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The effectiveness of the different completion systems would be evaluated using microseismic fracture diagnosticmonitoring techniques in combination with a 3 dimensional hydraulic fracture model. Post fracture productiontesting and well performance would be integrated into the evaluation.

Background and Geology of the Glauconitic Formation

The Glauconitic formation of west central Alberta is a preserved barrier island depositional system. Modern

analogues would include the Texas gulf coast (Galveston Bay and Island) and the north shore of Prince EdwardIsland in the Canadian Maritimes. The Glauconitic sands were deposited during the mid-Mannville of LowerCretaceous time and represents the maximum transgressive phase (high sea level) of the Mannville. This barrierisland complex has preserved all facies types associated with this depositional system, including preservedbarrier islands capped with linear aeolinites, tidal inlets and bays, subtidal channel sands, reworked intertidalsands, aggrading windblown and current transported spits and back bay fluvial deltas. The most economicallyimportant facies are the preserved barrier islands and to a lesser extent the tidal sands.

The barrier island trend runs in a southwest to northeast direction, from Ram River in the Alberta foothills in thesouthwest to Westerose in the northeast, a distance of approximately 200 km (see map in Figure 1). The trendcontinues at depth into the Rocky Mountains, where it is uplifted and outcrops. To the northeast the trend istruncated by fluvial channels. The Barrier Island Trend consists of several large preserved barrier islandsseparated from each other by mud and sand filled tidal inlets and bays. These separate islands lend themselvesto different Field or area names, as shown in Figure 1. A more detailed description of the geology may be foundin the paper by Chiang, 1985.

The zone increases in depth as it moves southwest into the Foothills of the Rocky Mountains. Depths in theWesterose area are approximately 1,840 m; increasing to a depth of 3,450 m in the Deanne Field. The porepressure gradient also varies with location and depth, from slightly under pressured to water in the northeast(8.5 kPa/m), to significantly over pressured in parts of the Foothills (16.1 kPa/m).

Total gross zone thickness varies between 15 m and 25 m; with porosities in the range of 6 to 15%. The watersaturation is believed to be sub-irreducible, in the range of 25 to 30%, and no significant formation water isproduced anywhere in the trend. A type log open hole log of the Glauconitic sands is shown in Figure 2.

Of particular interest to this project, are a series of regional coals which cap the Glauconitic sands the MedicineRiver coals. The coals vary in thickness from approximately 0.5 m to 5 m, are areally extensive and are good

markers for geological mapping and correlations. There will be more discussion on this later, with respect tohydraulic fracture height growth.

The play was initiated in the late 1970s with a series of vertical well discoveries in the Westerose area. Thisinitial phase of drilling targeted the higher permeability aeolionite facies capping the barrier island facies. Havingfocused on the higher permeability aeolionite facies, an enormous resource was left behind in the other lowerbarrier island sands. These tighter sands have been the focus of horizontal multiple fractured well drilling over thelast 3 years, particularly targeting the lower one third of the Barrier Island package (Figure 2). The expected in-situ permeability to gas is in the range of 0.001 mD to 0.01 mD in the sands of current interest.

The produced natural gas has a specific gravity of approximately 0.70 and is rich in NGLs, with a liquid yield ofapproximately 65 Bbl/MMcf.

Initial Hydraulic Fracture Design and Modeling

Prior to pumping the fracture treatment and recording the microseismic data, well and reservoir data was inputinto a 3-dimensional hydraulic fracture simulator in order to determine the expected fracture geometry for theplanned pump schedule. The treatments pumped into both the cased well and open hole well were planned to bevery similar to each other in order to compare how using the different completion systems affected the productivityof the wells. The designed fracture profile for the cased well can be seen in Figure 3 and for the open hole well inFigure 4. Table 1 highlights the design treatment parameters and Table 2 highlights the results of the simulations.Different logs from nearby vertical offset wells were used for each of the simulation runs, as different logs wereused, differences in stress contrasts between layers resulted. This difference is the primary reason for thedifferences in the simulation results, especially fracture height, between the two wells. These vertical wells werechosen in order to get log information below the horizontal wellbores being fractured.

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The fracture fluid system has been optimized through many years of experience in the Glauconitic sands. Thisformation is known to be sensitive to water, probably through imbibition and phase trapping as the watersaturation is at sub irreducible conditions although swelling clays are present in variable amounts in certainareas. Early fracture fluids were mainly Gelled Hydrocarbon systems, which cleaned up well and resulted inlonger effective hydraulic fracture half lengths. With larger fracture treatments required for access to the tightersands, costs of the hydrocarbon based systems became prohibitive.

With the introduction of Foamed Viscoelastic Surfactant (VES) based fracture fluids in the late 1990s, waterbased fracture fluids became a viable option for this formation (Oilfield Review, 1997). The fracture fluid systemconsists of nitrogen at 70% quality, greatly reducing the amount of fluid placed in the formation. This fluid hasproven to cleanup extremely well in the Glauconitic, and is far more cost effective than hydrocarbon basedsystems.

Hydraulic fracture treatment sizes up to 100 tonnes of proppant have been pumped successfully into theGlauconitic sands in vertical wells. For the MFHW, most Operators have optimized fracture sizing in the range of40 to 60 tonnes of proppant per fracturing stage.

Microseismic Project Design Details

The project was designed to monitor an 8 stage fracture treatment for both the cased horizontal well and openhole horizontal wells (operational issues reduced the cased well to 4 stages). The plan and depth view fortreatment and observation wells are seen in Figures 5 and 6. In the figures, the ports or perforation intervals foreach stage are marked by different colored ticks, and the packers are marked with black ticks.

The observation wells for the project are marked as Obs Well A and Obs Well B in the figure. An array of twelvegeophones was placed into each of these wells for the purposes of monitoring the fracture treatments. Thegeophones were separated by 15 m interconnects for a total array aperture of 177 m in both observation wells.

Completion and Hydraulic Fracture Operational Details

Well completion operations were carried out simultaneously on the two wells, between March 14 and April 3,2011. The 8 stage ball and sleeve fracture treatment was completed in a single day without issue.

The cased well experienced difficulty in getting fracture breakdown through the ported collars. Equipment was

pressure limited to 60 MPag at surface, and multiple pressure cycling, including acid, could not achievebreakdown. A decision was made to abrasively cut the ports using the coiled tubing, then breakdown wasachieved and the fractures were placed as per design. The first four fracture treatments were completed in oneday. At this point, the bottom hole assembly on the coiled tubing parted, resulting in a short fishing job to recoverpieces of the tool. Advancing warm spring weather and soft lease conditions halted any further fracture treatmentson the cased well.

Microseismic Results

When monitoring the fracture treatments in the cased well, there were 566 microseismic events located from ObsWell B, but no events located from Obs Well A. The 4 stages pumped were acquired with good quality andquantity of events, so both fracture azimuth and geometry could be determined (seen in Figures 7 and 8). It maybe observed from Figure 7, transverse fractures were created with an azimuth of approximately N46E. The

fracture geometries observed from the events for these stages were summarized in Table 3.

It also can be seen from Figure 7 that the fractures in stages 1, 2 and 3 appeared to be asymmetric about thewellbore toward the north-east. The asymmetry of stages 1 and 2 could have been caused by the bias torecorded events closer to the observation well allowing the north-east fracture wing to be better imaged. Theasymmetry of stage 3 may have been caused by reservoir heterogeneity. The fractures of stage 4 were generallysymmetric about the wellbore.

When monitoring the fracture treatments in the open hole well, there were 528 microseismic events located fromObs Well A and 6 microseismic events located from Obs Well B. These microseismic events were located in allfracturing stages however only stages 3 to 7 had enough events to determine fracture azimuths and geometries(seen in Figures 9 and 10). It is seen from Figure 9, transverse fractures were created with an azimuth aboutN46E. The fracture geometries observed from the events for these stages were summarized in Table 4.

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It also may be seen from Figure 9 that fractures in stages 4 and 5 appeared to be asymmetric about the wellboretoward the south-west. This was likely caused by the bias to recorded events closer to the observation wellallowing the south-west fracture wing to be better imaged. The fractures in the rest of the stages were generallysymmetric about the wellbore (Warpinski, 1996 and Wolhart, 2006).

Moment Magnitude of Microseismic Events

Two observation wells were required to comprehensively monitor the open hole well and the cased well. The sizeof the microseisms generated by hydraulic fracturing in the Glauconitic formation was not large enough to bedetected by only one observation well. Microseismic signals get attenuated while traveling into the surroundingrock formations. Microseismic signals which travel over long distances degrade to the point where they cannot becorrectly identified. As a result, events generated at greater distances away from the observation wells are eithernot detected or will have greater location uncertainty. In addition, lower magnitude events attenuate faster thanlarger magnitude events. As a result, the treatment stages closer to the observation well will appear to have ahigher density of events relative to the stages located further away. This denser cloud of microseismic eventscomprises of a mix of low and high magnitude events. The microseismic cloud located further away will have alarger portion of large magnitude events. All parameters being equal, an even distribution of various magnitudeevents should exist along the wellbore, regardless of what is detectable by the observation well. Figures 11 and12 are the magnitude-distance plots, showing the detection trend with distance (Zimmer, 2007).

Calibrated Fracture Model Discussion

Fracture modeling is normally based on some assumptions due to limited input data availability. The reservoirproperties, formation rock mechanical properties, well data quality and engineering experience are factorsaffecting the modeling results. Mini fracture analysis and post fracture pressure match are conventional methodsto fine tune fracture models. To fine tune a fracture model a pressure match is performed on the treatment data.This is typically a non unique solution as different fracturing engineers will have different fracture geometries forthe same pressure match. This is due to the number of variables that can be altered in a fracture simulator.

With the input of fracture geometry observed from microseismic monitoring, the fracture model calibration isfurther refined. In this case, we have the benefit of knowing the fracture geometry from the microseismic project.So, to create a calibrated fracture model, not only do we have to perform a pressure history match, but theresulting geometry from that match in the fracture simulator must match the microseismic geometry as well. This

is a much more robust fracturing solution for further development in this formation and field (Warpinski, 2009;Weijers, 2005; Mayerhofer, 2000).

Generally, the fracture treatments were pumped as per the design parameters outlined in Table 1. The onlydifference was that the cased well experienced higher treating pressures on all stages and the downhole injectionrate was reduced to an average of 2.3 m

3/min from the planned 3.0 m

3/min. The matched fracture geometry

profiles for the open hole well and the cased well can be seen in Figures 13 and 14 respectively, with the matchedsurface pressure charts shown in Figure 15 and 16.

Fracture Geometry Comparison Between Cased and Open Hole Wells

Figure 17 shows all of the microseismic events for both wells from the overhead view. A general observationwould be that the fractures were much more simple and planar from the cased well vs. the open hole well.

Measured event widths vary from 52 to 86 m for the cased well vs. 86 to 222 m for the open hole well. Multiplefracture initiations and more complex fracturing appear to be occurring in the open hole well and not in the casedhole well. An observation from Stage #4 in the open hole well (brown dots) suggests there are at least 4 parallelfracture liniments present over the length along the HZ wellbore of 222 m. A consequence of the multiple fractureinitiations is much shorter fracture half length from the open hole well (avg. 110 m vs. 175 m for the cased well).The importance of deep penetrating fractures in a tight gas reservoir cannot be emphasized enough. The shorterfracture half lengths will reduce well productivity and ultimately reserves recovery, due to a smaller drainage area.

The calibrated fracture models also show a significant difference in fracture geometry between the open hole andcased wells (Figure 13 and 14). One finding was the difference in fracture height growth (68 m for the open holeand 28 m for the cased well). For wells located in close proximity, this was quite surprising. We attribute thisdifference to differences in the rock properties in the overlying coals and shaly section, where bedding slippage orblunting of the fracture tip may occur when a coal or other heterogeneity is encountered. As mentioned earlier,

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the overlying coal thickness and properties can be quite variable. The high leakoff and rock mechanicalproperties of coals tend to reduce or stop fracture propagation. A bedding plane sliding at an interface, causingblunting of the fracture tip has been observed in many areas as a mechanism for containment of vertical fracturegrowth (Daneshy, 2009; Barree, 2010; Gu, 2008). This situation may also result in T-shaped or horizontalcomponent fractures at the bedding plane interface. It may be possible to look at changes in polarity of thewaveforms from individual microseismic events to ascertain whether the propagating fracture has changed itsorientation, but this sort of study has not been undertaken with this dataset. If a significant horizontal fracture

component exists in the cased hole well, it would help explain the higher fracture pressures observed in the casedhole well when compared to the open hole well (Maxwell, 2007).

NOTE:The geophones in Obs Well A were located slightly above the zone of interest, whereas, in Obs Well B thegeophones straddled the zone of interest. This may introduce a slight error in event locations in the verticaldirection for the open hole well, but would not account for the large amount of height difference observed.

While mini fractures were not performed on any fracture stages on these wells, the open hole well required anincreased transverse storage coefficient in the model (to get a pressure match), which may support multi-branched fractures in addition to the primary fracture. After shut-in a higher leakoff was observed, which maysupport connection with the coals cleat system. This high leakoff was not observed from the cased hole well,which was more vertically contained.

The pressure matched fracture models and the observations from the microseismic confirmed significantlydifferent fracture geometries between the open hole and cased wells. The cased well fractures were of simpler,planar geometry with much longer fracture half lengths.

Fracture Cleanup / Early Production Data

The surface location where both horizontal wells were located had a pipeline installed to the lease edge whiledrilling operations were underway. Once the nitrogen concentration dropped below 30%, the gas could be sentdown the pipeline to the processing plant. This minimized flaring while cleaning up and testing the wells.

After hydraulic fracturing operations were completed at both wells, a short cleanup period followed with the wellsflowing up the 114.3 mm casing string. The 60.3 mm production tubing strings were then snubbed into the wells.Each well had a complete test unit installed, with detailed recording of the test conditions.

During the initial 21 day cleanup / flow period, the open hole well produced at a gas rate of approximately85 10

3m

3/d with a flowing tubing head pressure (FTHP) of 3,950 kPag. At the same time, the cased well

produced at a gas rate of approximately 55 103m

3/d at a FTHP of 4,100 kPag. Both wells were producing

significant volumes of fracture load fluid during this time period. The wells were then shut-in for approximately 2weeks with pressure recorders landed downhole to record the pressure buildup data.

Both wells were placed on production on May 19, 2011. Pipeline capacity issues caused some significant downtime for the cased well, during the early production period. The production graphs (Cartesian scale) over the first3.5 months for each well are shown in Figures 18 (open hole) and 19 (cased hole). The initial gas rate for theopen hole well was approximately 90 10

3m

3/d vs. 60 10

3m

3/d for the cased hole well. After 3.5 months, the open

hole well was producing at a gas rate of 37 103m

3/d at a FTHP of 1,300 kPag, while the cased well was producing

at a gas rate of 25 103m

3/d at a FTHP of 1,200 kPag. After 3.5 months of production, the open hole well had

shown a higher decline rate than had the cased hole well. In terms of production rate per fracture after 3.5

months, the open hole well was producing 4.6 103

m3

/d, vs. the cased hole well at 6.25 103

m3

/d, or a difference of36%. It should be noted that both wells were still declining slightly at the end of this period, indicating the flowregime was still in the fracture dominated portion of the decline.

The cumulative gas production over 130 days (including the cleanup period), the open hole well had produced7,551 10

3m

3 of gas vs. 4,782 10

3m

3 for the cased hole well. On a per fracture basis, this is a difference of

approximately 27% in favor of the cased hole well. This conclusion goes against the conclusions of at least oneother comparative study between cased hole and open hole MFHW completions in a tight gas field (Edwards,2010).

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PTA and RTA Reservoir Analysis Results

In an attempt to evaluate the effectiveness of the fracture treatments in the different well types, both PressureTransient Analysis (PTA) and Rate Transient Analysis (RTA) techniques were used. These methods have provento be valuable in resolving hydraulically created vs. effective fracture half lengths, as well as assisting in thefracture optimization process, in conjunction with other diagnostic methods, such as microseismic (Cipolla, 1998and 2008; Barree, 2003).

Following a short cleanup period post fracture, both wells had the production tubing snubbed in and tandempressure recorders landed downhole. Both wells were flowed on an extended cleanup test for 3 weeks, followedby a 2 week shut-in for pressure buildup. The buildups were analyzed, with a summary of the results shown inTable 5. Pressure depletion of approximately 3,100 kPa was observed in the open hole well, while the cased holewell was at near virgin pressure. An older vertical well was located approximately 500 m east of the open holewell, which may have been responsible for the depletion. The horizontal radial flow regime was not observedduring either buildup, so test results were not considered to be accurate. However, there was some evidence ofeffective fracture half length in the cased hole well, which was not observed in the open hole well.

The wells were both placed on production under normal pipeline flowing conditions, and rate and flowing pressuredata was gathered using a SCADA system. After approximately 110 days of production, the data was analyzedusing RTA software in an attempt to determine the reservoir permeability and effective fracture half lengths. Thesummary results of this analysis are shown in Table 6, and Figures 20 and 21. Due to the very low matrixpermeability observed, boundary dominated flow was not reached. While a satisfactory history match wasachieved, there are non-unique solutions related to effective fracture half length, fracture conductivity, and matrixpermeability (Cipola, 2008) Results of this analysis should be used with caution.

NOTE: Throughout this analysis, the assumption was that all flow was from the fractures and the open holemade no contribution. The assumed drainage area for all cases was 1/3 section.

While the analysis indicated a short effective fracture half length of 11 m for both wells, the skin factor for thecased well was lower, indicating slightly more effective stimulation treatments. The average matrix permeabilitywas similar for both wells, in the high microDarcy range.

To understand the affect of the reservoir pressure differences on well productivity, a sensitivity case was run on ahypothetical well with identical reservoir parameters, run at the two observed reservoir pressures. This analysis

could account for 25% of the rate difference between the two wells, vs. the actual observed 36% incremental on aper fracture basis (3.5 month rate). Therefore, the cased well was producing at higher gas rates per fracture,once the reservoir pressure differences were accounted for.

The RTA will be repeated in the future after more flow time, and we expect the analysis may give a more accurateestimate of the effective fracture half lengths after boundary dominated flow conditions are reached.

Conclusions

Based upon multiple technical analysis techniques used, we make the following conclusions from this study:

1) The fractures initiated from the cased well were much simpler and planar vs. the open hole well. Morecomplex and multiple fracture initiations came from the open hole well. We believe natural planes of

weakness and minor fissuring in the open hole section would be the likely cause of the multiple initiationpoints.

2) The simpler fractures created in the cased well resulted in significantly longer created fracture half lengths(175 m vs. 110 m).

3) Fracture heights were quite different between the two HZ wells in close proximity, a surprising finding.We attribute this to differences in the rock mechanical properties of the overlying coals, with possiblebedding plane slippage blunting the fracture height growth in the fractures in the cased hole well.

4) The early production histories suggest that on a per fracture basis the 3.5 month gas rate was 36% higherand the cumulative gas recovered was 27% higher for the cased hole well. The open hole well also had ahigher rate of decline during this period. We believe this data supports the more complex fracturing, andshorter created fracture half lengths observed in the open hole well.

5) After accounting for the observed reservoir pressure differences, the gas rate per fracture wasapproximately 11% better for the cased hole well (after 3.5 months of production).

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6) Both PTA and RTA indicated significantly shorter effective fracture half lengths for both wells, vs. thehydraulically created half lengths observed from microseismic and calibrated 3-D modeling work.

7) While the rate transient analysis may have some non-unique solutions, it does indicate slightly moreeffective stimulation treatments in the cased hole well vs. the open hole well.

8) We expect on-going production data analysis over the next 1 to 2 years will better define the actualeffective fracture half lengths.

9) Multiple diagnostic and reservoir analysis techniques have proven to be complimentary in understanding

the hydraulic fracture placement and performance, and will assist in future fracture optimization efforts.

Acknowledgments

The authors would like to thank the management of TAQA North Ltd. and Trican Well Service Ltd. for theirsupport and permission to publish this paper. We would also like to recognize Bruce Taylor and Mary Downey ofTAQA North Ltd. for their contributions to the Background and Geology section.

References

Barree, R., et al: Closing the Gap: Fracture Half Length From Design, Buildup, and Production Analysis; SPE84491, presented at the Annual Technical Conference and Exhibition, Denver, CO, October 2003.

Barree, R. et al; Evidence of Strong Fracture Height Containment Based on Complex Shear Failure andFormation Anisotropy; SPE 134142, presented at the Annual Technical Conference and Exhibition, Florence,Italy, September 2010.

Cipolla, C. et al; Understanding Fracture Performance by Integrating Well Testing and Fracture Modeling; SPE49044, presented at the Annual Technical Conference and Exhibition, New Orleans, LA, September 1998.

Cipolla, C. et al; Resolving Created, Propped, and Effective Hydraulic Fracture Length; SPE 129618, presented atthe International Petroleum Technology Conference, Kuala Lampur, December 2008.

Chiang, K.; The Giant Hoadley Gas Field, South Central Alberta; in J.A. Masters, ed., Elmworth Case Study of aDeep Basin Gas Field; American Association of Petroleum Geologists Memoir 38, pp 297 313, 1985.

Daneshy, A.; Factors Controlling the Vertical Growth of Hydraulic Fractures; SPE 118798, presented at the

Hydraulic Fracturing Technology Conference, The Woodlands,TX, January 2009.

Edwards, W., et al; Tight Gas Multi-stage Horizontal Completion Technology in the Granite Wash; SPE 138445,presented at the Tight Gas Completions Conference, San Antonio, TX, November 2010.

Gu, H. et al; Hydraulic Fracture Modeling with Bedding Plane Interfacial Slip; SPE 117445, presented at theEastern Regional / AAPG Eastern Section Joint Meeting, Pittsburgh, PA, October 2008.

Mayerhofer, M. et al; East Texas Hydraulic Fracture Imaging Project: Measuring Hydraulic Fracture Growth ofConventional Sandfracs and Waterfracs; SPE 63034, presented at the Annual Technical Conference andExhibition, Dallas, TX, October 2000.

Maxwell, S. C. et al; Evidence of a Horizontal Hydraulic Fracture at Depth Due to Stress Rotations Across a

Thrust Fault; SPE 110696, presented at the Annual Technical Conference and Exhibition, Anaheim, CA,November 2007.

Oilfield Review, Clear Fracturing Fluids for Increased Well Productivity, pp 20 33, Autumn 1997.

Ravensbergen, J.; Cased Hole Multistage Fracturing: A New Coiled Tubing Enabled Completion; SPE 143250,presented at the SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands,TX, April 2011.

Scotia Capital; Bonavista Acquisition Focuses Spotlight on the Hoadley Glauconite Play, Oil & Gas Resource PlaySpotlight, August 20, 2009.

Warpinski, N.; Microseismic Monitoring: Inside and Out; JPT pp 80 85, November 2009.

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Warpinski et al; Microseismic Mapping of the B-Sand Hydraulic Fracture Experiment at the DOE/GRI Multi-SiteProject; SPE 36450, presented at Annual Technical Conference and Exhibition, Dallas, TX, 1996.

Weijers et al.; Developing Calibrated Fracture Growth Models for Various Formations and Regions Across theUnited States; SPE 96080, presented at the Annual Technical Conference and Exhibition, Dallas, TX, October2005.

Wolhart et al; Hydraulic Fracture Diagnostics Used to Optimize Development in the Jonah Field; SPE 102528,presented at the Annual Technical Conference and Exhibition, San Antonio, TX, 2006.

Zimmer et al; Microseismic Monitoring Quality-Control (QC) Reports as an Interpretative Tool for Nonspecialists;SPE 110517, presented at the Annual Technical Conference and Exhibition, Anaheim, CA, November 2007.

Tables

Table 1 - Fracture Treatment Design Parameters

Cased Well Open Hole Well

Fluid System Surfactant N2Foam Surfactant N2FoamPump Rate 3.0 m

3/min 3.0 m

3/min

Proppant Type 20/40 sand 20/40 sand

Proppant Tonnage 60 tonne 60 tonne

Proppant Concentration 100 to 600 kg/m3 100 to 600 kg/m

3

Table 2 - Fracture Treatment Simulation Results

Cased Well Open Hole Well

Created FractureLength 396m 396m

Fracture Height 50m 36mAverage Proppant

Concentration 1.5 kg/m2 1.8 kg/m

2

Average Fracture Width 5.2mm 6.0mm

Table 3 - Cased Well Fracture Geometries from Microseismic

StageFractureAzimuth

Half FractureLength (m)

FractureHeight (m)

MS Event Width(m)

1 N46E 176 28 52

2 N46E 198 33 84

3 N45E 174 34 864 N45E 160 21 74

Average N45.5E 177 29 74

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Table 4 Open Hole Well Fracture Geometries from Microseismic

StageFractureAzimuth

Half FractureLength (m)

FractureHeight (m)

MS Event Width(m)

3 N44E 116 96 108

4 N46E 114 90 222

5 N46E 118 88 133

6 N46E 111 78 96

7 N45E 99 76 86

Average N45E 112 86 129

Table 5 Pressure Transient Test Results Summary

P (kPaa) kx (mD) ky (mD) kz (mD) Xf (m) s Leff (m)

Cased Hole 17627 0.001 0.003 0.07 12 -0.5 315

Open Hole 14519 0.005 0.1 0.04 n/a -2.4 375

PTA result

Table 6 Rate Transient Analysis Results Summary

P (kPaa) kx(mD) ky (mD) kz (mD) Xf(m) Fcd s Leff(m)

Cased Hole 17627 0.01 0.007 0.008 11 8 -1.2 550

Open Hole 14519 0.01 0.008 0.008 11 8 0.2 1179

RTA result

Figures

Figure 1 Glauconitic Geological Map (from Chiang, 1985)

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Figure 6 - Well Configuration Depth View

Figure 7 - All Events, Cased Well Plan View

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Figure 8 - All Events, Cased Well Depth View

Figure 9 - All Events, Open Hole Well Plan View

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Figure 10 - All Events, Open Hole Well Depth View

Figure 11 Areal Microseismic Detection Plot

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Figure 14 - Matched Fracture Geometry for the Cased Well

Figure 15 Model Pressure Match for OH Well (Stage 8)

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Figure 16 Model Pressure Match for Cased Well (Stage 2)

Figure 17 All Microseismic Events

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0

20

40

60

80

100

120

0 20 40 60 80 100 120

Days On Prod

GasRate(e3m3/d)HoursonPro

0

5

10

15

20

25

30

Gas Produced Gross (e3m3/d)

Hours On Prod

Figure 18 Open Hole Well Production History

0

20

40

60

80

100

120

0 20 40 60 80 100 120

Days on Prod

GasRate(e3m3/d)HoursonProd

0

5

10

15

20

25

30

Gas Produced Gross (e3m3/d)

Hours On Prod

Figure 19 Cased Well Production History

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Figure 20 Open Hole Well RTA Analysis Match Results

Figure 21 Cased Well RTA Analysis Match Results