01-014 mannville horizontal ngc project (final)

Project Annual Report Requirements 1

Innovative Energy Technologies Program

Project Annual Report Requirements

Quicksilver Resources Canada Inc. (“QRCI”)

QRCI Mannville Horizontal NGC Project

207 Report - Submitted June 27, 2008

1. Summary: Project status report, including a chronological report of all activities and operations conducted,

and updated incremental reserves and production.

QRCI’s original plan, as outlined in its IETP application dated March 29 of 2005, was to drill up to 5 horizontal Manville wells in 2005, 12 in 2006 and 40 in 2007. In fact, QRCI drilled 2 horizontal Mannville wells in 2005, 2 more in 2006 and drilled 5 additional horizontal wells in 2007. The chronology of activities and operations conducted to date on the 2 wells drilled in 2005 is as follows: 100/01-11-047-24W4 - Wetaskiwin

2005/06/21 Spud 2005/07/09 Rig Release 2005/07/17 Equipped 2005/07/18 Completed 2005/07/20 On Production 2006/01/29 Cleanout 2006/06/22 Surgi Frac 2006/09/06-2007/07/16- pulled down-hole equipment 5 times in this period to change bottom-hole insert pump. Pump was sanding off because of re-frac sand migration. 2007/07/17-2007/08/08- Performed 2 coil cleanouts in this period 2007/08/01-2008/03/16- Replaced bottom-hole Insert pump 6 times in this period

100/13-04-048-21W4 – Bittern Lake

2005/07/11 Spud 2005/07/30 Rig Release 2005/08/26 Equipped 2005/08/26 Completed 2005/08/10 On Production 2006/03/29 Wax Cleanout Workover 2006/11/08 Pump Change-(bottom-hole Insert pump change) 2007/09/23 Pump Change-(bottom-hole Insert pump change) 2008/02/14 Shut-in due to directive 60 (enough data gathered)

The chronology of activities and operations conducted to date on the 2 wells drilled in 2006 is as follows: 100/01-20-044-22W4 – New Norway

2006/06/25 Spud 2006/07/13 Rig Release 2007/06/07 Pull Equipment 2007/06/10 Re-Frac well 2007/06/17 Equipped- (re-run down-hole equipment, (2-3/8” tubing, 5 gas lift mandrels, and packer)). 2008/02/07 Cleanout

102/01-29-045-22W4 – New Norway

2006/07/15 Spud 2006/07/30 Rig Release 2006/12/18 Equipped- (re-run down-hole equipment, (2-3/8” tubing, 5 gas lift mandrels, and packer). 2006/12/22 On Production

The chronology of activities and operations conducted to date on the 5 wells drilled in 2007 is as follows: 102/08-20-044-22W4 – New Norway (currently listed by ERCB as 102/01-20)


2007/08/16 Spud 2007/09/06 Rig Release 2007/12/20 Installed gas lift and equipment 2007/12/20 Completed 2008/01/23 On Production

Please note that the well in New Norway with bottom hole at 102/08-20-044-22W4 was licensed and is still listed by ERCB as 102/01-20-044-22W4. This has been noted consistently throughout this report. 100/03-28-045-22W4 – New Norway


100/02-29-045-22W4 – New Norway


100/01-18-046-24W4 – Wetaskiwin

2007/03/01 Spud 2007/03/13 Rig Release 2007/08/26 Installed pump jack and equipment 2007/10/30-2008/02/07- Replaced bottom-hole pump 3 times in this period 2008/01/09 Coil cleanout 2007/08/07 Completed 2007/08/30 On Production

102/03-20-046-24W4 – Wetaskiwin

2007/07/05 Spud 2007/07/16 Rig Release 2007/12/07 Installed pump jack and equipment 2008/03/10-Current- ERCB wanted shut-in due to no control well 2007/12/08 Completed 2007/12/13 On Production

Please note that the well in New Norway with bottom hole at 100/03-20-046-24W4 was licensed as 100/01-20-046-24W4. It has recently been corrected to 100/03-20 by the ERCB. This has been noted consistently throughout this report. QRCI has not yet booked any reserves from this project.

2. Pilot data a. Data submission.

i. Geology and Geophysical data. In 2007, QRCI drilled 2 wells in a new area, Wetaskiwin, which had been identified as a priority through QRCI’s prior geological\ geophysical initiatives, and twined 2 of its existing wells at New Norway (one with one twin and the other with 2). The twin wells did not add any significant new learnings from a geological perspective. The 1-18-46-24 well did show that a location that we would not have picked using geological criteria still did OK. After 9 wells drilled, we are not convinced that the data we have available to use to choose locations is sufficient to predict which wells/areas will be successful.

ii. Laboratory studies. N/A


iii. Simulations. Nothing to add since our last submission.

iv. Pressure, temperature, and other applicable reservoir data. Nothing to add since our last submission.

v. Any other measurements, observations, tests or data pertinent to the pilot. N/A

b. Interpretation of pilot data. QRCI has developed a calibrated reservoir simulation model for the Mannville coals based on available geological, core and petrophysical data, and production performance from wells in our pilot area, as well as additional Mannville wells operated by QRCI and others. Our primary objective in developing this calibrated model was to estimate the bulk permeability of the Mannville coals. Our simulation analysis suggests that permeability in the Mannville coals ranges from less than 1.0 mD to about 20 mD, with a typical value being about 5.0 mD. We used the results from this simulation calibration process as the basis for making our predictions of how a Mannville horizontal well would perform given all the observations and interpreted reservoir conditions derived from vertical Mannville wells. The plots indicate the permeability is not what we expected. It is not clear whether this is due to wellbore damage or if the inherent rock perm is different than predicted.

3. Well information a. Well layout map.

See Appendix 3 a for a map indicating the layout of the wells.

b. Review drilling, completion and workover operations and any difficulties encountered. The Drilling plan consisted of setting surface casing down to 215 m. Setting 7" Intermediate casing HZ in the Mannville coal. QRCI dropped off a 4.5" slotted liner in the 156 mm HZ hole. We then set a whipstock assembly in the 7" intermediate and milled out the 7" intermediate casing where we drilled the sump liner hole. QRCI dropped off a 5.5" flush joint liner in the 156 mm open hole. In June 2006 QRCI contracted Halliburton to conduct a “Surgifrac” treatment on the Wetaskiwin 1-11 horizontal well. The objective of the treatment was to improve permeability by fracing the horizontal section at 10 different positions along the wellbore and place 60 tonnes of proppant. The treatment was performed and the well was placed back on test to flare. The down hole pumping equipment has failed twice since the treatment was performed due to frac sand in the pump and we have had to perform 5 bottom hole equipment changes as the result of frac sand inflow plugging the bottom-hole pump. A coiled tubing cleanout is scheduled for the well as soon as road bans are lifted. No additional treatments have been performed on the Bittern Lake 13-4 well since the last report. Drilling of 100/01-20-44-22 Surface hole was drilled to 222mMD, cased and cemented without problems. Drilled intermediate hole tp 887mMD and kicked off directionally. Build section was drilled with Floc water to 1075mMD. Mudded up to a Gypsum based drill fluid and drilled the remainder of the intermediate to 1721mMD = 1321mTVD. Problems were encountered finding the Mannville coal which in turn caused for a longer than expected intermediate section of the hole. Intermediate hole was cased into the Mannville at 90 deg with 177.8mm casing and cemented in full length. The lateral section of the hole was drilled with a 159mm bit utilizing Schlumberger’s Powerdrive RSS/Periscope. The Periscope system allowed us to stay in our thin coal seam by predicting where our upper and lower boundaries were. We reduced our drill time in the lateral by 50% (2.5 days vs 5 days in 2005) and maintained access in the coal seam 95% of the time. Previous wells drilled in 2005 could only stay in the coal seam 45-50% of the time. The lateral section was drilled to a TD of 2720mMD = 1322mTVD. Instead of using weighted brine (1230kg/m3) the entire lateral was drilled with produced Mannville water (1010kg/m3). A total of


550m3 of fluid was lost while drilling the lateral section. The lateral section was cased with 114.3mm casing and cemented with acid soluable cement. Drilling of 102/01-29-45-22 Surface hole was drilled to 220mMD, cased and cemented without problems. Drilled intermediate hole tp 880mMD and kicked off directionally. Build section was drilled with Floc water to 1100mMD. Mudded up to a Gypsum based drill fluid and drilled the remainder of the intermediate to 1410mMD = 1237mTVD. Intermediate hole was cased into the Mannville at 90 deg with 177.8mm casing and cemented in full length. The lateral section of the hole was drilled with a 159mm bit utilizing Schlumberger’s Powerdrive RSS/Periscope. The Periscope system allowed us to stay in our thin coal seam by predicting where our upper and lower boundaries were. We reduced our drill time in the lateral by 50% (2.5 days vs 5 days in 2005) and maintained access in the coal seam 99% of the time. Previous wells drilled in 2005 could only stay in the coal seam 45-50% of the time. The lateral section was drilled to a TD of 2585mMD = 1243mTVD. Instead of using weighted brine (1230kg/m3) the entire lateral was drilled with produced Mannville water (1010kg/m3). A total of 172m3 of fluid was lost while drilling the lateral section. The lateral section was cased with 114.3mm casing and cemented with acid soluble cement. Initial completion operations were conducted on New Norway 100/ 1-20 and New Norway 102/1-29 in July and August 2006. The Initial completion on these wells involved dividing the horizontal wellbore into sections and perforating, stimulating and evaluating each section individually. Perforating guns were either conveyed to their position with a well tractor or run on jointed tubing. Sections of the well were isolated by a composite bridge plug after they were evaluated and then the bridge plugs were drilled out previous to putting the well on production. A number of stimulation techniques were performed on the wells including, pumping a gelled water frac with proppant down casing, pumping a nitrogen frac down casing with perf balls to divert flow, and fracing each set of perforations individually with nitrogen pumped down coiled tubing. Both wells were equipped with gas lift mandrels for production. In June of 2007 a produced water re-frac was performed on New Norway 100/1-20. Initially the treatment was attempted to be pumped down coiled tubing but high break down and friction pressures dictated that the job be pumped down the casing. Filtered Mannville produced water and proppant was used for this treatment, there were no chemicals added. The well is now back on production for evaluation. Five wells were completed in the remainder of 2007. Each well had a liner in the horizontal section. The liner was cement in place on four of the five wells, the fifth had a liner in place but it was not cemented due to technical difficulties. The completion of each well varied mainly because of the quality of the cement surrounding the horizontal liner. A discussion of each completion follows. 102/8-20-44-22W4 A 114.3mm liner was run into the well with the drilling rig with the intention of cementing it in place however, circulation could not be established and the liner was left un-cemented. A Surgifrac treatment was performed on this well at ten locations along the horizontal liner. 3.5 tonnes of 40/70 sand was pumped into each location, the fluid used was Mannville produced water with friction reducer to lower the pumping pressure down the coiled tubing. Well was equipped with gas lift mandrels to de-water the well. 100/3-28-45-22W4 A cement bond log was run and indicated good cement from 2180m to the toe at 2650m but showed that the cement was channelled from 2180m to the heel of the well. This well was also perforated and stimulated in three sections. Perf guns were conveyed into the well using a well tractor, the fracs were programmed to, and successfully placed +/- 8 tonnes of lightweight proppant in each interval. Fluid was Mannville produced water with no gel. There was a failure at a collar in the horizontal liner during the first frac, otherwise operations went well. The well was swab evaluated at +/- 30m3/day. Gas lift mandrels were run to equip well for de-watering. 100/2-29-45-22W4 A cement bond log was run and indicated good cement from 1975m to the toe at 2577m but showed that cement was channelled from 1975m to the heel. This well was perforated and stimulated in three sections. The first two intervals were perforated using a well tractor to convey the guns to position. The third section was tubing conveyed due to a partial obstruction in the casing that wouldn’t let the


tractor pass through. The frac treatments were programmed to pump 8 tonnes of lightweight proppant in Mannville produced water without any gel, however we were only able to place +/- 4 tonnes in each section before we reached our pressure limitations. Well was swab tested at +/- 35m3 /day. Gas lift mandrels were run to equip wells for de-watering. 100/1-18-46-24W4 A cement bond log was run and indicated good cement throughout the length of the horizontal section. The well was perforated and stimulated in three sections. Tubing conveyed perforating was used in this well with one section at a time being perforated and fraced. The frac treatments were programmed to place 17 tonnes of 40/70 sand with Mannville produced water as a carrying medium with no gel in the fluid. We were only able to place +/- 9 tonnes in each section before we reached our pressure limitations. Our swab evaluation indicated a water inflow rate of +/- 40m3 /day. Well was equipped with a sand screen and an insert pump was run on sucker rods to de-water the well. 100/3-20-46-24W4 (also known as 100/01-20) A cement bond was run and indicated good cement from 2150m to the toe at 2450m but, very poor cement from 2150m to the heel. The cemented section was perforated by conveying guns with a well tractor. This section was then fraced , and, 4.7 tonnes of lightweight proppant was placed. A Surifrac treatment was performed on the remaining un-cemented section. Ten locations were stimulated and 3.5 tonnes of 40/70 sand was placed in each interval. Friction reducer was added to lower pumping pressures down the coiled tubing. A sand screen was run on tubing and well was equipped with a pump and rods to de-water well.

c. Well operation. i. Well list and status.

100/01-11-047-24W4/00 – Producing, on production date: 20-Jul-05 100/13-04-048-21W4/00 – Shut in, on production date: 10-Aug-05 100/01-20-044-22W4/00 – Producing, on production date: 03-Dec-06 102/01-29-045-22W4/00 – Producing, on production date: 12-Dec-06 102/08-20-044-22W4/00 – Producing, on production date: 23-Jan-08 (also known as 102/01-20) 100/03-28-045-22W4/00 – Producing, on production date: 13-Dec-07 100/02-29-045-22W4/00 – Producing, on production date: 13-Dec-07 100/01-18-046-24W4/00 – Producing, on production date: 30-Aug-07 100/03-20-046-24W4/00 – Shut in, on production date: 13-Dec-07 (also known as 100/01-20)

ii. Wellbore schematics. See Appendix 3 c ii

iii. Spacing and pattern.

Wells are single-well horizontals. Orientations are: (A) 100/01-11-047-24W4/00 east-southeast from 12-11 to 01-11 (B) 100/01-20-044-22W4/00 southeast from 13-20 to 01-20 (C) 102/01-29-045-22W4/00 south from 16-29 to 01-29 (D) 102/08-20-044-22W4/00 southeast from 13-20 to 08-20 (also known as 102/01-20) (E) 100/03-28-045-22W4/00 southeast from 16-29 to 03-28 (F) 100/02-29-045-22W4/00 southwest from 16-29 to 02-29 (G) 100/01-18-046-24W4/00 southeast from 14-18 to 01-18 (H) 100/03-20-046-24W4/00 south from 16-20 to 01-20 (also known as 100/01-20) Well (D) is a twin to well (B) and wells (E) and (F) are twins to well (C). See Appendix 3 a for a map indicating the well layout

4. Production performance and data a. Injection and production history on an individual well and composite basis.

100/1-11-47-24W4 Stabilized H2O production rate: 8.0 m3/day


Stabilized Gas production rate: 2.0 e3m3/day Cumulative H2O production: 2,700 m3 Cumulative Gas production: 1,209 e3m3 100/13-4-48-21W4 Stabilized H2O production rate: 4.5 m3/day Stabilized Gas production rate: 1.1 e3m3/day Cumulative H2O production: 4,487 m3 Cumulative Gas production: 791 e3m3 100/1-20-44-22W4 Stabilized H2O production rate: 10.0 m3/day Stabilized Gas production rate: 2.1 e3m3/day Cumulative H2O production: 5,451 m3 Cumulative Gas production: 965 e3m3 100/1-29-45-22W4 Stabilized H2O production rate: 2.0 m3/day Stabilized Gas production rate: 1.4 e3m3/day Cumulative H2O production: 1,679 m3 Cumulative Gas production: 609 e3m3 102/08-20-44-22W4 (also known as 102/01-20) Stabilized H2O production rate: 14.0 m3/day Stabilized Gas production rate: 1.0 e3m3/day Cumulative H2O production: 648 m3 Cumulative Gas production: 32 e3m3 100/03-28-045-22W4 Stabilized H2O production rate: 10 m3/day Stabilized Gas production rate: 2.7 e3m3/day Cumulative H2O production: 901 m3 Cumulative Gas production: 262 e3m3 100/02-29-045-22W4 Stabilized H2O production rate: 8.0 m3/day Stabilized Gas production rate: 2.1 e3m3/day Cumulative H2O production: 1,443 m3 Cumulative Gas production: 247 e3m3 100/01-18-046-24W4 Stabilized H2O production rate: 20.0 m3/day Stabilized Gas production rate: 4.3 e3m3/day Cumulative H2O production: 4550 m3 Cumulative Gas production: 690 e3m3 100/03-20-046-24W4 (also known as 100/01-20) Stabilized H2O production rate: 11.0 m3/day Stabilized Gas production rate: 2.1 e3m3/day Cumulative H2O production: 1,279 m3 Cumulative Gas production: 117 e3m3 See Appendix 4 a for production plots.

b. Composition of produced / injected fluids. See Appendix 4 b for gas, water, scale, and wax analyses

c. Comparison of predicted versus actual well / pilot performance and a discussion regarding the difference.


In its IETP application, QRCI anticipated that it would experience producing rates from the wells of up to 500 mcf/d of gas and 800 bbl/d of water. In fact, the wells have peaked and/or stabilized at rates significantly below significantly below expectations based on our reservoir simulations. Please see Appendix 4 a for production plots. There are a number of potential reasons why our horizontal wells have not meet expectations, including, but not limited to: coal fines plugging permeability, hydrostatic pressure on formation, unsuccessful frac’s. i. Lower-than-expected formation permeability

ii. Near-wellbore damage caused by drilling and completion operations. Because these wells were cased and cemented it would suggest that a certain amount of damage would have occurred with cement invasion into the coal reservoir. Subsequently, because they were cased and cemented, we were able to isolate different sections of the seam to fracture past any damage. It appeared from the evaluations that the N2 frac’d zones performed better than the zones that had been frac’d with polymer fluids. The productivity of the 2007 wells are similar to the 2006 wells with no defined improvement with any of the different completion techniques. The well that is showing the best productivity is the 100/1-18-46-24W4 well, and it showed signs of being fractured or having high perm when it was being drilled as there was a large volume of fluid lost to the formation.

iii. Unidentified relative permeability effects iv. Wellbore hydraulics issues, resulting in a low effective lateral length Some of these issues relate to making better a-priori location selections, assuming that we can develop a process that can predict better formation permeability. The study performed by United attempted to address this issue, among others. Results to date do not support the reliance upon the United study to select locations. The remaining issues relate to the development of best practices (drilling, completion, production), which should improve as we drill additional wells and derive key learnings from those results. Cementing the liner and perforating gives us a better control in directing the stimulation treatments down the whole length of the wellbore. For its 2007 horizontal Mannville activity QRCI tested one additional region and tested the impact of twinning existing wells with 1 and 2-well twin pilots.

d. History of injection, production and observation well pressures and average reservoir pressure. As a result of the constant producing casing pressure and fluid level, there appears to be little reservoir pressure depletion at this point.

5. Pilot economics to date

a. Sales volumes of natural gas and by-products. Sales volumes are nil from wells drilled in 2005 as all produced gas from Wetaskiwin well 100/01-11-047-24W4 is being flared and Bittern Lake well 100/13-04-048-21W4 is shut in. Wells drilled in 2006 are producing to our gathering system and are being compressed to sales. Wells drilled in 2007: New Norway wells 102/08-20-044-22W4 (also known as 102/01-20), 100/03-28-045-22W4 and 100/02-29-045-22W4 are being compressed to sales, Wetaskiwin well 100/01-18-046-24W4 is being flared and Wetaskiwin well 100/03-20-046-24W4 (also known as 100/01-20) is shut in. See Appendix 4 a for production plots.

b. Capital costs (include a listing of items with installed cost greater than $10,000). Please see attached Appendix 5 for capital and operating statement information.

c. Direct and indirect operating costs by category (e.g. fuel, injectant costs, electricity). Please see attached Appendix 5 for capital and operating statement information.

d. Crown royalties, applicable freehold royalties, and taxes. Please see attached Appendix 5 for capital and operating statement information.

e. Cash flow.


Please see attached Appendix 5 for capital and operating statement information.

f. Cumulative project costs and net revenue. Please see attached Appendix 5 for capital and operating statement information.

g. Explanation of material deviations from budgeted costs. Please see attached Appendix 5 for capital and operating statement information.

6. Facilities

a. Description of major capital items (including new facilities and additions /modifications to existing facilities). 100/1-11-47-27W4 - 912 Pump Jack system - Generator Package - 2PH-860 kPa Separator (0.61m x 1.52m) - Flare Stack - 2 x 400 bbl production tanks - Meter Run - 2-7/8” Well head - 1,270 m of 2-7/8” tubing - 1,260 m ¾” rod string - 2” bottom hole insert pump 100/13-4-48-21W4 - 640 Pump Jack system - 2PH-860 kPa Separator (0.61m x 1.52m) - Incinerator - 2 x 400 bbl production tanks - Meter Run - 2-7/8” Well head - 1,210 m of 2-7/8” tubing - 1,200 m ¾” rod string - 1-1/2” bottom hole insert pump

100/01-20-44-22W4 - 185 HP screw compressor - 95HP reciprocating compressor - Weatherford gas lift system w/mandrels - 3 x 400 bbl production tanks (at 13-20 padsite) - Meter Run - 2-3/8” Well head - 1,652 m of 2-3/8” tubing

102/01-29-45-22W4 - 95HP screw compressor - 95HP reciprocating compressor - Weatherford gas lift system w/mandrels - 4 x 400 bbl production tanks (at 16-29 padsite) - Meter Run - 2-3/8” Well head - 1,373 m of 2-3/8” tubing

102/08-20-044-22W4/00 (also known as 102/01-20)


- 185 HP reciprocating compressor - Schlumberger gas lift system w/mandrels - 3 x 400 bbl production tanks (at 13-20 padsite) - Meter Run - 2-3/8” Well head - xxxx m of 2-3/8” tubing

100/03-28-045-22W4/00 - 95 HP reciprocating compressor - Weatherford gas lift system w/mandrels - 4 x 400 bbl production tanks (at 16-29 padsite) - Meter Run - 2-3/8” Well head - xxxx m of 2-3/8” tubing

100/02-29-045-22W4/00 - 95 HP reciprocating compressor - Weatherford gas lift system w/mandrels - 4 x 400 bbl production tanks (at 16-29 padsite) - Meter Run - 2-3/8” Well head - xxxx m of 2-3/8” tubing

100/01-18-046-24W4/00 – VSH2 hydraulic jack – Nitrogen-over-hydraluic pumping skid – 3 x 400 bbl production tanks – Incinerator – Meter Run 100/03-20-046-24W4/00 (also known as 100/01-20) – VSH2 hydraulic jack – Nitrogen-over-hydraluic pumping skid – 2 x 400 bbl production tanks – Incinerator – Meter Run

b. Capacity limitation, operational issues, and equipment integrity. QRCI has experienced no capacity issues as of yet. Being that the two wells are not tied into a gathering system, capacity issues such as high line pressures, line liquid loading, and compression facility capacity are not present at this time. The only significant operational issues encountered as of yet, were the production of down hole wax and some forming of scale on our bottom hole pump barrel. While performing a standard pump change with the intent of remedying what appeared to be a plugged / damaged pump, QRCI discovered that the pump and some of the rod strings were covered in a produced waxy substance (see attached wax analysis). To address the issue, we pulled all of our equipment of the wellbore and flushed the horizontal leg with a chemical to breakdown and flush out the wax. The well has since been put back on production and appears to be pumping normally. In another case, QRCI experienced a separate inability to pump fluids. Upon retrieval of the pump on surface, QRCI noticed that the pump failure was a result of a hole in the pump barrel. After further equipment inspection, QRCI noticed that there was some scale present on the pump barrel as well (see attached scale analysis).


c. Process flow and site diagram identifying major facilities, including production equipment, connected pipelines, gathering and compression facilities. See Appendix 6 c for a diagram of major facilities

7. Environment/Regulatory/Compliance a. Summary of project regulatory requirements and compliance status.

QRCI has been and is in compliance with all project regulatory requirements.

b. Procedures to address environmental and safety issues. There are no known environmental or safety issues to be addressed.

c. Plan for shut-down and environmental clean-up There are no immediate plans to shut in any of the wells for environmental cleanup.

8. Future operating plan

a. Project schedule update including deliverables and milestones. QRCI has no plans to drill additional horizontal Mannville CBM wells at present. QRCI will continue to produce existing wells to assess productive capability.

b. Changes in pilot operation, including production operations, injection process, and cost optimization strategies. The operation strategy for 2007 and beyond is to continue to produce our New Norway Wells to sales using gas lift and to flare other production where possible.

c. Salvage update QRCI has not yet salvaged any of the equipment from its horizontal Mannville program, nor does it have any current salvage plans.

9. Interpretations and Conclusions An assessment of the overall performance of the pilot, including: a. Lessons learned.

The results of QRCI’s Mannville horizontal well program have come in below expectations relative to our reservoir simulation models. There are a number of potential reasons why our horizontal wells drilled through 2007 did not meet expectations, including, but not limited to:

i. Lower-than-expected formation permeability ii. Unidentified relative permeability effects

iii. Experienced some lube oil entering annulus via gas lift - solved by adding filtration. iv. Gas lift system limited to 100 - 150 psi bottom hole pressures.

These reasons, and/or others yet unidentified, and probably in combination, make the Mannville a complex and difficult problem to solve. QRCI continues to address the previously identified issue “the development of best practices for drilling, completion and production that will yield the best possible Mannville coal well”.

b. Difficulties encountered. 01-11-047-24W4 Drilling The well was originally AFE'd for 12 days. Actual time was 18 days due to

• an extra 1/2 day rigging up top drive,

• numerous motor failures while drilling the intermediate hole,


• the build section drilled much slower than expected (1 day longer),

• the EUB required us to log the intermediate hole with drill pipe (lost 1 day),

• top drive failures (1/2 day),

• staged the cement job for intermediate section,

• EM tool failures while drilling horizontal section,

• longer amount of time drilling the sump section of the hole than anticipated

• unplanned gyro surveys for sump section of the hole.

Completions\Operations QRCI had to perform an unplanned chemical flush to clean out the horizontal section. The “Surgifrac” treatment that was performed required considerably more fluid than was anticipated due to the high leak-off near the heel of the well. The insert pump that we are using has been seized twice by frac sand necessitating a pump change and a coiled tubing clean out. 13-04-048-21W4 Drilling Well was originally AFE'd for 12 days. Actual time was 21 days due to problems encountered in the horizontal section. Directional tools were lost as a result of getting stuck. Completions\Operations QRCI had to perform an unplanned chemical flush to clean out a wax build-up in the horizontal section. 01-20-044-22W4 Drilling Well was AFE’d for 14 days but actually took 19 days. Extended days were due to the Mannville formation coming in at a lower TVD than predicted. 3 days were spent looking for the Mannville. Problems were also encountered after cementing the lateral section. The well was programmed so we could rotate off the top of the lateral liner to allow our production pumping to be done from the 177.8mm casing. Because of rig problems we were unable to rotate off the Monobore Liner system to circulate any cement from the liner top. Therefore our casing above our liner top was cemented in.

Completions\Operations The completion operations went relatively smoothly, there were a couple of mechanical failures that resulted in additional rig days, confirming exact coiled tubing depth in the horizontal was a challenge, and a questionable piece of metal that was dropped in the well (possibly sabotage) that required a fishing job. 01-29-045-22W4 Drilling Well was AFE’d for 14 days but drilled in 16 days. The only problems encountered was during the cementing operation with the lateral liner. Because of equipment problems while cementing the cement density was not mixed at the programmed weight. Bond log revealed it was still good cement.

Completions\Operations Completion operations went smoothly. 102/08-20-044-22W4 (also known as 102/01-20) Drilling Well AFE’d for 14 days, but drilled in 21days. The problem encountered was that we were not able to run the liner in to the lateral section due to poor hole conditions caused by excessive directional changes in the lateral section. A whipstock assembly was then run in the intermediate casing, and a window was milled out at a depth 1513.36mMD. A side track hole was then drilled at a distance of 150m beside the original HZ hole to a depth of 2632mMD. A 4.5” liner was then run in the side track hole to a depth of 2551mMD where the liner became stuck. We were unable to break circulation on the liner, and therefore could not cement the liner in place.


Completions\Operations Completion operations went smoothly 100/03-28-045-22W4 Drilling Well was AFE’d for 14 days but drilled in 17 days. No problems with this well.

Completions\Operations A collar in the liner parted on our first frac, the toe section of the well is now not accessible with tubulars. 100/02-29-045-22W4 Drilling Well was AFE’d for 14 days but drilled in 12 days. No problems with this well.

Completions\Operations There is a minor obstruction in the horizontal liner that prevented the last set of guns from being conveyed with the tractor, otherwise, completion went well. 100/01-18-046-24W4 Drilling Well was AFE’d for 14 days but drilled in 12 days. No problems with this well.

Completions\Operations Completion operations went well. 100/03-20-046-24W4 (also known as 100/01-20) Drilling Well was AFE’d for 14 days but drilled in 11 days. No problems with this well.

Completions\Operations Part of the liner was un-cemented, necessitating a deviation from our typical completion technique. The toe section was perforated and fraced down casing and the un-cemented section had a Surgifrac performed.

c. Technical and economic viability. QRCI’s 9 well program to date has not demonstrated sufficient technical or economic viability and QRCI has no further drilling plans for its Mannville CBM mineral interests.

d. Overall effect on overall gas and bitumen recovery. Nil.

e. Assessment of future expansion or commercial field application and discussion of reasons. QRCI will continue to produce gas from its Horizontal Mannville CBM program where possible and practical to evaluate potential commercial viability. QRCI currently has no plans to expand its Horizontal Mannville CBM drilling program.


Appendix 3 a

Well Layout


Appendix 3 c ii

Well plans for the following 2007 well to follow under separate cover

102/08-20-44-22W4 (also known as 102/01-20)

100/03-28-45-22W4

100/02-29-45-22W4

100/01-18-46-24W4

100/03-20-46-24W4 (also known as 100/01-20)


Appendix 4a

Production Plots

100/01-11-047-24W4 Production Chart

0

1

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ul-05

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Fluid Level (MD ft from Surface)

Top of Sump Depth: 3,995 ft-MD

Horizontal Scetion Depth: 4,487 ft-MDBack to

Summary page


Appendix 4a Cont’d

Production Plots

100/13-04-048-21W4 Flow Test Chart

11

01

00

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00

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-05

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-05

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Top of Sump Depth: 3,707 ft-MD

Horizontal Scetion Depth: 4,149 ft-MDBack to

Summary page

Well shut-in Feb 15/08

to comply with Directive 60



Production Plots


1

10

100

1,000

Dec-06 Jan-07 Feb-07 Mar-07 Apr-07 May-07 Jun-07 Jul-07 Jul-07 Aug-07 Sep-07 Oct-07 Nov-07 Dec-07 Jan-08 Feb-08 Mar-08 Apr-08 May-08 Jun-08

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(b

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Back to

Summary page



Production Plots


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Dec-06 Jan-07 Feb-07 Mar-07 Apr-07 May-07 Jun-07 Jul-07 Aug-07 Sep-07 Oct-07 Nov-07 Dec-07 Jan-08 Feb-08 Mar-08 Apr-08 May-08 Jun-08

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ter

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Back to

Summary page



Production Plots


1

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Jan-08 Feb-08 Mar-08 Apr-08 May-08 Jun-08

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(b

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(M

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)

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Back to

Summary page



Production Plots


1

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Dec-07 Jan-08 Feb-08 Mar-08 Apr-08 May-08 Jun-08

Date

Wa

ter

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te (

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ls)

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(M

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Back to

Summary page



Production Plots


1

10

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1,000

Aug-07 Sep-07 Oct-07 Nov-07 Dec-07 Jan-08 Feb-08 Mar-08 Apr-08 May-08 Jun-08

Date

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om

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e)

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Back to

Summary page



Production Plots


1

10

100

1,000

Dec-06 Jan-07 Feb-07 Mar-07 Apr-07 May-07 Jun-07 Jul-07 Jul-07 Aug-07 Sep-07 Oct-07 Nov-07 Dec-07 Jan-08 Feb-08 Mar-08 Apr-08 May-08 Jun-08

Date

Wate

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ate

(b

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Ga

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(M

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Gas Rate (Mscf/d)

Back to

Summary page


Appendix 4 b

Gas & Water Analyses

102/08-20-44-22W4 (also known as 102/01-20)

100/03-28-45-22W4

100/02-29-45-22W4

None to Report


Appendix 4 b cont’d

Gas & Water Analyses 100/01-18-46-24W4



Gas & Water Analyses 100/01-18-46-24W4



Gas & Water Analyses 100/03-20-46-24W4 (also known as 100/01-20)


Appendix 5

Capital and Operating Statements

Horizontal Mannville Capital Cost Estimates

AFE # AFE Type Initial Estimate Supplements Note* Total Estimate

2005 Program

100/01-11-047-24W4 - Wetaskiwin

3027705 Drilling 733,000.00 805,065.00 1 1,538,065.004040205 Completion 66,341.00 192,390.00 2 258,731.00

5002105 Equipping 298,435.00 298,435.005002205 Capitalized Op Costs 284,245.00 591,201.00 3 875,446.006000406 Recompletion 458,520.00 350,470.00 4 808,990.00

6001007 Recompletion 89,240.00 257,393.19 5 346,633.191,929,781.00 2,196,519.19 4,126,300.19

100/13-04-048-21W4 – Bittern Lake

3030805 Drilling 733,000.00 1,181,700.00 6 1,914,700.005004005 Equipping 298,435.00 80,100.00 7 378,535.00

5004105 Capitalized Op Costs 284,245.00 436,372.50 8 720,617.506000106 Recompletion 103,520.00 125,000.00 9 228,520.00

1,419,200.00 1,823,172.50 3,242,372.50

2006 Program

100/01-20-044-22W4 – New Norway

3035706 Drilling 1,501,765.16 530,238.00 10 2,032,003.16

4023806 Completion 475,690.00 989,800.00 11 1,465,490.005005906 Equipping 307,505.00 307,505.005006406 Capitalized Op Costs 416,827.00 416,827.00

2,701,787.16 1,520,038.00 4,221,825.16

102/01-29-045-22W4 – New Norway

3035506 Drilling 1,501,765.16 300,640.00 12 1,802,405.164023606 Completion 475,690.00 729,900.00 13 1,205,590.005005706 Equipping 272,155.00 272,155.00

5006206 Capitalized Op Costs 405,677.00 405,677.002,655,287.16 1,030,540.00 3,685,827.16

2007 Program

102/08-20-44-22W4 - New Norway

3004007 Drilling 1,499,628.00 466,590.00 14 1,966,218.004008507 Completion 725,160.00 725,160.005003107 Equipping 207,505.00 207,505.00

5007507 Capitalized Op Costs 352,827.00 352,827.002,785,120.00 466,590.00 3,251,710.00

100/03-28-45-22W4 - New Norway

3004107 Drilling 1,499,628.00 1,499,628.004008607 Completion 725,160.00 332,795.00 15 1,057,955.00

5002907 Equipping 207,505.00 207,505.005003007 Capitalized Op Costs 352,827.00 352,827.00

2,785,120.00 332,795.00 3,117,915.00

100/02-29-45-22W4 - New Norway

3004207 Drilling 1,499,628.00 1,499,628.004008707 Completion 725,160.00 725,160.005008107 Equipping 207,505.00 207,505.00

5008207 Capitalized Op Costs 352,827.00 352,827.002,785,120.00 0.00 2,785,120.00

100/01-18-46-24W4 - Wetaskiwin

3003907 Drilling 1,499,628.00 191,092.00 16 1,690,720.004005507 Completion 725,160.00 105,040.00 17 830,200.00

5007107 Equipping 288,870.00 288,870.005007307 Capitalized Op Costs 296,637.40 296,637.40

2,810,295.40 296,132.00 3,106,427.40

100/01-20-46-24W4 - Wetaskiwin

3035806 Drilling 1,499,628.00 1,499,628.00

4008807 Completion 725,160.00 356,530.00 18 1,081,690.005007207 Equipping 288,870.00 288,870.005007407 Capitalized Op Costs 296,637.40 296,637.40

2,810,295.40 356,530.00 3,166,825.40


Appendix 5 Cont’d


Horizontal Mannville Capital Cost Estimates

Supplemental Cost Notes:

1 Well was originally AFE'd for 12 days. Actual time was 18 days due to the following issues: Extra 1/2 day rigging

up topdrive. Numberous motor failures while drilling intermediate hole. Build section drill much slower than

expected (1 day longer) EUB required us to log the intermediate hole with drill pipe (lost 1 day). Lost 1/2 day with

topdrive failures. Staged the cement job for intermediate section. EM tool failures while drilling horizontal section.

Longer amount of time drilling the sump section of the hole than anticipated. Unplanned gyro surveys for sump

section of the hole.

2 This AFE is required to pull the pump and sump liner, run in with tubing and clean out the Hz section, and re-run

the liner and pump.

The original cost estimate did not include a chemical squeeze or coil tubing cleanout to the toe of the well. An

extra 8 days of rig time was required for swabbing and build up testing.

3 The capital funds allocated in the original AFE was to cover all operating costs of producing our Mannville Hz

CBM 100/01-11-047-24W4 for a 6 month period. Supplements were requiered to add 24 months of captalized

operating costs.

4 Funds are required for a "Surgi Frac" stimulation on hz MNVL CBM well. Supplemental Funds are required. Complicated well conditions resulted in the need for large quantities of

additional fluid and two days of extra time to complete the procedure.

5 These funds will cover the cost of performing a N2 coil tubing cleanout on our Hz MNVL CBM well: 100/01-11-047-

24W4/00.

Supplement Justification: This AFE was for 1 coil cleanout for the 1-11 well to restore production of the well due to

sand buildup from the frac due to flowing the well. Subsequently there were 4 more cleanouts done.

6 Reason for Supplements: Well was originally AFE'd for 12 days. Actual time was 21 days due to problems

encountered in the horizontal section. Directional tools were lost as a result of getting stuck. Additional excessive

hole problems caused high cost overruns.

7 The majoity of these supplemental funds (93%) are to cover the costs of the material transfer costs of 3 x 400 bbl

production tanks ($75,000). Being that the tanks were in QRCI inventory, the costs were not included from the

cost estimate.

8 Supplement 1 Explanation:

The capital funds allocated in the original AFE were to cover all operating costs of producing our Mannville Hz

CBM well: 100/13-04-048-21W4 for a 6 month period. As of March 31st, the well has been producing for a total

of 19 months (13 months longer than originally AFE'd for). Therefore, the supplemental capital is to cover this

additional 13 months of operating expenses and pump change workovers.

Supplement 2 Explanation:

The previous capital funds allocated for this AFE were to cover operating costs of the experimental horizontal well

up to March 31/07. Since then, the well has been operating for an additional 10 months. The supplemental

capital funds are therefore to cover these last 10 months of operating expenses as well as 6 months going

forward - up until June 30/08. Please refer to the Estimate tab for a breakdown of supplemented costs. This

supplement also includes costs required for the purchase of a flare stack for the well - this will remove the

9 This operation entails pulling the rod string, BHP, tubing, and sump liner with a service rig. The intent is to run in

the hole with coil tubing and perforam a chemical flush / cleanout on the horizontal lateral to eliminate the wax

accumulation.

AFE Supplement is required due to overexpenditure. A scope change in the project as well as a fishing job

resulted in the overexpenditure.

10 Supplement 1: Long rig move and rig up time due to brand new rig. Drilled for three extra days on intermediate

hole due to geological reasons. High construction costs due to wet conditions, required extra stripping and lease

preperation.

Supplement 2: Well was drilled directional and took more time than anticipated thus increasing service and day

rate costs. Not originally AFE'd for core.

11 Scope of completion program changed from the initial AFE. Additional swab evaluation was required, and a

fishing job contributed to the overexpenditure.

12 Rig moving costs higher then AFE'd for due to size of rig, and rig availablity. Also charged for de-mob on this well

as it was drilled after 2-20HZ. Directional costs higher then Afe'd for due to cost of running specialized directional

tools (PerriScope tool).

13 Scope of completion program changed from original.

14 Well became unstable while running casing, had to side track.

15 Overexpenditure due to change in fracture procedures and efforts to repair parted casing in horizontal section of

wellbore.

16 Very high construction costs due to rush to get on location, and very soft and wet conditions. Higher then

expected directional and geological supervision costs.

17 Overexpenditure caused by lost circulation and hole cleaning problems after frac treatments.

18 Overexpenditures related to various problems that occurred during the well completion. CBL indicated that most

of the liner was not cemented, a Surgifrac was done to stimulate the uncemented section, a casing frac was done

on the cemented section. Two fishing operations were required and a leak at the liner top necessitated running

isolation tools to identify leak source. Considerable rental costs were incurred waiting on Halliburton frac crew and

contuously re-heating frac fluid.


Appendix 5 Cont’d


Please see attached file [] for accounting detail statements.


Appendix 5 Cont’d



Appendix 5 Cont’d


100/13-04-048-21W4/00

No Operating Summary Information to report.


Appendix 5 Cont’d



Appendix 5 Cont’d


102/08-20-044-22W4/00 (also known as 102/01-20)



Appendix 5 Cont’d


100/03-28-045-22W4/00



Appendix 5 Cont’d


100/02-29-045-22W4/00



Appendix 5 Cont’d



Appendix 5 Cont’d


100/03-20-046-24W4/00 (also known as 100/01-20)



Appendix 6 c

Major Facilities Diagram

Flaring Scheme


Appendix 6 c

Major Facilities Diagram

Gas Lift Scheme

[To follow under separate cover]

01-014 mannville horizontal ngc project (final)

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