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Streamlined Completions Process: An Eagle Ford Shale Case HistoryAndrew L. Arguijo, SPE, and Lee Morford, SPE, Cabot Oil & Gas; Jason Baihly, SPE, and Isaac Aviles, SPE,Schlumberger

Copyright 2012, Society of Petroleum Engineers

This paper was prepared for presentation at the 2012 SPE Canadian Unconventional Resources Conference being held 30 October-1 November in Calgary, Alberta, Canada.

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 have not beenreviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, itsofficers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission toreproduce 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 SPE copyright.

AbstractThe Eagle Ford shale is a hydrocarbon-producing formation of significant importance due to its capability for producing at

high-liquid/gas ratios, more so than other traditional shale plays. Situated in south Texas, the total Eagle Ford liquidsproduction in 2007 was less than 21,000 bbl total. In 2011, production averaged 65,500 BOPD in the play (EIA, 2011).Activity in the Eagle Ford continues to increase because the benefits from producing high liquid yields across much of the

play, along with attractive commodity prices, have made the Eagle Ford a more attractive development over many other shalereservoirs.

The rapid development of the Eagle Ford shale was enabled by horizontal drilling. In 2007 none of the reported productionwas from horizontal wells. In 2011 alone over 2,800 drilling permits were issued, virtually all of them for horizontal wells

(RigData, 2012). The Eagle Ford shale has low-clay content, high-carbonate content, and is in an extensional basin, making itconducive to somewhat complex hydraulic fracturing (Martin et al, 2011). The plug and perforating technique has become the

preferred completion method in the play due to multiple entry points creating complex fractures at a minimal cost. Thiscompletion technique requires a mechanical means for conveying perforating guns, such as coiled tubing (CT), wireline tractoror stick pipe, for the first fracturing stage at the toe of the well.

To streamline their completion process, an Eagle Ford operator chose to use an initiator valve that is run at the toe of thewell as part of the final completion design. This pressure activated valve is capable of initiating operations on the firstfracturing stage without the need for CT or other mechanical means of conveyance of perforating guns. Simple and robust, the

valve is activated by a pressure increase from the surface. The valve uses a rupture disc for precise activation and a helical portdesign that allows for hydraulic fracturing to be performed through the valve into the cement and the formation. With over adozen wells completed in the Eagle Ford formation by the operator, the valve has provided logistical and economic benefits to

the streamlined completion process.This paper describes the initiator valve completion tool and its application in the Eagle Ford shale. A case history is

presented to show the specific design and operation of the initiator valve, as well as its benefits over other completion practicesthat target the first stage in a closed lateral system. Detailed activation of the valve and fracturing data through the valve arealso presented.

Introduction

Tight economics in many onshore North American unconventional oil and gas plays has made it important for operators insuch reservoirs to maximize economics as much as possible. One way to aid in maximizing the economics is through the use

of improved drilling and completion techniques and cost control; one such method is to eliminate interventions during the wellcompletion process. Every time a tool is run in the hole, the total cost of the well increases. One costly intervention that can beeliminated is the initial perforating run on the first stage of a cemented lateral well. During this operation, the well is a closed

system which prevents the plug and gun assembly from being pumped to the toe of the lateral. To address this inefficiency acostly, timely, and in some cases risky CT, stick pipe, or wireline tractor run must be used to convey the guns into the lateralwhich is a closed system. A novel valve was developed to initiate the fracturing process in horizontal cemented wells. The

process eliminates the intervention historically used to perforate the first stage. The initiator valve is a pressure-activated valveinstalled as part of the casing string placed at the toe stage of the well. The valve, cemented in place and requiring no changesto the cement operation or chemistry, is pressure activated and once the sliding sleeve in the valve is opened, the wellbore fluid

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is exposed to the cement sheath in the annular space. At this point the fracturing operation can begin. Once the first stage iscomplete, lower cost pump down plug and perf operations can begin.

There have been concerns expressed by many in the industry in the past about fracturing through cement without thebenefits of perforation tunnels. This paper shows how a novel helical port pattern reduces the near-wellbore fracture-initiationpressure in a cemented sliding sleeve and allows for an entire fracture stage to be pumped through the valve. The research and

engineering that went into developing the cemented initiator valve is presented in addition to a multi-well field case in theEagle Ford shale.

Eagle Ford Overview

The Eagle Ford shale play extends from Mexico, through Texas and into Louisiana, covering roughly 11,000,000 acres inTexas alone (Fig. 1) (Sanchez Energy, 2012; UPI, 2009). The portion of the play being commercially targeted today is fromthe US-Mexico border in Webb County, Texas, northeast to Brazos County, Texas (Fig. 2) (IHS, 2012). This area covers over6,000,000 acres (Ivey, 2011). The Eagle Ford shale is somewhat unique in that it contains distinct volatile oil, gas condensateand dry gas windows (Fig. 3) (Martin et al, 2011). Similar to nearly all unconventional plays, wells are drilled horizontally and

completed with multistage fracturing, incorporating mechanical isolation.The Eagle Ford has experienced little or no slowdown in activity due to its vast area of high-liquid cut wells. The rig count

in the basin has remained steady between 265 and 285 for the last six months (Fig. 4). Obviously, the price of oil has helped to

sustain the activity in all of the liquid-rich basins throughout North America. Currently, West Texas Intermediate (WTI) crudeoil is priced at approximately $90/bbl and Eagle Ford liquids, which are on the lighter side, average a pricing premium of $6 to8/bbl above that (UPRR, 2012). Conversely, gas is priced at $3/Mscf across North America (EIA, 2012). Most Eagle Ford

shale wells produce both types of hydrocarbon at various ratios. With the increased costs due to servicing capacity issues,advantageous price of liquid hydrocarbon and challenging gas price, it is important for operators in the basin to maximize theirasset performance by optimizing lateral spacing, stage count, drilling and completion cost control, and enhanced drilling andcompletion techniques, tools, and processes.

Eagle Ford Shale Geology

The Eagle Ford shale is a late Cretaceous-aged carbonate-rich shale located between two other carbonate formations. TheAustin Chalk is located above and the Buda Limestone below the Eagle Ford shale (Fig. 5). The Eagle Ford, which runs asdeep as 14,000 ft and as shallow as 1,500 ft has some rather dramatic stratigraphic changes across the south Texas area

including the Maverick Basin, San Marcos Arch, restricted basin in the south, and the Karnes Trough (Fig. 6). Due to thesevariations, the play runs from 50 to 350 ft in thickness and varies so much in depth. The most commercially targeted areashave a pay thickness of at least 125 ft. The majority of the Eagle Ford shale in south Texas contains two members, an upper

and a lower section which are easily identifiable on a log (Fig. 7). The lower Eagle Ford was deposited in a transgressive

shallow-marine environment and contains organic-rich shale. The upper Eagle Ford was deposited in a regressive environmentand contains calcareous shale, bentonites, limestones, and quartzose siltstones. The Eagle Ford shale contains 20% quartz,

50% calcite, 20% clay, and 10% kerogen, making it one of the lowest clay, highest kerogen shale plays in North America(Martin et al, 2011). Permeability can be quite high as well with a maximum of 405 nd and an average of 180 nd. Porosity istypically 3% to 10% with an average of 6% (Liro et al., 1994; Dawson, 2000; Lock & Peschier, 2006; Martin et al, 2011).

Eagle Ford Shale Completion Practices

Nearly every well drilled in the Eagle Ford shale today is a horizontal well with an average lateral length of 5,387 ft. The

average lateral length has increased by nearly 1,500 ft over the last 3 years (Fig. 8) (IHS, 2012). All Eagle Ford wells arefracture stimulated with proppant-laden fluid and incorporate isolation between multiple treatment stages. Of the more than4,000 wells drilled in the Eagle Ford shale, more than 75% are traditional cemented and cased lateral wells that use the plug-

and-perf method as the preferred method for fracture stage isolation (IHS, 2012). In each stage, a selected number ofpotentially productive intervals or clusters are perforated and the stimulation treatment is then pumped. The number ofperforation clusters ranges from 3 to 12 per stage in the Eagle Ford. After completing the stimulation, a wireline gun string

with a plug-setting tool, an adaptor kit and a frac plug are run down the vertical section of the well with gravity and pumpedalong the lateral with the aid of slickwater or low viscosity fluid. Once across the target depth the plug is set and released.Then the guns are pulled up hole and the intended perforated intervals are shot and the gun string is pulled out of the hole. The

fracturing treatment operation for that stage can then be started. This process is repeated until all stages are fractured. Theaverage stage count in the Eagle Ford shale today is 16. The stage count was much smaller in the play 4 years ago, but hasincreased steadily over time (Fig. 9).

With the experience gained over the years, the plug-and-perf method for treating multiple production intervals sequentiallyhas proven to be a cost-effective and efficient method to treat every stage with the exception of the first stage, which is muchmore difficult because once the casing is cemented, the system is closed. A closed system does not allow for an economic or

efficient pump-down plug-and-perf run. Instead, a mechanical method for conveying the perforating guns to the initial toestage is required before initiating the plug-and-perf operation. To meet this requirement, CT, stick pipe, or tractor-conveyed

perforating is required because pumping is not possible. Coordinating a CT unit, mobilizing a workover rig, or running in with

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a tractor on wireline to perform this operation is not only an added expense for the first stage only, but the logistics of thecompletion operations are further complicated and are highly inefficient.

To circumvent these challenges, the industry has been experimenting with a variety of methods to stimulate the toe stage ina way that optimizes operational speed and economics while maintaining the functionality to be able to fracture stimulate thisfirst interval. Historically, the difficulty has centered on finding a method that is efficient, effective, reliable, and cost

competitive. An initial approach to solve this situation has been the use of a wet-shoe (Stegent & Howell, 2012). With thistype of completion, the cement is over displaced so that a flow path at the bottom of the completion (wet shoe) is present,

enabling the lower cost pump-down plug-and-perf process to be performed on the first stage. For operators, this procedure isusually an unacceptable solution because of the risks that include leak paths, lack of isolation, and no pressure integrityverification of the casing.

A new method for initiating cased and cemented completions has been engineered. The method involves placing adownhole valve as part of the casing string, eliminating the first stage perforation gun intervention while providing positiveisolation and allowing for a pressure integrity test of the casing to be performed. This tool is referred to as an initiator rupturedisc valve (RDV) and provides a way to efficiently start the hydraulic fracturing process for the toe stage.

Fracturing Through Cement without Perforations

Fracturing through cemented sleeves is not an easy task. One immediate issue that always arises when considering cemented

sleeves is whether the fracture initiation pressure will be significantly higher without the perforation tunnels that pass throughthe cement and into the formation. The key to the initiator valve performance is its ability to breakdown and convey an entirelarge propped fracture stimulation treatment through the ports and cement sheath into the formation without the need for any

perforation tunnels. To achieve breakdown and fracture through a cement sheath, various theoretical port and slotconfigurations were built and tested to assess the viability of the initiator sleeve concept by attempting to minimize and predictfracture initiation pressures. A series of finite element analyses (FEA), mathematical models, and laboratory tests wereconducted in an attempt to discover a solution to this problem.

Full-scale tests were conducted in unstressed concrete cylinders to investigate how the valves port (slot) geometry affectedfracture initiation pressures in unstressed, surface conditions. The main goals of these tests were to minimize fracture initiation

pressure and investigate which port design promoted a single vertical fracture in the concrete. These tests were performedusing 4!-in. casing and valve assemblies cemented inside concrete cylinders 36-in. in height with an average compressivestrength of 4,000 to 5,000 psi. A unique cylinder was constructed for each port configuration tested. The assemblies were

pressured up until failure (fracture initiation) and the pressure was recorded at failure. The pressure breakdown responsecreated by perforating guns was also evaluated against that of the various port/slot configurations. The results showed fractureinitiation pressures varying from 327 psi to 1,790 psi. Each port configuration had a unique effect on the near-wellbore

geometry of the hydraulic fractures. A cutaway of the test performed with the valve that consisted of six 12-in. vertical slots

with 60 phasing can be observed in Fig. 10. Notice how these slots created a bi-wing vertical fracture plane. One of theperforating gun tests with 120 phasing can be observed in Fig. 11. Notice that fractures were initiated in two or three planes

near the wellbore but that these fractures are sub vertical (did not remain planar and vertical as the fracture grew more than afew inches outside of the casing).

The unstressed cylinder tests showed that a port configuration consisting of six 6-in. ports with 60 phasing provided the

optimum performance with respect to fracture initiation. An elaborated 3D FEA model was created to predict the stress nearthe wellbore in tight sandstone with far-field stresses applied. This 3D FEA analysis was necessary to determine the optimum

parameters for tests under actual bottom-hole conditions. A full-scale stress frame was constructed and tests were conducted

using sandstone blocks with far field stresses applied. A true tri-axial stress capabilities apparatus was used to simulateformation in-situ stresses with three different principal stresses. For each test, a 30-in. wide by 30-in. deep by 54-in. tall blockof sandstone was placed in the tri-axial test apparatus. Once the block was secured in the tri-axial apparatus, a minimum

horizontal stress of 4,000 psi, maximum horizontal stress of 5,000 psi, and an overburden stress of 6,000 psi were applied tothe block.

The base case test was constructed using 4!-in. diameter casing cemented in the rock block and then perforated using a 1-

ft gun with 3 spf at 120 phasing with one shot aligned with the preferred fracture plane (PFP). One of the shots was aligned tothe PFP to simulate the best possible alignment scenario for the perforating gun. The pressure to fracture the sandstone blockwith the 120 perforations was 4,540 psi. Another test using a six slot valve phased at 15 from the PFP broke down the

sandstone block at 4,598 psi. The difference between the perforating and 15 helical port sleeve tests was negligible, andindicated that the valve does not require a high fracturing pressure, making it a viable completion option compared to

perforating. To reduce the near-wellbore pressure affects further, the calibrated 3D FEA model was used to analyze various

port configurations (Table 1). New helical ports were developed to best emulate the effect of oriented perforations in thewellbore. Based on this model, a new helical port configuration was developed and used successfully in real-well applications(Fig. 12).

Rupture Disc Valve Overview

The initiator RDV eliminates an intervention trip into the wellbore that would be required by one of the aforementioned

methods. Although the RDV can be used in wells having any deviation, it is particularly useful in horizontal or highly deviated

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wells as the lowest stage of these wells cannot be perforated using simple gravity force driven gun strings. The novel valveallows for the first fracture stage to be initiated easily and without intervention. The RDV contains two rupture discs that block

the flow and pressure from the wellbore to the inside of the tool. Once the RDV is pressured up and activated, pumping of thefirst fracturing stage can be performed at the desired rate and proppant concentration through the helical slots in the valvewithout the need for any perforations. The RDV is installed in the casing string, spaced three to four joints of pipe above the

float shoe to align the valve with the desired toe stage frac point in the formation. When the RDV is set in place, cementingoperations can begin. The cementing process proceeds in the same manner that it would if the wellbore was lined with casing

only. Furthermore, there are no changes in the cement pumping procedure nor is any special type of cement chemistry such asacid soluble cement needed. After the cement is set, an integrity test is performed to the desired casing test pressure. Uponcompletion of the integrity test, the initiator valve is activated by pressuring up slightly above the casing test pressure whichcauses the rupture discs to fail and a sleeve in the valve to open. This open sleeve exposes the cement sheath to the wellborefluid and the first stage can be fractured out of the RDV or pump-down plug-and-perf operations can begin. A completesequence of this operation is shown in Fig. 13.

Activating the RDV is achieved by increasing bottom-hole pressure to rupture either one of two rupture discs that are

positioned to block flow (Fig. 14). Rupture discs can be selected ahead of time and installed before the RDV is delivered to therig or on the rig floor during the casing running operation. The discs are selected based upon the sum of surface pressure andthe well hydrostatics. The rupture discs are manufactured in 250-300 psi increments allowing for a precise activation window

when ruptured. The rupture disc is typically selected to have a value approximately 500 psi greater than the desired casing testpressure. It is not a requirement that both discs rupture, only one needs to rupture for the RDV to operate. When the disc(s)rupture at the set pressure, a pathway for fluid flow opens to the tools internal atmospheric chamber, pressure along with fluid

rushes in and the valve is opened in a piston-like manner (Fig. 14). When the internal sleeve slides open, the valves helicalports create a window from which the casing fluid can be pumped out of (Fig. 14).

The helically-aligned ports around the RDV expose the entire circumference of the valve to the cement sheath. The hoopstress in a horizontal wellbore typically contains two points 180 apart that are the weak point in the near wellbore area. Nomatter the tool orientation, one of the fracturing ports (slots) is never more than 3 from one of the minimum stress points onthe hoop stress envelop. This ensures that the hydraulic fracture near the wellbore does not have far to reorient, minimizing

tortuosity, which reduces fracture treating pressure. The helical ports allow for the cement to be broken down with ease andthe fluid can then continue on into the formation to create the hydraulic fracture. The total sum of all ports is 10.7-in

2;

equivalent to six perforation clusters, each 2 ft in length with 6 spf. After the sleeve is opened, the first fracturing stage is

ready for treatment or pump-down plug-and-perf operations. The first stage is pumped through the RDV with relatively lowinitiation and surface treatment pressure similar to hydraulic fractures pumped through perforation tunnels, which is due to thehelical ports. Once the first stage is completed, economic pump down plug-and-perf operations can commence. Alternatively,

the valve does not have to be fractured through if for some reason a change is called for or the operator prefers multiple

perforation clusters, a gun string with a frac plug can be pumped down and set as in any plug-and-perf operation. Throughoutthe entire operation no frac balls are required.

The RDV is rated to 20,000 psi and 325F. Treatments can be pumped through the RDV at rates to 120 bbl/min and up to10 lbm/gal of proppant added. This pump rate allows operators to use the RDV across a wide variety of formations types,

pressures, and temperatures. Rupture discs can be easily changed at any time if required, aiding to any last minute

modifications to the wellbore construction. The elimination of a pre-treatment intervention significantly reduces time andcosts, optimizing operations as described in the case study that follows and minimizing the risks associated with anintervention trip.

Eagle Ford Shale Case History

The operator in this case study holds a significant acreage position in the Eagle Ford shale with over 50,000 acres. The

operator currently operates three rigs in the basin and has drilled over 30 horizontal wells since 2009 in the play. The majorityof the operators activity has been focused in the Buckhorn field located in southeastern Frio County of south Texas (Fig. 15).The operator has been an innovator in the basin in regards to maximizing asset value. Case in point, the operator has pushed

well spacing down to 55 acres, while 80 acres has been the normal spacing for laterals in the basin. The operator achieved thisdown spacing between laterals without compromising the length of the lateral. The initial production results of decreased vs.normal spacing are shown in Table 2. The results demonstrate that similar initial production rates were achieved for laterals

with tighter spacing compared to those with normal spacing (Eagle Ford Shale Blog, 2012; OilVoice, 2012). Other operatorsin the basin are currently trying to emulate this success.

In addition to the lateral spacing optimization, the operator has improved their completion practices by incorporating the

RDV. Similar to well spacing, the operator was one of the first adopters of this novel initiator valve technology in the basin.The operator found that by employing the RDV that they could reduce the cost of their wells by eliminating the CT conveyedfirst-stage perforating gun run and began incorporating the valve in the second quarter of 2011. The operator generally drills

laterals around 5,500 ft in length in the Buckhorn area of the Eagle Ford shale. The fracture stage count ranges from 14 to 20in this portion of the play. The operator has installed the RDV in over a dozen wells in the Buckhorn field.

Routine casing tests are performed by the operator in their horizontal wells to 10,000 psi. They typically select rupture

discs that activate at 600 to 800 psi above the casing test pressure for their initiation valves. The rupture disc activation

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pressure of three of the wells that the operator has drilled in the Buckhorn field are shown in Table 3and are the B-6H, H-1Hand H-2H. Observe that all of the RDVs have activated within 200 psi of the desired range. The operator activates the RDV

with the drilling rig on location so it is open and ready to pump into when the fracturing treatment crew arrives on location.The geometry of one of the example wells that incorporated a RDV is shown in Fig. 16. This figure shows a fairly commonwellbore design for a horizontal well drilled in the Eagle Ford shale today. The operator routinely pumped the first fracturing

treatment, consisting of over 250,000 lbm of proppant at 65 bbl/min, through the helical ports of the RDV. For the rest of thestages, 80 bbl/min and 400,000 lbm of proppant is common. The treatment plots for the first stage (RDV stage) of the three

example wells can be observed in Figs. 17-19. Notice in these figures that the fracturing treatment rate was 65 to 80 bbl/minfor all wells. Also it can be seen in Figs. 17-19, some of the increases and decreases in the treating pressure were due to fluidtype or additive changes and equal one wellbore volume pumped. Table 4shows the average rate, treating pressure, hydraulichorsepower (HHP) and instantaneous shut in pressure (ISIP) of the first ten stages on the B-6H lateral. The RDV stage hadsimilar average treating pressures, the lowest HHP, and the second lowest ISIP of all stages analyzed. This is proof thatfracturing through a cemented sliding sleeve with helical ports is not troublesome and is very similar to other plug-and-perfstages in the same wellbore.

By using the RDV, the operator was able to save over $100,000 per well. This takes into account the cost of the valve andthe savings created by eliminating the CT perforating gun run on the first stage. The operator was able to consistently fracturestimulate treatments over 250,000 lbm of proppant through all of their RDVs without any issues. The initiator valves have

been highly successful for the operator and they continue using the RDVs for completions in the basin. .Over 300 RDVs have been installed in horizontal unconventional wells in North America. The RDV has been used in

the Marcellus shale, Avalon shale, Fayetteville shale, Barnett shale, Montney shale, Granite Wash, and Horn River basin

among others.

ConclusionsThe conclusions made based on the experiments with various valves port configurations and the case study results include thefollowing:

Cemented sliding sleeves have historically had issues in lateral wells when trying to fracture through cementcomposed of standard chemistry.

The helical port design minimizes the fracture tortuosity caused by realignment thus lowering the fracture initiationpressure. Furthermore, helical ports allow for easier fracture initiation and lower treating pressures compared to liner

ports or phased nozzles in cemented laterals.

Special cement chemistry or changes to cement practices are not needed in order to allow the RDV to fracturethrough the cement sheath.

The RDV eliminates the need for a CT, stick pipe or wireline tractor intervention that would be used to runperforating guns in a lateral closed system.

The RDV can be hydraulically pumped through to form a fracture or pump down plug-and-perf operations can beemployed.

Once opened, the RDV was able to allow all fracturing treatments to be pumped to completion without incident in theoperators wells.

The helical port design has similar fracturing treatment pressures to those pumped through plug-and-perfcompletions.

The RDV had no problems handling large fracture stages of 250,000 lbm of proppant pumped at 65 bbl/min.

The RDVs eliminate the need for an intervention that can save operators up to and in excess of $100,000 per well.

Toe RDVs have been used successfully in over 300 horizontal well applications in nearly a dozen unconventionalplays.

References

Dawson, W. C. 2000. Shale Microfacies: Eagle Ford Group (Cenomanian-Turonian) North-Central Texas Outcrops and SubsurfaceEquivalents. Gulf Coast Association of Geological Societies Transactions. 50. 607-621.

Eagle Ford Shale Blog. Cabot Oil & Gas Eagle Ford Down Spacing Success at 55-Acres. 2012. http://eaglefordshale.com/news/cabot-oil-gas-eagle-ford-down-spacing-success-at-55-acre-spacing/ (accessed 28 July 2012).

Energy Information Energy. 2011. Trends in Eagle Ford drilling highlight the search for oil and natural gas liquids.http://www.eia.gov/todayinenergy/detail.cfm?id=3770# (accessed 18 July 2012).

Ewing, E. T. 2010. Geology in outcrop in the San Antonio Area (An occasional series). South Texas Geologic Society Bulletin. April 2010.

IHS Energy. 2012. Enerdeq, http//energy.ihs.com/Products/Enerdeq/. (downloaded 25 July 2012).

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Liro, L.M., Dawson, W.C., Katz, B.J., and Robison, V.D. 1994. Sequence Stratigraphic Elements and Geochemical Variability within a

Condensed Section: Eagle Ford Group, East-Central Texas. Gulf Coast Association of Geological Societies Transactions.44. 393-402.

Lock, B.E. and Peschier, L. 2006. Boquillas (Eagle Ford) Upper Slope Sediments, West Texas: Outcrop Analogs for Potential ShaleReservoirs. Gulf Coast Association of Geological Societies Transactions. 56.491-508.

Martin, R., Baihly, J., Malpani, R., Lindsay, G., and Atwood, W.K., 2011. Understanding Production from Eagle Ford-Austin ChalkSystem. SPE Paper 145117 presented at the SPE Annual Technical Conference and Exhibition, Denver, Colorado, 30 October2

November.

Oil Voice 2012. Cabot Oil & Gas provides operations update, reports success in Marcellus, Marmaton and Eagle Ford.http://oilvoice.com/tw/75b9b3b467dd.aspx(accessed 12 July 2012).

Petrohawk Energy Corporation. Shareholders, http://www.petrohawk.com/Investor-Relations/presentations.aspx (accessed on 25 April

2011).

Rail Road Comission. Rail Road Comission of Texas Eagle Ford Information site. 2012.

http://www.rrc.state.tx.us/eagleford/index.php#general (accessed July 27th, 2012).

Rig Data. Well Information System. 2012. http://www.rigdata.net/login.aspx?ReturnUrl=%2fDefault.aspx (accessed on 1 August 2012).

Rytlewski, G. and Cook, J. 2006. A Study of Fracture Initiation Pressures in Cemented Cased Hole Wells Without Perforations. SPE Paper

100572 presented at the 2006 SPE Gas Technology Symposium, Calgary, Alberta, Canada, 1517 May.

Sanchez Energy Corporation. Eagle Ford Shale. 2012. http://sanchezenergycorp.com/areas-of-operation/eagle-ford-shale (accessed on 28July 2012).

Smith STATS. Rig Count History. 2012. http://stats.smith.com/new/history/statshistory.htm (accessed on 1 August 2012).

Stegent, N. and Howell, M., 2009. Continuous Multistage Fracture Stimulation Completion Process in a Cemented Wellbore. SPE Paper125365 presented at the SPE Eastern Regional Meeting, Charleston, West Virginia, USA, 23-25 September.

Texas Alliance. Water and Disposal Issues in the Eagle Ford Shale. 2012.http://texasalliance.org/admin/assets/Water_and_Disposal_Issues_in_the_Eagle_Ford_by_Ivey.pdf(downloaded on 19 July 2012).

Union Pacific Rail Road, 2012. West Texas Intermediate Crude Oil (WTI) Prices. http://www.uprr.com/customers/surcharge/wti.shtml

(accessed 1 August, 2012).

UPI. Eagle Ford shale activity prompts upgrades. 2012. http://www.upi.com/Business_News/Energy-Resources/2009/12/04/Eagle-Ford-

shale-activity-prompts-upgrades/UPI-67191259943401/ (accessed on 15 July 2012).

Tables & Figures

Table 1 Fracture pressure for various port configurations.

Configuration Ref to PFP Fracture

Pressure(psi)

Pressure Above

!min

(psi)

3 perfs @ 120 1 shot @ 0 4,540 301

6 slots x 6-in long 0 (Helical) 4,283 126

6 slots x 6 long 15 4,598 550

6 slots x 6 long 30 5,382 1,063

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Table 2 Production comparison of varied offset spacing.

Well Lateral

Spacing(acres)

24 Hour Initial

Production Rate(BOPD)

Average of Q4 2011 completions 80 861

#1H 55 788

#2H 55 791

Table 3 Initiator valve opening pressure comparison across multiple laterals.

Well Rupture Disc SetPressure

(psi)

Rupture Disc ActivationPressure

(psi)

B-6H 10,600 10,600

H-1H 10,600 10,750

H-2H 10,600 10,700

Table 4 B-6H well treating properties for the first ten stages.

Stage Average

Rate

(bbl/min)

Average Treating

Pressure(psi)

Average HHP ISIP

(psi)

1 65 6,830 10,881 4,562

2 80 7,089 13,848 4,996

3 79 6,110 11,771 5,007

4 80 6,764 13,246 4,741

5 81 6,805 13,443 4,736

6 80 6,806 13,295 4,783

7 81 6,739 13,395 4,462

8 80 6,748 13,198 4,890

9 80 6,871 13,540 5,031

10 79 6,293 12,139 4,702

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Fig. 1 Austin Chalk trend and main producing fields (Martin et al, 2011).

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Fig. 2 Map of Eagle Ford shale activity in south Texas (RRC, 2012).

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Fig. 3 Map showing the maturation windows for the Eagle Ford (Martin et al, 2011).

Fig. 4 Eagle Ford shale rig count (Smith, 2012; Eagle Ford Shale Blog, 2012).

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Fig. 5 Upper Cretaceous stratigraphic column showing the Eagle Ford shale (Dawson, 2000).

Fig. 6 Top Eagle Ford shale structure map with key geologic features (Martin et al, 2011).

Cretaceo

us

Early

Late

!"#$%&'() $%+'#,-#&.##) /01233 4&5 67#""(.8

%)9 /0:1233 4&5 69%+; -"

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Fig. 7 Eagle Ford Shale type log of the Dora Martin in La Salle County, Texas (Petrohawk, 2011; Ewing, 2010).

Fig. 8 Eagle Ford shale horizontal well average lateral length (IHS, 2012).

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Fig. 9 Eagle Ford shale average stage count pumped per lateral.

Fig. 10 Post fracture concrete cylinder test of a six finned valve with 12-in long slots.

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Fig. 11 Post fracture concrete cylinder test of a 3 spf perforating gun phased at 120.

Fig. 12 2D and 3D FEA analysis along with a helical port picture.

Fig. 13 Initiator valve completion sequence.

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Fig. 14 Initiator valve schematic with rupture discs highlighted.

Fig. 15 Location of case study wells in south Texas.

Fig. 16 Well B-6H 2D directional survey.

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Fig. 17 Well B-6H first fracturing treatment stage pressure, rate, and proppant concentration plot.

Fig. 18 Well H-1H first fracturing treatment stage pressure, rate, and proppant concentration plot.

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Fig. 19 Well H-2H first fracturing treatment stage pressure, rate, and proppant concentration plot.