well as formations that are more sensitive to water treatments (high capillary pressure, swelling clays etc). In particular, the Frontier Formation located in Bighorn Basin, Wyoming, has seen a variety of stimulation fluids used over the past years with varying degrees of success. When dealing with water sensitive formations, a common practice has been to use oilbased fluids. However, fluids of this nature can have detrimental effects on gas zones with low reservoir pressure and this might be the reason for erratic well performance of previously treated Frontier completions. It has also been determined that oil-based fluids can alter the reservoir wettability and hence cause formation damage. With this in mind and considering the environmental and economical benefits of using a water-based fracturing fluid, a novel viscoelastic surfactant based, CO2-compatible, high foam quality (>60%) fluid was proposed as the main fracturing fluid. This paper will discuss the first application of this visco-elastic based fluid on wells in Park County, Wyoming. This paper will discuss stimulation with the new fluid and how pin-point pressure measurement enabled the operator to make informed decisions to define fracturing/completion strategy. We also present the additional benefits of incorporating existing dipole sonic tool information to calibrate "in-situ" stress, Young's Modulus and Poisson's ratio. Finally, a production history match is conducted on wells treated with the new fluid.

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Polymer-Free Fracturing Fluid Exhibits Improved Cleanup for Unconventional Natural Gas Well Applications

Cited by 5 publications

References 0 publications

Recent Advances in Viscoelastic Surfactants for Improved Production from Hydrocarbon Reservoirs

Recent Advances in Viscoelastic Surfactants for Improved Production from Hydrocarbon Reservoirs

Quantifying Proppant Transport for Complex Fractures in Unconventional Formations

Case Study: Application of a Viscoelastic Surfactant-Based CO2 Compatible Fracturing Fluid in the Frontier Formation, Big Horn Basin, Wyoming

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