Programa Therma Source

SP-02 Drilling Handbook Domo San Pedro Project

Designed and Prepared By:

Enal Drilling Program

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3883 Airway Drive Suite 340

Santa Rosa, CA 95403 TELEPHONE: (707) 523-2960

Drilling Program

Operating Company Enal

Field Domo San Pedro

Well SP-02

Location Nayarit, Mexico

Well Type Directional Production Well

Drilling Engineer Louis Capuano III

Date of Issue August 19, 2011

Signature Date

Prepared Louis Capuano III

Drilling Engineer ThermaSource Inc.

Reviewed Salvador Espindola

Technical Director Energías Alternas, Estudios y Proyectos S.A. de C.V.


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Table of Contents

Section:

A. General Well Information B. Surface Drilling Program C. Intermediate 1 Drilling Program D. Intermediate 2 Drilling Program E. Production Drilling Program F. BOP Wellhead Diagrams G. Directional Well Plan H. Geologic Well Plan and Site Map I. Preliminary Well Cost Estimate J. Lost Circulation Cementing Procedure K. Well Kill Procedure L. Top Job Cementing Procedure M. Leak-Off Procedure N. Blind Drilling Procedure O. Logging Procedure


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Section A: General Well Information

Well Information Table

Domo San Pedro SP-02

Location Nayarit, Mexico

Elevation GL: 1337.5 m

KB: 7.12 m

Planned Days 52 days

Final Total Depth 2124

Surface Coordinates 21˚11’06.51”N, 104˚43’20.87”W

Bottom Hole Target 410.6 m S and 410.6m W from the surface location

Target Zone: Granitic Intrusion

Section Depth Interval

Casing OH MD TVD

40” 6 m 6 m 30”, 98.9 ppf, Line Pipe, Welded pipe

26” 100 m 100 m 20”, 94 ppf, K-55, BTC

17-1/2” 300 m 300 m 13-3/8”, 68 ppf, K-55 BTC

12-1/4” 1020 m 1000 m 9-5/8”, 47 ppf, L-80, Tenaris

8-1/2” 2124 m 2000 m 7”, 29 ppf, L-80, Slotted Liner w/ TOL at 970 m MD.

Wellhead Information

Flange Size Pressure Test (psi)

20” SOW x API 21-1/4”, 2M 250 / 1000

13-3/8” SOW x 13-5/8” 3M Casing Head

(must have a minimum bore of 12-3/8”)

250 / 2000

API 13-5/8”, 3M x 10” ANSI 900 Series Expansion Spool. 250 / 2000

10” ANSI 900 Series Through Conduit Expanding Gate Valve. 250 / 2000


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Overview: SP-02 will be drilled as a directional production well. The well is to be drilled from surface to a True Vertical Depth of 2000 m. The directional drilling is intended to encounter a reservoir that lies below the San Pedro Dome. The well will be drilled vertically until the kick off point at 600 m is reached. At that time a directional drilling assembly will be used to build an angle of 25 degrees of inclination toward an azimuth of 225 degrees. Once 25 degrees is obtained, the rig will hold direction and inclination until TD. The rig should expect to encounter granitic formations at 1000 m. This granitic formation can be considered as the reservoir formation. An approximate surface formation temperature of 20˚C is to be expected. The temperature should rise approximately 15˚C/100m. The estimated reservoir temperature is 200˚C. Before the rig arrives on location, the 30” conductor pipe will be set at 6m TVD in a 40” open hole. The 20” surface casing will be set at 100 m in a 26” open hole. The 13-3/8” intermediate casing will be set at 300 m in a 17-1/2” open hole. The 9-5/8” cemented production casing will be set at 1000 m in a 12-1/4” open hole and will be the final casing cemented to the surface. The 8-1/2” hole section will be drilled to 2000 m while maintaining 25 degrees of inclination. The separation between bottom hole location and the vertical will be 580 m. The well will be completed with a 7” slotted liner hung at 970 m. Safety, Hazards and Special Considerations: Surface Hole The surface section of any well is designed to withstand subsurface pressures that may be encountered while drilling to the next casing point. The 20” casing that will be installed in the 26” open hole will withstand any pressures that may be encountered while drilling the 17-1/2” hole section to 300 m. From offset well data, it is recognized that the formations that will be encountered will consist primarily of rhyolite volcanics. There has been some evidence of some obsidian in certain wells in the area. The 26” hole section should be drilled using a mud motor in order to increase the rate of penetration. There has been no sign of lost circulation in this upper section of the wellbore. However it is critical to be prepared to cure losses. The rig should attempt to cure the upper loss zones with LCM before trying to pump a lost circulation cement plug. Intermediate Hole 1 This intermediate hole section and casing is designed to withstand any subsurface pressures that may be encountered while drilling the 12-1/4” hole section. It is likely to encounter dacites, rhyolites and obsidian in this hole section. These formations are known to have some fractures that may cause lost circulation. The rig should attempt to cure the upper loss zones with LCM before trying to pump a lost circulation cement plug.


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Intermediate Hole 2 The 9-5/8” casing string will be the final casing string cemented to the surface. It has been designed to withstand any formation pressure that will be encountered while drilling to TD. It is likely to encounter dacites and rhyolites in this hole section. These formations are known to have some fractures that may cause lost circulation. The rig should attempt to cure the upper loss zones with LCM before trying to pump a lost circulation cement plug. The 12-1/4” hole section will be drilled vertically to a depth of 600 m, at which time the rig will pull out of the hole and run in with a directional assembly. The directional drilling assembly will begin building angle at 2.5˚ per 30 m until 25˚ of inclination is achieved. The well will be directed in a 225˚ azimuth toward the dome. It should take approximately 300 m to build the required 25˚. Once this has occurred the rig will hold the 25˚ of inclination and 225˚ of azimuth until the casing point of 1000 m TVD (1020 MD) is achieved. Production Hole The 8-1/2” hole section will be the final hole section in the well design. This section will be drilled through the potential reservoir. In order to protect the reservoir productivity, no bentonite mud may be used in this section. It can be assumed that the granitic reservoir formation will be encountered at 1000 m and will continue until the well is at TD (2000 m TVD). It is highly likely that the formations that will be encountered will be fractured resulting in massive lost circulation. Since this is the reservoir section of the well, no Lost Circulation Material or Cement Plugs may be used to cure the losses. If losses are severe then the rig will drill ahead blind with water. The water well and onsite storage must be adequate to supply enough water to drill blind. The section will be drilled using a mud motor and possibly and MWD tool. The MWD usage will depend on circulating temperatures. The 25˚ of inclination and 225˚ of azimuth will be maintained while drilling the production section. At section TD (2000 m TVD, 2124 m MD) the bottom hole location should be 580 m from the vertical surface location.


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Wellbore Schematic

HOLE Information CASING Information

CONDUCTOR CONDUCTOR PIPE40 in to 6 m 30 in, Welded

SURFACE HOLE SURFACE CASING26 in to 100 m 20 in, 94 ppf, K-55, Seamless

INTERMEDIATE HOLE 1 INTERMEDIATE CASING 117-1/2 in to 300 m 13-3/8 in, 68 ppf, K-55, BTC, Seamless

Top of 7 in Production Liner 1 at 970 m

INTERMEDIATE HOLE 2 INTERMEDIATE CASING 212-1/4 in to 1020 m 9-5/8 in, 47 ppf, L-80, Tenaris, Seamless

PRODUCTION HOLE 1 PRODUCTION LINER 18-1/2 in to 2124 m 7 in, 29 ppf, L-80, , Seamless

PROPOSED WELL DIAGRAM

ENALNayarit, Mexico: Domo San Pedro Project

for

ThermaSourceGEOTHERMAL CONSULTING AND DRILLING

3883 Ai D i


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0

500

1,000

1,500

2,000

2,500

0 10 20 30 40 50 60

Mea

sure

d D

epth

, m

Days

ENALDomo San Pedro Project

ThermaSourceGEOTHERMAL CONSULTING AND DRILLING


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Section B: Surface Drilling Program

26" Hole Section to 100 m MD / 100 m TVD (20” Casing): Safety / Hazards Considerations in This Section: The surface section of any well is designed to withstand subsurface pressures that may be encountered while drilling to the next casing point. The 20” casing that will be installed in the 26” open hole will withstand any pressures that may be encountered while drilling the 17-1/2” hole section to 300 m. From offset well data, it is recognized that the formations that will be encountered will consist primarily of rhyolite volcanics. There has been some evidence of some obsidian in certain wells in the area. The 26” hole section should be drilled using a mud motor in order to increase the rate of penetration. There has been no sign of lost circulation in this upper section of the wellbore. However it is critical to be prepared to cure losses. The rig should attempt to cure the upper loss zones with LCM before trying to pump a lost circulation cement plug.

Bit & Hydraulics Program Mud Program

Bit Type 26” Tri-cone Mud Weight 8.7 – 9.0 ppg

Nozzles 3 x 24 Mud Type Gel – Polymer / Water-based

IADC Code 5-1-7 Funnel Vis < 15 cc/30 min

RPM 50 – 60 RPM YP 25 – 45 lb/sq ft

Pump Rate 800 – 1000 gpm PH 10.5 – 11.0

See Drilling Fluids Program provided by Mud Engineering Company for further details.

Run a maximum of 50,000 lbs WOB. An Average of 35,000 lbs to 45,000 would suffice.

26” BHA

w/ Motor

26” Bit, 9-1/2” Mud Motor, 26” Stab, 1 x 9-1/2” DC, Shock Sub, 26” Stab, 2 x 9-1/2” DC, XO Sub, 3 x 8” DC, XO Sub and 12 x 4-1/2” HWDP.

26” BHA

w/o Motor

26” Bit, Near Bit Roller Reamer, 1 x 9-1/2” DC, 26” Stab, Shock Sub, 26” Stab, 2 x 9-1/2” DC, XO Sub, 3 x 8” DC, XO Sub

Drilling: 1. Move in and rig up on well.

1.1. Mix mud to desired properties.

1.2. Note on tour sheet and morning report when beginning to pick up the 26” BHA.


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2. Make up 26” BHA and RIH to the top of cement in the conductor at approximately 6 m.

2.1. Circulate and condition mud.

3. Drill 26” hole from 6 m to 100 m.

3.1. The 26” hole section should take 1 bit run.

3.2. Collect, Dry, Bag and Label Formation Samples every 3 m.

3.3. Maintain desired mud properties to ensure proper hole cleaning.

3.4. Drill in singles with Kelly.

3.5. Limit ROP to 10 m/hr.

4. Attempt to cure lost circulation with lost circulation material.

4.1. If losses are severe set lost circulation cement plug.

See “Lost Circulation Cementing Procedure” in Appendix.

5. Take drift shots at approximately 50 m and casing point.

5.1. Have excess mud weighting material on location in order to kill the well.

See “Well Kill Procedure” in Appendix.

6. At TD make wiper trip back to 9-1/2” collars and return to bottom.

6.1. Circulate and pull out of the hole.

7. Run 20”, 94 ppf, K-55, BTC casing equipped with a float shoe and stab-in float collar 1 joint above the shoe.

7.1. Tack-weld the float shoe and first three collars.

7.2. Place centralizers in the middle of the shoe joint and every third collar to surface. Leave the centralizer off the first collar below ground level.

7.3. Make sure circulating swage is onsite in order to circulate casing to bottom.

8. Run in the hole with stab-in sub on 4-1/2” drill pipe and stab into float shoe.

9. Cement casing as per cementing program.

9.1. Have 100 m of 1-1/4” pipe on location.

9.2. Perform ECD calculations with cementing personnel before pumping.

10. POOH with inner string and WOC 8 hours.

10.1. If a top job is required, wait a minimum of 4 hours prior to pumping top job cement.

See “Top Job Cementing Procedure” in Appendix.

10.2. Wait a total of 8 hours prior to cutting off the casing.

11. Cut off 20” casing as required for BOP space out.


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12. Weld on 20” SOW by 21-1/14”, 2M casing head and pressure test to 500 psi.

13. Nipple up 21-1/4” BOP and function test.

13.1. Install the choke manifold and kill line on mud cross.

13.2. Well head stack up to consist of the following components.

20” SOW x 21-1/4” 2M casing head.

21-1/4” 2M x 21-1/4” 2M Mud Cross Spool with (2) 3-1/8” 2M flanged outlets with valves.

21-1/4” 2M Annular

21-1/4” Pitcher Nipple with Flow-T.

13.3. See “BOP Wellhead Diagram” in Appendix.

14. Run into the hole with 17-1/2” BHA.

15. Pressure test the BOP and choke manifold to 350 psi for 30 minutes with 10% or less fall off.

15.1. Chart the pressure test and retain copies for the regulatory agency and ENAL.

15.2. Email copies of test data to ENAL.


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Cementing Table 1

26” open hole, 20” casing

Slurry Details Lead Tail

Spacer 10 bbls Mud Clean,

30 bbls Fresh Water,

20 bbls Sodium Silicate Preflush 6 bbls Fresh Water.

N/A

Cementing method Inner String N/A

Weight (ppg) 15.6 ppg N/A

Design Top = Surface

Bottom = 100 m

N/A

Excess 100% N/A

Approximate Volume of Cement (bbl)

191 bbls N/A

Cement Class “G” Cement with 40% Silica Flour.

N/A

Pump Lead Cement until cement returns are observed at surface. Then under displace by 1 bbl. Displacement Volume = 3 bbls.

Top Job Procedure

Follow “Top Job Cementing Procedure” in Appendix.


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Section C: Intermediate 1 Drilling Program

17-1/2" Hole Section to 300 m MD / 300 m TVD (13-3/8” Casing): Safety / Hazards Considerations in This Section: This intermediate hole section and casing is designed to withstand any subsurface pressures that may be encountered while drilling the 12-1/4” hole section. It is likely to encounter dacites, rhyolites and obsidian in this hole section. These formations are known to have some fractures that may cause lost circulation. The rig should attempt to cure the upper loss zones with LCM before trying to pump a lost circulation cement plug.


Bit Type 17-1/2” Tri-cone Mud Weight 8.8 – 9.5 ppg

Nozzles 3 x 20,

1 x 24 Center Jet

Mud Type Gel – Polymer / Water-based

IADC Code 5-3-7 to 5-4-7 Fluid Loss < 8 cc/30 min

RPM 50 – 60 RPM YP 10 – 35 lb/sq ft

Pump Rate 800 – 1000 gpm PH 10.5 – 11.0

Run a maximum of 50,000 lbs of WOB. An average of 35,000 lbs to 45,000 lbs would suffice.

17-1/2” BHA

w/o Motor

17-1/2” Bit, 17-1/2” Near Bit Stab, 1 x 9-1/2” DC, 17-1/2” Stab, 9-1/2” Shock Sub, 1 x 9-1/2” DC, 17-1/2” Stab, 3 x 9-1/2” DC, XO Sub, 7 x 8” DC, Drilling Jars, 2 x 8” DC, XO Sub, 12 x 4-1/2” HWDP.

(Use this BHA not the BHA in the “Directional Program”)

17-1/2” BHA

w/ Motor

17-1/2” Bit, 9-1/2” Mud Motor, 17-1/2” Stab, 1 x 9-1/2” DC, Shock Sub, 17-1/2” Stab, 2 x 9-1/2” DC, XO Sub, 5 x 8” DC, Drilling Jars, 2 x 8” DC, XO Sub and 12 x 4-1/2” HWDP.

Potential Formations

Dacites, Rhyolites and Obsidian.

Drilling:

1. Pick up the 17-1/2” BHA and run in the hole to the top of cement.

1.1. Clean out cement and drill out float shoe.

1.2. Drill 1.5 m of new formation.


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1.3. Perform Leak-off Test.

See “Leak-off Procedure” in Appendix.

2. Drill 17-1/2” vertical hole to the 13-3/8” casing point at 300 m.

2.1. Install drill pipe float in the NBS equipped with high temperature rubber elements.







4. Watch for formation markers that indicate shallow geothermal zones:

An increase in flowline temperature (5.5˚C in a 30 m interval).

4.2. Take drift shots at 100 m intervals.

4.3. Monitor the mud properties and utilize corrosion rings for corrosion control.

4.4. Have excess mud weighting material on location in order to kill the well.

See “Well Kill Procedure” in Appendix.

5. The 17-1/2” hole section is expected to take 1 bit run.

5.1. At section TD circulate, survey and make a wiper trip to the 20” casing shoe and POOH.

6. Run 300 m of 13-3/8”, 68 ppf, K-55 BTC Casing equipped with a float shoe, 1 joint of casing and a stab-in float collar.

6.1. Weld the shoe track including the float collar and one additional collar.

6.2. Place centralizers in the middle of the shoe track and every third collar to surface.

Leave centralizer off first collar below ground level.

7. Make sure circulating swage is onsite in order to circulate casing to bottom.

8. Run in the hole with stab in sub on 4-1/2” drill pipe and stab into float collar.

8.1. Maintain drilling mud properties prior to cementing.

9. Cement casing as per cementing program summarized in Table 2 below.






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10.2. Wait on top job cement for 8 hours prior to cutting off casing.

11. Cut off 13-3/8” casing as required for the BOP stack up.

12. Weld on 13-3/8” SOW x 13-5/8” 3M casing head and pressure test the weld to 1000 psi. Must be leveled with high accuracy.

12.1. 13-3/8” SOW x 13-5/8” 3M casing head must have a minimum bore of 12-3/8”.

12.2. Complete both a pre-weld and post-weld heat treat on casing head weld.

12.3. Follow TNG welding procedure for K-55 casing to the ASME 4130 wellhead.

12.4. Nipple up 13-5/8” BOP and function test.

12.5. Install choke manifold and kill line on mud cross outlets.

12.6. The wellhead stack up shall consist of the following components.

13-3/8” SOW x 13-5/8” 3M Casing Head with 3-1/8” 3M side Outlets.

13-5/8” 3M x 13-5/8” 5M Crossover Spool.

13-5/8” 5M Mud Cross with 3-1/8” 5M valves.

13-5/8” 5M Double Gate Ram Preventer

o Bottom Rams – Blind Rams

o Top Rams – Pipe Rams

13-5/8” 5M x 13-5/8” 5M Annular

13-5/8” 5M Rotating Head.

12.7. See “BOP Wellhead Diagrams” in Appendix.

12.8. Pressure test the Blind Rams and choke manifold to 250 and 1500 psi for 30 minutes with 10% or less fall off.

12.9. Run in the Hole with 12-1/4” BHA.

12.10. Test pipe rams and annular preventer to 250 and 1500 psi for 30 min with 10% or less fall off.




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Cementing Table 2

17-1/2” open hole, 13-3/8” casing




40 bbls Sodium Silicate Preflush

10 bbls Fresh Water.

N/A

Cementing method Inner String Inner String

Weight (ppg) 13.5 ppg 15.6 ppg

Design Top = Surface

Bottom = 200 m

Top = 200 m

Bottom = 300 m

Excess 100% 0%


162 bbls 50 bbls


Class “G” Cement with 40% Silica Flour.

Pump Lead Cement until cement returns are observed at surface. Then switch and pump entire volume of Tail Cement and under displace by 2 bbls. Displacement Volume = 11 bbls.

Top Job Procedure



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Section D: Intermediate 2 Drilling Program

12-1/4" Hole Section to 1020 m MD / 1000 m TVD (9-5/8” Casing): Safety / Hazards Considerations in This Section: The 9-5/8” casing string will be the final casing string cemented to the surface. It has been designed to withstand any formation pressure that will be encountered while drilling to TD. It is likely to encounter dacites and rhyolites in this hole section. These formations are known to have some fractures that may cause lost circulation. The rig should attempt to cure the upper loss zones with LCM before trying to pump a lost circulation cement plug. The 12-1/4” hole section will be drilled vertically to a depth of 600 m, at which time the rig will pull out of the hole and run in with a directional assembly. The directional drilling assembly will begin building angle at 2.5˚ per 30 m until 25˚ of inclination is achieved. The well will be directed in a 225˚ azimuth toward the dome. It should take approximately 300 m to build the required 25˚. Once this has occurred the rig will hold the 25˚ of inclination and 225˚ of azimuth until the casing point of 1000 m TVD (1020 MD) is achieved.



Nozzles 3 x 18 Mud Type Gel – Polymer / Water-based

IADC Code 5-3-7 to 6-1-7 Fluid Loss < 8 cc/30 min

RPM 70 RPM / 0 Rpm (Directional) YP 10-35 lbs/sq ft

Pump Rate 700 – 800 gpm PH 10.0 – 12.0


12-1/4” BHA

w/o Motor

12-1/4” Bit, NBS, 8” Monel, 12-1/4” String Stabilizer, 1 x 8” DC, 12-1/4” String Stabilizer, 10 x 8” DC, Jar, 2 x 8” DC, XO, 12 x 4-1/2” HWDP

12-1/4” BHA

w/ Motor

12-1/4” Bit, 8” Mud Motor, 12-1/4” Stab, 8” Monel, Shock Sub, 12-1/4” Stab, 10x 8” DC, Drilling Jars, 2 x 8” DC, XO Sub and 12 x 4-1/2” HWDP.

12-1/4” BHA Directional

12-1/4” Bit, 8” Steerable Mud Motor, 12-1/4” Stab, 8” Orientation Sub, 8” MWD, Monel, 13 x 8” DC, Drilling Jars, 2 x 8” DC, XO Sub and 12 x 4-1/2” HWDP.

Potential Formations

Rhyolites, Dacites and Granite


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Drilling:

1. Make up 12-1/4” Motor BHA and RIH to the top of cement at approximately 260 m.

1.1. Install drill pipe float in the NBS equipped with high temperature rubber elements.

1.2. Circulate and condition mud.

1.3. Drill out cement and shoe track to 300 m.

1.4. Drill 1.5 m of new formation.

1.5. Perform Leak-off test.

See “Leak-off Procedure” in Appendix.

2. Drill ahead to 600 m TVD.




2.4. Take deviation surveys every 50 m.

2.5. Attempt to keep well vertical.

3. At 600 m pull out of the hole and pick up 12-1/4” Directional BHA.

3.1. Run back into the well.

3.2. Tag bottom and orient directional assembly.

4. Directionally drill 12-1/4” hole to section TD at 1020 m MD / 1000 m TVD.

4.1. Begin building angle at 2.5˚ / 30 m of hole with an azimuth of 225˚.

4.2. Once 25˚ is reached hold angle and drill ahead.

It should take 305 m to obtain desired deviation.

4.3. Building should occur with an azimuth of 225˚.




4.7. Granitic formations may be present around 1000 m TVD.





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6. Monitor the flowline temperature.

Report increases – especially those greater than 5.5˚C/30 m.


7. The 12-1/4” hole section is expected to take 3 bit runs.

8. At section TD, circulate, make a wiper trip to the 13-3/8” casing shoe and POOH.

9. Run approximately 1020 m of 9-5/8”, 47 ppf, L-80, Tenaris connection casing equipped with a float shoe, 2 joints of casing and a stab-in float collar.

9.1. Weld the shoe track including the float collar and one additional collar.

9.2. Place centralizers in the middle of the shoe track and every third collar to surface.

Leave centralizer off first collar below ground level.

10. Make sure circulating swage is onsite in order to circulate casing to bottom.

11. Run in the hole with stab in sub on 4-1/2” drill pipe and stab into float collar.

11.1. Maintain drilling mud properties prior to cementing.

12. Cement casing as per cementing program summarized in Table 3 below.






13.2. Wait on top job cement for 8 hours prior to cutting off casing.

14. Unbolt Crossover Spool from wellhead.

15. Lift BOP stack off of wellhead and make rough cut on 9-5/8” casing.

15.1. Rough cut must be made according to Expansion Spool Manufacturer – Standard Operating Procedure.

Every manufacturer uses different dimensions in the construction of the expansion spool. The manufacturer should have a procedure to cut and set expansion spool.

16. Move BOP stack from under rig and set aside.

17. Take measurement and make final cut on casing as per Expansion Spool Manufacturer procedure.

18. Nipple up expansion spool and master valve.

19. Energize pack-off.

20. Nipple up BOP stack.


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20.1. The wellhead stack up shall consist of the following components.

13-3/8” SOW x 13-5/8” 3M Casing Head with 2 x 3-1/8” 3M side Outlets.

12” ANSI 900 Series x 10” ANSI 900 Series Expansion Spool with 2 x 3-1/8” 3M side Outlets.

10” ANSI 900 Series Through Conduit Expanding Gate Valve

10” ANSI 900 Series x API 13-5/8” 5M Crossover Spool.

13-5/8” 5M Double Gate Ram Preventer

o Bottom Rams – Blind Rams

o Top Rams – Pipe Rams

13-5/8” 5M x 13-5/8” 5M Annular

13-5/8” Rotating Head.

20.2. See “BOP Wellhead Diagrams” in Appendix.

20.3. Pressure test the Blind Rams and choke manifold to 250 and 2000 psi for 30 minutes with 10% or less fall off.

20.4. Run into the 8-1/2” BHA.

20.5. Test pipe rams and annular preventer to 250 and 1500 psi for 30 min with 10% or less fall off.




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Cementing Table 3

12-1/4” open hole, 9-5/8” casing




40 bbls Sodium Silicate Preflush

10 bbls Fresh Water.

N/A

Cementing method Inner String Inner String

Weight (ppg) 13.5 ppg 15.6 ppg

Design Top = 0 m

Bottom = 920 m

Top = 920 m

Bottom = 1020 m

Excess 100% on open hole section 100% on open hole section


286 bbl 39 bbl


Class “G” Cement with 40% Silica Flour.

Comments:

Pump Lead Cement until cement returns are observed at surface. Then switch and pump entire volume of Tail Cement and under displace by 2 bbls. Displacement Volume = 45 bbl

Top Job Procedure



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Section E: Production Drilling Program

8-1/2" Hole Section to 2124 m MD / 2000 m TVD (7” Slotted Liner): Safety / Hazards Considerations in This Section: The 8-1/2” hole section will be the final hole section in the well design. This section will be drilled through the potential reservoir. In order to protect the reservoir productivity, no bentonite mud may be used in this section. It can be assumed that the granitic reservoir formation will be encountered at 1000 m and will continue until the well is at TD (2000 m TVD). It is highly likely that the formations that will be encountered will be fractured resulting in massive lost circulation. Since this is the reservoir section of the well, no Lost Circulation Material or Cement Plugs may be used to cure the losses. If losses are severe then the rig will drill ahead blind with water. The water well and onsite storage must be adequate to supply enough water to drill blind. The section will be drilled using a mud motor and possibly an MWD tool. The MWD usage will depend on circulating temperatures. The 25˚ of inclination and 225˚ of azimuth will be maintained while drilling the production section. At section TD (2000 m TVD, 2124 m MD) the bottom hole location should be 580 m from the vertical surface location.



Nozzles 3 x 16 Mud Type Water / Brine

IADC Code 5-4-7 to 6-1-7 PH > 9.0

RPM 60 - 100 at surface Pump Rate 800 – 1100 gpm


8-1/2” BHA

w/o Motor

8-1/2” Bit, NBS, Monel, 8-1/2” String Stabilizer, 1 x 6-1/4” DC, 8-1/2” String Stabilizer, 14 x 6-1/4” DC, Jar, 2 x 6-1/4” DC, XO, 12 x 4-1/2” HWDP. (Use this BHA not the BHA in the “Directional Program”)

8-1/2” BHA

w/ Motor

8-1/2” Bit, 6-1/4” Mud Motor, 8-1/2” Stab, Monel, Shock Sub, 8-1/2” Stab, 12x 6-1/4” DC, Drilling Jars, 2 x 6-1/4” DC, XO Sub and 12 x 4-1/2” HWDP.

8-1/2” Directional BHA

8-1/2” Bit, 6-1/4” Steerable Mud Motor, 8-1/2” Stab, 6-1/4” Orientation Sub, 6-1/4” MWD, 8-1/2” Under-gage Top Stab, 13 x 6-1/4” DC, Drilling Jars, 2 x 6-1/4” DC, XO Sub and 12 x 4-1/2” HWDP.


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Potential Formations Granite

Drilling:

1. RIH with Motor 8-1/2” BHA.

1.1. Install drill pipe float in the bit sub equipped with high temperature rubbers elements.

2. Drill 8-1/2” hole to section TD at 2124 m MD / 2000 m TVD.

2.1. Have under-gage stabilizers onsite in case course direction change is needed.

2.2. Survey at 100 m intervals.

2.3. Adjust BHA as necessary to maintain angle and azimuth.

If well deviates from plan consider a directional correction run.

2.4. Building should occur to SW 45˚ NE with an azimuth of 225˚.




2.8. Monitor the flowline temperature.

Report increases – especially those greater than 5.5˚C / 30 m.

3. If circulation cannot be maintained:

3.1. Pull up to the 9-5/8” casing shoe and begin circulating water.

3.2. Pump theoretical hole volume of water.

3.3. Begin to stage back into the hole trying to circulate with water every 3 stands.

4. Follow “Blind Drilling Procedure” in Appendix.

5. The 8-1/2” hole section is expected to take 4 bit runs.

5.1. At section TD circulate, make a wiper trip to the 9-5/8” casing shoe and POOH.

6. Rig up logging tools consisting of TP and Geophysical tools

6.1. See “Logging Procedure” in Appendix.

7. Run logs to TD and back to the 9-5/8” liner shoe.

8. POOH with logging tools.

8.1. Onsite Geologist may want to take spot cores at TD.

9. If logging tools did not reach bottom, then make wiper trip with 8-1/2” BHA to bottom.

10. Run approximately 1154 m of 7”, 29 ppf, L-80, Slotted Liner on a 9-5/8” x 7” landing collar.


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10.1. Plan liner for a 50 m liner lap with blank casing.

10.2. Adjust the amount of perforated liner based on the final section TD.

10.3. Equip liner with a drillable guide shoe.

10.4. Weld the bottom four joints of casing.

10.5. Run liner in the hole on 4-1/2” drill pipe.

10.6. Set liner on bottom and release from landing collar.

11. POOH and lay down setting tool.

12. Run TP Survey once out of the hole.

12.1. Equip TP logging tool with centralizer and sinker bar.

12.2. See “Logging Procedure” in Appendix.

13. Test well per Onsite Geologists recommendations.

14. Rig down and move off location.


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Section F: BOP Wellhead Diagrams


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Ground Level

21‐1/14" Pitcher Nipple with Flow‐T

API 21‐1/4" 2M

Annular Preventer

21‐1/4" 2M Mud Cross w/ 3‐1/8"

20" SOW x API 21‐1/4" 2M Casing

Head

20" Casing

ENAL ‐ SP‐02 ‐ 21‐1/4" BOP Stack


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API 13‐5/8" 5M

Annular Peventer

API 13‐5/8" 5M Double Gate Preventer

13‐5/8" 3M x 13‐5/8" 5M Crossover Spool

13‐3/8" SOW x 13‐

5/8" 3M Casing Head w/ 3‐1/8"

valves

ENAL ‐ SP‐02 ‐ 13‐5/8" BOP

Ground Level

13‐3/8" Casing

20" Casing

13‐5/8" 5M

Rotating Head


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13‐5/8" Rotating

Head

13‐5/8" Annular

Peventer

13‐5/8" 5M Double

Gate Preventer

10" ANSI 900

Series x 13‐5/8" 5M Spacer Spool.

13‐5/8" x 10" 900

13‐3/8" SOW x 13‐

5/8" 3M Casing Head w/ 3‐1/8"

valves

10" 900 Master

Valve

ENAL ‐ SP‐02 ‐ 13‐5/8" BOP w/Expansion Spool

Ground Level

13‐5/8" 3M x 10"

900 Expansion

13‐3/8" Casing

20" Casing


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13‐3/8" SOW x 13‐5/8" 3M Casing Head w/ 3‐

1/8" valves

8" 900 Blank Flange

ENAL ‐ SP‐02 ‐ Final Wellhead

Ground Level

13‐5/8" 3M x 10" 900 Expansion Spool

13‐3/8" Casing

20" Casing

8" 900 Valve

10" 900 Valve


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Section G: Directional Well Plan


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Section H: Geologic Well Plan and Site Map


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Section I: Preliminary Well Cost Estimate


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Section J: Lost Circulation Cementing Procedure

Purpose Permeability or Fracture Systems, while good for production zones, are a cause of great concern while drilling the upper hole sections in any geothermal well. These zones cause lost circulation which means that the drilling fluid and the cuttings that the fluid carries do not return to surface. Without these returns all of the cuttings can fall back on the bit causing the bit to get stuck. Full circulation is needed in order to cement the casing string in the well. If losses occur then it may be difficult to get a good cement bond along the length of the casing and if fluid gets trapped between cement and casing then the casing could collapse when heated due to production, so lost circulation needs to be controlled. Minor loss zones can be cured with Lost Circulation Materials (LCM). LCMs are materials that will fill the voids (permeable spaces or fractures) and stop the losses from occurring. However major losses cannot be controlled with LCM and need to be cemented up. In order to cement a lost circulation zone the rig needs to set a balanced cement plug through the zone. The following procedure will instruct how to set a balanced cement plug at any depth. Lost Circulation Cementing Procedure

1. Record the depth at which losses were first encountered and the MD of the bottom of the

hole. 2. Pull out of the hole and stand back BHA. 3. Run into the hole with hollow bobber on slick line and check fluid level. 4. Run into the hole open ended. 5. Set slips with open ended pipe 10’ above loss zone. 6. Break off Kelly or Top Drive and set back. 7. Pick up and make up drill pipe cementing head. 8. Begin circulating drilling fluid. 9. Determine spacer, cement and displacement volumes.

9.1. See “Equations” below for volume calculations. 10. Mix cement and pump calculated spacer ahead. 11. Pump calculated cement volume. 12. Pump calculated spacer volume behind. 13. Pump calculated displacement volume. 14. Shut Down Pumps. 15. Pull out of the hole. 16. Clean out drill pipe on surface. 17. Wait on cement 8 hours or until surface samples are hard.


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18. Run back into the well and tag cement top. 19. Establish circulation.

19.1. If circulation cannot be established return to Step 1. 20. Drill out cement and back to bottom.

20.1. If circulation is lost return to Step 1 after drilling 5 additional feet. 21. Drill ahead as planned.

Equations Nomenclature

DH = Hole ID (inch)

DDPO = Drill Pipe OD (inch)

DDPI = Drill Pipe ID (inch)

LSA = Length of Spacer Ahead (ft)

LCMT = Linear Length of Cement Plug (ft)

LSB = Length of Spacer Behind (ft)

LCMTA = Length of Cement in Annulus (ft)

LCMTDP = Length of Cement in DP (ft)

LDP = Length of Drill Pipe (ft)

LFL = Depth of Fluid Level (ft)

CA = Annular Capacity (bbl/ft)

CH = Hole Capacity (bbl/ft)

CDP = Capacity of Drill Pipe (bbl/ft)

VSA = Volume of Spacer Ahead (bbl)

VCMT = Volume of Cement (bbl)

VSB = Volume of Spacer Behind (bbl)

VDP = Volume of Drill Pipe (bbl)

VDis = Volume of Displacement Fluid (bbl)

1. Annular Capacity

1.1. CA (bbl/ft) = (DH2 – DDPO

2)/1029.4 2. Volume of Spacer Ahead

2.1. VSA (bbl) = LSA * CA 3. Volume of Cement

3.1. LCMT (ft) = determined by engineer. 3.2. CH (bbl/ft) = DH

2/1029.4 3.3. VCMT (bbl) = LCMT * CH

4. Volume of Spacer Behind 4.1. LSA (ft) = LSB (ft) 4.2. CDP (bbl/ft) = (DDPI

2)/1029.4 4.3. VSB (bbl) = CDP * LSB

5. Volume of Displacement 5.1. LCMTA (ft) = LCMTDP (ft) = LCMT (ft) 5.2. VDis (bbl) = (LDP – (LSB + LCMT + LFL)) * CDP


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Section K: Well Kill Procedure

Purpose Geothermal wells are generally considered an underbalanced system, which means that the formations possess less pressure than a static column of water at the same depth. However the some geothermal fields have shown evidence of some over pressured formations that could cause a kick. A kick is defined as an unscheduled, unwanted entry of water, gas or oil into the wellbore. This entry of fluid will cause the well to flow and if left uncontrolled can further cause a blowout situation. The most dangerous type of kick is a gas kick because a migrating gas bubble will continue to increase in size which results in a greater decrease in hydrostatic pressure. The well will continue to flow uncontrolled with this decrease in hydrostatic pressure. One should assume that every kick is a gas kick and treat as such. Kicks can be encountered naturally, but the majority of causes can be controlled at the rig. The following is an example of some of these causes:

Insufficient Mud Density

Failure to Keep Hole Full of Fluid

Poor Pipe Tripping Procedures

Lost Circulation

Abnormally Pressured Formations

Obstructions in Wellbore

Poor Cementing Operations

Excessive Drilling Rate Through Sand

Excessive Water Loss of Mud

Poor BOP Testing Procedures

Trapped Gas Below BOPs

Water Flushes

Drill Stem Testing

Failure to Maintain Back Pressure while Underbalanced Drilling

Kicks can occur whenever a permeable formation or fracture system is exposed to the wellbore. Kicks might be encountered when changes are observed in the following drilling parameters:

Pump Pressure

Flow Return Rate

Pump Speed Changes

Rate of Penetration

Torque/Drag

String Weight

Fill on Bottom

Pit Level

Volume to Fill Hole During Trip

Mud Density, Temperature, Viscosity and Salinity

Size and Shape of Cuttings

If one of the previous identifiers of a kick were detected then follow the Flow Check Procedure below.


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Flow Check Procedure

1. Pull up off bottom and space out tool joint to the rotary table. 2. Stop Rotation 3. Shut Down Pumps. 4. Monitor Flow.

If flow does occur then the well must be shut in and killed. There are primarily two methods for killing flowing wells; these are the Driller’s Method and the Wait and Weight Method. Both methods require the operator to perform two actions; 1 – Weight up the drilling fluid, 2 – Circulate out the formation fluid. The difference between the two methods is the order of these operations. In geothermal, the common practice is to use the Driller’s Method because it circulates the formation fluid out of the well as soon as possible. Driller’s Method is described in the Well Kill Procedure below. Well Kill Procedure

1. Shut in well.

1.1. Make sure Adjustable Choke is closed. 1.2. Close Pipe Rams. 1.3. Open all valves in line to Adjustable Choke (keeping Adjustable Choke closed).

2. Record Initial Data 2.1. Present Mud Weight (MW). 2.2. Depth of Kick: MD and TVD. 2.3. Pit Gain (Kick Size) 2.4. Shut in Drill Pipe Pressure (SIDPP) from standpipe. 2.5. Shut in Casing Pressure (SICP) from choke pressure gage. 2.6. Slow Circulating Rate (SCR) and Pressure (SCP) for 1 pump.

3. Determine Initial Circulating Pressure (ICP) 3.1. ICP = SCP + SIDPP

4. Slowly bring the mud pump up to SCR while keeping the SICP constant with the Adjustable Choke.

5. Once pump is up to speed keep pump pressure equal to ICP using the Adjustable Choke. 6. Continue to pump at ICP using Adjustable Choke for control until the Choke Pressure

(Casing Pressure) equals SIDPP. 7. Close Choke and shut pump down. 8. Record SICP and SIDPP 9. Calculate Kill Weight Mud Density (KWM).

9.1. KWM = MW + [SIDPP/(.052*TVD)]


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10. Calculate Downhole mud volume. 10.1. Hole Volume = Open Hole without drill pipe * Capacity Factor for Hole Size 10.2. Drill Pipe Volume = Length of Drill String * Capacity Factor for Drill Pipe Size 10.3. Annular Volume for open hole = Section Length * (Capacity factor for open hole

– Capacity factor for drill pipe). 10.4. Annular Volume for casing = Section Length * (Capacity factor for casing –

Capacity factor for drill pipe). 10.5. Total downhole mud volume = Hole Volume + Drill Pipe Volume + Annular

Volume for Open Hole + Annular Volume for Casing. 11. Weight up mud in pits.

11.1. Make sure that the volume of weighted mud is greater than total downhole mud volume.

12. Calculate Final Circulating Pressure (FCP) 12.1. FCP = SCP * KWM/MW

13. Slowly bring the mud pump up to SCR while keeping the SICP constant with the Adjustable Choke.

14. Once pump is up to speed keep SICP constant using the Adjustable Choke. 15. The Pump rate should remain constant until FCP is reached.

15.1. This means that the KWM has reached the bit. 16. Continue to pump at the same rate while keeping FCP constant on the pump using the

adjustable choke. 17. Once KWM has reached surface the well should be killed and static. 18. Shut down pumps. 19. Check for flow. 20. If flow occurs return to step 1. 21. If no flow occurs

21.1. Calculate New Mud Weight 21.1.1. NMW = KWM + 0.3 ppg

21.2. Finish weighting up mud in pits to NMW. 22. Bring pump up to speed. 23. Circulate mud around until NMW returns to surface. 24. Return to bottom and drill ahead.


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Section L: Top Job Cementing Procedure

Purpose During the cementing of casing in the wellbore, it is common for cement not to return to surface or for it to fall back due to lost circulation zones or formation breakdown. No matter the cause, the lack of cement at surface requires a top job to be performed. The only difference is the type of top job required. Listed below are the two different situations that require a top job and the procedures to perform the same. No Cement to Surface The following procedure is to be used in the situation where no cement was returned to surface. 1. Wait a minimum of 4 hours prior to pumping top job. 2. Calculate volume of cement needed to fill from surface to top of the deepest loss zone

2.1. Annular Capacity (CA) = ((ID Hole)2 – OD Casing) 2)/1029.4 2.2. Volume of Cement = CA * MD of deepest loss zone * 1.3. 2.3. Recommended to continually pump cement until clean cement returns to surface.

3. Pick up and run 1” pipe into annulus. 3.1. Pick up enough 1” pipe to reach the shoe of the previous casing.

4. Pump cement through 1” tubing. 4.1. Do not pump any water in front or behind cement. 4.2. Pump cement slowly into place. 4.3. Recommended to continually pump cement until clean cement returns to surface.

5. Pull tubing out slowly and clean tubing out on surface away from wellbore. 6. If cement returned to surface proceed to next section below. 7. If cement did not return to surface return to step 1.

Cement Returns to Surface But Falls Back *DO NOT FILL UP ANNULUS WITH ANY FLUID 1. Wait a minimum of 4 hours prior to pumping cement. 2. Run into the annulus with 1” tubing and tag top of cement. 3. Pick up off the top of cement 1’. 4. Pump cement through 1” tubing.

4.1. Do not pump any water ahead or behind cement. 4.2. Pump cement slowly into place.

5. Continue pumping cement until clean cement is present at surface. 6. Pull tubing out slowly and clean out on surface.


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7. Return to Drilling Program.

Section M: Leak-Off Procedure

Purpose After each casing string is successfully cemented in place, a pressure test known as a Leak-Off Test (LOT) is performed. This test verifies that the casing, cement and lithological formations that are below the casing shoe can withstand the wellbore pressures required to safely drill to the next casing setting depth. Essentially all flow paths to the surface are sealed off using BOPs and the rig then pumps into the closed wellbore. The pumping is done at a constant flow rate which will increase the internal wellbore pressure until the wellbore begins to take fluids. Once this happens the pump is then shut down and the pressure is monitored and logged in order to create a pressure profile. Below you will find a detailed LOT procedure to be used before drilling the next hole section. LOTs are performed after the casing has been pressure tested and the cement has been drilled out of the casing shoe track. Do not exceed casing test pressure during LOT. Procedure

1. Following completion of the casing pressure test, drill out cement from casing shoe and clean

out any rat hole below the casing. 2. Drill 5’ of new formation below the casing shoe. 3. Circulate well clean to ensure uniform mud density throughout the wellbore and to verify that

the hole stands full of drilling fluid. 3.1. If an Electronic Data Recorder (EDR) is available make sure it is set up and functioning

properly. 3.2. If NO EDR is on site then set one man to record pressure, one man to record strokes or

volume pumped and one man to record time. 3.2.1. The man recording time will tell the other two when to take a reading.

4. Note the height of the pressure gage above ground level. 5. Measure and record the circulating mud density. 6. Pull drill string inside the casing shoe and set in slips. 7. Disconnect Top Drive or Kelly and set back. 8. Connect cement circulating head. 9. Purge all air out of cementing lines. 10. Start Cement Pumps, pressure test all lines and circulate one drill string volume of mud.

10.1. Pump rate should be 0.5 bbls/min.


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10.1.1. Pump rate should be no more than 1 bbl/min. 11. Begin recording data.

11.1. Activate EDR. 11.2. Record time, pressure, flow rate, and total volume pumped every second. 11.3. Take initial readings manually if EDR is not present. 11.4. Record time, pressure, strokes per minute and total strokes every 10 seconds. 11.5. Stop Pumping.

12. Close the pipe rams and start pumping into the well at a steady rate of approximately .5 bbl/min. Once the pump rate has been set do not attempt to make pump rate adjustments during the test.

13. After fracture initiation occurs, when pump pressure levels off continue pumping for at least 5 minutes or until a stabilized injection pressure can be determined from the pressure monitoring system.

14. Note and record the stabilized injection pressure. Shut down the pump, but do not bleed off the pressure.

15. Monitor pressure decline as fluid leaks off into the formation. Continue monitoring pressure decline until fracture closure can be identified. If no clear closure can be seen, continue to monitor until the pressure has stabilized or for a maximum of 15 minutes.

16. Generate a plot of the pump pressure vs. volume pumped as shown in the figure below.

17. Calculate the fracture gradient using the stabilized injection pressure with the equation below.

Fracture Gradient = (SIP+(TVD-RF +GH)*MW*0.052)/(TVD-RF) where,

SIP – stabilized injection pressure (psig) TVD - true vertical depth as measured from rotary table (ft) GH - pressure gage height above ground level (ft) MW - mud weight (lb/gal) RF – rig floor height above ground level (ft)

Data Interpretation

The leak off test can be used to define several different pressure values, which are shown in the figure and described below.

1. Breakdown Pressure (BP) - The highest pressure reached when first initiating a fracture.

2. Stabilized Injection Pressure (SIP) - The combination of friction pressure losses in the system and pressure required to hold the fracture open.

3. Instantaneous Shut In Pressure (ISIP) - The pressure measured immediately after flow is stopped and is equal to the pressure required to hold the fracture open to a given width.


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4. Closure Pressure (CP) - The pressure at which the fracture closes. This is interpreted as the minimum principle stress.

Example Leak-Off Test Data Plot

Leak Off Test Example

0

100

200

300

400

500

600

700

0 5 10 15 20 25 30 35 40

Time

Pre

ssu

re (

Psi

g)

0

0.5

1

1.5

2

Pu

mp

Rat

e (b

bl/

min

)

Breakdown PressureStabilized Injection Pressure

Instantaneous Shut In Pressure

Closure Pressure

Volume Pumped


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Section N: Blind Drilling Procedure

Purpose Permeability or Fracture Systems, while good for production zones, are a cause of great concern while drilling the upper hole sections in any geothermal well. These loss zones in the upper sections can be cured or diminished using LCM or cement plugs. However in the bottom hole sections the loss zones are all potential production intervals, so sealing these zones off is out of the question. In order to drill ahead one must lighten the fluid column with aerated fluid or straight air or drill blind ahead with water. Drilling blind with water is the easier of the two methods, but there are some causes of concern that need to be handled with care. The first problem is proper hole cleaning away from the bit. If the flowrate out of the bit is not great enough to lift the drill cuttings away from the bit and into the surrounding fracture system then a stuck pipe situation could ensue. It is necessary to keep a constant rate pumping through the drill string. A significant falling of cuttings will occur while the pumps are shut off. It is critical to only shut the pumps off when the bit is off bottom. Also when a connection is made it is critical to circulate (turn pump back on) before proceeding back to bottom. To ensure proper hole clean it is also recommended to take frequent wiper trips up to the last casing shoe. This will make sure that an accumulation of drill cuttings have not collected on the drilling tools in the open hole section which could cause a stuck pipe situation. Blind Drilling Procedure

1. Set pump rate at 1000 gpm. 2. Pump into annulus at 5 gpm to prevent cuttings accumulation above shallowest loss zone. 3. Monitor standpipe pressure. 4. Drill ahead as planned.

4.1. Limit ROP to 20 ft/hr. 5. Before connections pull off bottom and circulate to clean hole.

5.1. When making a connection, do not leave pipe static for a long time. 6. Always keep the pipe moving. 7. Every 6 joints (180’) pull wiper trip to casing shoe. 8. If stand pipe pressure increases suddenly pull off bottom and into casing shoe. 9. Continue drilling until section TD.


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Section O: Logging Procedure

Purpose Once a certain hole section has been drilled or the overall TD of the well has been reached it is necessary to evaluate the lithology of the wellbore. One method of evaluation is to log the wellbore with geophysical tools. These logs need to be run after the well section has been drilled and before the subsequent casing has been installed. This procedure will cover three different procedures; 1) wellbore remains full of reservoir temperature fluid, 2) wellbore has been evacuated due to lost circulation or production intervals, 3) well flows to surface. If the reservoir is full of cool fluid then log normally. Logging Procedure for a Full Wellbore with Reservoir Temperatures

1. Before pulling out of the hole with the drilling assembly, circulate hole clean with cool fluid. 2. Rig up wireline equipment on pad and in derrick. 3. Bolt lubricator onto Rotating Head Assembly. 4. Pump cold water through wellhead side outlets in order to cool well. 5. Run Wireline logs in hole. 6. Log planned interval and remove tools from wellbore. 7. Rig down logging equipment. 8. Return to Drilling Program for casing procedure.

Logging Procedure for an Evacuated Wellbore or Flowing Well

1. Pull out of the hole. 2. Run in the hole with 2 joints of drill pipe. 3. Close annular preventer around drill pipe. 4. Rig up wireline equipment on pad and in derrick. 5. Screw lubricator onto drill pipe. 6. Pump cold water through wellhead side outlets in order to cool well. 7. Run Wireline logs in hole. 8. Log planned interval and remove tools from wellbore.

8.1. Monitor tool temperature. 8.2. Prepare to remove tools before tool temperature threshold is reached.

9. Rig down logging equipment. 10. Return to Drilling Program for casing procedure.


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