The Pennsylvania State University. The Graduate School. Department of Energy and Mineral Engineering

The Pennsylvania State University The Graduate School Department of Energy and Mineral Engineering FRACTURE HEIGHT CONTAINMENT IN THE STIMULATION OF ORISKANY FORMATION A Thesis in Energy and Mineral Engineering by Tushar Vatsa Submitted in Partial Fulfillment of the Requirements for the Degree of Master of Science May 2011

ii The thesis of Tushar Vatsa was reviewed and approved* by the following: John Yilin Wang Assistant Professor of Petroleum and Natural Gas Engineering Thesis Advisor Chair of Committee Derek Elsworth Professor of Energy and Geo -Environmental Engineering Terry Engelder Distinguished Professor of Geosciences R. Larry Grayson Professor of Energy and Mineral Engineering Graduate Program Officer for Energy and Mineral Engineering *Signatures are on file in the Graduate School

ABSTRACT The Oriskany formation has been a prolific producer of natural gas in the Appalachian basin since 1930s. Lot of production wells have been converted to gas storage wells for the ease of operation. Natural gas storage industry is a vital part of North American energy driven economy because of the fluctuation in seasonal demand and in maintaining the reliability of supply needed to meet the demands of the consumer. However, the storage wells suffer from an annual deliverability loss of 5% owing to the various damage mechanisms. A lot of work pertaining to the issue of identification of damage mechanisms, and subsequent development of stimulation technology in order to mitigate the damage and restore the wells deliverability has been done in a joint effort between The Gas Research Institute, Department of Energy, American Gas Association and the various other operator companies involved in the storage industry. Operators mostly rely on traditional methods such as blowing, washing, reperforating, acidizing, infill drilling to restore wells deliverability. These traditional methods do provide short term benefits but the longevity is not sustained and the overall situation remains same. Hydraulic fracturing is not preferred in terms of legitimate concerns over excessive vertical height growth, long fracture fluid clean up times, lack of expertise and cost. This research study was carried out to understand the various damage mechanisms affecting the Oriskany wells, with a focus on gas storage wells. I then developed a dataset of reservoir properties, rock properties and fracture treatment data for Oriskany based on a complete literature review and calculations from a sonic log. New stimulation methods were developed based on a systematic parametrical study on the type of fracture fluids, injection rate, types of proppant, treatment volume, reservoir pressure and treatment schedule. These new methods lead to increased well deliverability, fracture height containment and higher average fracture conductivity. iii

iv TABLE OF CONTENTS LIST OF FIGURES... vi LIST OF TABLES... ix Chapter 1 INTRODUCTION... 1 Chapter 2 LITERATURE REVIEW... 4 2.1. Oriskany Sandstone... 4 2.2. Gas Storage Wells... 6 2.2.1. Different Types of Gas Storage Fields... 7 2.2.2. Depleted Oil and Gas Wells... 9 2.2.3. Candidate Selection... 12 2.3. Damage Mechanisms... 14 2.3.1. Damage Mechanism in Gas Storage Wells... 14 2.3.1.1. Bacteria Fouling... 15 2.3.1.2. Relatively Permeability Effects / Water Blockage... 16 2.3.1.3. Inorganic Precipitates / Scaling... 17 2.3.1.4. Production Chemicals / Organic Residues... 18 2.3.1.5. Drilling / Injection... 18 2.3.1.6. Mechanical Obstruction & Unconsolidated Formation... 19 2.3.1.7. Wellbore Condition... 19 2.3.1.8. Stimulation Fluid... 20 2.3.2. Damage Mechanism in Producing Oriskany Wells... 21 2.3.2.1 Tubing Obstructions... 21 2.3.2.2 Hydrates... 22 2.3.2.3. Salt Blockages... 22 2.3.2.4. Liquid Loading... 23 2.3.2.5. Excessive Brine Production... 23 2.4. Stimulation Technologies... 24 2.4.1. Hydraulic Fracturing... 26 2.4.1.1. Tip Screen Out Fracturing... 27 2.4.1.2. Liquid CO 2 Fracturing with Proppant... 28 2.4.1.3. Extreme Overbalance Fracturing... 28 2.4.1.4. High Energy Gas Fracturing... 28 2.4.1.5. Gelled Liquefied Petroleum Gas Fracturing... 29 2.4.2. Acidizing... 30 2.4.2.1. Mineralogy... 30 2.4.2.2. Reservoir Characteristics... 31 2.5. Fracture Vertical Height Growth... 32 2.5.1. Factors Affecting Vertical Height Growth... 34 Chapter 3 PROBLEM STATEMENT... 37 Chapter 4 RESERVOIR, FLUID AND ROCK PROPERTIES... 39 4.1. Reservoir Rock Properties... 41

v 4.2. Reservoir Properties... 43 4.3. Fracture Treatment Data... 44 4.4. Model Description... 46 4.4.1. 3- D Tip Dominated... 48 Chapter 5 RESULTS AND DISCUSSION... 51 5.1. Effect of Fracture Fluid Type on Fracture Propagation... 52 5.2. Effect of Injection Rate on Hydraulic Fracture Propagation... 56 5.3. Effect of Proppant on Hydraulic Fracture Propagation... 59 5.4. Effect of Injection Volumes on Hydraulic Fracture Propagation... 69 5.5. Effect of Reservoir Pore Pressure on Hydraulic Fracture Propagation... 79 5.6. Effect of Treatment Schedule on Hydraulic Fracture Propagation... 83 5.6.1. Effect of Treatment Schedule on Binary Foam fluids... 84 5.6.2. Effect of Treatment Schedule on Linear Gel 40#... 87 5.6.3. Effect of Treatment Schedule on Crosslink 40# Gel... 90 Chapter 6 SUMMARY AND CONCLUSIONS... 93 6.1. Oriskany Producing Wells... 94 6.1.1. Hydraulic Fracture Propagation Using Crosslink Gel 40#... 94 6.1.2. Hydraulic Fracture Propagation Using Linear Gel 40#... 96 6.1.3. Hydraulic Fracture Propagation Using Binary Foam Fluid... 97 6.2. Oriskany Gas Storage Wells... 99 6.2.1. Hydraulic Fracture Propagation Using Crosslink Gel 40#... 99 6.2.2. Hydraulic Fracture Propagation Using Linear Gel 40#... 101 6.2.3. Hydraulic Fracture Propagation Using Binary Foam Fluids... 102 REFERENCES... 105 Appendix A Detail Treatment Schedule for Each Run... 109 Appendix B Summary of All Simulations and Results... 146

vi LIST OF FIGURES Figure 1. Different Fracturing Technologies (Reeves et al., 1999)... 25 Figure 2. Propagation of Hydraulic Fracture... 26 Figure 3. Tip Screenout Fracturing (Reeves et al., 1999)... 27 Figure 4. Different Orientations of Hydraulic Fractures (Wright et al., 1999)... 33 Figure 5. Log Section of Various Zones Under Consideration... 40 Figure 6. Average Fracture Conductivity of Different Fracture Fluids (Run 1to Run 9)... 53 Figure 7. Vertical Fracture Height for Different Fracture Fluids (Run 1 to Run 9)... 54 Figure 8. Fracture Length for Different Fracture Fluids (Run 1 to Run 9)... 55 Figure 9. Vertical Height Growth for Different Fracture Fluids at Constant Injection Rate of 10 BPM (Run 8, Run 4, Run 2)... 56 Figure 10. Average Fracture Conductivity for Different Fracture Fluids at Constant Injection Rate of 10 BPM (Run 8, Run 4, Run 2)... 57 Figure 11. Fracture Length for Different Fracture Fluids at Constant Injection Rate of 10 BPM (Run 8, Run 4, Run 2)... 58 Figure 12. Effect of Proppant Types on Fracture Conductivity for Binary Foam Fluid (Run 47, Run 56, Run 64, Run 67, Run 70, Run 75, Run76, Run2)... 60 Figure 13. Effect of Proppant Types on Fracture Length for Binary Foam Fluid (Run 47, Run 56, Run 64, Run 67, Run 70, Run 75, Run76, Run2)... 61 Figure 14. Effect of Proppant Types on Vertical Fracture Height for Binary Foam Fluid (Run 47, Run 56, Run 64, Run 67, Run 70, Run 75, Run76, Run2)... 62 Figure 15. Effect of Proppant Types on Fracture Conductivity of Linear Gel 40# (Run 51, Run 60, Run65, Run 68, Run 71, Run 74, Run 77, Run 4)... 63 Figure 16. Effect of Proppant Types on Fracture Length for Linear Gel 40# (Run 51, Run 60, Run65, Run 68, Run 71, Run 74, Run 77, Run 4)... 64 Figure 17. Effect of Proppant Types on Fracture Height for Linear Gel 40# (Run 51, Run 60, Run65, Run 68, Run 71, Run 74, Run 77, Run 4)... 65

vii Figure 18. Effect of Proppant Types on Fracture Conductivity for Crosslink Gel 40# (Run 53, Run 62, Run 66, Run 69, Run 72, Run 73, Run 78, Run 8)... 66 Figure 19. Effect of Proppant Types on Fracture Length for Crosslink Gel 40# (Run 53, Run 62, Run 66, Run 69, Run 72, Run 73, Run 78, Run 8)... 67 Figure 20. Effect of Proppant Types on Vertical Fracture Height for Crosslink Gel 40# (Run 53, Run 62, Run 66, Run 69, Run 72, Run 73, Run 78, Run 8)... 68 Figure 21. Effect of Different Design Fluid Volumes on Fracture Conductivity for Binary Foam Fluids (Run 79, Run 84, Run 85, Run 90, Run 92, Run2)... 70 Figure 22. Effect of Different Fluid Volumes on Vertical Fracture Growth for Binary Foam Fluid (Run 79, Run 84, Run 85, Run 90, Run 92, Run2)... 71 Figure 23. Effect of Different Fluid Volumes on Fracture Length for Binary Foam Fluid (Run 79, Run 84, Run 85, Run 90, Run 92, Run2)... 72 Figure 24. Effect of Different Design Fluid Volumes on Fracture Conductivity for Linear Gel 40# (Run 80, Run 82, Run 86, Run 89, Run 91, Run 4)... 73 Figure 25. Effect of Different Fluid Volumes on Vertical Fracture Growth for Linear Gel 40# (Run 80, Run 82, Run 86, Run 89, Run 91, Run 4)... 74 Figure 26. Effect of Different Fluid Volumes on Fracture Length for Linear Gel 40# (Run 80, Run 82, Run 86, Run 89, Run 91, Run 4)... 75 Figure 27. Effect of Different Fluid Volumes on Fracture Conductivity for Crosslink Gel 40# (Run 81, Run 83, Run 87, Run 88, Run 93, Run 8)... 76 Figure 28. Effect of Different Fluid Volumes on Vertical Fracture Growth for Crosslink Gel 40# (Run 81, Run 83, Run 87, Run 88, Run 93, Run 8)... 77 Figure 29. Effect of Different Fluid Volumes on Fracture Length for Cross link Gel 40# (Run 81, Run 83, Run 87, Run 88, Run 93, Run 8)... 78 Figure 30. Effect of Reservoir Pressure on Fracture Conductivity of Oriskany gas wells (Run 101, Run 100, Run 102, Run 98, Run 99, Run 97, Run 95, Run 94, Run 96)... 80 Figure 31. Effect of Reservoir Pressure on Vertical Height Growth of Created Fractures (Run 101, Run 100, Run 102, Run 98, Run 99, Run 97, Run 95, Run 94, Run 96)... 81 Figure 32. Effect of Reservoir Pressure on Fracture Length (Run 101, Run 100, Run 102, Run 98, Run 99, Run 97, Run 95, Run 94, Run 96)... 82 Figure 33. Effect of Treatment Schedule on Fracture Conductivity of Binary Foam Fluid ( Run 109, Run 108, Run 105)... 84 Figure 34. Effect of Treatment Schedule on Fracture Length for Binary Foam Fluid (Run 109, Run 108, Run 105)... 85

Figure 35. Effect of Treatment Schedule on Vertical Fracture Height for Binary Foam Fluid (Run 109, Run 108, Run 105)... 86 Figure 36. Effect of Treatment Schedule on Fracture Conductivity of Linear Gel 40# (Run 110, Run 107, Run 104)... 87 Figure 37. Effect of Treatment Schedule on Fracture Length for Linear Gel 40# (Run 110, Run 107, Run 104)... 88 Figure 38. Effect of Different Treatment Schedule on Vertical Fracture Height for Linear Gel 40# (Run 110, Run 107, Run 104)... 89 Figure 39. Effect of Treatment Schedule on Fracture Conductivity of Crosslink Gel (Run 111, Run 106, Run 103)... 90 Figure 40. Effect of Different Treatment Schedule on Fracture Length for Crosslink Gel 40# (Run 111, Run 106, Run 103)... 91 Figure 41. Effect of Different Treatment Schedule on Vertical Height Growth for Crosslink Gel 40# (Run 111, Run 106, Run 103)... 92 viii

ix LIST OF TABLES Table 1.Mineralogies of Typical Gas Storage Formations (Yeager et al., 1997)... 5 Table 2. Summary of Various Zones under Consideration... 39 Table 3. Average Rock Properties... 41 Table 4. Reservoir Properties... 43 Table 5. Sample Treatment Schedule Input File... 47 Table 6. Proppant Pack Conductivity for Different Proppants... 59 Table 7. Different Treatment Schedules Included in the Parametric Study... 83 Table 8. Final Treatment Schedule for Crosslink Gel 40#... 94 Table 9. Final Treatment Schedule for Linear Gel 40#... 96 Table 10. Final Treatment Schedule Binary Foam Fluid... 97 Table 11. Final Treatment Schedule Crosslink Gel 40#... 100 Table 12. Final Treatment Schedule Linear Gel 40#... 101 Table 13. Final Treatment Schedule Binary Foam Fluid... 102

x ACKNOWLEDGEMENTS First of all I would like to take this opportunity to thank the Department of Energy and Mineral Engineering for providing me with the opportunity to pursue my Master s Degree. Secondly Dr. John Y. Wang my thesis advisor for his patience, kindness, perseverance in helping me understand the nuances of Petroleum Engineering and motivating me from time to time complete my degree. It is because of his guidance, wisdom that I have been successfully able to complete my research and thesis. I would also like to thank Dr Derek Elsworth and Dr Terry Engelder for being a part of my committee and providing their valuable input and time. My journey at Penn State was made possible by both my parents who have supported me in all aspects of my life for which I shall remain forever indebted. My parents have been my pillar of strength and my role models for helping me pursue my dream. I have no words to say how much it means to me personally. Last but not the least I would like to thank all my 3S lab mates, Paul Dudenas and my friends especially Harisha Kinilakodi, Dennis Arun Alexis, Sachin Rana, Hemant Kumar and Tushar Swami for urging me to carry on irrespective of the outcome.

Chapter 1 INTRODUCTION Underground gas storage reservoirs are used worldwide to store produced natural gas during the periods of low demand and for use during the periods of high demand ( Bennion et al., 2000). Underground gas storage is an efficient way to balance the discrepancies between demand and supply. Effective use of underground gas storage requires delivery and permanent containment of a certain level of gas as base or cushion gas. The base gas maintains the pressure required for deliverability at the minimum acceptable flow rate (Survey of Underground Gas Storage Facilities in the United States and Canada, 2004). Gas deliverability from an underground gas storage facility requires the pre-injection of desired level of working gas. The rate at which an underground gas storage facility can accept gas on injection and deliver gas on withdrawal is normally dependent on the characteristics of both underground reservoir and surface facilities (Survey of Underground Gas Storage Facilities in the United States and Canada, 2004). These reservoirs are often depleted oil & gas reservoirs which have been converted to storage for the ease of operation and to better utilize the already existing facilities. As depleted reservoirs are formations that have already been tapped of their recoverable reserves, this leaves an underground formation geologically capable of holding natural gas. Also as the inventory in terms of production and surface equipment already exists costs are minimized when depleted reservoirs are converted to gas storage facility. Factors governing whether or not depleted reservoirs will be suitable for gas storage are both geographic and geologic. Geographically depleted reservoirs should be relatively close to the consuming regions, transportation facilities, and distribution network. Geologically depleted reservoirs should have

2 high permeability and porosity. The porosity determines the amount of gas that can be stored whereas the permeability determines the rate at which the gas flows in the formation which in turn determines the rate at which gas can be injected or withdrawn from the formation. Proper selection of gas storage reservoir is important to allow safe and economic operation of the project on a long time basis. Studies have shown that with time, the repeated high- pressure injection and withdrawal of gas progressively damages gas storage wells by filling the pore spaces with inorganic precipitates, hydrocarbons, organic residues, production chemicals, bacterial fouling, emulsions, water blockages and naturally occurring particulates (Barker et al., 2010). As a result of formation damage individual US gas wells are prone to deliverability losses at the rate of 5% annually (Reeves et al., 1999). Hence over a period of 10 years losses can amount to 50% which further increases the operating costs and serves as a huge loss considering today s energy prone economy. Most of the times the damage is in and around the wellbore hence we need short, wide high conductivity fractures rather than massive hydraulic fracturing. A significant amount of money is expended without a clear knowledge of the damage being addressed. Secondly even though storage operators may understand the different damage mechanisms they have no diagnostic approach to determine which mechanism is responsible for damage in a particular case (Frantz et al., 2002). Storage operating companies have tried and tested various techniques to maintain and enhance deliverability. Amongst the various stimulation technologies hydraulic fracturing remains one of the most cost- effective means of accomplishing deliverability enhancement although valid concerns such as fracture height growth outside the zone of interest, expected cost or lack of experience and long fracture fluid clean up times need to be addressed accordingly. Also hydraulic fracturing if and when executed can effectively stimulate the well and restore deliverability irrespective of any kind of damage the well might be suffering from. This in

3 turn with the longevity of the treatment makes it the best alternative to mitigate and surpass damage in gas storage wells. Lot of work on the testing and subsequent development of new and novel fracture stimulation technologies had been carried out as part of a joint effort between the U.S. Department of Energy and Gas Research Institute Research & Development program that began in 1994. The technologies included tip-screen out fracturing, hydraulic fracturing with liquid CO 2 and proppant, extreme overbalance fracturing, and high-energy gas fracturing. Based on the results derived from the project, conclusions were drawn concerning the applicability and utility of these technologies, storage well damage conditions, remediation candidate selection and future technology needs (Reeves et al., 1999). Also not to mention the fact that storage operators mostly rely on traditional methods for deliverability maintenance such as blowing the wells, surging, swabbing, coil tubing cleanouts, reperforating and acidizing accounting for 80% of all storage well remediation which in turn provides limited short term results but the overall scenario remains the same. Apart from the exception of acidizing none will improve the well to a stimulated condition for a sustained period of time (Reeves, 1998). In this research after identification of the various damage mechanisms, I will develop suitable fracturing technologies in order to mitigate and bypass the near wellbore damage and subsequently restore and increase the wells deliverability. Also through this research I will address the legitimate concerns of the storage operators in terms of fracture height growth out of the zone.

Chapter 2 LITERATURE REVIEW 2.1. Oriskany Sandstone The Oriskany has been a major source of natural gas production in the Appalachian Basin for more than sixty years. The overlaying Huntersville Chert is not always present with the Oriskany across the Appalachian Basin and in fact, there is a coincidence between no Oriskany production and overlaying Chert. It is postulated that the highly fractured Chert is a poor cap rock allowing the gas to escape ( Diecchio, 1982). As a result in some places, the Chert is supposed to be a better gas reservoir than the Oriskany. The lower Devonian Oriskany sandstone is an expansive sheet deposit in the Appalachian Basin extending from Newyork to Kentucky. The thickest section of the reservoir is 250 feet to 300 feet (Bruner, 1991). Oriskany is described as a hybrid sandstone with variable quantities of detrial quartz and sand sized carbonate detritus. The Oriskany in general is a fossiliferous quartz arenite cemented with carbonate and silica minerals. Within the Oriskany, four basic rock units can be characterized. (Gottschling, 2004). Facies one can be described as basically a limestone section interbedded with fine grain sandstone. The second facies is a medium grained clean sandstone with decreasing carbonate matrix. In facies three the rock is a mix of bioturbated calcareous sandstones and fossiliferous sandy limestones with argillaceous and organic laminae. Facies four is at the top of the Oriskany which is coarse grained to pebble sized quartz overlain by laminated fine-grain sandstones with grain size increasing vertically. Porosity or the lack of porosity is the result of the lithology and cementation combinations in the Oriskany.

Table 1.Mineralogies of Typical Gas Storage Formations (Yeager et al., 1997) 5

6 2.2. Gas Storage Wells Natural gas- a colorless, odorless, gaseous hydrocarbon- may be stored in a number of different ways. It is most commonly held in inventory underground under pressure in three types of facilities (www.eia.doe.gov). These are as follows Depleted oil / gas reservoirs Aquifers Salt cavern formations Each type has its own physical characteristics in terms of porosity, permeability, retention capability and economics which in turn govern their respective selection. Two of the most important characteristics of gas storage reservoirs are its capability to hold natural gas, and the rate at which the gas can be withdrawn- its deliverability rate. 84% of the gas storage reservoirs in the United States are in depleted oil & gas reservoirs (www.eia.doe.gov). Conversion of a field from production to storage takes advantage of existing wells, gathering systems, and pipeline connections (www.eia.doe.gov). Also depleted oil & gas reservoirs are the most commonly used underground storage sites because of their wide availability.

7 2.2.1. Different Types of Gas Storage Fields Base Load Storage Natural gas storage as we know is required for two reasons: meeting seasonal demand requirements, and as insurance against unforeseen supply disruptions (http://www.naturalgas.org/naturalgas/storage.asp). Base load storage capacity is used to meet seasonal demand fluctuations. These facilities are capable of holding enough natural gas to satisfy long term seasonal demand requirements. Typically the turnover rate for natural gas in these facilities is once a year. Natural gas is injected during the summer and withdrawn during the winter. When compared these types of reservoirs have lower deliverability rates but these facilities provide a prolonged, steady supply of natural gas (http://www.naturalgas.org/naturalgas/storage.asp). Peak Load Storage Designed to have high- deliverability for short periods of time, meaning natural gas can be withdrawn from storage quickly should the need arise. They are intended to meet sudden short term demand increases. These facilities cannot hold as much gas as base load facilities however they can deliver small amounts of gas more quickly should the need arise. Most of the salt caverns and mined caverns fall in this category. Storage Measures / Terminologies Total Gas Storage Capacity- is the maximum volume of gas that can be stored in an underground storage facility by design and is determined by the physical characteristics of the reservoir and installed equipment s respectively. Base Gas (cushion gas) - is the volume of gas intended as permanent inventory in a storage reservoir to maintain adequate pressure and deliverability rates throughout the withdrawal season.

8 Working Gas Capacity - is the volume of gas in the reservoir above the level of base gas. Working gas is available for withdrawal and subsequent use. Deliverability - is often defined as the amount of gas that can be delivered from a storage facility on a daily basis. Also referred to as the deliverability rate, it is usually expressed in millions of cubic feet per day (MMcf / day). The deliverability of a given storage facility is variable, and depends on various factors such as amount of gas in the reservoir at any particular time, the pressure within the reservoir, compression capability available to the reservoir, the configuration and capabilities of surface facilities associated with the reservoir. In short it is highest when the reservoir is full and declines as the working gas is withdrawn. Injection Capacity - is the opposite of deliverability. It is the amount of gas that can be injected into a storage facility on a daily basis. It has the same units as deliverability. It varies inversely with the amount of gas in storage that is it is at its lowest when the reservoir is full and increases as the working gas is withdrawn.

9 2.2.2. Depleted Oil and Gas Wells Gas storage reservoirs are used worldwide to store produced natural gas during the periods of low demand and for use during the periods of high demand ( Bennion et al., 2000). These reservoirs are often depleted oil & gas reservoirs which have been converted to storage for the ease of operation and to better utilize the already existing facilities. Proper selection of a gas storage reservoir is important to allow safe and economic operation of the project on a long time basis. For reservoirs to be candidates for gas storage the following criteria s must be satisfied ( Bennion et al., 2000). Sufficient reservoir volume in order to store the required amount of gas without uneconomic compression to high levels, without exceeding containment pressure constraints Containment of gas by the sealing capability of the upper and lower caprock Sufficient inherent permeability to allow injection, withdrawal at required deliverability rates As a result of formation damage individual US gas wells are prone to deliverability losses at the rate of 5% annually (Reeves et al., 1999). Most of the times the damage is in and around the wellbore hence we need short, wide high conductivity fractures rather than massive hydraulic fracturing (MHF). A significant amount of money is expended without a clear knowledge of the damage being addressed. Secondly even though storage operators may understand the different damage mechanisms they have no diagnostic approach to determine which mechanism is responsible for damage in a particular case (Frantz et al., 2002). To counteract the decline in deliverability as mentioned above the storage industry spends more than $100 million annually to drill new infill wells in order to supplement the

10 already existing ones (Reeves et al., 1999). New wells definitely increase deliverability but stimulation, restimulation is a much more efficient and cost effective approach. Also a key element in maximizing injection and withdrawal rates in gas storage fields is minimizing the damage. A highly efficient completion technique can reduce the number of storage wells required to produce and refill a storage zone. It also reduces the cost of installation and operation of compression equipments required to achieve commercial injection and withdrawal rates. Operators mostly rely on traditional practices such as blowing, surging, coil tubing clean outs which does provide short term benefits but the longevity is not sustained and hence the overall situation remains same. Many operators avoid the usage of fracturing over legitimate concerns of unwanted fracture height growth, long fracture fluid clean up times, cost, lack of experience etc. Hence it becomes imperative to develop technologies which can effectively stimulate these fields keeping in mind the various concerns mentioned. Also with typically tight well spacing in storage fields, there is not as big a need for long fracture lengths as in production operations (Reeves et al., 1999). Hence we should create an opportunity to take advantage of technologies which tend to create shorter fracture lengths. Permeability of gas storage reservoirs is generally high, also the process of cycling dry pipeline quality gas in and out of storage wells over many years reduces the near well area to very low residual water saturation. The re-introduction of aqueous fluids in itself can be damaging because a higher liquid saturation is established reducing the relative permeability to gas (Jiang et al., 2003). These issues have been described as being a result of water imbibition, capillary pressure, phase trapping, under pressurized reservoirs. Selection of appropriate fracture fluid goes a long way in deciding the effectiveness of treatment. Relevant fracturing fluid properties are: density, viscosity, surface tension, solubility which should be tailored to effectively stimulate the native hydrocarbon formation.

11 Frequently deliverability of gas storage reservoirs actually declines following a traditional hydraulic fracture treatment and may take a long time to clean up before we see any increase in deliverability. In many reservoirs this unrecovered fracturing fluid remains immobile within the formation creating an obstruction to flow. This significantly compromises the effective fracture length and results in decreased well productivity. From the above discussion it is evident that identification of damages / damage mechanism should be given foremost importance before planning any stimulation job. Identifying the source of the problem makes it much easier to determine the remedy rather than carrying a generalized treatment and hoping to get good returns. Historically when operators detected underperformance in one well other wells within the same reservoir were treated uniformly, under the assumption that the cause of underperformance was the same for all wells. As each treated well might not have the same problem, some treatments were unsuccessful. Also minimally damaged wells are treated same as severely damaged wells, falsely indicating mixed treatment results and when the results appeared inconsistent, operators assumed overall job failure and randomly selected another inappropriate treatment. (Blauch et al., 1998) Standard industry practices often fail to remove all formation damage or prevent it from occurring for a variety of reasons including improper identification, selection of inappropriate techniques and not to mention that improved deliverability rates are not easily maintained once they are created; therefore operators have to invest additional funds from time to time. (Blauch et al., 1998). Customized individual treatments focusing on specific wells, taking into consideration all the factors involved can provide better incremental improved deliverability resulting in lower long term maintenance costs.

12 2.2.3. Candidate Selection Candidate selection goes a long way in deciding whether the stimulation technique chosen would be effective or not. Emphasis should be given to identify and quantify the various damage mechanisms in order to effectively mitigate them. Various factors such as location of wells within a reservoir, age of the wells, deliverability of wells, evidence of damage observed during various well interventions should be considered. Identification of damage mechanism is one of the foremost prerequisites for designing individual treatments for different wells. Quantifying and analyzing the damage mechanism induced in gas storage wells can be broadly classified into the following: Using downhole video cameras to observe the wellbore and formation Physical sampling of liquids and solids present in the wellbore Well test analysis in order to quantify the damage Analysis of past stimulation treatment / well records to determine possible causes of damage Core analysis to determine the mineralogy and inherent properties of the formation Once done with candidate selection downhole diagnostics is carried out in order to determine the cause of wells decline in deliverability Downhole Video is used to image the wellbore in order to identify the physical damage as well as determine its severity. It basically acts as a visual tool and doesn t provide any information regarding the physical or chemical characteristics of the damages. To interpret results, the design team must compare the new DHV results to past video results (Blauch et al., 1998).

13 Well Test Analysis - Helps in quantification of degree of damage that is determining the skin factor and subsequent evaluation of reservoir properties Well Sample Analysis Bailer sampling is carried out to procure a physical sample of the wellbore. The extracted sample is analyzed in the laboratory in order to design the best treatment strategy and fluid formulations. Also most of the times the samples procured appeared to have the same physical characteristic that is in terms of colour they all appear to be black tarry masses which can be mistakenly assumed to be organic deposits. Hence exact composition should be determined in order to mitigate and surpass the damage

14 2.3. Damage Mechanisms 2.3.1. Damage Mechanism in Gas Storage Wells One of the foremost considerations before applying any type of deliverability enhancement technique is to identify the type of damage that has to be removed. A clear understanding of the damage mechanism is necessary in order to fully utilize the benefits of various stimulation technologies, without which ineffective / appropriate methods might be chosen, failure to which will lead to wastage of grants and overall job failure. According to all the literature related to gas storage wells damage is confined to near wellbore with the depth being a few inches hence surpassing the near wellbore damage would definitely lead to increase in deliverability of gas storage wells (Yeager et al., 1997). The prominent damage mechanisms occurring in gas storage wells are as follows Bacteria Fouling Inorganic Precipitates / Scaling Production Chemicals and Hydrocarbon Deposits Drilling / Injection Particulate Plugging Mechanical Obstruction Relative Permeability Effects / Water Blockage Excessive Sand Production / Unconsolidated Formation Wellbore Condition Stimulation Fluid Effects

15 2.3.1.1. Bacteria Fouling Stagnant water and low flow conditions as encountered in the bottom of the wellbore are ideal for bacterial growth. Also even small amounts of oil and grease provide nutrients for growth. The above mentioned problem is further strengthened by a case study conducted in an Oriskany storage field. The wells were watered with fresh water in order to wash away the plugging material. It was allowed to stand for 24 hours after which a bailer sample was procured and tested. Every sample contained general bacteria population especially sulfate reducing bacteria and almost all samples indicated iron oxide, iron sulfide or hydrogen sulfide of significant quantities, however byproducts of biological growth attributed greatly to the plugging incurred in well (Wright et al., 1967). The results of the treating program are as follows All samples contained general bacteria population. Water samples used to treat the wells also showed signs of microorganisms. Plugging can be greatly attributed to byproducts of biological growth such as bacteria slime, iron sulfide High Iron content supports the reaction with hydrogen sulfide to form iron sulfide which was further confirmed by sidewall cores. It showed definite plugging with iron sulfide. It is also indicative of the presence of sulfate reducing bacteria which reduces sulfates to sulfides Low ph indicated acidity in samples, corrosive atmosphere and also the surface tension of the water sample procured was extremely high which could definitely lead to the problem of water blockage As can be seen from above bacteria plugging and water blockage were identified as the major causes for the reduction in flow rate. The treatment program developed included a solution of alcohol, bactericide and fresh water. Water was used as a carrier fluid for the

16 alcohol and bacteria and also to penetrate deeper into the formation whereas alcohol and bactericide were added to reduce the surface tension and eliminate the growth of bacteria respectively. Results showed significant increase in accordance with the open flow potential of wells and hence increase in deliverability. 2.3.1.2. Relatively Permeability Effects / Water Blockage Water blocking is caused by the capillary forces present in porous rock and the high mobility ratio of gas and water (McLeod et al., 1966). Gas rapidly breaks through the water remaining around the wellbore when the well is put back on production following a stimulation treatment. The low viscosity gas forces some of the water out but after the gas breaks through, a higher water saturation is left around the wellbore. This higher water saturation reduces the effective permeability to gas. Severity of water blocking increases in low permeability formations where capillary pressures are high. In gas storage wells, dry cycling of natural gas in and out of the wellbore upteem number of times reduces the near wellbore to very low residual water saturation, hence any aqueous fluid introduced will definitely increase the residual saturation. This would decrease the relative permeability to gas and in turn reduce deliverability. Water blocking is also severe when combined with other forms of damage, either mechanical plugging such as mud filtrate invasion, cement filtrate invasion, scaling and organic precipitation. Use of alcohol in stimulation treatments aids in removal of water blockages. The advantages associated are as follows:- Better and rapid clean up due to volatile nature of alcohol Reduces the surface tension which further reduces the capillary pressure and aids in better and rapid clean up

17 Ease of availability and low in cost as compared to surfactants, also can penetrate deeper into the formation as compared to surfactants which have a tendency to get adsorbed on the clay surface 2.3.1.3. Inorganic Precipitates / Scaling Precipitated compounds include compounds such as iron oxide, iron carbonate, iron sulfides, salts such as sodium chloride, calcium chloride and barium sulfates to name a few. The presence of inorganic precipitates is undoubtedly influenced by the following Type and quantity of fluids injected and withdrawn from the formation Operating procedures Presence of bacteria Reservoir characteristics such as temperature and pressure Examining the source of damage can provide a keen insight into the amount of scales that can exist downhole. Downhole samples or sidewall core samples should be obtained to quantify the amount and type of scale. Scales basically refer to the precipitation of compounds such as calcium carbonate, iron carbonate, iron oxides and iron sulfides to name a few. Carbonate Scales Occurs as the ph increases in the presence of carbonate or bicarbonate ions and metal ions such as Calcium, Magnesium and Iron. The origin of calcium, magnesium can be the formation brines whereas origin of iron can be traced back to either formation brine, but a more likely source is the casing or tubing. Many waters naturally contain carbonates or bicarbonates, but in gas storage wells, the source of carbonate is probably the CO 2 in the injected gas (Yeager et al., 1997). Guidelines

governing the CO 2 content of injected gas might vary, but it does not take much CO 2 in the gas to produce huge amounts of carbonate scales over the years. 18 Sulfide scales- Source is probably the formation. H 2 S (hydrogen sulfide) can react with iron to precipitate iron sulfide. Also if H 2 S reacts with oxygen, elemental sulfur could also precipitate out. 2.3.1.4. Production Chemicals / Organic Residues Hydrocarbon oils, ester compounds, compressor oils, bactericides, corrosion inhibitors are all part of the production chemicals/organic residues found in the samples collected and are generally identified as a dark layer along the wellbore face or as substances lining /plugging the pore throats. Also the production chemicals are filtered out near the wellbore plugging the pore throats which further reduces the permeability. Seepage of compressor oil, lube oil and grease has been identified as a universal problem which not only reduces permeability but also serves as nutrients for bacteria growth. 2.3.1.5. Drilling / Injection Drilling leads to deposition of mud cake and filtration of drilling fluids into the formation which can impair permeability by plugging the pore throats and by reducing the effective permeability to gas.

19 2.3.1.6. Mechanical Obstruction & Unconsolidated Formation Mechanical obstructions include inefficient connectivity between wellbore and formation and any tools lost downhole and not recovered during fishing operations. Proper cement job should be carried out in order to prevent the well from sloughing. Oriskany is believed to be a well sorted sandstone without much unconsolidation. 2.3.1.7. Wellbore Condition According to the American gas association database 70% of the active gas storage reservoirs are 25 to 100 years old. This means that they may contain wellbores of similar ages and hence ample opportunities for corrosion products, geochemical precipitates, microbial byproducts, fluid etc to accumulate in these wellbores. No stimulation technique will be effective if it never reaches the formation, spends or reacts with wellbore fill, precipitates (Yeager et al., 1997). Pickling (removal of iron scales from tubing / casing) is also considered a good practice for wells that haven t been treated in many years; circulation of fluids removes some soluble salt minerals and other debris. It also helps in elimination of large source of iron which prevents formation of iron related precipitates later on if and when the well is subjected to treatment.

20 2.3.1.8. Stimulation Fluid Fluids introduced from workover and stimulation / remediation may also be a source of fluid which may be retained by the formation. This can occur when the portion of the formation that accepts the injected gas is undersaturated with water. This undersaturation leads to the inability of aqueous stimulation fluids, including spent acids, to be recovered (Yeager et al., 1997). Moreover, the most likely reason for fluid being retained in the formation is lack of reservoir pressure. Most of the stimulation / remedial treatments are carried out after the withdrawal season. The reservoir pressure is lowest during this period of time and hence effective fluid cleanup is not possible.

21 2.3.2. Damage Mechanism in Producing Oriskany Wells The Oriskany formation has been a prolific producer of natural gas in the Appalachian basin since the early 1930 s (Henderson, 1991). Identification, detection and quick resolution of both downhole and surface production problems are necessary for maintaining efficient field operations (Henderson, 1991). Downhole production problems occurring on Oriskany wells include tubular hydrates, saltblocks, water loading and excessive brine production. Remediation technologies are available for blockings, liquid loading but excessive water production is a function of reservoir and also depends on how fluids can be disposed at low costs. 2.3.2.1 Tubing Obstructions Tubing obstruction occur either in the form of hydrates or salt blockages. A substantial decrease in gas flow rate and tubing pressure is indicative of blockage existence which if left unattended can lead to complete blockage (Henderson, 1991). It has been found that general correlation exists between the depth and type of obstruction. Field experience has shown that most obstructions between surface and 2000 feet are hydrates and from 2000 feet to 5000 feet are salt blocks. Consequently, the first step in resolving the obstruction problem is to determine its depth. This is accomplished by either using a wireline or acoustical recorder. The latter is preferred due to its portability (Henderson, 1991).

22 2.3.2.2 Hydrates Hydrate formation in the tubing is a common problem during initial production at higher pressures. Hydrates roughly consist of 10% hydrocarbon and 90% water (Henderson, 1991). Hydrates are solid compounds which form as the gas stream cools in its ascent from the reservoir to surface (Henderson, 1991). Methanol injection is the preferred method to deal with hydrate problems. Also lot of times prior to start of production methanol is injected downhole to wet the tubing string annulus. Upon commencement of production methanol is swept into the gas stream. This method has largely prevented the formation of hydrates and also helps in saving time and money required for workover operations. The concept of installation of downhole chokes has proven to be effective in hydrate formation control. 2.3.2.3. Salt Blockages Salt blockages also occur as a result of a gas cooling process when rising formation brine liquids precipitate salt crystals in the production string (Henderson, 1991). Salt blockages are more prevalent in depleted wells which produce large volumes of highly saturated brine. Fresh water injection is one of the most common methods used to dissolve salt blockages. High pressure water is pumped into the tubing string and pressured up against the salt blockage. This is followed by blowing the well to atmosphere, which is repeated several times until movement is initiated and the obstruction is removed (Henderson, 1991). A better preventive method involves continuous injection of fresh water production soap mixture down the production string annulus, which during the winter months should be heated to prevent freezing.

23 2.3.2.4. Liquid Loading Liquid loading generally occurs later in the life of the wells primarily because of decrease in reservoir pressure to an extent that it can no longer lift the fluids to the surface. Water buildup in the wellbore creates a hydrostatic head which reduces gas flow (Henderson, 1991). One of the cheapest and least expensive methods is to inject foams, surfactants and chemicals through the tubing or down the annulus. Also other methods include swabbing, coiled tubing, plunger lift, beam pump, gas lift and other artificial lift systems. 2.3.2.5. Excessive Brine Production Although several wells have significant gas production potential, they also produce excessive quantities of brine water (Henderson, 1991). Reduction in gas flow rate to minimize the water production can be rendered ineffective if the production reaches a bare minimum. Also excessive production of water is a characteristic of the reservoir hence good simulation studies should be carried out in advance to attain substantial information about the formation.

24 2.4. Stimulation Technologies To bypass the near wellbore damage, several new and novel fracturing technologies have been proposed and tested at different test sites in USA by a joint effort between DOE and GRI in the year 1998. These new technologies include- Reperforation Acidizing Hydraulic Fracturing Water Crosslink Gels Energized Fluids (Foamed Acid Treatments) Liquid CO 2 Fracturing with Proppant Extreme Overbalance Technique Tip Screen Out Fracturing High Energy Gas Fracturing Propellant Fracturing Gelled Liquefied LPG Fracturing All the above mentioned methods have their own advantages and disadvantages hence comparisons as such cannot be made and also we may have to use them in tandem in order to reap maximum benefits. Lot of these methods are new to the industry hence it is imperative to investigate each method in detail, and evaluate the applicability of each in the Oriskany formation by analyzing past treatments, production data, pressure transient analysis and well logging.

Figure 1. Different Fracturing Technologies (Reeves et al., 1999) 25

26 2.4.1. Hydraulic Fracturing Hydraulic fracturing is an effective technique for stimulating wells in low and high permeability reservoirs. The process involves the pressurization of an isolated perforated section of the wellbore with a viscous fluid until the induced stresses exceed the formation strength, which causes a failure and thus creates the fracture. Proppants are then pumped into the newly created fracture which following the release of fracturing pressure holds the fracture open and provides a conductive channel through which reservoir fluids flow to the wellbore (Acharya, 1988). Hydraulic fractures propagate perpendicular to the minimum, compressive, principal insitu stress. The fracture prefers to take the path of least resistance and therefore opens up against the smallest stress as shown in figure 2 below. Figure 2. Propagation of Hydraulic Fracture

27 2.4.1.1. Tip Screen Out Fracturing Tip screen out fracturing is ideally suited to stimulation of higher permeability formations where the main aim is to bypass near wellbore damage. High fracture conductivities are achieved with a screen out at the fracture tip to arrest further lateral growth, widening the fracture with continued pumping, and finally packing it with proppant in a high density slurry (Reeves et al., 1999). Also another added advantage is that it minimizes the risk of unacceptable fracture height growth which is a legitimate concern amongst various gas storage operators. Figure 3. Tip Screenout Fracturing (Reeves et al., 1999)

28 2.4.1.2. Liquid CO 2 Fracturing with Proppant As a result of low residual water saturation near the wellbore fracturing with aqueous based fluids can have long term cleanup effects on gas storage wells, which might offset the stimulation induced by the created fractures. Hence fracturing with liquid CO 2 and proppant is a good option because of low fluid cleanup times and immediate increase in deliverability. Higher costs as compared with other conventional treatments can be offset by the positive aspects of nonaqueous fracturing fluids (Reeves et al., 1999). 2.4.1.3. Extreme Overbalance Fracturing This technique was originally intended to be used in conjunction with perforating operations (Reeves et al., 1999). It basically involves using a liquid cushion at the bottom of the well and over pressuring the wellbore with a gas. The formation is quickly exposed to the pressure as the perforator is fired. If the pressure level and the injection rates are sufficient, then multiple fracture s extending radially outward are created and is useful when trying to stimulate wells were fractures tend to grow horizontally (Reeves et al., 1999). 2.4.1.4. High Energy Gas Fracturing The technique involves the use of electric line tools to ignite a propellant charge which is positioned across the formation (Reeves et al., 1999). The propellant burns within a few milliseconds and creates a high- pressure gas pulse. Propellant fracturing is designed to increase the pressure in the wellbore above the insitu stresses to create short multiple fractures but still remain below the yield stress of rock, thus avoiding the damage related with explosive fracturing.

Although the fracture height is limited the fractures are left unpropped and hence are susceptible to closure. 29 2.4.1.5. Gelled Liquefied Petroleum Gas Fracturing A novel hydraulic fracturing process using 100% liquefied petroleum gas has demonstrated quick and complete fracture fluid recovery, significant production improvements and longer effective fracture lengths. The process gels the liquefied petroleum gas for efficient fracture creation and proppant transport. Also once the fracture treatment is complete and the viscosity of the gelled liquefied petroleum gas is broken, the properties of liquefied petroleum gas make it an ideal fluid for cleanup. Removal of this fluid is easily achieved; relative permeability effects, irreducible saturation behavior and capillary pressure demands are eliminated (Tudor, 2009).

30 2.4.2. Acidizing Acidizing has typically been one of the most popular techniques for removal of damage in gas storage wells (Yeager et al., 1997). Various conditions such as mineralogy, completion type, well s capacity to return fluids to the surface, types of acids and their associated chemistry, reservoir characteristics should be taken into account beforehand before going forward with an acidizing treatment. No stimulation technique will be effective if it never reaches the formation or spends or reacts adversely with the wellbore fill, precipitates (Survey of Underground Gas Storage Facilities in the United States and Canada, 2004). Therefore pretreatment of a wellbore is a must before going ahead with the stimulation technique. 2.4.2.1. Mineralogy Acidizing gas storage wells in sandstone formation is not as universally successful as acidizing wells in carbonate reservoirs (Yeager et al., 1997). HCl alone will dissolve the carbonates, iron, sulfide scales but will not dissolve the sandstone formation. A mixture of mud acid (HCl+ HF) is used to treat sandstone formation. Also concerns about the chemistry of HF reacting with sandstone and the low dissolving power of HF further complicate the process. It is believed that HF acidizing treatments can cause more damage by precipitation of reaction products, unconsolidating the formation, swelling of clays etc. General trend has been to lower the concentration of HF fluids in order to avoid secondary precipitation reactions (Yeager et al., 1997). Temperature of the formation also plays a key role in determining whether precipitation would occur or not.

31 2.4.2.2. Reservoir Characteristics As the near wellbore region of gas storage wells is under saturated with water, fluid s introduced for work over / stimulation may act as a source which may be retained by the formation and would lead to inefficient recovery during flowback. The unrecovered fluid may continue to react with in the formation and will eventually lead to precipitation of reaction products. Non acid aqueous preflush should be used to prevent retention of acid based fluids. Also foam acid treatments can be carried out which aid in better recovery of the stimulation fluid.

32 2.5. Fracture Vertical Height Growth Fracture height growth has been recognized as one of the critical factors that can determine the success or failure of a hydraulic fracturing treatment. Unwanted fracture height growth into the upper and lower barriers can have detrimental effects in terms of unwanted gas / water production. It also reduces the overall effectiveness of the stimulation treatment in terms of the designed fracture conductivity and subsequently the overall gain in deliverability. In context to the above statement containment of hydraulic fractures in gas storage wells is of prime importance as unwanted fracture height growth can lead to loss of gas and subsequently loss in deliverability. Different orientations of hydraulic fracture can be seen in figure 4.

Figure 4. Different Orientations of Hydraulic Fractures (Wright et al., 1999) 33

34 2.5.1. Factors Affecting Vertical Height Growth Insitu Stress- Insitu stress difference between the pay zone and the bounding layers is the most important factor controlling vertical height growth. The above statement has been verified by various theoretical, laboratory and field data. Layers of greater insitu stress act as a barrier because of the increase in fracturing pressure required to continue fracture propagation in that particular layer. Effectiveness of the barrier would depend on the difference in the stress contrast that is greater the stress contrast more efficient would be the fracture containment and vice-versa. Variations in insitu stress is dependent on a number factors including the elastic properties of the layers, pore fluid pressures, tectonic boundary stresses, thermal stresses. The relative difference in the magnitude of horizontal stresses in different layers is a function of different elastic properties. Young s Modulus- Although the variation in insitu stress is the dominant fracture controlling fracture height growth the effect of Young s modulus cannot be negated. Young s modulus becomes the dominant factor when the net treating pressure is comparable to the insitu stress contrast. Both types of modulus contrast that is lower modulus outer layers and higher modulus outer layers and can hinder fracture growth. A higher modulus outer layer hinders fracture growth when a fracture is approaching the interface whereas lower modulus outer layer hinders fracture growth when the fracture is inside the layer. Also although neither situation can stop fracture growth completely, the hindering process of both can contribute to fracture height containment (Gu et al., 2006). That is when a fracture approaches a high modulus layer from a lower modulus layer the stress intensity fracture decreases, it approaches zero as the tip of fracture gets closer to the interface, making it harder for the fracture to propagate (Simonson et al., 1978). On the other hand when a fracture approaches a lower modulus layer from a high modulus layer, the stress intensity factor increases drastically. Hence lower modulus outer layer promotes fracture growth towards it. However once inside the fracture the stress intensity factor

35 decreases and further growth is arrested (Gu et al., 2006). Another reason can be that in layered formations fracture width depends not only modulus of the pay zone, but is also influenced by modulus in the outer layers. Fracture width is larger for the above mentioned case which means that there is less resistance to fluid flow, fluid pressure is lower hence the fracture is more contained under the same stress contrast. Similar reason can be formulated for the opposite case in which lower modulus middle layer is surmounted by higher modulus layers. (Gu et al., 2006). Stress Intensity Factor- Stresses around the tip of a crack are singular with r^ (-1/2), where r is the distance from the wellbore to the crack tip (Eekelen et al., 1982). The strength of the singularity is measured by the means of the stress intensity factor. The value of the stress intensity factor depends on the fracture geometry and on the load applied. Fracture propagates if the stress intensity factor reaches a critical value K c, which is assumed to be a material property called as either the stress intensity factor or fracture toughness. In the absence of Young s Modulus and insitu stress contrast fracture toughness can affect height growth (Gu et al., 2006). That is higher fracture toughness in the outer layer can restrict height growth and vice-versa. Also since the variation in toughness values of sedimentary rocks measured in laboratory is small the effect of fracture toughness is negligible except for cases where stress contrast is minimal. Fracture Slippage- Fracture sliding at the interface due to low shear strength can definitely lead to height containment. Although these cases are likely to occur at shallow depths due to less overburden stress and smaller frictional forces at the interface (Daneshy, 2009). In the above mentioned case the fracture will completely stop at the boundary. Sliding occurs wherever fracture encounters a weak interface, such as a weak natural fracture within the same formation. Basically the shear strength of the interface is sufficiently weak relative to the tensile strength and the minimum compressive stress of the bounding layers (Teufel et al., 1984). This type of fracture containment is usually very local and bounded by the size of the plane of weakness. At greater depth however high frictional resistance caused by the overburden load will prevent interface

36 slippage, so this crack arrest mechanism will not be operative (Eekelen et al., 1982). The depth to which interface slippage occurs depends both upon the frictional pressure and to some extent on the rock properties. Permeability- Fracture growth can be restricted if the upper and lower barriers have higher permeability in comparison to the pay zone. Higher permeability in the upper and lower cap rocks would lead to an increase in fluid leakoff. The increase in fluid leakoff allows the proppant slurry to bridge at the top and bottom of the fracture inhibiting further fracture growth along these tips. The objective is to arrest the growth of either the upper or lower tip or both the tips of fracture by the bridging action of proppant laden slurry.

37 Chapter 3 PROBLEM STATEMENT Gas storage is an integral, vital part of the natural gas industry. It forms a vital link between demand and supply of natural gas. Depleted oil and gas reservoirs are the preferred choice of the storage industry due to already available inventory and presence of a formation geologically capable of holding natural gas. Gas storage wells are prone to deliverability losses at an average rate of 5% per annum in the U.S.A as a result of formation damage. Formation damage can be attributed to various factors such as inorganic scaling, bacterial growth, water blockage, relative permeability effects, hydrocarbon organic residue and production chemicals, unconsolidation, injection particulate. Lot of times the damage is in and around the wellbore, hence what we need is a short, wide high conductivity fracture. Hydraulic fracturing is feared by some operators over legitimate concerns of height growth. So it is critical to understand the factors affecting vertical height to effectively stimulate gas storage wells. Also it serves to sustain the longevity of the treatment, hence remedial dollars can be saved. The objective of this research is to develop suitable hydraulic fracturing technologies in order to effectively stimulate gas wells in the Oriskany. The procedures to be followed are as follows:- 1. Carrying out a detailed literature review of all the engineering and geological data related to Oriskany gas storage wells 2. Gathering all geological data, rock properties, fluid data and reservoir properties of Oriskany formation 3. Building up of models to incorporate all the data acquired in step 2

38 4. Conducting parametric studies to quantify the effect of different factors affecting fracture height growth 5. Documenting the new findings in my Master s thesis

Chapter 4 RESERVOIR, FLUID AND ROCK PROPERTIES In this section, we will describe the reservoir properties, associated fluid properties and subsequently the calculations of the average rock properties of various zones under consideration in Table 2.The rock properties have been calculated from a sonic log given to us by East Resources. Due to lack of available data regarding Helderberg limestone which is below the Oriskany, we have made reasonable estimations as shown in Table 3. The various zones considered in the development of our model are as follows: Table 2. Summary of Various Zones under Consideration Marker A & Stafford Upper Marcellus Lower Marcellus Basal Onondaga Limestone Oriskany Sandstone Helderberg Limestone

Figure 5. Log Section of Various Zones Under Consideration 40