Copyright 2007, Society of Petroleum Engineers This paper was prepared for presentation at the 2007 SPE Eastern Regional Meeting held in Lexington, Kentucky, U.S.A., 17–19 October 2007. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, Texas 75083-3836 U.S.A., fax 01-972-952-9435.

Abstract The primary purpose of stimulating fractured shale reservoirs is the extension of the drainage radius via creation of a long fracture sand pack that interconnects with natural fractures thereby establishing a flow channel network to the wellbore. However, there is limited understanding of a successful method capable of stimulating Utica Shale reservoirs. Indeed, most attempts to date have yielded undesirable results. This could be due to several factors, including formation composition, entry pressure, and premature pad fluid leak-off. Furthermore, stimulation of Utica shale reservoirs with acid alone has not been successful. This treatment method leads to a fracture length and drainage radius less than expected resulting in poor well productivity. In this work, geological data is first examined for the reservoir. Laboratory data are then presented to address the unique mineralogy and mechanical properties of the Utica shale. The high percentage of acid soluble carbonate and dolomite suggests an acid treatment to lower entry pressures. This treatment can be the main stimulation of a vertical or horizontal well since natural fractures are present, or the acid breakdown can precede a gelled acid or proppant laden water frac or crosslinked fracturing fluid treatment. Experimental results reveal the impact of clays, potential generation of fines both siliceous and organic, acid solubility, low temperature biological activity, potential for scale generation and the prevalent problem of recovery of injected fluids. Acid solubility is presented vs. time and acid strength. Conductivity data is presented for gas fracs, matrix acidizing and proppant fracturing of the shale. The adsorption, as well as the regained relative permeability to gas is examined vs surfactant type to allow the selection of an additive package that will optimize fluid recovery and improve relative permeability to gas. Information obtained from this study can

be used to optimize fracturing treatments of Utica shale reservoirs in the Appalachian Basin. Introduction As interest in drilling and producing shale reservoirs throughout North America increases due to the success of the Barnett, Woodford, and Fayetteville shales, numerous potential reservoirs that have previously been undeveloped are being examined for their potential. The organic-rich, low-permeability Upper Ordivician Utica Shale is one such reservoir that displays many attributes which may result in a commercially viable play of great areal extent. This interest is driven largely by increased natural gas prices and improved completion technologies. Indeed, there may be no better example of the role of technology in natural gas recovery than the Late Mississippian Barnett Shale of the Fort Worth Basin, which provides an analog for exploration of similar unconventional reservoirs throughout North America. Nevertheless, there is no universal production model method of stimulating each and every unconventional reservoir that exists. The Utica Shale compares favorably with such organic-rich units as the Middle Devonian Marcellus Shale of the Appalachian Basin and the Upper Cretaceous Lewis Shale of the Green River Basin (Table 1). Table 1. Properties of various shales

Comparison of Various Shales

SHALE TYPE Utica Marcellus Lewis

AGE Upper Ordovician Mid-Devonian Cretaceous

POROSITY 3.70% 4-9% 1.72%

TOC 2.06% 4-6% 0.45%-1.59%

VITRINITE REF 2.75% 1.40% 1.58%

RESERVOIR PRESS. 0.35 0.5 0.22GRADIENT psi/ft

THICKNESS ft 1,000 80-100 1,200-1,500

KEROGEN TYPE III + II Gas II + III Oil Gas III + II GasWindow Window Window

Nevertheless, most unconventional reservoirs vary in terms of basic stratigraphic facies distribution, mineralogy (i.e., quartz content, clay type and content), natural fracture parameters (length, orthogonal spacing, connectivity, anisotropy), porosity and permeability, and rock mechanical properties. The tight, organic-rich black shale deposits generating the

SPE 111063

Investigation of Methods To Improve Utica Shale Hydraulic Fracturing in the Appalachian Basin J. Paktinat, J.A. Pinkhouse, and J. Fontaine, Universal Well Services Inc.; G.G. Lash, State University of New York- College at Fredonia; and G.S. Penny, CESI Chemical A Flotek Industries Co.

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interest of explorationists are the Utica Shale and the Devonian Marcellus and Rhinestreet shales of the Appalachian Basin. A previous publication described promising results of an experimental investigation of hydraulic fracturing and post-fracturing cleanup of the Upper Devonian Rhinestreet Shale of the Appalachian Basin.1 However, several recently drilled Utica shale wells have not responded well to the normal shale fracturing practices. An understanding of Utica shale mineralogy and rock mechanics is necessary before a stimulation method and fluid are selected. The main objective of this paper is to examine methods of stimulating the Utica Shale. An overview of the geology of the Utica Shale is presented first. Laboratory data are then examined to address the unique mineralogy and mechanical properties of the Utica shale. The high percentage of acid soluble carbonate and dolomite suggests that an acid treatment to lower entry pressures will be required. This treatment may be the main stimulation of a vertical or horizontal well since natural fractures are present, or the acid breakdown can precede a gelled acid or proppant laden water frac or crosslinked fracturing fluid treatment. Experimental results reveal the impact of clays on extraction, potential generation of fines both siliceous and organic, acid solubility, low temperature biological activity, the potential for scale generation and the prevalent problem of recovering injected fluids. Acid solubility vs. time and acid strength is also presented. Conductivity data for gas fracs, matrix acidizing and proppant fracturing of the shale is considered. The adsorption as well as the regained permeability to gas is examined vs. surfactant type to allow the selection of an additive package that will optimize fluid recovery and improve relative gas permeability. Utica Shale - Geological Overview The Upper Ordovician Utica Shale is a fractured black shale that outcrops along the southern and southwestern edge of the Adirondack Highlands of New York State. The unit dips to the south away from the Adirondacks to a depth of ~8,000 feet along the New York-Pennsylvania state line. The Utica Shale and equivalent units can be traced north into Canada, west into Ohio, and south into Pennsylvania. This impermeable organic-rich unit is assumed to be the source of hydrocarbons contained in Cambrian to Devonian reservoirs of the northern Appalachian Basin.2 However, with the exception of some recent gas shows from the Utica Shale in Trenton-Black River exploration wells,3 there has been little to report to date on this unit. Figure 1. Map showing the thickness of the Utica Shale in New York State and northern Pennsylvania (modified from4).

The Utica Shale in New York State ranges from more than 1,000 feet thick in the eastern part of the state to less than 100 feet thick along the Lake Erie shoreline (Fig. 1). The internal stratigraphy of the Utica Shale is more complex than previously realized (Fig. 2). In the western Mohawk Valley, near Syracuse, New York, the Utica Shale comprises a lower black shale interval as thick as ~ 300 feet and the Flat Creek Member, comprised of black calcareous shale and sparse thin limestone beds5. The Flat Creek Shale is overlain by interbedded black shale and limestone of the Dolgeville Formation, which is part of the Trenton Group. These deposits are unconformably overlain by 290 feet of calcareous black shale, the Indian Castle Member of the Utica Shale. Thus, the Utica Shale in the Mohawk Valley comprises two tongues of organic-rich shale separated by Trenton Group limestone and black shale. Figure 2. Simplified stratigraphic column of the Upper Ordovician interval of New York State (modified from 5; not to scale).

The Utica Shale accumulated on the western flank of the north-south trending Taconic foreland basin that had formed as a consequence of thrust loading during the Taconic orogeny.6 Sediment was transported to the basin from the eroding Taconic highlands to the east. Basinward (westward) migration of the Utica marine deposits was episodic as evidenced by alternating limestone and organic-rich shale signaling abrupt deepening of the basin followed by accumulation of more clastic dominated or clay-rich sediment.6 The basin may have migrated westward as much as 300 miles, yet its north-south orientation remained approximately constant during its life.6 Transition of the Utica black shale upward into organic-lean shale, siltstone, and fine-grained sandstone of the Lorraine Shale records the approach of non-marine near-shore environments near the end of the Ordovician (Fig. 2). Utica Source Rock and Reservoir Characteristics Composition and Thermal Maturity. The Utica Shale comprises more than 50% detrital quartz and feldspar. More important, though, to present considerations is the abundance of calcite and dolomite (Table 2). Total organic carbon (TOC; weight %) content of a limited number of Utica Shale samples taken from cores recovered from the Mohawk Valley region of New York State ranges from 1.5 to 2.5 % (unpublished data). Assessment of organic matter type based on oxygen and

SPE 111063 3

hydrogen abundance, as expressed by the Rock-Eval oxygen index (OI) and hydrogen index (HI) parameters,7 suggests that the Utica Shale is comprised dominantly of gas prone Type III organic matter, principally terrestrial-derived woody organic matter (Fig. 3). Table 2. Mineralogy of the Utica Shale

Mineral/Clay Percent Quartz/Feldspar 25

Calcite 26 Fe Dolomite 8 Plagioclase 8

Pyrite 4 Smectite 8

Illite 13 Chlorite 6

Other/Organic 2 Total 100

Figure 3. Crossplot of Rock-Eval hydrogen index (HI) versus oxygen index (OI) showing hydrocarbon generative (kerogen) types for the Utica Shale, New York State.

Crucial to assessing the production potential of a source rock is its thermal maturation. Vitrinite reflectance is arguably the most widely used measure of thermal maturity. However, analysis of land-derived plant material is not applicable to pre-Devonian rocks such as the Utica shale8. Instead, coloration of conodonts and phosphatic skeletal remains of fauna present in rocks ranging from the Cambrian through Permian, has been correlated with vitrinite reflectance.9 Color alteration index (CAI) values of the Middle and Upper Devonian rocks in New York State and Pennsylvania (2.5 – 5.0)10,11 suggest a range in equivalent vitrinite reflectance of >1.5% indicating that these rocks were subjected to thermal stress high enough to generate gas. The Rock-Eval Tmax parameter is another measure of the thermal maturation level of organic matter.7 A plot of Rock-Eval Tmax versus HI reveals a spread of maturity among the measured samples ranging from early (biogenic) gas through dry gas (Fig. 4). This plot also demonstrates the dominance of Type III kerogen in the Utica Shale.

Figure 4. Crossplot of Rock-Eval Tmax versus hydrogen index (HI) data showing the range in thermal maturity of Utica Shale samples as well as hydrocarbon generative (kerogen) types for the Utica Shale, New York State.

Utica Porosity and Permeability. Porosity and permeability data for the Utica Shale is sparse. However, analysis of a small number of Utica shale samples by a commercial lab reveals the tight nature of these rocks. The porosity of the four samples range from 3.7 – 6.0% while the permeability ranges from 0.000080 – 0.003583 md, comparable to studied Devonian black shales of the Appalachian Basin.12,13 The tight nature of the Utica Shale can be observed in scanning electron microscopic images that display a moderately planar microfabric of platy clay grains (Fig. 5A). However, occasional large quartz grains dispersed throughout the clay-grain matrix likely propped the clay-grain microfabric thereby preserving void spaces on a local scale (Fig. 5B). Figure 5. Scanning electron images of Utica Shale samples: (A) planar clay-grain microfabric; note void in the center of the image; (B) oversize quartz silt grain (Q) in an otherwise tight clay-grain matrix.

4 SPE 111063

Combining results of adsorption isotherm analysis of Utica Shale samples (Fig. 6) with calculated gas filled porosity suggests that ~ 25% of the gas contained within the Utica Shale is contained in pore space, the balance being adsorbed onto organic particles and clay grains. Figure 6. Methane adsorption isotherm for the Utica Shale.

Stimulation of the Utica Shale There clearly is a need to enhance our understanding of the technology necessary to extract gas from the Utica Shale. However, before this can be considered, specific criteria of the Utica Shale or any potential pay unit must be met.

• Total Organic Carbon content must be about 3-5%. Utica has been measured at 2.06% in some studies to as high as 3%.

• Thermal Maturity, Ro – Vitrinite reflectance measurement are to define the maximum temperature organics and whether or not the organics in the rock have been baked enough to generate oil/gas. Utica Shale is in excess of 2.0 indicating dry gas.

• Reservoir pressure – We must have adequate residual pressure to have adsorbed gas and to offset injection pressure. Pressure in the reservoir varies from less than 1000 psi in depleted areas to as high as 2500 psi. The reservoir pressure is probably mostly dependent on depth. Shallow Utica will obviously have lower formation pressure than will deeper. In general it can be assumed that pressure will have a gradient of approx 0.5 psi/ft.

• Rock mechanics – We must understand Young’s Modulus and Poissons Ratio which indicates brittleness vs. malleability. These rock mechanics measures must be in a range to allow wellbore stability and allow the rock to fracture upon injecting fluid. Young’s Modulus averages 2.2 x E6 psi while Poisson’s Ratio is in the range of 0.214. This indicates that the Utica Shale is highly elastic making it resistant to fracturing in some areas. Also, immersion in water, salt water or acid tends to soften the shale by 15 to 40% and an average of 29% based on Brinnel Hardness measurements. This indicates the potential for ½ grain embedment on each fracture face.

• Low horizontal stress differential is preferable – determines the frac orientation and degree of complexity created (bi-wing frac or a fairway frac).

• Presence and orientation of natural fractures is an important gas transport mechanism. Further, natural fractures, especially those orientated parallel to the maximum horizontal stress of the contemporary stress field, can be reopened and further propagated by stimulation. Utica Shale has a high degree of natural fracturing.

Fluid Selection Criteria Selecting a method of extracting the gas is crucial in how one should stimulate the shale pay. The mechanical properties indicate that horizontal wells may be a viable option. Whether vertical or sub-vertical wells are drilled, there will be a variety of stimulation options available, with the selection of the fluid and additives being based upon the mineralogy. Fluid selection needs to take into account the:

• High percent of clays • Potential generation of fines both siliceous and

organic • Acid solubility • Low temperature microbiological activity • Potential for scale generation • Problem of recovering of injected fluids

Impact of Clays and Fines. The high percent of clays call for the use of KCl to stabilize the clays. The movement of the clays can be abated by the use of polymer type clay stabilizers. In this case a lower molecular weight product is indicated which will hold the clays and organics in place so that they do not plug the proppant pack and will also not damage the fragile matrix permeability, which is the primary gas mobility mechanism. Mobile fines have an impact on the conductivity of the pack if proppant fracturing is used. A typical 1.0 lb/sq ft pack of 30/50 sand would normally have a conductivity of 900 md-ft at 5000 psi. The addition of fines to the pack can lower the pack permeability to less than half of the expected value. Figure 7 presents the test results of using clay stabilizer vs without on fines generation. A 1 ft column is packed with unwashed fragments of Utica Shale interspersed in a 20/40 white sand. Water is flowed through the pack, the permeability is measured vs time at a rate of 80 ml/min and the fines are collected. The results are shown in Figure 7. In the test with water only, the permeaiblity gradually deteriorates to 50% of the orginial value. With 2% KCl, the permeability drops in a similar fashion. The permeability is slightly higher due to a reduction in swelling. In the test where the pack is treated with 2% KCl and 5 gpt fines stabilizer, the permeability is maintained with fresh water at 110 Darcies over the course of the flow test. This indicates that the fines stabilizer is successful in locking the fines in place and preventing the reduction in permeability of the proppant pack. Also the fines exiting the pack were reduced substantially.

SPE 111063 5

Figure 7. Permeabilty vs time at a flow rate of 80 ml/min through a 20/40 sand pack with shale fragments.

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Acid Solubility Tests. Acid solubility tests were performed on crushed Utica Shale samples collected from an outcrop in NY. The crushed shale was pre-washed with a solution of 2% KCl to remove fines and dried in an oven at 125°F prior to testing. Each test consists of transferring 5.0 grams of dried Utica Shale to a beaker and then exposing it to varying concentrations of HCl for a known period of time. Each sample was then washed, dried and weighed to determine the percent dissolved. Figure 8 shows the percentage of acid soluble material in the Utica Shale samples at varying acid strengths and contact times. Acid solubilities of 30 to 38% were measured depending on acid strength and contact time. The 5% HCl was sufficient to dissolve the acid soluble materials. In an actual job design the acid would have to be suitably inhibited to insure reaching the desired penetration depth. Figure 8. Acid solubility of Utica Shale vs. Acid strength and time

Utica Shale Solubility in Hydrochloric Acid

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Low Temperature Microbiological Activity. The relatively low temperatures of 80-125°F are ideal for microbiological activity. The injected water must have adequate biocide to prevent the growth of anaerobic bacteria. The additive will preferably be persistent enough to prevent growth for several years as the well is completed and produced. Scale Inhibitors. The introduction of water into a carbonate/dolomite environment has the potential for creating

scale and plugging the natural fractures or the proppant pack. This can be prevented by the addition of small amounts of a scale inhibitor in the injected fluid and/or the proppant pack. Recovery of Injected Fluids. The recovery of injected fluid is one of the biggest problems associated with completing shale wells. Recoveries of 15 to 30% are very common thus leaving substantial amounts of fluid in the formation. This retained fluid lowers the relative gas permeability. Methods available to minimize fluid invasion and retention include gas fracs, foam fracs and water or acid fracs with surfactants to aid in water recovery. Fractured Core Experiments If the rock mechanical properties do not allow fracturing,an alternative completion method is the matrix acidizing of the in situ natural fractures with water recovery aids. This should be very effective with a horizontal completion. Once these fractures are opened it may be possible to inject proppant to increase the conductivity. Several tests were run to determine the conductivity following the injection of various fluids/slurries. 1- Inject nitrogen gas only to simulate gas frac and measure conductivity with methane gas. 2- Inject 3% HCl followed by nitrogen and determine conductivity with methane gas, and 3- Inject 3% HCl followed by gelled water/acid frac with 1 lb/sq ft 30/50. The results of this testingare presented in Figure 9. Additional testing with 5% HCl showed a continual decrease in conductivity vs time pumped. Based on these observations it is advisable to use the acid only to insure breakdown and fracture initiation. The main frac should be water or foam frac with the additives as discussed above. Figure 9. Comparison of Conductivity vs. Stimulation Method.

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Treating Fluid Optimization Testing Laboratory experiments have been conducted to optimize the treating fluid recovery and regained permeability for Utica Shale stimulation. The tests conducted include shale packed column adsorption tests to determine the extent of adsorption of various surfactants and post-injection shale core cleanup tests. Shale Packed Column Adsorption Tests. The primary method of adsorption evaluation is surface tension differential measurement of injected fluids. Data interpretations are based

6 SPE 111063

on the premise that when fluids containing surface reducing material migrate through a packed column, some of the surfactants being carried adsorb into the media. Therefore, the surface tension of the fluids traveling further away from the injection point would be higher than at the injection point. In this study any change in surface tension activity is defined as surfactant being adsorbed within the shale pack matrix. Surfactant Selection. Surfactants selected for testing include: a non-ionic C10 straight chain alcohol with twelve moles ethylene oxide (AE), a non-ionic microemulsion (ME) containing linier and branched alcohol ethoxylate with eleven moles of ethylene oxide, a cationic alkyl amine ethoxylate with 15 mole of ethylene oxide (CA), and ethoxylated alcohol fluorosurfactant (FS). Table 3 lists the properties of the surfactants used during this testing. Table 3. Properties of Surfactants Utilized in Absorption Study

Surfactant MW % Activity Moles of EO AE 671 35 12 ME 671 33 11 CA 922 33 15 FS 750 25 0

Adsorption Testing Apparatus. Adsorption tests are conducted by injecting test fluids through a column with the dimensions of 4 foot long by 1.50 inch inner diameter column which is assembled in a vertical position. The column was tapped at 1 foot intervals for collection of fluids. This column is packed with 8-12 mesh crushed Utica shale to regulate the fluid migration throughout the shale pack. Treated fluid was then injected into the shale packed column with pressurized dry nitrogen connected directly to the 4.5 gallon accumulator. This configuration operates at 30 psi. Table 4 lists the specs for the shale packed column apparatus. Table 4. Adsorption Apparatus Testing Setup

Shale Packed Column Adsorption Apparatus Item # Description Dimensions

1 Shale Packed Column Tapped at 1 Foot Intervals

4 ft. Long 1.5 in. Diameter

2 Fluid Accumulator 1.5 ft. Tall

9 in. Diameter 4.5 gal. Capacity

3 Compressed Nitrogen Cylinder

2.5 ft. Tall 6 in. Diameter

The shale packed column was saturated with 2% KCl brine solution to stabilize any clay prior to injecting the various surfactants. Samples were collected at 1 foot intervals and the surface tension of each sample was measured. As surfactant solution replaces the 2% KCl solution, the surface tension drops. These steps were repeated until 61 pore volumes (PV) had been collected from each port over the 4 foot column. Figures 10-13 show the surface tension vs. number of pore volumes of fluid at each of the 4 ports.

Figure 10. AE Surface Tension vs. Pore Volume Number Average Surface Tension vs Pore Volume Number for AE @ 2 gpt in 2% KCl Water

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Average Surface Tension vs Pore Volume Number for ME @ 2 gpt in 2% KCl Water

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Average Surface Tension vs Pore Volume Number for CA @ 2 gpt in 2% KCl Water

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SPE 111063 7

The fluid collected at the 1 ft port is plotted in Figure 14 which summarizes the results for the four surfactants. The ME shows the least retention while the FS shows the most. Previous work showed that even at highly reduced concentrations, the ME is the most effective of the tested surfactants. The Veronoi structure of the three phase microemulsion suggests higher available surfactant properties over the entire area of shale structures making it more effective fluid. It is predicted that higher accumulation of the ME at the shale matrix face provides some trapped surfactants in flowback, thus promoting better fracture cleanup. Figure 14. Surface Tension vs Pore Volume Number at 1st Port

Surface Tension vs Pore Volume Number at the 1st Port for the 4 Tested Surfactants

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AE ME CA FS Shale Core Cleanup Tests. A core flow phase trapping experiment was conducted in the manner described by Bannion et al.15 In this experiment the low permeability core is saturated with 2% KCl and treated with 2 gpt AE and with 2 gpt ME. Results are presented in Figure 15. The AE showed 10% recovery at 1500 psi and 20% at 3000 psi. The ME begins recovery at less than 100 psi with 30% at 1500 psi and 80% at 4500 psi. Figure 15. Phase trapping experiment on 0.001 md core saturated with 2% KCl and treated with 2 gpt of conventional (AE) and ME.

The phase trapping experiment shows the benefit of altering the capillary pressure to allow fluids to flow at lower pressures. It has also been observed that the water saturation in the ME treated cores is 10% less allowing the relative permeability to gas to be double that of the conventional system.

Field Experience Some of the first jobs in the Utica were fracs of varying sizes. Since all shales have varying degrees of natural fractures, the successful stimulation of most of these reservoirs has been shown to be related to the stimulated reservoir volume. Figure 16 shows the range of production expected based upon SRV. Figure 16. Relationship between shale production and stimulated reservoir volume

To achieve these high SRV’s the Appalachaian shales are tending toward larger volumes. An example of this type of completion design is shown in Table 5 below. The initial volumes were 250,000 to 500,000 gal and 500,000 lb of sand. Today the jobs are near 1,000,000 gal of fluid and 1,000,000 lb of 30/50 sand. Table 5. Initial completion designs for the Appalachian shales

Description Volume Rate

Pad 100,000 gallons 40 - 60 BPM

½ PPG 30/50 50,000 40 – 60

¾ PPG 30/50 50,000 40 – 60

1 PPG 30/50 50,000 40 – 60

1-1/2PPG 30/50 50,000 40 – 60

2 PPG 30/50 50,000 40 – 60

3 PPG 30/50 50,000 40 – 60

3 PPG 20/40 50,000 40 – 60

Why such a large volume? Depending on h, microseismic indicates that with more volume comes more Stimulated Reservoir Volume (SRV). Also, depending on the area, an even larger treatment may increase SRV and EUR. Optimization requires information – microseismic. Economics of the treatments are simply that water is relatively cheap. Necessary additives include a friction reducer to lower pumping pressure 60%, a biocide and an additive package to enhance the recovery of the injected fluid. Proppant is required as was shown in the lab data to insure conductivity as reservoir pressure is depleted. Some Barnett operators are increasing volumes and densities with good results. Some are adding equivalent N2 volume. As is pointed out above, other

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additives that may be beneficial include a scale inhibitor and a fines stabilizer package. As technology has advanced in the Barnet, there has been progressively more horizontal wells drilled vs vertical wells. The Utica shale has this possibility as well. Once the wells are drilled, the completion technique is still the question. It is possible that acid washes of the intersected natural fractures with stabilizers may be beneficial as opposed to multiple fracs especially in areas where Poisson’s ratio is low. Figure 17. Barnett Shale Production in vertical wells (light) vs horizontal wells (dark) Conclusions

1. Column adsorption tests show that the microemulsion (ME) adsorbs the least while the fluorosurfactant and cationic adsorb the most. The microemulsion formulation minimizes adsorption and allows the surfactant to penetrate into the formation

2. Acid solubility experiments reveal that 38% of Utica shale is dissolved in 5% hydrochloric acid and higher strength acid does not improve solubility except at lower fluid to rock ratios.

3. Fractured core experiments show that gas frac conductivities are in the range of 200 md-ft at 500 psi closure pressure and nearly disappear at 2500 psi closure pressure, while treatment with 3% HCl doubles the conductivity at all tested closure pressures.

4. 1 lb/ft2 30/50 sand maintains the conductivity at 850 md-ft up to 5000 psi of closure pressure. The use of acid in the prepad or pad is useful in breaking down and opening the fractures to accept proppant.

5. The Utica Shale formation contains clays and fines that can be inhibited with use of KCl and polymeric clay stabilizers. Fines migration can cut the conductivity of the proppant pack in half if not stabilized.

Acknowledgments The authors wish to thank the management personnel at Universal Well Services and CESI Chemical for their support of this project. Further thanks are in order to other staff personnel for their time and efforts towards completing this project. We appreciate the help from Michael Forgione, Jeff Little and Sam Stoner who helped gathering samples, run tests, and collect data. The authors also wish to thank the personnel at CESI Chemical for their efforts in generating the core data and physical properties of the fluid systems. Finally,

we acknowledge the collaboration we received from many colleagues who provided technical advice. References:

1. Paktinat, J., Pinkhouse, J, Williams, C. and Penny, G.S., Lash, G. G.: “Optimizing Hydraulic Fracturing Performance in Northeastern United States Fractured Shale Formations,” paper SPE 104306 presented at the 2006 SPE Eastern Regional Meeting, Canton, Ohio Oct. 11-13.

2. Jenden, P.D., Drazan, D.J., and Kaplan, I.R., 1993, Mixing of thermogenic natural gases in Northern Appalachian Basin: American Association of Petroleum Geologists Bulletin, v. 77, p. 980-998.

3. White, J., and Read, Roger, 2007, The shale shaker: www.oilandgasinvestor, January 2007, p. 2-9.

4. Hill, D.G., Lombardi, T.E., and Martin, J.P., n.d., Fractured shale gas potential in New York: p.49

5. Agle, P., Jacobi, R., Mitchell, C., Nyahay, R., Slater, B., and Smith, L., 2006, Faulting and mineralization in the Cambro-Ordovician section of the Mohawk Valley: New York State Geological Association, 78th Annual Meeting, guidebook, p. 1-53.

6. Lehmann, D., Brett, C.E., Cole, R., and Baird, G., 1995, Distal sedimentation in a peripheral foreland basin: Ordovician black shales and associated flysch of the western Taconic foreland, New York State and Ontario: Geological Society of America Bulletin, v. 107, p. 708-724.

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