well plan for the drilling and completion of dwdno

WELL PLAN FOR THE DRILLING AND COMPLETION OF

DWDNo.l

Preparedfor:

THE DOW CHEMICAL COMPANY MAGNOLIA, ARKANSAS

Prepared by:

.TERRA DYNArv1ICS INC

AUSTIN, TEXAS

Project No. 99-177.06 February 2006

99-177 DOW DWD No.1 Well Page i Plan .TERRA

Copyright © 2006 by Terra Dynamics Incorporated DYNAIV1ICS INC 03/01106

Table ofContents

List ofFigures ii · ...ppen Ices A d 111

1.0 General Description of Project 1-1 1.1 Well Construction Summary 1-1 1.2 Waste Cuttings and Fluid Management Program 1-6

2.0 Well Construction Prognosis 2-1

3.0 Well Construction Drilling Procedures 3-1 3.1 Location Preparation and Conductor Installation 3-1 3.2 Mobilization and Rig up ofDrilling Equipment.. 3-2 3.3 Surface Borehole and 11 7/8-inch Casing Installation 3-3 3.4 Long-string Borehole and 7 S/8-inch Casing Installation 3-9

4.0 Well Construction Completion Procedures 4-1 4.1 Long-string Casing Drillout and Pressure Testing Operations 4-1 4.2 James Lime Perforating and Development Operations 4-2 4.3 Pre-Completion Radioactive Tracer Survey and Injectivity Test 4-3 4.4 Injection Packer Installation 4-4 4.S Injection Tubing and Tree Installation 4-4

5.0 Mechanical Integrity and Injectivity Testing Procedures 5-1 5.1 Mechanical Integrity and InjectivitylFall-OffTesting 5-1

List ofFigures

Figure Title 1-1 Proposed Construction Schematic ofPlant Disposal Well DWD No.1 1-2 Proposed Protection Casing Detail for Plant Disposal Well DWD No.1 1-3 DPI Completion System 1-4 Wellhead and Tree Valve Arrangement for DWD No.1 1-5 Map to Dow Facility

99-177 DOW DWD No. 1 Well Page ii Plan .TERRA

Copyright © 2006 by Terra Dynamics Incorporated DVNArvJlCS INC 03/01/06

List ofAppendices

Appendice

Appendix A Appendix B Appendix C AppendixD Appendix E Appendix F Appendix G Appendix H

Title

Type Log for Anticipated Subsurface Environment Drilling Mechanics Mud Program Drill Pipe - Blowout Preventers Casing and Atlas Bradford Calculated Duplex 2205 ST-L Connection Data Cement and EPSEAL Compressive Test Data Calibration of Surface Equipment and Record Requirements Copy of ADEQ Permit for DOW DWD No. 1

99-177 DOW DWD No. I Well Page iii Plan .TERRA

Copyright © 2006 by Terra Dynamics Incorporated DVNAIVIICS INC 03/01106

1.0 GENERAL DESCRIPTION OF PROJECT

DOW's compliance with regulatory requirements, and thorough logging, sampling, and

testing of DWD No. 1 prior to operation, as outlined in the following well plan, will

ensure that the proposed injection well will be constructed in such a way as to prevent the

migration of injected fluids outside of permitted injection intervals. The injection well

has been designed such that both ground and surface fresh water will be adequately

protected. The following plan discusses the proposed procedures to drill, construct, and

test the DOW injection well according to the plans contained within the approved permit

document. Note that this plan is intended to serve as a guide only and may be

subject to changes that develop during field installation. Figure 1-1 is a schematic

representation of the proposed post-construction configuration for DWD No.1. Figure 1

2 is the proposed protection casing detail for DWD No. 1.

1.1 Well Construction Summary

The drilling rig selected for this project is Reliance Well Service Drilling Rig No.4. The

drill floor (DF) elevation for Reliance Rig No.4 is 12.0 feet above ground level (GL)

elevation. The kelly bushing (KB) elevation for Reliance Rig No.4 is 13.6 feet above

ground level (GL) elevation. For sake of convention, all relative ground surface

measurements converted to KB elevation will be rounded to the nearest whole foot or in

the case of Rig No. 4'8 13.6-foot KB elevation, will be referenced as being ~ feet.

Should there be a change in the drilling contractor, the well plan will be revised to

incorporate the necessary changes. DWD No.1 will be drilled to a planned total depth of

approximately 4,586 feet relative to GL elevation (4,600 feet KB). The proposed

injection zone is Mesozoic age strata in the approximate subsurface from 2,175 to 4,445

feet GL (2,189 to 4,459 feet KB). The proposed primary injection interval is the James

Lime Formation in the portion of the injection zone between the approximate subsurface

depths of 4,335 to 4,445 feet GL (4,349 to 4,459 feet KB). The proposed alternate

injection interval is the Tokio Fonnation in the portion of the injection zone between the

approximate subsurface depths of 2,885 to 3,070 feet GL (2,899 to 3,084 feet KB). The

99·177 DOW DWD No.1 Well Page 1-1 Plan eTERRA

Copyright © 2006 by Terra Dynamics Incorporated DVNAIV1ICS INC 03/01/06

confining zone is defined to be the lower shale unit of the Nacatoch Fonnation from

approximately 2,065 to 2,175 feet GL (2,079 to 2,189 feet KB). Appendix A contains a

type log of the anticipated subsurface environments expected to be encountered in DWD

No. 1 with all relative permit, casing and cementing information identified.

The 11 7/8-inch surface casing ofDWD No.1 will be set to approximately 1,586 feet GL

(1,600 feet KB) in 14 %-inch hole and cemented to surface. The base of the surface

casing will extend into confining beds below the base of the lowermost USDW and will

be cemented from the base of the casing to the surface using a minimum of 120 percent of

the calculated annular volume as determined from bore-hole geometry logs (or as

appropriate based on bore-hole conditions). This depth allows for protection of the

lower-most USDW {base at approximately 1,305 feet GL (1,319 feet KB)} from injected

fluids.

DWD No.1 will be completed with 7 5/8-inch long-string casing set to approximately

4,586 feet GL (4,600 feet KB) in 10 5/8-inch hole and cemented by circulating cement

from the base of the casing to the surface in two (2) stages, using a minimum of 120

percent of the calculated annular volume as determined from bore-hole geometry logs (or

as appropriate based on bore-hole conditions). Setting the casing at this depth allows for

a cased hole, perforated completion in either of the proposed injection intervals.

The 11 7/8-inch surface casing will consist of API Standard K-55 (or equivalent) grade

carbon steel proven to be compatible with shallow reservoir fluids. The 7 5/8-inch long

string casing will be a mixed string consisting of approximately 3,800 feet of N-80 (or

equivalent yield) grade carbon steel and approximately 800 feet of 7 5/8-inch Duplex

2205 casing. All of the long-string casing materials should be compatible with the

reservoir brines present below the DOW facility. In addition, compatibility testing

demonstrated that the Duplex casing material should provide the required corrosion

resistance to DOW's wastestream for DWD No.1. The surface casing and long-string

1"'"".;.,\",

l c)'- c'-,'"

99-177 DOW DWD No.1 Well Page 1-2 Plan eTERRA

Copyright © 2006 by Terra Dynamics Incorporated DYNAIVIICS INC 03/01/06

casing will be set using centralizers as appropriate to centralize the casing in the borehole

to allow for a more thorough cementing job.

The injection tubing will be 3 ~-inch, Future Pipe Industries (formerly Tubular Fiberglass

Company), Red Box 2,000 psi material (with Nexus Veil lining) engaged to a retrievable

packer system, set at approximately 4,270 feet (in the shale unit immediately above the

James Lime Injection Interval) in the Duplex 2205 section of 7 5/8-inch casing. The

packer will be a Groundwater Protection Systems (GPS), "Model 12" 7 5/8-inch x 3 Y2

inch, Hastelloy C-276 retrievable, full-bore packer which has been widely used in

injection well applications with very good results. Figure 1-3 presents a technical

drawing of the GPS Model 12 packer system proposed for use in DWD No.1.

The cement and casing to be used in the construction of the well have been designed for

the life expectancy of the well, including the post-closure care period in accordance with

40 CFR §146.65. The tubulars proposed for DWD No.1 (including connections), are

rated to have sufficient structural strength to withstand, for the design life of the well, the

maximum burst and collapse pressures which may reasonably be expected and the

maximum tensile stress, which may reasonably be expected at any point, along the length

of casing or tubing.

The cements selected for use in completing construction of DWD No. 1 are Halliburton

Lite Standard, Standard cement and EPSEAL synthetic cement. Previous materials

compatibility testing revealed that the EPSEAL synthetic cement should be resistant to

any corrosive effects due to contact with the Dow wastestream. EPSEAL is also

generally recommended for use by Halliburton in deepwell completions involving

exposure to low pH wastestreams. The cementing program for the 7 5/8-inch long-string

casing calls for cementing the casing in two stages as follows:

First Stage: 4,586 (±) to 2,680 (±) feet GL, (4,600 (±) to 2,694 (±) feet KB) Second Stage: 2,680 (±) GL to surface, (2,694 (±) feet KB to surface)

99-177 DOW DWD No. 1 Well Page 1-3 Plan eTERRA


The cement properties for the surface and longstring casings, based upon preparation and

testing of local field blends available for this project, are as follows:

11 7/8-Inch Surface Casing: Lead Slurry: Standard lite cement with 5 percent salt and Y4 lb/sk Pheno Seal Fine. Mixed at 12.8 lb/gal, 1.83 ft3/sk, 9.69 gal H20/sk. Tail Slurry: Standard cement with one (1) percent CaCh and Y4 lb/sk Pheno Seal. Mixed at 15.6lb/gal, 1.18 ft3/sk, 5.06 gal H20/sk.

7 5/8-Inch Longs/ring Casing: First Stage Slurry: EPSEAL Synthetic Cement. Epseal RE System with one (1) drum/drum Epsea1 RE, 0.25 gals/drum Plastic Fixer, 700 1b/drum SSA-l and 1.50 gals/drum LC Catalyst (or as required based on temperature data). Mixed at 13.8 1b/gal.

Second Stage Lead Slurry: Standard lite cement with 5 percent salt and 1!4 1b/sk Pheno Seal Fine. Mixed at 12.8 1b/ga1, 1.83 ft3/sk, 9.69 gal H20/Sk. Second Stage Tail Slurry: Standard cement. Mixed at 15.6 1b/ga1, 1.18 ft3/sk, 5.06 gal H20/sk.

Compatibility tests, discussions with vendors, past performance records and materials

brochures were also considered when selecting the materials to be used in constructing

the proposed injection well. Cementing will be by the inner string method for the surface

casing cementing operation and by the pump and plug method in combination with

staging for the long-string casing cementing operation.

After the long-string casing is set and cemented, the stage tools will be drilled and the 7

5/8-inch casing cleaned out to approximately 4,581 feet GL (4,595 feet KB). The James

Lime will then be perforated as indicated from open-hole logs. After perforating, the

bottom-hole pressure and bottom-hole temperature will be measured as close to the

completion depth as practical to obtain these initial reservoir conditions. In addition, the

static fluid level in the well will be determined.

After determination of the initial static bottom-hole pressure, the perforated interval will

then be thoroughly cleared of residual drilling fluid, as necessary, by producing formation

fluid as required. If necessary, any residual formation material or debris in the wellbore

will be bailed out under static wellbore conditions or circulated out of the wellbore as

99-177 DOW DWD No.1 Well Page 1-4 Plan .TERRA


required. A preliminary radioactive tracer survey and injectivity test will then be

performed to determine whether remedial cementing is required prior to final well

assembly and to provide an initial indication of injection performance.

The fmal phase of the completion will involve installation of a retrievable injection

packer and the running of the 3 Y2-inch fiberglass injection tubing. Figure 1-3 is a

diagram of the proposed injection packer and latching seal assembly. In addition, post

assembly mechanical integrity and reservoir testing consisting of an annulus pressure test,

a base-line temperature log, injectivity and pressure fall-off testing and a spinner survey

(or other flow profile survey) will be performed. A formal radioactive tracer survey will

also be performed following installation of completion equipment to meet ADEQ

requirements for demonstrating external mechanical integrity.

Injection tests conducted prior to putting the well into operation will provide estimates of

the permeability and thickness of the injection interval. Following the injectivity test, the

well will then be closed in for a pressure decay test. Bottom-hole pressure and surface

pressure will be recorded during the flow and shut-in periods. The results of these tests

will be utilized to calculate average reservoir pressure, permeability and reservoir extent.

The information derived from these tests will also be used to determine if stimulation is

required. Should stimulation be required, the stimulation program will be designed and

performed to enhance the injectivity of the target disposal formation. Following

stimulation, injectivity and fall-off testing will again be performed to evaluate the results

of the stimulation program and to calculate post-stimulation average reservoir pressure,

permeability and reservoir extent.

Following installation of the completion equipment, the slips will be set against the 3 Y2

inch Hastelloy C-276 landing joint, the landing joint cut and dressed as required and a

Duplex 2205 tubing head adapter installed to the tubing head. Three (3) Duplex 2205

stainless steel surface injection valves and a flow tee, comprising the injection tree

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Copyright © 2006 by Terra Dynamics Incorporated DVNAIVlICS INC 03/01106

assembly, will then be installed to the Duplex 2205 tubing head adapter. Figure 1-4 is a

diagram of the proposed injection wellhead and injection tree.

1.2 Waste Cuttings and Fluid Management Program

Considerations will be taken to properly dispose of any drilling mud and drill cuttings

produced from the well. Prior to rigging up the drill rig over the well location, the area

below the drill rig substructure will be graded and bermed as required. The bermed

containment area will be constructed in a manner to divert any collected liquids to a

below grade sump (well cellar). The containment area will collect drilling mud, rig wash

water, stormwater and other liquids that could spill onto the drill rig floor and fall below

the drill rig. The liquids from the sump will be pumped into the active rig pit.

In addition to a containment liner below the drill rig, the rig mud tanks will be above "ground steel tanks. A close~ !oop solids control syste~ will be used to drill this well due

to nature of the shallow groundwater and limited location available for the drill site.

Drilling mud circulated out of the borehole will flow through solids control equipment

consisting of two (2) high speed flow-line cleaners, a mud cleaner and two (2) high speed

centrifuges to remove drill cuttings and low gravity solids from the drilling mud. Since

the closest Class I injection well is over 8 miles from this location, the drill cuttings and

fluids are expected to be non-hazardous in nature. As such, the drill cuttings will be

stabilized with fly ash and stockpiled for future use on the DOW site.

The liquid drilling mud will be collected, hauled and disposed in approved liquid waste

injection wells or landfarmed as appropriate.

99-177 DOW DWD No. 1 Well Page 1-6 Plan .TERRA

Copyright © 2006 by Terra Dynamics IncoJllorated DVNAIV1ICS INC 03/01/06

2.0 WELL CONSTRUCTION PROGNOSIS

The following general drilling and completion prognosis is proposed for the disposal

well.

WELL NAME: DWD No.1

LOCATION: Dow/Albemarle Magnolia, Arkansas Facility

PERMITTED TOTAL DEPTH: 4,600 feet GL, 4,614 feet KB

PLANNED TOTAL DEPTH: 4,586 feet GL, 4,600 feet KB

DRILLING CONTRACTOR: Reliance Well Service Rig No.4

ELEVATION: GL at approximately 275 feet AMSL, KB is 13.6 feet above GL (rounded to 14 feet)

DISPOSAL INTERVALS: James Lime (Primary) from approximately 4,349 to 4,459 feet KB and Tokio Formation (Alternate) from approximately 2,899 to 3,084 feet KB

WELL DESIGN AND TEST SPECIFICATIONS:

DRILLING FLUID PROGRAM

Interval Type Weight Viscosity Water Loss LG (ft-KB) DriUing Fluid fimg} (sec/gt) (cc/30 min) Solids(%)

0-74 Conductor NA NA NA NA

74 to 1,600 Non-dispersed PHBIEZ 8.6 to 9.2 32 to 50 N/C to 15 <6 MudIPostassium Acetate

1,600 to 2,700 Non-dispersed PHBIEZ 8.8 to 9.4 34 to 65 20 to 10 <6 MudIPostassium Acetate

2,700 to 4,600 Non-dispersed PHBIEZ 8.8 to 9.5 34 to 65 10 to 6 <6 MudIPostassium Acetate

99-177 DOW DWD No. I Well Page 2-1 Plan eTERRA


LOGGING PROGRAM

Surface: 14 'I.-Inch Open Hole 11 7/8-Inch Cased Hole S.P., Dual Induction, Gamma RaY,1 Temperature, Cement j

4-Arm Integrated Borehole Caliper Bond LogNariable (with Directional Survey) Density Log/Gamma

Ray/Casing Collar Locator

Longstring: 10 S/8-Inch Open Hole 7 S/8-Inch Cased Hole S.P., Dual Induction Log, Gamma Ray, Temperature, Cement I Lithodensity, Compensated Neutron, Bond LogNariable Formation Microscanner (selected I Density Log/Gamma intervals), FMS as Dipmeter over Ray/Casing Collar remaining intervals, 4-Arm Integrated Locator, Base-line Casing Bore-hole Caliper (with Directional Survey), Inspection Logs and Side-wall Cores ifrequired.

CORING PROGRAM

Formation Approx Depth (ft-GLlKBl* ~ Nacatoch Shale (Confming Zone) 2,10612,120 feet Full Ozan Shale (Top ofInjection Zone) 2,62812,642 feet Full Tokio (Alternate Injection Interval) 2,97812,992 feet Full James Lime (Primary Injection Interval) 4,378/4,392 feet Full

Cores will be cut in 30-foot lengths using aluminum-sleeved or equivalent inner barrels to retain the sediments.

*Coring depths listed are approximate depths only. Actual picks will be determined by on-site project geologist.

FORMATION CORE SAMPLE TESTING PROGRAM

All COres will be recovered in aluminum-sleeved (or equivalent) inner barrels and recovery depths will need to be affixed upon retrieval. Once this has been accomplished, cores are to be sealed (to retain in-situ fluid content), and sent to a core laboratory for pertinent analyses.

Core testing to include:

Frequency Slabbing Entire length Standard Full Diameter Analysis Every foot Core Gamma Ray Entire length Vertical Penneability Selected samples in Confinement Zone Mineralog Analysis Selected samples from all cores


Copyright © 2006 by Terra Dynamics Incorporated DYNAIV1ICS INC 03/01/06

X-Ray Diffraction Selected samples in Tokio and James Lime

Scanning Electron Microscopy Selected samples in Tokio and James Lime

Thin Section Preparation and Petrography Selected samples in Tokio and James Lime

Waste to Formation Compatibility Selected samples in Tokio, James Lime and Confinement Zone

Mechanical Properties and Acoustic Velocity Selected samples in Tokio, James Line And Confinement Zone

FORMATION FLUID COMPATIBILITY TESTING PROGRAM

Representative samples of the composite waste streams will be provided by DOW for fluid compatibility testing with James Lime Formation (primary Injection Interval)water and cores. A sample of the James Lime Formation (Primary Injection Interval) water will be obtained after perforating by swabbing operations. Rapid turnaround compatibility testing with local fresh water and NaCI brine will need to be performed to determine whether these fluids will be satisfactory for use for injectiviiy testing and as completion fluids. If the James Lime Formation is determined to be unsuitable for injection based upon injectivity testing, then the Tokio Formation (Alternate Injection Interval) will be perforated and developed for injection use. Should this be the case, then the above formation fluid and core compatibility testing will be performed using Tokio Fonnation fluid.

CASING PROGRAM

Conductor: l6-inch, plain-end, beveled and welded carbon steel set to approximately 60 feet GL (74 feet KB) and cemented to surface with standard Portland cement with three (3) to four (4) percent bentonite and two (2) percent calcium chloride during location construction.

Surface: 11 7/8-inch, 71.8 lb/ft, J-55, with 11 %-inch, BT&C connections set in 14 %-inch hole from surface to approximately 1,600 feet KB and cemented to surface.

Longstring: 7 5/8-inch mixed string from surface to approximately 4,600 feet KB and cemented to surface in two (2) stages approximated as follows. Note that these depths are based upon the geologic type log prepared for this well (Appendix A) and will need to be adjusted as required to fit the open-hole log signature generated during the drilling ofthis welL

Surface to ±2,694 feet 7 5/8-inch, 26.4 lb/ft, N-80, LT&C ±2,694 to ±2,697 feet 7 5/8-inch Davis-Lynch Stage Tool


Copyright © 2006 by Terra Dynamics Incorporated DVNAIVIICS INC 03/01/06

±2,697 to ±2,787 feet 7 5/8-inch, 26.4lb/ft, N-80, LT&C ±2,787 to ±2,813 feet 7 5/8-inch Corrosion Protection Joint No.3 ±2,813 to ±3,213 feet 7 5/8-inch, 25.54Ib/ft, Duplex 2205, ST-L ±3,213 to ±3,243 feet 7 5/8-inch Corrosion Protection Joint No.2 ±3,243 to ±4,243 feet 7 5/8-inch, 26.4lb/ft, N-80, LT&C ±4,243 to ±4,269 feet 7 5/8-inch Corrosion Protection Joint No. 1 ±4,269 to ±4,544 feet 7 5/8-inch, 25.54Ib/ft, Duplex 2205, ST-L ±4,544 to ±4,547 feet 7 5/8-inch, 25.54Ib/ft, Duplex 2205,

Davis Lynch Float Collar, ST-L box x pin ±4,547 to ±4,597 feet 7 5/8-inch, 25.54Ib/ft, Duplex 2205, ST-L ±4,597 to ±4,600 feet 7 5/8-inch, 25.54Ib/ft, Duplex 2205,

Davis Lynch Float Shoe, ST-L box x plain end

CASING INSPECTIONS

11 7/S-inch Surface Casing: Hydrotest to 2,450 psi, Electronic Inspection White Band 0 to 25 percent (due to thick wall of substitute pipe), Special End Area Inspection, Full Length Drift to 10.625-inches.

7 SIS-inch CS Long-string Casing: Hydrotest to 4,800 psi, Electronic Inspection White Band 0 to 12 ~ percent, Special End Area Inspection, Full Length Drift to 6.844inches.

7 SIS-inch Duplex 2205 X-Ray ofall welds, Ultrasonic Testing, Longstring Casing and Thread Inspection and Gauging, Full Length Corrosion Protection Joints: Drift to 6.844 inches.

Note: All internal rack hydrotesting of carbon steel casing material will be conducted to a test pressure equivalent to 80 percent of the rated burst characteristics of the tube.

CEMENTING PROGRAM

Surface: Lead: 510 sacks of Lite Standard cement with 5 percent salt and 114 lb/sk Pheno Seal Fine mixed at 12.8 lb/gal, 1.83 ft3/sk, 9.69 gal HzO/sk to surface; then Tail: 200 sacks of Standard cement with one (1) percent CaCh and ~ lb/sk Pheno Seal Fine mixed at 15.6Ib/gal, 1.18 ft3/sk, 5.06 gal HzO/sk.

Calculated cement volume represented above includes a 20 percent excess for lead slurry open-hole volume plus shoe joint volume plus 9I'AI pipe /") volume (lead circulated to surface prior to pumping tail slurry) and 0 }iercent

./

excess for tail slurry. Actual system excess to be a minimum of 20 percent



above open-hole caliper volume or as required based upon local experience but no less than 20 percent excess to be applied.

Longstring:

- First Stage {4,586 to 2,680 feet GL, (4,600 to 2,694 feet KEn:

130 barrels (20 percent excess plus 6 barrels for waste) Epseal RE System with one (1) drum/drum Epseal RE, 0.25 gals/drum Plastic Fixer, 700 lb/drum SSA-l and 1.50 gals/drum LC Catalyst (or as required based on temperature data). Mixed at 13.8 lb/gal.

Calculated first stage Epseal volume represented above based on 7 5/8-inch casing in an average 10 5/8-inch hole and includes a 20 percent excess factor. Actual system excess to be a minimum of 20 percent above openhole caliper volume or as required based upon local experience but no less than 20 percent excess to be applied.

- Second Stage {2,680 feet GL to Surface (2,694 feet KE to Surface)}:

Lead: 385 sacks of Standard lite cement with 5 percent salt and Y-t lb/sk Pheno Seal Fine mixed at 12.8 lb/gal, 1.83 ft3/sk, 9.69 gal HzO/sk. Tail: 210 sacks Standard cement (185 sacks ahead of plug and 25 following plug) mixed at 15.6lb/gal, 1.18 ft3/sk, 5.06 gal HzO/sk.

Calculated second stage cement volume represented above based on 7 5/8inch casing in an average 10 5/8-inch hole and includes a 20 percent excess factor in the 7 5/8-inch casing x open-hole annular interval and 0 percent excess in the 7 5/8-inch x 11 7/8-inch annular interval. Actual system excess to be a minimum of 20 percent above open-hole caliper volume or as required based upon local experience but no less than 20 percent excess to be applied.

Note: Blend and pump time tests will be run prior to pumping each slurry using samples of mix water and bulk blends being used. All cement blends that may come in contact with the waste stream have been previously demonstrated to be compatible with the waste stream.

AUXILIARY CEMENTING EQillPMENT

Surface Casing: 1 - 11 7/8-inch Float Shoe 1 - 11 7/8-inch Float Collar 1- 11 7/8-inch Stab-in Adapter

18 - 11 7/8-inch Centralizers 2 - 11 7/8-inch Stop Rings


Copyright © Z006 by Terra Dynamics Incorporated DVN.A.IVIICS INC 03/01/06

Longstring Casing: 1 - 7 5/8-inch Duplex 2205 Down Jet Float Shoe 1 - 7 5/8-inch Duplex 2205 Float Collar 1 - 7 5/8-inch Stage Cementing Collar (mechanical opening)

27 - 7 5/8-inch Centralizers 30 -7 5/8-inch Plastic-Coated Turbolizers 28 -7 5/8-inch Carbon Steel Turbolizers 30 -7 5/8-inch Plastic-Coated Stop Rings

4 -7 5/8-inch Standard Carbon Steel Stop Rings

FLUID SAMPLING PROGRAM

Recover one quart of mud prior to each open-hole logging suite. Give to logging company for resistivity analysis. A sample of injection interval water will be obtained after perforating the James Lime Formation via swabbing for use in compatibility testing.

COMPLETION PROGRAM

Tubing: 3 Yz-inch, TFC Red Box 2,000 psi (with Nexus Veil Lining) with GPS Hastelloy C-276 latching seal assembly (with 2.75-inch integral bore polished profile) on bottom.

Packer: GPS "Model 12" Hastelloy C-276 7 5/8-inch x 3 Yz-inch full bore retrievable packer. Integral bore polished profile in bottom of packer =

2.625-inch ill. Top of packer will be set at approximately 4,270 feet KB (in shale package above top of James Lime Formation interval).

WELLHEAD DETAIL

Starting Flange: 11 7/8-inch slip-on-weld x II-inch, 3,000 psi WP

Tubing Head: 7 S/8-inch slip-on-weld x 7 lIl6-inch, 3,000 psi WP with two, 2-inch line pipe outlets and 2-inch, 2,000 psi ball valves. 3 Y2-inch slip type hanger with P-seal and 7 1I16-inch, 3,000 psi x 3-inch, ANSI, 600 lb, ring joint grooved Duplex 2205 Tubing Head Adapter. Landing joint is 3 Yz-inch Hastelloy C-276, 0.216-inch AW with 3 Yz-inch, EUE-8rd Long-form box down x NUB-lOrd pin up (with carbon steel collar for handling/landing).

Tree Valves: 3-inch nominal ill, AN"SI, 600 lb, ring joint grooved full-opening Duplex 2205 stainless steel ball valves. Main, crown and flow-line valves to be used with 7 1I16-inch, 3,000 psi WP x 3-inch ANSI, 600 lb, ring joint grooved Duplex 2205 Tubing Head Adapter and 3-inch ANSI, 600 lb, ring joint grooved Duplex 2205 stainless steel tee.



MECHANICAL INTEGRITY TEST PROGRAM

1) Annulus Pressure Test to 1,000 psi for 30 minutes.

2) Differential Temperature Survey from surface to total depth after well has been static for 36 hours.

3) Radioactive Tracer Survey.

4) Spinner Survey.

AMBIENT PRESSURE MONITORING PROGRAM

1) Gradient stop checks to identify fluid level and wellbore fluid gradient profile.

2) Static bottom-hole pressure survey at 4,329 feet (or as required to be at least 20 feet above perforated interval) for four (4) hours.

3) Step rate injectivity and fall-off testing to evaluate hydrologic capacities of the of the James Lime Formation reservoir.


Copyright © 2006 by Terra Dynamics Incorporated DVN.A.IVIICS INC 03/01/06

3.0 WELL CONSTRUCTION DRILLING PROCEDURES

.. The DOW DWD No. 1 drilling and completion program, consistent with pertinent federal

and state regulations, is outlined in the following sections. The basic down-hole well

design provides for drilling and completion to a depth of approximately 4,586 feet GL,

(4,600 feet KB). Note that all depths herein have been corrected to reflect a 13.6-foot KB

elevation rounded to 14-foot which is the KB elevation for the rig selected for this

project.

The DOW DWD No.1 drilling and completion program is described as follows:

3.1 Location Preparation and Conductor Installation:

1. Survey and stake well centerline location as required to fit rig layout. Obtain ground level (GL) elevation and provide this information to TDI for conveyance to logging company for header information.

2. Mobilize and rig up cellar and conductor auger equipment.

3. Auger out 72-inch hole to a depth of approximately 5 feet as required to install 6-foot diameter cellar. Set 6-foot diameter well cellar with centerline of well location located in center of cellar. Backfill around cellar as required.

4. Auger out 26-inch hole in center of cellar to approximately 60 feet GL.

5. Install approximately 62 feet of 16-inch OD, 0.219-inch wall conductor with appropriate centralization inside of 26-inch hole (leaving 24-inches sticking up above ground level for installation of rig's drilling riser and bell nipple).

6. Cement 26-inch x 16-inch annulus from approximately 60 feet to base of cellar with grout mixture of standard Portland cement with three (3) to four (4) percent gel and two (2) percent calcium chloride and allow grout to cure over night.

7. Cap base of cellar with approximately I-foot, 2-inches of concrete such that depth to top of cement in cellar is no greater than 3-feet, 10 inches below ground surface elevation. Rig down and release conductor augering company and cementing company.

99-!77DOWDWDNo.! Well Page 3-1 Plan .TERRA03/01106 Copyright © 2006 by Terra Dynamics IncollJorated DYNAIVIICS INC

8. Allow conductor grout and concrete in base of cellar to cure for approximately two (2) weeks prior to mobilizing rig.

9. Assure that a copy of the ADEQ Permit is available to site supervisory personnel.

Note: Ms. Laura Stuart of the Arkansas Department of Environmental Quality (ADEQ) Office of Conservation (501) 682-0642 should be given advance notification of spud date and 24 hour advance courtesy notification of cementing, casing pressure testing, cased-hole logging and mechanical integrity testing so she or her staff may have the opportunity to witness any of the above operations.

3.2 Mobilization and Rig up of Drilling Equipment:

1. Ascertain number and placement of frac tanks for storage of excess mud and dewatered fluids that will be generated during drilling and cementing operations. Frac tanks will need to be first equipment mobilized and spotted on location prior to rig mobilization.

2. Move in drilling rig and equipment and rig up. Assure that drilling rig is level and that rotary table is centered exactly over center of conductor and can accommodate a 14 %-inch bit. Mobilize and rig up any necessary solids control equipment.

3. Cut out 2-inch hole and weld on 2-inch nipple below pre-determined 16inch and 11 7/8-inch cut point to drain annulus of cement from the 11 7/8-inch cement job. Screw on 2-inch bull plug. Note that the 11 718inch SOWx 11-inch, 3,000 psi WP rental startingjlange will need to be set at ground level elevation after cutting 16-inch and 11 718-inch casings.

4. Install rig's drilling riserlbell nipple and space out under rig floor for height requirements of flowline. Nipple up flowline and boot from 16inch bell nipple to shakers. Run shaker bypass line out from shaker stand to point where line can be routed to a steel tank (or reserve pit) for taking excess cement returns. Rig to drill own mousehole and rathole.

5. Check drill pipe, drill collars, changeover subs and kelly inspection papers. Make sure that no coarse or external hardbanding is on any drill pipe or drill collars. Do not accept rig if there is any doubt about the condition of the drill pipe or drill collars or ifno inspection papers are available. Obtain and confirm the number of joints of drill pipe, heavy wate drill pipe (if applicable) and drill collars on location.


Copyright © 2006 by Terra Dynamics Incorporated DVNArvllCS INC 03/01106

3.3 Surface Borehole and 11 7/8-Inch Casing Installation:

1. Build surface mud volume to fill all active rig tanks prior to spudding. Assure adequate pre-hydration period for bentonite to obtain maximum yield (approximately 6 hours). Do not use peptized bentonite (subquality bentonite treated with PHPA) while drilling this well. Have a lost circulation pill blended to drilling fluid specialist's recommendations and circulating in 100-barrel pill tank in case lost circulation occurs while drilling this interval.

2. Arrange for delivery of 11 7/8-inch casing to location. Offload casing to pipe racks using cherry picker with double nylon web slings or extended reach forklift with coupling ends toward rig. Note that each joint of 11 7/8-inch will weigh approximately 3,000 pounds. Arrange to have thread protectors removed and threads inspected in advance of running. Note that the original storage dope was removed and Preserv-A-Thread compound applied prior to shipment to site. This does not require steam or power thread cleaning to remove. It wipes off readily with a rag. Clean off shortly before running to prevent rust and inspect threads for blast beads, etc. Do not use any pipe dope compound on 11 7/8-inch casing connections when re-installing thread protectors.

3. Pick up 14 %-inch bit (with crow's foot installed), two (2) 8-inch drill collars with 14.625-inch OD (lI8-inch under 14 %-inch bit diameter) welded blade stabilizer (WBS) at 60 feet (or as local experience dictates) and up to twelve 6 'l4-inch drill collars as required. Caliper OD and ill of collars prior to picking up.

4. Drill a 14 %-inch borehole to approximately 1,600 feet (or slightly deeper to fit casing tally such that casing can be landed with the top connection near the rig floor). Do not drill with excessive hydraulics when drilling out of the conductor and the first 500 feet of 14 %-inch surface borehole to minimize potential for washing out around the conductor. Control drill at penetration rates justified by the lithology being drilled but being careful to avoid loading the fluid returns with excessive cuttings. Attempt to drill through the sand sequences as quick as possible to establish a wall cake and minimize washouts due to circulating erosion. If hole cleaning problems are encountered, slow down penetration rates in the shale units (where washout problems should be minimal) to circulate and clean the hole. Use the minimum circulation rate to adequately clean the borehole and use viscous sweeps as necessary. Hole should be drilled with drilling fluid under laminar flow conditions and with appropriate fluid loss control as indicated in the mud program included as Appendix C. Short trip as required to wipe and

99-177 DOWDWDNo. 1 Well Page 3-3 Plan .TERRA

Copyright © 2006 by Terra Dynamics Incorporated DYNArvJlCS INC 03/01106

clean the borehole. Obtain inclination surveys every 250 feet from base of conductor to surface casing point.

Note: Major lost circulation zones are not anticipated while drilling the surface hole. However, drilling fluid seep losses can occur in some of the sand units. Formation breakdown is possible if gumbo shale packs off around bottom-hole assembly causing high bottom-hole pressures while drilling this interval.

14 %-inch Bore-hole Drilling Lost Circulation Contingency Plan If circulation is lost while drilling the 14 %-inch borehole, lost circulation material (LCM) pills will be pumped to re-establish circulation. Depending upon the severity of lost circulation encountered, LCM may need to be blended with the drilling fluid in concentrations dictated by hole conditions to maintain circulation to the 11 7/8-inch casing point.

Should lost circulation occur while drilling from the base of conductor to the 11 7/8inch surface casing point, paper, cottonseed hulls or other forms of standard LCM may be used to remedy the loss condition.

5. Circulate and condition hole and mud to optimum properties for logging. Pull out ofhole and stand back 14 %-inch bit and bottom-hole assembly.

6. Rig up loggers. Run Spontaneous Potential, Dual Induction, Natural Gamma Ray, 4-arm Integrated Bore-hole Caliper log (with continuous directional survey) from TD to surface. Calculate and order cement volumes based upon results of integrated bore-hole caliper log. Assure that 50 percent excess of the calculated Halliburton Lite lead slurry volume is ordered to location in case lost circulation occurs during cementing. Any significant volume of unused excess can be stored by Halliburton for use on the 7 5/8-inch casing second stage lead cement job. Record time since cessation of circulation and maximum recorded bottom hole temperature obtained during logging operations. Convey this information to Halliburton for adjusting cement slurry acceleration or retardation additives as required. Obtain sample of cement mix water for compatibility analysis to be performed by Halliburton laboratory prior to cementing operations. After completion of logging, instruct loggers to provide three (3) copies of field prints (labeled as field copy) prior to leaving location. Final prints to be generated at end of job after all tallies and log header information has been verified.

7. Trip back to bottom with 14 %-inch bit and drilling assembly. Work and ream any tight spots that may be encountered. Circulate and condition hole and mud to optimum properties for running casing. Assure that hole is standing full to minimize differential sticking tendency of large diameter casing across anticipated seep/loss zones, otherwise circulate LCM pill prior to pulling out of hole with 14 %-inch bit and


Copyright © 2006 by Terra Dynamics Incorporated DVNAI'VIICS INC 03/01/06

drilling assembly. Pull out of hole and lay down l4.625-inch OD WBS and 14 %-inch bit.

8. Run 11 7/8-inch OD, 71.8 lb/ft, J-55, BT&C (note that connection is 11 %-inch BT&C) casing to approximately 1,600 feet. Use Davis-Lynch float shoe, one (1) joint casing with thread-locked mill-end coupling identified by yellow painted coupling, Davis-Lynch stab-in float collar and other two (2) joints with thread-locked mill-end coupling identified by yellow painted couplings. Threadlock float shoe, shoe joint, float collar and next joint up and make up threadlocked connections to positional triangle makeup point as indicated on threads. Use APIModified thread compound on all non-threadlocked connections and make up connections to positional triangle makeup point as indicated on threads. Run Davis-Lynch centralizers as follows:

1 - center of shoe joint on stop ring 1 - center ofjoint above float collar on stop ring 1 - across collar on joint above float collar

14 - across every other collar to surface

11 7/8-inch, 71.8 lb/ft J-55 (Nominal), with 11 %-inch, BT&C Casing Specifications are as Follows:

Wall 0.582-inches I.D. 10.71 I-inches Drift 10.625-inches Coupling O.D. 12.75-inches Collapse 3,880 psi* Burst 4,720 psi* Pipe Body Strength 1,135,0001bs* Joint Strength 1,24l,0001bs* Capacity 0.1114 bbls/ft *Denotes values calculated from API 5C3 for J-55 nominal grade

9. Mobilize Halliburton to location. Rig up to fresh (mix) water supply. Run 2-inch line from RCM blender/pumper to rig floor and manifold bulk units to RCM blender/pumper as required. Assure that ample supply of fresh mix water is available on location for cementing operations. Obtain samples, of each dry mix cement, from bulk units and give to DOW to archive as required.

10. Set slips on last joint of 11 7/8-inch casing with casing just off bottom in full tension and top of casing as close to rig floor as practica1. Lay down casing elevators and rig up to run 4-inch drill pipe.



11. Pick up first joint of 4-inch drill pipe and make up Davis-Lynch Tag-In Adapter on bottom and install one centralizer and stop ring 10 feet above adapter. Run Tag-In Adapter seal on first joint of 4-inch drill pipe and install false rotary plate and slips on top of casing. Install drill pipe wiper rubber on 4-inch drill pipe to prevent foreign objects from falling into the 11 7/8-inch casing during drill pipe run-in.

12. Run drill pipe to within one joint of Tag-In Receiver in float collar.

13. Make up the last joint of drill pipe to the joint in the bowl and slips. Pick up the weight of the drill string and unset the slips. Clear the bowl and false rotary plate from the top ofcasing.

14. Lower drill pipe until the Tag-In Adapter engages in the receiver above the float collar. Set down all drill pipe weight. Attempt to space out drill pipe such that all connections can be reached from the floor. Ifpossible, stay tagged into the receiver until the job is complete to avoid damage to the o-rings on the Tag-In Adapter. Chain and boom 11 7/8-inch casing to prevent hydraulic pumping out of hole during cementing operations.

15. Install pump-in sub with low torque value to the drill pipe. Then establish circulation to insure that a seal between the adapter and receiver has been established and that the drill pipe is clear and ready for pumping operations.

16. Circulate and condition hole and mud to establish optimum properties commensurate with good cementing practices. After completion of circulating and conditioning operations, transfer required amount of active pit mud volume to frac tanks for storage and/or dewatering as required. Based upon calculated open-hole integrated caliper volumes, assure that ample frac tank capacity is available to accommodate drilling fluid returns during cementing operations. Release casing crew and all non-used casing running equipment after completion of circulation operations to avoid additional costs for standby equipment unless other arrangements have been made with casing crew for no standby charges.

17. Pump 30 barrels fresh water spacer then cement 11 7/8-inch OD surface casing from TD to surface with a lead slurry of 510 sacks (or as required based upon actual hole volume calculated from 4-arm caliper plus a minimum of 20 percent excess [50 percent excess over intervals where caliper does not indicate wall contact]) of Halliburton Light Standard Cement with 5 percent Salt and 14 lb/sk Pheno Seal Fine mixed at 12.8 lb/gal, 1.83 ft

3/sk, 9.69 gal H20/sk until lead cement returns are observed

at surface. Mix and pump lead cement at 7 to 8 barrels per minute.

99-177 DOW DWD No. 1 Well Page 3-6 Plan _TERRA

Copyright © 2006 by Terra Dynamics Incorporated DVNAIV1ICS INC 03/01106

Note: Only 303 sacks of lead cement are required to occupy the annular volume from 1,100 feet to surface under gauge hole conditions with 20 percent excess applied. However, the 510 sacks of lead cement specified include the entire annular volume with 20 percent excess applied plus the shoe joint plus the drill pipe capacity of cement that will be required to assure circulation of lead cement to surface prior to switching to the proposed tail slurry.

18. Divert lead cement returns to steel tank and retard as required with sugar. Then pump a tail slurry of 200 sacks (or as required to assure 500 feet of tail coverage) of Standard Cement with one (1) percent CaClz and ~ lb/sk Pheno Seal Fine mixed at 15.6 lb/gal, 1.18 ft3/sk, 5.06 gal H20lsk. Mix and pump tail cement and displacement at 7 to 8 barrels per minute.

11 7/8-inch Casing Cementing Lost Circulation Contigency Plan If circulation is lost while performing the lead cementing operation for the 11 7/8-inch casing, reduce cementing pump rate to between 1/3 and Y2 of the mixing and pumping rate to reduce ECD and continue mixing and pumping lead slurry to attempt to re-establish returns. Should lost circulation occur while mixing, pumping and/or displacing the tail slurry, continue mixing, pumping and/or displacing the tail slurry as required.

After completion of the cement job, the operator will drill out the float equipment and conduct cement bond and/or temperature logging to determine the top of cement. The operator will then evaluate options to obtain sufficient cementing. If necessary, the operator will perforate and squeeze to complete cementing. Once sufficient isolation has been demonstrated, no further action should be required since the 11 7/8-inch surface casing will be behind cemented 7 5/8-inch longstring casing following 7 5/8-inch longstring installation.

Should cement fall-back occur after completion of cementing operations, the top ofcement will be identified from a temperature log or the post-drillout bond log. If necessary, the casing would then be cemented externally (top job) using thin tubing, to ensure sufficient cementing is accomplished.

19. Displace drill pipe with the required amount of mud to displace cement to within one barrel of float collar - do not overdisplace and create a wet shoe condition since won't be able to use latching drill pipe wiper plug due to ill of 4-inch drill pipe.

19. Check that float shoe is holding. Unsting from float collar and re-verify that float system is holding. Dump remaining cement on top of float collar and pull out of hole with 4-inch drill pipe and Tag-In Adapter seal. Lay down and return seal to cementing representative. Request that any significant volume of unused lead excess cement can be stored by Halliburton for use on the 7 5/8-inch casing second stage lead cement job.



20. Drain cement in the 16-inch x 11 7/8-inch annulus below 11 7/8-inch cut point through 2-inch drain nipple and wash out 16-inch riser and bell nipple to pre-determined cut point.

21. Keep 11 7/8-inch casing in full tension and wait on cement for a minimum of 12 hours.

22. Rig up loggers. Run Temperature Log from TD to surface within 12 hours of completion of cementing. Pull out of hole with logging tool and release loggers. After completion of logging, instruct loggers to provide 3 copies of field prints (labeled as field copy) prior to leaving location. Final prints to be generated at end of job after all tallies and log header information has been verified.

Note: If cement did not circulate during cement job, locate top of cement from temperature log and make plans to top off prior to proceeding with the drilling of the 10 5/8-inch hole.

23. Cut off 16-inch conductor riser and 11 7/8-inch casing at required cut point.

24. Install 11 7/8-inch slip-on-weld (SOW) x II-inch, 3,000 psi working pressure (WP) rental starting flange. Note that flange will require an inside and outside weld - assure that there is no inside weld bead that could interfere with running of the 10 S/8-inch bit or other equipment. Test welds to 1,000 psi after welds have cooled.

25. Nipple up II-inch, 3,000 psi WP x II-inch, 3,000 psi WP drilling spool and II-inch, 3,000 psi WP RRA blowout preventer stack (BOP) to drilling flange.

26. Strap in hole with 10 S/8-inch bit and slick bottom-hole drilling assembly to float collar. Pressure test II-inch BOP equipment and 11 7/8-inch OD surface casing to 250 psi (low pressure test) and 1,000 psi (high pressure test) for a minimum of 30 minutes each to determine whether gross failure ofcasing or BOP exists. Report results oftesting.

27. Drill out 11 7/8-inch float collar and float joint to within 5 feet of float shoe. Pull out ofhole and stand back 10 5/8-inch drilling assembly.

28. Rig up loggers. Run Cement Bond with Variable Density Log, Gamma Ray and Casing Collar Locator from TD to surface after approximately 48-hour wait-on-cement (WaC) period. After completion of logging, instruct loggers to provide three (3) copies of field prints (labeled as field



copy) prior to leaving location. Final prints to be generated at end of job after all tallies and log header infonnation has been verified.

3.4 Long-string Borehole and 7 5/8-inch Casing Installation:

1. Arrange for delivery of 7 5/S-inch casing to location. Offload casing to pipe racks using forklift or cherry picker with double nylon web slings with coupling ends toward rig. Exercise extreme care when handling Duplex 2205 casing and JGC corrosion protection joints and lay down on board runs strapped to pipe racks or laid across top row of carbon steel casing - do not stack any pipe on top of Duplex 2205 or JGC corrosion protection joints. Note that each joint of 7 5/8-inch casing will weigh approximately 1,100 pounds. Arrange to have thread protectors removed, threads cleaned and inspected in advance of running. Note that the original storage dope was removed and Preserv-A-Thread compound applied prior to shipment to site. This does not require steam or power thread cleaning to remove. It wipes off readily with a rag. Clean off shortly before running to prevent rust and inspect threads for blast beads, etc. Do not use any pipe dope compound on 7 5/8-inch casing connections when re-installing thread protectors.

2. Run back in hole with 10 5/8-inch bit (with crow's foot installed) with two (2) S-inch drill collars, twelve 6 'i4-inch drill collars and install 10 12inch OD (lIS-inch under 10 5/S-inch bit diameter) WB string stabilizers at 60 and 90 feet (or as local experience dictates) for pendulum drilling assembly to within 5 feet above float shoe. Drill out shoe using mud from previous hole section. After drilling shoe, begin to break over mud system according to plan in drilling fluids section included as Appendix C.

3. Drill a 10 5/8-inch borehole to approximately 2,120 feet (or as directed by site geologist for first core point in the Confining Zone). Control drill at penetration rates justified by the lithology being drilled but being careful to avoid loading the fluid returns with excessive cuttings. Ifhole cleaning problems are encountered, slow down penetration rates in the shale units (where washout problems should be minimal) to circulate and clean the hole. Use the minimum circulation rate to adequately clean the borehole and use viscous sweeps as necessary. Hole should be drilled using drilling fluid with rheological properties and appropriate fluid loss control as indicated in the mud program included as Appendix C. Obtain inclination surveys every 250 feet from base of 11 7/8-inch surface casing to core point. Short trip as required to wipe and clean the borehole.


Copyright © 2006 by Terra Dynamics Incorporated DVNArvllCS INC 03/01106

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5.

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8.

9.

Trip out of hole and stand back 10 5/8-inch drilling assembly. Gauge bit and evaluate cutting structure. Ifnecessary, make magnet and junk basket run as dictated by bit condition prior to running coring assembly.

Mobilize coring service. Pick up coring assembly and strap in hole. Rig up and cut (1) 4-inch x 30-foot whole core of Confining Zone (Nacatoch Shale). Trip out of hole and lay down core. Break out and stand back coring assembly.

Trip back in hole with 10 5/8-drilling assembly. Ream hole to base of core point and drill 10 5/8-inch borehole to approximately 2,642 feet (or as directed by site geologist for second core point in the Injection Zone). Control drill at penetration rates justified by the lithology being drilled but being careful to avoid loading the fluid returns with excessive cuttings. If hole cleaning problems are encountered, slow down penetration rates in the shale units (where washout problems should be minimal) to circulate and clean the hole. Use the minimum circulation rate to adequately clean the borehole and use viscous sweeps as necessary. Hole should be drilled using drilling fluid with rheological properties and appropriate fluid loss control as indicated in the mud program included as Appendix C. Obtain inclination surveys every 250 feet from first core point to second core point. Short trip as required to wipe and clean the borehole.

Trip out of hole and stand back 10 5/8-inch drilling assembly. Gauge bit and evaluate cutting structure. If necessary, make magnet and junk basket run as dictated by bit condition prior to running coring assembly. Pick up coring assembly and strap in hole.

Rig up and cut one (1) 4-inch x 30-foot whole core of Injection Zone (Ozan Shale). Trip out of hole and lay down core. Break out and stand back coring assembly.

Trip back in hole with 10 5/8-inch drilling assembly. Ream hole to base of core point and drill 10 5/8-inch borehole to approximately 2,992 feet (or as directed by site geologist for third core point in the Alternate Injection Interval). Control drill at penetration rates justified by the lithology being drilled but being careful to avoid loading the fluid returns with excessive cuttings. Ifhole cleaning problems are encountered, slow down penetration rates in the shale units (where washout problems should be minimal) to circulate and clean the hole. Use the minimum circulation rate to adequately clean the borehole and use viscous sweeps as necessary. Hole should be drilled using drilling fluid with rheological properties and appropriate fluid loss control as indicated in the mud program included as Appendix C. Obtain inclination surveys every 250

99-177 DOW DWD No. I Wen Page 3-10 Plan .TERRA

Copyright © 2006 by Terra Dynamics Incorporated DVN.A.IV1ICS INC 03/01/06

feet from second core point to third core point. Short trip as required to wipe and clean the borehole.

At approximately 2,700 feet, begin to tighten up drilling fluid properties in accordance with plan in drilling fluids section. Also, be aware that Anhydrite intervals will be encountered below 3,300 feet which will most likely cause mud flocculation to occur while drilling the Anhydrite necessitating mud treatment. Begin decanting barite from mud system. Replace weighting and slugging agent as necessary with graded calcium carbonate (to minimize potential for damage to injection intervals).

10. Trip out of hole and stand back 10 S/8-inch drilling assembly. Gauge bit and evaluate cutting structure. If necessary, make magnet and junk basket run as dictated by bit condition prior to running coring assembly. Pick up coring assembly and strap in hole.

11. Rig up and cut one (1) 4-inch x 30-foot whole core of the Alternate Injection Interval (Tokio Fonnation). Trip out of hole and lay down core. Break out and stand back coring assembly.

12. Trip back in hole with 10 S/8-inch drilling assembly. Ream hole to base of core point and drill 10 S/8-inch borehole to approximately 4,392 feet (or as directed by site geologist for fourth core point in the Primary Injection Interval). Control drill at penetration rates justified by the lithology being drilled but being careful to avoid loading the fluid returns with excessive cuttings. If hole cleaning problems are encountered, slow down penetration rates in the shale units (where washout problems should be minimal) to circulate and clean the hole. Use the minimum circulation rate to adequately clean the borehole and use viscous sweeps as necessary. Hole should be drilled using drilling fluid with rheological properties and appropriate fluid loss control as indicated in the mud program included as Appendix C. Obtain inclination surveys every 250 feet from third core point to fourth core point. Short trip as required to wipe and clean the borehole.

13. Trip out of hole and stand back 10 S/8-inch drilling assembly. Gauge bit and evaluate cutting structure. If necessary, make magnet and junk basket run as dictated by bit condition prior to running coring assembly. Pick up coring assembly and strap in hole.

14. Rig up and cut one (1) 4-inch x 30-foot whole core of the Primary Injection Interval (James Lime Fonnation). Trip out ofhole and lay down core. Break out and lay down coring assembly. Release coring services.



15. Trip back in hole with 10 5/S-inch drilling assembly. Ream hole to base of core point and drill 10 5/S-inch borehole to planned total depth of approximately 4,600 feet (or as required to accommodate longstring casing strap). Control drill at penetration rates justified by the lithology being drilled but being careful to avoid loading the fluid returns with excessive cuttings. If hole cleaning problems are encountered, slow down penetration rates in the shale units (where washout problems should be minimal) to circulate and clean the hole. Use the minimum circulation rate to adequately clean the borehole and use viscous sweeps as necessary. Hole should be drilled using drilling fluid with rheological properties and appropriate fluid loss control as indicated in the mud program included as Appendix C. Obtain inclination surveys every 250 feet from fourth core point to total depth. Short trip as required to wipe and clean the borehole.

Continue decanting barite from mud system. Replace weighting and slugging agent as necessary with graded calcium carbonate (to minimize potential for damage to injection intervals).

10 518-inch Bore-hole Drilling Lost Circulation Contingency Plan If circulation is lost while drilling the 10 S/8-inch borehole, stop drilling and pick up above the suspected lost circulation zone. Lost circulation material pills will be pumped to reestablish circulation. If unable to regain circulation or maintain the recommended bentonite concentration in the drilling fluid, pull out of hole to base of 11 7/8-inch casing, rebuild volume to recommended properties and resume drilling activities.

Depending upon the severity of lost circulation encountered, lost circulation material may need to be blended with the drilling fluid in concentrations dictated by hole conditions to maintain circulation to the casing point. The operator must be cognizant of the formation where loss of circulation occurs as this will dictate the choice of lost circulation material used to restore circulation.

16. Circulate and condition hole and mud to optimum properties for logging. Pull out ofhole and stand back 10 5/S-inch bit and bottom hole assembly.

17. Rig up loggers. Run open hole logs of 10 5/S-inch borehole which include Spontaneous Potential, Dual Induction Log, Gamma Ray, Lithodensity, Compensated Neutron, Formation Microscanner 4-Ann Integrated Bore-hole Caliper log (with Directional Survey). Logs run from TD to bottom of surface casing with the exception of the Formation Microscanner which is to be run from TD to base of surface casing acquiring approximately 1,000 feet of EMI data with the remaining approximately 2,000 feet of EM! being run as dipmeter - Note: site geologist to call intervals for Formation Microscanner data acquisition.

99-177 DOWDWDNo. 1 Well Page 3-12 Plan eTERRA


Calculate and order cement volumes based upon results of the integrated bore-hole caliper log. Record time since cessation of circulation and maximum bottom-hole temperature recorded during last logging operation. Convey this information to Halliburton for adjusting cement slurry acceleration or retardation additives as required. Obtain samples of cement mix water for compatibility analysis (for second stage cement) to be performed by Halliburton prior to cementing operations.

After completion of logging, instruct loggers to provide three (3) copies of field prints (labeled as field copy) prior to leaving location. Final prints to be generated at end of job after all tallies and log header infonnation has been verified.

18. Trip back in hole with 10 5/8-inch bit and drilling assembly. If required, based upon open hole log and core evaluation continue to drill 10 5/8inch hole to assure that the 7 5/8-inch casing is set at a depth that completely penetrates the anticipated James Lime with approximately 150 feet of rathole below the base of the James Lime (giving consideration to the amount of Duplex 2205 casing available for the project). Re-Iog lower section of well if deepened substantially following logging program and notification requirements as specified in Step 17.

19. Circulate and condition hole and mud to optimum properties m preparation for running casing - assure that hole is standing full, otherwise circulate non-damaging LCM pill prior to pulling out of hole with 10 5/8-inch bit and drilling assembly.

20. Pull out ofhole and lay down drill pipe and 10 5/8-inch drilling assembly.

21. Mobilize and rig up casing crew with rubber trough pick upllaydown machine. Run 7 5/8-inch combination carbon steel and Duplex 2205 longstring casing from surface to approximately 4,600 feet using Varco 150 ton Elevator, Slips and Spider dressed with fme-tooth, nondirectional dies and non-marking slip inserts for power tongs when running alloy casing sections. Use Torque Tum System Test Monitor while running the 7 5/8-inch combination casing string. Assure that Atlas Bradford Representative is on location to assist with makeup of 7 5/8inch Duplex 2205 casing with Atlas Bradford ST-L connections.

Note that the depths indicated below are based upon the geologic type log prepared for this well (Appendix A) and will need to be adjusted as required to fit the specific open-hole log signature generated during the drilling of this well. Specific material transitions have been indicated in the bolded text following the anticipated depths specified with

99-177 DOW DWD No. I Well Page 3-13 Plan .TERRA


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each casing section along with critical spaceout criteria. Run 7 5/8inch mixed casing string as required to fit the geologic environment indicated via open hole logging - do not exceed 40 feet per minute running speed to minimize surge pressure on formations due to running operations:

Three (3) foot long, 7 5/8-inch, 0.328-inch wall, Duplex 2205 DavisLynch float shoe with Atlas Bradford ST-L flush joint box up connection. Use thread-lock compound on connection. Make up connection until it shoulders, then bring up torque to the recommended range of between 2,900 to 3,700 ft-Ibs or as directed by the Atlas Bradford representative. (4,600 to 4,597 feet).

Two (2) joints (approximately 50 feet) of 7 5/8-inch, 0.328-inch wall, Duplex 2205 casing with Atlas Bradford ST-L flush joint pin x box connections. Use thread-lock compound on connections. Make up connection until it shoulders, then bring up torque to the recommended range of between 2,900 to 3,700 ft-Ibs or as directed by the Atlas Bradford representative. (4,597 to 4,547 feet).

Three (3) foot long, 7 5/8-inch, 0.328-inch wall, Duplex 2205 DavisLynch float collar with Atlas Bradford ST-L flush joint pin down x box up connection. Use thread-lock compound on float collar connections. Make up connection until it shoulders, then bring up torque to the recommended range of between 2,900 to 3,700 ft-Ibs or as directed by the Atlas Bradford representative. (4,547 to 4,544 feet).

11 joints (approximately 275 feet) of 7 5/8-inch, 0.328-inch wall, Duplex 2205 casing with Atlas Bradford ST-L flush joint pin x box connections. Use Best of Life Premium Thread Compound (PTC) on connections. Make up connection until it shoulders, then bring up the torque to the recommended range of between 2,900 to 3,700 ft-Ibs or as directed by the Atlas Bradford representative. (4,544 to 4,269 feet or as required to locate the top of the Duplex 2205 casing (including approximately 24feet of the Duplex 2205 from the Corrosion Protection Joint No.1) approximately 100 feet into the shale unit above the top of the James Limestone unit).

Corrosion Protection Joint No.1: Approximately 26 feet overall length consisting of 24 foot, 7 5/8-inch, 0.328-inch wall, Duplex 2205 casing with Atlas Bradford ST-L pin down and 2-foot, 7 5/8-inch, 26.4 lb/ft, N80, LTC-8rd box up drifted to 6.844-inch ill (same as 26.4lb/ft material). Use Best of Life PTC on ST-L pin connection. Make up connection until it shoulders, then bring up torque to the recommended range of between


Copyright © 2006 by Terra Dynamics Incorporated DYNAIV1ICS INC 03/01/06

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2,900 to 3,700 ft-Ibs or as directed by the Atlas Bradford representative for the flush joint connection. (4,269 to 4,243 feet).

Approximately 1,000 feet of 7 5/8-inch, 26.4 lb/ft, N-80, LTC-8rd, carbon steellongstring casing. Use Best of Life 2,000 thread compound on connections. Make up connection to the last thread scratch plus or minus one (1) turn. For reference, the API torque range for this connection is between 2,830 to 4,710 ft-lbs. (4,243 to 3,243 feet).

Corrosion Protection Joint No.2: Approximately 30 feet overall length consisting of 5-foot, 7 5/8-inch, 26.4 lb/ft, N-80, LTC-8rd pin down special-drifted to 6.844-inch ill (same as 26.4 lb/ft material) and 25 foot, 7 5/8-inch, 0.328-inch wall, Duplex 2205 casing with Atlas Bradford STL box up. Use Best of Life 2,000 thread compound on 8rd carbon steel connection. Make up connection to the last thread scratch plus or minus one (1) turn. For reference, the API torque range for this connection is between 2,830 to 4,710 ft-lbs. (3,243 to 3,213 feet).

16 joints (approximately 400 feet) of 7 5/8-inch, 0.328-inch wall, Duplex 2205 casing with Atlas Bradford ST-L flush joint pin x box connections. Use Best of Life PTC on connections. Make up connection until it shoulders, then bring up the torque to the recommended range of between 2,900 to 3,700 ft-Ibs or as directed by the Atlas Bradford representative. (3,213 to 2,813 feet).

Corrosion Protection Joint No.3: Approximately 26 feet overall length consisting of 24 foot, 7 5/8-inch, 0.328-inch wall, Duplex 2205 casing with Atlas Bradford ST-L pin down and 3-foot, 7 5/8-inch, 26.4 lb/ft, N80, LTC-8rd box up drifted to 6.844-inch ill (same as 26.4 Ib/ft material). Use Best ofLife PTC on ST-L pin connection. Make up connection until it shoulders, then bring up the torque to the recommended range of between 2,900 to 3,700 ft-lbs or as directed by the Atlas Bradford representative for the flush joint connection. (2,813 to 2,787 feet).

Approximately 90 feet of 7 5/8-inch, 26.4 lb/ft, N-80, LTC-8rd, carbon steel long-string casing. Use Best of Life 2,000 thread compound on connections. Make up connection to the last thread scratch plus or minus one (1) turn. For reference, the API torque range for this connection is between 2,830 to 4,710 ft-lbs. (2,787 to 2,697 feet).

3-foot Davis-Lynch 7 5/8-inch LTC-8rd pin x box 2-stage MechanicalOpening Cementing Collar built on 26.4 Ib/ft, N-80 mandrel stock. Use thread-lock compound on stage tool connections using the two (2) 7 5/8inch joints with thread-locked mill-end coupling identified by yellow painted couplings above and below stage tool. Make up connection to the


.~ 03/01/06 Copyright © 2006 by Terra Dynamics Incorporated DVNAIVIICS INC

last thread scratch plus or minus one (1) turn. For reference, the API torque range for this connection is between 2,830 to 4,710 ft-1bs. Depth to top of Mechanical-Opening Cementing Collar should be approximately 2,694 feet with casing landed. (2,697 to 2,694 feet).

• Approximately 2,694 feet of 7 5/8-inch, 26.4 lb/ft, N-80, LTC-8rd, carbon stee110ngstring casing to surface. Use Best of Life 2,000 thread compound on connections. Make up connection to the last thread scratch plus or minus one (1) tum. For reference, the API torque range for this connection is between 2,830 to 4,710 ft-Ibs.

• Run Davis-Lynch centralizers as follows: 1- Turbolizer (plastic-coated), 10 feet above float

shoe on plastic-coated stop ring. 1- Turbolizer (plastic-coated), 10 feet above

connection of doublefloat joint on plastic-coated stop ring.

1- Turbolizer (plastic-coated), 10 feet above float collar on plastic-coated stop ring.

11- Turbolizers (plastic-coated), one (1) above each Dulex 2205 flush joint connection on plasticcoated stop ring.

25- Turbolizers (standard carbon steel), one (1) across each carbon steel LT & C connection

16- Turbolizers (plastic-coated), one (1) above each Duplex 225 flush joint connection on plasticcoated stop ring.

1- Turbolizer across carbon steel LT & C connection of double carbon steel joints below stage tool.

2- Turbolizer, one (1) 10 feet below and 10 feet above stage collar on stop rings.

16- Standard centralizers, one (1) across every other LT & C connection to 1,422 feet.

11- Standard centralizers, one (1) across every third LT & C connection to surface.

7 S/8-inch, 26.4 lb/ft, N-80, LT&C Casing Specifications are as Follows: Wall 0.328-inches J.D. 6.969-inches Drift 6.844-inches Coupling a.D. 8.50-inches Collapse 3,400 psi Burst 6,020 psi Pipe Body Strength 602,000 lbs


Copyright © 2006 by Terra Dynamics Incorporated DYNAIVlICS INC 03/01106

Joint Strength 490,000 lbs Capacity 0.0471 bbls/ft

7 S/8-inch O.D., Duplex 220S, Atlas Bradford ST-L Connection Casing Specifications Have Been Calculated as Follows: Weight 25.54 lbslft Average Wall 0.328-inches LD. 6.969-inches Drift 6.844-inches (special drift) Coupling O.D. 7.625-inches (flush joint) Specified Yield Strength 65,000 psi Collapse* 3,100 psi Burst* 4,890 psi Pipe Body Strength* 489,000 lbs Specified Joint Strength 284,000 lbs at 65,000 psi yield strength Capacity 0.0471 bblslft

*Denotes calculated values based upon formulas from API Bulletin 5C3

19. Fill casing with mud while running. Break circulation with 7 5/8-inch casing at base of surface casing. Continue running in hole with casing to bottom ofwell. When casing has landed, pick up I-foot offbottom. It is strongly desired to locate top joint of casing within three (3) feet of the rig floor for cementing head installation and plug dropping operations. Use remaining 7 S/8-inch spaceout pups as necessary to accomplish safe floor elevation spaceout. Circulate and condition hole and mud to establish optimum properties commensurate with good cementing practices.

Note: Mobilize Halliburton to location with appropriate equipment for Epseal and calcium-based cementing operation. Rig up all equipment marking lines/valves as necessary making sure that no source of fresh water, water base mud or calcium-based cement can come into contact with Epseal blending and pumping equipment Run lines as necessary from pumping manifold to rig floor. Assure that ample fresh mix water is available on location for blending the Halliburton Standard Lite and Standard calcium-base cement blends. Obtain samples of each dry mix cement from bulk units and give to DOW to archive as required. Halliburton to set up hot water sample baths in office trailer at expected static bottomhole temperatures for the Epseal slurry phase at the top of the stage tool. Obtain blended samples of Epseal and immerse in water baths to verify time to initial set while circulating between stages prior to proceeding with second stage cementing operations.


Copyright © 2006 by Terra Dynamics Incorporated 03/01106

20. Cement 7 5/8-inch OD long-string casing from TD to surface with EPSEAL, Standard Lite, and Standard cement in two (2) stages as follows:

First Stage: A. Pump 20 barrels of 11.0 1b/gal Modified Dual

Spacer containing 104 Ibs/bbl Barite (Weighting Material), one (1) gal/bbl Musol ® A (Defoamer), 0.1 gal/bb1 Dual Spacer Mixing Aid EXP (Viscosifier), 0.5 gal/bbl Dual Spacer Surfactant B (Flush/Spacer Additive) and 1.12 Ib/bbl D-Air 3000 (Defoamer). Pump Modified Dual Spacer at 5 to 6 barrels per minute.

B. Pump 27 barrels of 11.5 Ib/gal My-T-Oil IV Spacer containing 185 1bs/bb1 Barite and 55 Ibs/bb1 SSA-l (Weighting Materials), 35.02 ga1lbb1 diesel oil, 0.21 gal/bb1 MO-75 and 0.21 gal/bb1 MO-76. Pump MyT-Oil IV Spacer at 5 to 6 barrels per minute.

C. Mix and pump 130 barrels (or as required to provide 20 percent excess over open hole section calculated from open-hole caliper from casing point to stage tool at approximately 2,694 feet) of 13.8 Ib/gal Epseal RE System with one (1) drum/drum Epsea1 RE, 0.25 ga1s/drum Plastic Fixer, 700 1b/drum SSA1 and 1.50 gals/drum LC Catalyst (or as required based on temperature data). Epsea1 to occupy 10 5/8-inch x 7 5/8-inch annular region from ±4,600 to ±2,694 feet. Pump Epsea1 synthetic cement at 5 to 6 barrels per minute.

D. Manually release cement plug then pump 10 barrels of 11.5 lb/gal My-T-Oil IV Spacer containing 185 lbs/bbl Barite and 55 Ibs/bb1 SSA-l (Weighting Materials), 35.02 gal/bbl diesel oil, 0.21 ga1lbbl MO-75 and 0.21 gal/bbl MO-76. Pump My-T-Oil IV Spacer at 5 to 6 barrels per minute.

E. Pump approximately 62 barrels mud (or as required for 15 of the 45 barrels of the My-T-Oil IV spacer in the next step to locate approximately 15 barrels below the stage tool). Pump mud at 5 to 6 barrels per minute.

99-177 DOW DWDNo. I Well Page 3-18 Plan eTERRA

Copyright © 2006 by Terra Dynamics Incorporated DVNA.I'JIICS INC 03/01106

F. Pump 45 barrels of 11.5 1b/gal My-T-Oil N Spacer containing 185 lbs/bbl Barite and 55 lbs/bbl SSA-1 (Weighting Materials), 35.02 gal/bbl diesel oil, 0.21 gal/bbl MO-75 and 0.21 gal/bbl MO-76. Pump MyT-Oil N Spacer at 5 to 6 barrels per minute.

G. Pump approximately 97 barrels of mud to displace the cementing plug to the float collar at 5 to 6 barrels per minute. With the displacement mud 10 barrels shy of total displacement, slow the pump rate to two (2) barrels per minute for the final 10 barrels of displacement.

H. When the plug lands in the float collar, slowly increase pressure to 500 psi above displacement pressure to assure plug has seated.

I. Slowly bleed offpressure and check for flow back.

J. With no flow back, proceed to next step. If flow back occurs, repeat steps H and I.

K. With plug holding, manually release free-fall opening device. Allow time for the device to gravitate to the stage tool. Nonnal free-fall rate is approximately 200 feet per minute (or approximately 14 minutes with stage tool at approximately 2,694 feet).

L. When free-fall opening device has landed in the stage tool (approximately 14 minutes), apply 1,000 psi pressure to open the stage collar cementing ports.

M. Circulate for 18 to 24 hours (or as required for Epseal to obtain initial set in water bath at anticipated stage tool downhole temperature) between first and second stage cementing using rig pumps. Observe returns for Epseal cement. Circulate and condition hole and mud for second stage cementing.

Second Stage: A. Pump 20 barrels of 11.0 lb/gal Modified Dual

Spacer containing 104 lbs/bb1 Barite (Weighting


Copyright © 2006 by Terra Dynamics Incorporated DVNAI'V1ICS IN~ 03/01106

B.

c.

D.

E.

F.

G.

Material), one (1) gal/bbl Musol ® A (Defoamer), 0.1 gal/bbl Dual Spacer Mixing Aid EXP (Viscosifier), 0.5 gal/bbl Dual Spacer Surfactant B (Flush/Spacer Additive) and 1.12 lblbbl D-Air 3000 (Defoamer). Pump Modified Dual Spacer at 5 to 6 barrels per minute.

Lead Slurry: Mix and pump 385 sks (or as required to provide 20 percent excess over open hole section calculated from open-hole caliper from 2,094 feet to surface) of 12.8 lb/gal Halliburton Lite Standard Cement containing 5 percent salt and Y4 lb/sk Pheno Seal Fine. Mix and pump lead cement at 5 to 6 barrels per minute.

Tail Slurry: Mix and pump 185 sks (or as required to provide 20 percent excess over open hole section calculated from open-hole caliper from stage tool at approximately 2,694 feet to approximately 2,094 feet for 600 feet tail fillup) of 15.6 lb/gal Standard cement. Mix and pump tail cement at 5 to 6 barrels per minute.

After the second stage cement has been pumped, manually release the stage tool closing plug followed by approximately 5 additional barrels (25 sks) Standard cement (to minimize potential for wet-tool condition). Displace cement/closing plug/cement with approximately 123 barrels of mud at 5 to 6 barrels per minute. As the plug approaches the stage tool, slow displacement to two (2) barrels per minute for approximately 10 barrels prior to landing the plug.

When the closing plug lands in the stage tool, increase the pressure to 1,200 to 1,500 psi above displacement pressure. Hold this pressure for 5 minutes.

Slowly bleed offpressure and check for flow back.

With no flowback, 7 5/8-inch cement job is complete.


Copyright © 2006 by Terra Dynamics Incorporated DVNAIV1/CS INC 03/01/06

7 5lB-inch Cementing Contingency Plan If circulation is lost while performing the fIrst stage of the 7 S/8-inch cementing job prior to releasing the cementing plug, evaluate the point at which lost circulation occurred to identify the possible leading edge of the Epseal cement. Reduce the Epseal pumping rate to Y:! the scheduled rate to reduce ECD's and attempt to regain circulation. However, if indications are that returns can be reestablished, it will be critical to release the pump-down cementing plug after pumping the exact volumes of Epseal and MY-T-Oil spacer as originally planned. If the indications are that circulation can not be regained, then do not release the pump-down cementing plug, circulate the well at Y:! the actual circulation rate to clear the 7 Sl8-inch casing of Epseal (either into loss zone or from the well). If circulation is regained, then the remaining Epseal will need to be circulated from the wellbore and the fIrst stage cementing operation attempted again after allowing an appropriate Epseal curing period (to allow the Epseal in the loss zone to cure).

If circulation is lost after the cementing pump-down plug has been released, then the Epseal job is totally committed as planned volumetrically. Reduce the cementing pump-down plug displacement rate to Y:! the rate being pumped prior to losing circulation to attempt to regain circulation. When the plug lands in the float collar, drop stage tool free-fall opening device, open tool, circulate the well as planned and look for evidence of excess Epseal and/or MY-T-Oil spacer in the returns. Follow the plans for completion of second stage cementing operations. After completion of cementing operations, the stage tool will be drilled, the 7 S/8-inch casing logged to determine whether adequate cementing exists and remedial squeeze cementing performed as necessary. Once sufficient isolation has been demonstrated, the squeeze perforations will be isolated by means of7 S/8-inch casing patches.

Should lost circulation or fall-back occur on the second stage alone, the top of cement will be identifIed from a temperature log or the post-drillout cement bond log. The casing would then be cemented externally (top job) using thin tubing, to ensure sufficient cementing is accomplished.

If lost circulation occurs between stages, condition mud, as needed, with appropriate lost circulation material additives until circulation is re-established. Then continue to circulate at Y:! the planned circulation rate while continuing to observe the required wait-on-cement period between stages.

21. After completion of cementing, wash out excess lead cement in stack and riser to a point approximately three (3) feet below anticipated cut points (unless top job is required). Center 7 5/8-inch casing inside 11 7/8-inch casmg.

22. Nipple down BOPs, cut off 7 5/8-inch casing and 11 7/8-inch SOW x 11inch, 3,000 psi WP rental casing flange. While rigging down, maintain centralization of 7 5/8-inch casing inside 11 7/8-inch casing and install Y:zinch thick plate between 11 7/8-inch and 7 5/8-inch casings and weld in place. Install 7 5/8-inch slip-on-weld x 7 1I16-inch, 3,000 psi tubing head such that weld is approximately flush with filled-in cellar elevation and at least 6-inches are available between the base of the tubing head flange and filled in cellar to allow makeup of tubing head flange bolts.



Note that head will require an inside and outside weld - assure that there is no inside weld bead that could interfere with running of the 6 3/4-inch bit or other equipment Test welds to 1,000 psi after welds have cooled. Install rental 7 1I16-inch, 3,000 psi WP abandonment flange (with Y2-inch bleeder valve) to tubing head.

23. After extracting kelly shuck from rathole and drill pipe shuck from mousehole, run into each of the rathole and mousehole with 4-inch drill pipe and cement rathole and mousehole from bottom to surface with standard Portland cement containing 5 percent gel until grout returns are observed at surface. Slowly remove drill pipe from rathole and mousehole and flush pipe with fresh water until clean. Top off rathole and mousehole with grout mixture as required. Clean up and rig down rig from location. Release drilling rig.



4.0 WELL CONSTRUCTION COMPLETION PROCEDURES

4.1 Long-string Casing Drillout and Pressure Testing Operations

1. Set and pull test anchors for completion unit. Mobilize completion unit on location. Spot rig pump, mud tank, catwalk and two(2) sets of pipe racks as required. Set two (2) lined frac tanks for mixing completion and testing fluids and two (2) unlined tanks (500 barrel for slop mud returns, 250 barrel for contaminated My-T-Oil spacer returns)

2. Bleed off any potential trapped pressure and remove 7 1/16-inch, 3,000 psi WP abandonment flange from tubing head and nipple up 7 1I16-inch, 3,000 psi BOP (with 2 7/8-inch pipe and blind rams) to wellhead.

3. Pick up and run in hole with 6 %-inch bit, eight 4 %-inch drill collars and 2 7/8-inch workstring to top of cement above stage tool at approximately 2,586 feet (note: top of stage tool at 2,694 feet). Using approximately 50 barrels of fresh water to establish circulation, reverse well into the 500 barrel slop mud tank with the starting volume of fresh water.

4. Pressure test 7 5/8-inch OD longstring casing and BOPs to 250 psi (low pressure test) and 1,500 psi (high pressure test) above stage tool for minimum of 30 minutes each.

5. Drill out cement and stage tool with the 6 %-inch bit.

6. Clean out 7 5/8-inch OD longstring casing to float collar at approximately 4,544 feet. Reverse well with 8.8 lblgal brine and divert mud returns to the 500 barrel slop mud tank and My-T-Oil spacer returns to the 250 barrel slop fluid tank. Circulate casing clean.

7. Drill up float collar and Epseal cement in float joint to within 5 feet of float shoe (approximately 4,595 feet) - PBTD. Circulate casing clean.

8. After wellbore fluids have cleaned up, pressure test 7 5/8-inch OD longstring casing to 250 psi (low pressure test) and 1,500 psi (high pressure test) above float collar for minimum of 30 minutes each. Report results of testing. Trip out of hole with 6 %-inch bit.

9. Pick up 7 5/8-inch, 26.4lb/ft casing scraper and work scraper across stage tool. Carefully scrape Duplex 2205 casing to PBTD (to minimize potential for damaging the Ceram-Kote applied to the ill ofthe corrosion protection joints) and reverse hole clean - do not work scraper across


Copyright © 2006 by Terra Dynamics Incorporated 03/01106

intervals where the corrosion protection joints are located. Carefully trip scraper above stage tool.

10. Retest 7 5/8-inch OD longstring casing to 1,500 psi above stage tool for minimum of 30 minutes to assure that scraper did not shift stage tool sleeve and create a leak condition.

11. Trip out ofhole and lay down scraper.

12. Rig up loggers and run Cement Bond with Variable Density Log (and Gamma Ray/Casing Collar Locator), Ultrasonic Cement and Baseline Casing Inspection Logging from top of float collar to surface. Rig down loggers. Evaluate logs for zonal isolation. After completion of logging, instruct loggers to provide three (3) copies of field prints (labeled as field copy) prior to leaving location. Final prints to be generated at end ofjob after all tallies and log header information has been verified.

4.2 James Lime Perforating and Development Operations

1. Trip back to bottom with open-ended workstring. Reverse circulate wellbore fluids until clean through filtration equipment, then pull out of hole and stand back workstring.

2. Rig up Gulf Coast Well Analysis. Perforate James Lime using deep penetrating charges with a four (4) jspf shot density at 90 degree phasing as directed by on site geologist taking in consideration of anticipated permeability and minimal formation thickness required by No-Migration Petition.

3. Run in hole with surface readout down-hole presssure gauge to 4,329 feet (or as required to be at least 20 feet above perforated interval) while making pressure and temperature gradient stop checks every 1,000 feet to gauge datum. Obtain initial static bottom-hole pressure and temperature at 4,329 feet relative to kelly bushing. Rig down Gulf Coast Well Analysis and place on standby.

4. Run in hole with open-ended 2 7/8-inch workstring to bottom of perforations.

5. Swab back well until fluid cleans up and a representative sample of formation brine is obtained. Collect two (2) 55 gallon drum samples of formation brine. Conduct chemical analysis of formation brine including determination of formation fluid temperature, pH, conductivity, specific gravity, and viscosity. Conduct compatibility testing of formation brine from James Lime and James Lime Core material to determine


Copyright © 2006 by Terra Dynamics Incorporated DYNAIVIICS INC 03/01106

compatibility with local fresh water (for injectivity testing) and NaCI brines (for use as completion fluid). Rapid turnaround of fluid compatibility testing will be required.

6. Pick up bottom ofworkstring and locate 50 feet above top ofperforations.

4.3 Pre-Completion Radioactive Tracer Survey and Injectivity Testing:

1. Mobilize wireline unit. Conduct RAT time drive surveys at this time to evaluate whether external mechanical integrity exists behind 7 5/8-inch casing prior to running injection tubing - this is not the official ADEQ I

RAT survey. It will be used to determine if remedial cementing could be required prior to final well assembly. Fill lined frac tank with 500 barrels 8.8 Iblgal NaCI brine for testing purposes (unless fluid compatibility testing indicates other type oftest fluid is required). Mobilize appropriate pumping equipment to pump filtered 8.8 Iblgal brine for RAT survey and initial injectivity test into 2 7/8-inch workstring at a rate of approximately 100 gallons per minute.

a) Conduct initial gamma ray base log from total depth to 4,070 feet (or 200 feet above the proposed completion packer setting depth).

b) Position RAT tool lower detector 20 feet above top of perforations and conduct 5-minute statistical.

c) Establish injection rate of approximately 100 gallons per minute with filtered 8.8 lblgal brine.

d) Eject isotope and record in time drive for 20 minutes. e) Repeat time drive survey. At conclusion of time drive repeat survey,

continue pumping filtered 8.8 Iblgal brine until the 500 barrel system of test brine has been depleted.

f) Cease injection. Conduct fmal gamma ray base log from total depth to 4,070 feet (or 200 feet above the proposed completion packer setting depth).

2. Rig down and release wireline unit. Evaluate results of RAT survey to determine whether any 7 5/8-inch casing remedial action is required and injectivity testing to determine if stimulation will be required. If stimulation is required, perform prior to installing completion equipment and assure that appropriate inhibitors are used in the acid system suitable for protecting the Duplex 2205 casing material. Also, if well filled in with formation material, note depth and make plans for clean out prior to running completion equipment. After completion of logging, instruct loggers to provide three (3) copies of field prints (labeled as field copy) prior to leaving location. Final prints to be generated at end of job after all tallies and log header information has been verified.



4.4

4.5

3. Pull out ofhole and stand back workstring.

Injection Packer Installation:

1. Mobilize GPS personnel to location with 7 5/8-inch x 3 ~-inch GPS Model 12 Hastelloy C-276 retrievable packer with 2.625-inch integral polished bore profile sub and Hastelloy C-276 latching seal assembly with 2.75-inch integral polished bore profile. Assure that detailed measurements and dimensions of all packer and seal assembly have been made prior to running.

2. Rig up and run 7 5/8-inch x 3 ~-inch GPS Model 12 Hastelloy C-276 retrievable packer with 2.625-inch integral polished bore profile sub on 2 7/8-inch workstring. Install wiper rubber on 2 7/8-inch workstring to prevent foreign objects from falling into the wellbore while running.

3. Allow packer rubbers to thermally conform for two (2) hours prior to setting packer. Set packer in 7 5/8-inch Duplex 2205 casing with packer from approximately 4,270 to 4,275 feet (or as required to locate in a well cemented section of 7 5/8-inch Duplex casing in the shale interval above the top of the James Lime Formation Injection Interval).

4. Prior to releasing from packer, top off 7 5/8-inch casing x workstring annulus, allow annulus system to thermally equilabrate and conduct pressure test on 7 5/8-inch casing x workstring annulus to 1,000 psi for 30 minutes.

5. Release running tool from packer and pull out of hole while laying down workstring.

6. Pre-displace well with filtered, 9.0 lblgal brine containing inhibitors, oxygen scavenger and biocide. Change out double ram BOP for 7 1/16inch, 3,000 psi WP annular BOP for running fiberglass tubing.

Injection Tubing and Tree Installation:

1. Mobilize fiberglass tong unit, Future Pipe Industries (formerly Tubular Fiberglass Corporation) representative and Gatorhawk external pressure testers with digital pressure recording and indicating instrumentation. Rig up fiberglass power strap and fiberglass tubing handling system and Torque Tum System Test Monitor. If pickup/laydown machine used, make sure that rubber lined trough is employed.

2. Make up pre-tested GPS Hastelloy C-276 latching seal assembly and 3 Y2inch tubing pup to first full joint of 3 ~-inch tubing. Run 3 ~-inch FPI



3.

4.

5.

Red Box 2,000 psi fiberglass injection tubing with GPS Hastelloy C-276 latching seal assembly set to appropriate packer depth as specified above. All 3 ~-inch, Red Box 2,000 psi fiberglass tubing to be torque turned to between 250 to 280 ft-lbs or as directed by FPI representative and externally tested to 1,750 psi.

Verify [mal tubing space-out requirements and space out tubing as necessary. Install 3 ~-inch x 0.2l6-inch AW Hastelloy landing joint (with 3 ~-inch EUE-8rd long form box down) to fiberglass tubing using the FPI Red Box 2000 psi 3 ~-inch, EUE-8rd Long Form pin x pin pup and test connection to 1,750 psi.

3 ~-Inch, FPI (Formerly TFC) Red Box, 2,000 psi Fiberglass Tubing Specifications are as Follows:

a.D. 3.50-inches ID. 3.00-inches Drift 2.90-inches Nominal a.D. 3.5 I-inches Pin Upset 3.85-inches Max Box O.D. 4. 84-inches Nominal Wall 0.25-inches Weight 2.30lbs/ft Connection Type 3 Y2-inch, EUB-8rd, Long Form U Collapse 2,300 psi Burst 2,000 psi Axial Tension Rating 32,0001bs Capacity 0.00874 bbls/ft

Engage Hastelloy seal assembly to packer and top off annulus with two (2) drums of diesel followed by inhibited 9.0 lb/gal brine (note: use diesel in annulus tank: for slip-to-landing joint corrosion protection and upper wellbore freeze protection). Conduct preliminary annulus pressure test to 1,000 psi for 30 minutes with an acceptable test resulting in less than 50 psi pressure loss within the 30 minute test period. Release fiberglass casing crew and all non-used fiberglass running equipment after completion of fiberglass tubing running operations to avoid additional costs for standby equipment unless other arrangements have been made with fiberglass running company for no standby charges.

Nipple down and strip off BOP. Pull the required tension to maintain tensile loading during all thermal operational conditions with 3 ~-inch

Hastelloy landing joint in tubing head. Note that the 3 ~-inch Hastelloy landing joint has a 3 Y2-inch NUB-lOrd pin up and a corresponding carbon steel collar for handling purposes and that any carbon steel pups

99-177 DOW DWD No. I Well Page 4-5 Plan _TERRA


used for landing will need to have a 3 Y:z-inch, NUE-10rd pin down. Set slips, cut off landing joint as required to fit Duplex 2205 Tubing Head Adapter (THA), install P-seal and flange up THA.

6. Conduct additional preliminary annulus pressure test to 1,000 psi for 30 minutes with an acceptable test resulting in less than 50 psi pressure loss within the 30 minute test period.

7. Nipple up Duplex 2205 tree section of wellhead (see Figure 1-4) to Duplex 2205 THA. Rig down and release workover rig and support equipment. Allow well to stabilize for a minimum of 36 hours prior to conducting formal mechanical integrity testing.


Copyright © 2006 by Terra Dynamics Incmporated DVNAIVlICS INC 03/01106

5.0 MECHANICAL INTEGRITY AND INJECTIVITY TESTING PROCEDURES

5.1 Mechanical Integrity and Injectivity/Fall-Off Testing:

1. Mobilize Gulf Coast Well Analysis to location. Rig up and run baseline differential temperature survey (DTS) from surface to maximum achievable depth at 30 [pm logging speed. After completion of DTS, conduct official annulus pressure test to 1,000 psi for a minimum of 30 minutes with an acceptable test resulting in less that 50 psi pressure loss within the 30 minute test period.

2. Mobilize filtration equipment and pumping equipment and rig up to fresh water source (or test brine source ifnecessary) capable of delivering up to 100 gallons per minute to the well.

3. Gulf Coast Well Analysis to make up and run in hole with surface readout (SRO) downhole presssure gauge (with memory tool backup) and casing collar locator to 4,329 feet (or at least 20 feet above the top perforations) while making pressure and temperature gradient stop checks every 1,000 feet to gauge datum. Obtain static bottom-hole pressure at 4,329 feet for 30 minutes.

4. Initiate injection with filtered fresh water (if compatibility not an issue with formation brine and material) to a maximum of 100 gallons per minute.

5. Monitor and record bottom-hole and surface injection presure response until injection pressure has stabilized.

6. Cease injection and close flowline valve to well and conduct the pressure fall-off test for 24 to 48 hours or until the bottom-hole shut-in pressure has stabilized. Verify that an infinite acting, radial flow response has been obtained from the fall-off test data utilizing PanSystem analysis of field data prior to test conclusion.

7. After completion ofinjectivity test, pull out of hole with SRO. Exchange SRO for RAT tool. Conduct formal ADEQ mechanical integrity test RAT survey at this time to confirm that external mechanical integrity exists behind 7 5/8-inch casing.

a) Conduct initial gamma ray base log from total depth to 4,070 feet (or 200 feet above top of GPS Hastelloy packer).

b) Conduct 5-minute statistical 20 feet above top of perforated interval.



c) Establish 42 gpm injection rate, eject isotope and profile slug to repose. d) Repeat profile operation at 42 gpm. e) Increase injection rate to 100 gallons per minute and position RAT tool

20 feet above top ofperforated interval. f) Eject isotope and record in time drive for 20 minutes. g) Repeat time drive operation at 100 gpm. f) Conduct fmal gamma ray base log from total depth to 4,070 feet (or 200

feet above top of GPS Hastelloy packer).

8. Pullout of hole with RAT tool and exchange for spinner tool. Perform spinner survey profile passes and stationary checks as required corresponding to the same rate as injectivity testing was performed. Pull out of hole with spinner tool and rig down Gulf Coast Well Analysis from well.

9. Assure that well is secure prior to leaving location. Prior to releasing wireline unit, obtain 1 field copy of all pressure data and plots for DWD No. 1 and field copies of all mechanical integrity logs. Obtain a copy of the pressure fall-offtest raw data on 3.5-inch diskette.

10. Release wireline unit.

11. After completion of testing, rig down and release tanks and any additional testing equipment from well.

12. Prepare report of drilling and completion activities for submission to the ADEQ following conclusion of all site activities.

99-177 DOW DWDNo. I Well Page 5-2 Plan .TERRA

Copyright © 2006 by Terra Dynamics Incorporated DYNAI'v'IICS INC 03/01106

-:)j

Confining Zone (Nacatoch Fm) 2,065' - 2,175' GL 2,079' - 2,189' KB

Injection Zone 2,175' - 4,445' GL 2,189' - 4,459' KB

Alternate Injection Interval Tokio Fm 2,885' - 3,070' GL 2,899' - 3,084' KB

~ Calcium Cement

Epoxy Cement

Primary Injection Interval James Lime Fm 4,335' - 4,445' GL 4,349' • 4,459' KB

Total Depth = 4,600'± Plug Back Total Depth = 4,595'±

All depths relative to kelly bushing (KB) elevation of Reliance Rig No.4 dedicated for this project (14 feetAGL) and account for ground level elevation difference between

Brazos Dow No.1 lithologic offset log and DWD No.1 Copyright <!:> 2006 by Terra Dynamics, Inc.

3

4

7

BELOW GROUND DETAIL

1. CONDUCTOR PIPE: 16" setto 60'± GL or 74' KB in advance ofrig mobilization. Cemented with 10 yards ofcement and topped offwith ready mix.

2. SURFACE CASING: 11 7/8", 71.8Ib/ft, J-55 with 113/4", BT&C connections set to 1,600'± in 143/4" hole. Cemented to surface with Standard lite lead cement with design coverage from approximately I, I00' to surface and Standard tail cement with design coverage from approximately I,600' to 1,100'.

3. LONGSTRING CASING: Mixed string of7 5/8", 26.4lb/ft, N-80 (or equivalent), LTC-8rd and 7 5/8", Duplex 2205 with AB ST-L flush joint connections set to 4,600'± in 105/8" hole as follows:

Surface to 2,789'± - 75/8", 26.4lb/ft, N-80, LTC-8rd 2,789'±to 3,238'± - 7 5/8", 25.54 Ib/ft, Duplex 2205, ST-L 3,238'± to 4,245'± -75/8", 26.4Ib/ft, N-80, LTC-8rd 4,245'± to 4,600'± -75/8", 25.54Ib/ft, Duplex 2205, ST-L

Note: The carbon steel-to-Duplex 2205 sections will be connected by corrosion protection joints.

75/8" mixed casing cemented to surface as follows:

First Stage: 13.9 Ib/gal Epseal synthetic cement with design coverage from 4,600'± to 2,694'±.

Second Stage: Lead Slurry: Standard lite cement. Design coverage from

2,094'±to surface. Tail Slurry: Standard cement. Design coverage from 2,694'± to

2,094'±.

4. STAGE TOOL: 7 5/8" mechanical-type at 2,694'±.

5. ANNULUS FLUID: Inhibited 9.0 Ib/gal brine topped off with two drums diesel for corrosion and freeze protection.

6. INJECTION TUBING: 3 Yo", FPI (formerly TFC), Red Box 2,000 psi, with Nexus Veil Lining set with GPS Model" 12" Hastelloy C-276 latching seal assembly into packer at4,270'±.

7. PACKER: 7 5/8" x 3 W', GPS Model "12" Hastelloy C-276 retrievable packerset from 4,270' to 4,275'±.

8. PERFORATIONS: (four (4) shots/ft) as indicated from logs in James Lime from approximately 4,349' - 4,459'±.

FIGURE 1-1

~TERRA L:)""'" I'-J ~ I'v'1 I C=;~ I I'-J c=;

PROPOSED COMPLETION SCHEMATIC OF PLANT DISPOSAL WELL

DWDNO.l

PREPARED FOR

DOW CHEMICAL COMPANY MAGNOLIA, ARKANSAS

ATE:SCALE:RAWN BY: M. Eide 2/11106 N.T.S. JOB NO. 99-177.06HECKED BY: R.F..Bielenda

ESIGNED BY: R.F. Bielenda

, ~,

':$

..

"

75/8" LONGSTRING CASING DETAIL KB Elevation

Surface to ±2,694' 7 5/8",26.4 lb/ft, N-80, LT&C. Carbon Steel, N-80,LT&C

±2,694' to ±2,697' 7 5/8" Davis-Lynch Stage Tool. to 2,789'

±2,697' to ±2,787' 7 5/8", 26.4lb/ft, N-80, LT&C.

Second Stage: 2,694' to Surface ±2,787' to ±2,813' OA 7 5/8" Corrosion Protection Joint No.3; Standard lite 26.4lb/ft, CS, N-80, LT&C from 2,787' cement followed to 2,789' and 25.54Ib/ft, 0.328" AW,by Standard cement. Duplex 2205, ST-L from 2,789' to 2,813'.

±2,813' to ±3,213' 7 5/8",25.54 lb/ft, Duplex 2205, ST-L.

±3,213' to ±3,243' OA 7 5/8" Corrosion Protection Joint No.2; 22.54 lb/ft, Duplex 2205, ST-L from 3,213' to 3,238' and 26.4lb/ft, CS, N-80, LT&C from 3,238' to 3,243'.

Stage Tool (2,694' to 2,697') ±3,243' to ±4,243' 75/8",26.4 lb/ft, N-80, LT&C.

Corrosion Protection Joint No. 3 ±4,243' to ±4,269'OA 75/8" Corrosion Protection Joint No.1;

(2,787' to 2,813' OA) 26.4 lb/ft, CS, N-80, LT&C from 4,243' to 4,245' and 25.54Ib/ft, 0.328" AW, Duplex 2205, ST-L from 4,245' to 4,269'.

Duplex 2205

(2,789' to 3,238') ±4,269' to ±4,544' 7 5/8", 25.54Ib/ft, Duplex 2205, ST-L.

Corrosion Protection ±4,544' to ±4,547' 7 5/8", 25.54 lb/ft, Duplex 2205, Davis-Joint No. 2 Lynch Float Collar, ST-L box x pin.

(3,213' to 3,243' OA)

±4,547' to ±4,597' 7 5/8",25.54 lb/ft, Duplex 2205, ST-L.

Carbon Steel, N-80 ±4,597' to ±4,600' 75/8", 25.54Ib/ft, Duplex 2205, Davis(3,238' to 4,245')

Lynch Float Shoe, ST-L box x PE.

NOTE: All alloy pipe and corrosion protection joints must be drifted to 6.844" ID which is equivalant to drift ID of 75/8", 26.4lb/ft, N

First Stage: 80, IT&C casing material. 4,600' to 2,694'

EpseaJ RE System.

Corrosion Protection Joint No. I FIGURE 1-2 (4,243' to 4,269' OA)

Duplex 2205 .TERRA (4,245' to 4,544')

FloatCoUar (4,544' to 4,547') PROPOSED PROTECTION CASING DETAIL

FOR PLANT DISPOSAL WELL DWD NO.1Duplex 2205 (4,547' to 4,597')

PREPARED FORFloat Shoe (4,597' to 4,600') DOW CHEMICAL COMPANY

MAGNOLIA ARKANSAS elevation for Reliance Rig No.4 which is 14 feet above RAWNBY: .

Note: All depths above referenced to kelly bushing

ATE:SCALE:Mike Eide 211/06ground level elevation. ESIGNEDBY: R.F. Bielenda JOB NO.

Copyright © 2006 by Terra Dynamics, Inc. HECKEDBY: N.T.S. 99-177

R.F. Bielenda

I"

AI

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Q) ~ U

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4 Dow Chemical Corporation Figure 1-3Delta P Inc Magnolia, Arkansas DPI Completion System

1069PaxronStreet-HaJey,u 70058 • DWD No.1 75/8'ModeI12AnchorSeaIAssembly C-276(Wetted) 5041341-3107 _ 504/34H317fax jo;""':;;..:biby~,-= ,~S<ak,--=---=-----~""""""=::~~=5/~~:~.~~od~e:!.!11~2~Di~sp~os~al~p~ac~ke~r~C~.2!!76~f:N~e~tted~) --I

TR None

formerly known as Groundwater Protectio" Syssel1lS

PlqwatFor: DIIIc:

R.F. Bielenda 02-15-06 DPlf'JojectNo.:

10R051402 onla::t hone

~

A. 11 7/8", 71.8 lb/ft, 1-55, BTC surface casing. B. 75/8", mixed carbon steel and Duplex 2205

intermediate casing with 26.4 lb/ft, N-80, LTC-8rd carbon steel at surface.

C. 3 W', FPI Red Box 2,000 psi injection tubing. D. 75/8", SOW x 7 1/16",3,000 psi WP tubing head with

2" threaded LPO's and 2", 2,500 psi ball valves, 3 W' slip type hanger.

E. 2" x W' NPT bushing, tee and liz" NPT needle valve316 stainless. WASTEWATER F. 2" xl" NPT bushing and 1" line to annulus tank.

..LINE G. 0 to 1,000 psi pressure gauge, 1/z" NPT. H. 7 1/16", 3,000 psi WP x 3" Nominal, ASA, 600 lb

Duplex 2205 tubing head adapter with 3 1/z" P-seal. I. 3 W', Hastelloy C-276 landing joint. J. 3" Nominal, ASA, 600 lb full-opening, ring joint

grooved Duplex 2205 ball valves. K. 3" Nominal, ASA, 600 lb, ring joint grooved Duplex

2205 tee. L. 3" Nominal, ASA, 600 lb, ring joint grooved Duplex

FROM 2205 flange tapped 2 7/8", EUE-8rd. WAMS M. 2 7/8", EUE-8rd x W' NPT Duplex 2205 bull plug. .....

;( •• 1 I rc

1.. 1 (B

FIGURE 1-4

eTERRA r:=»'t' I"J.A..1'v'I1 CS II"J C

WELLHEAD AND TREE VALVE ARRANGEMENT FOR DWD No.1

PREPARED FOR

DOW CHEMICAL COMPANY MAGNOLIA, ARKANSAS

DRAWN BY: M. EIDE SCALE: I IDATE: 2/8/06DRAWINGDESIGNED BY: R.F. BIELENDA NOT TO JOB NO. CHECKED BY: SCALE 99-177.06

MapQuest: Maps Page 1 of 1

_-' .........1 ...... -:. ~. ~~Jl/I'~ '....

Magnolia AR US

Notes:

Figure 1-5

.~

. ;~

All rights reserved. Use Subject to License/Copyright

This map is informational only. No representation is made or warranty given as to its content. User assumes all risk of use. MapQuest and its suppliers assume no responsibility for any loss or delay resulting from such use.

httn'//umroJ m~nml~"t rnm/m::m,,/nrint ::lc1n?m:mcht::l=%?'i?hK7mp.iThflNR 1%?'i?hhn-7VF~O ?/1 noo,;

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........ 0 l-o ~ ~ ....... ~

APPENDIX A TYPE LOG FOR ANTICIPATED SUBSURFACE ENVIRONMENT

99-177 DOW DWD No.1 Well Plan .TERRA

Copyright © 2006 by Terra Dynamics Incorporated DVNAI'v'IICS INC 03/01/06

APPENDIXB DRILLING MECHANICS

99-177 DOW DWD No.1 Well Plan eTERRA

Copyright © 2006 by Terra Dynamics Inc01l'orated DVNAIVIICS INC 03/01106

DRILLING MECHANICS

WELL NAME: DOW DWD No.1 PREPARED BY: RF. Bielenda DATE: 2/12/06

DEPTH (FT.)

HOLE SIZE

(INCHES) BIT TYPE

IADCCODE 1000 LBS LBSJIN.-DIA.

ROTARY SPEED (RPM)

BTM. HOLE ASSEMBLY

CODE

HWDP & DRILL COLLARS

0.0. x I.D. (IN.) LENGTH (FT.) I(CONN TYPE) (WTJFT (LBS))

MAXIMUM DEVIATION

TOTAL DEV. DEVJ1000 FT. AT DEPTH

o to 1,600

143/4 STCXR+ 1-1-7

15t040 1,017t02,712100t0150

8x3 (6 5/8" H-90) 61/4x21/2 (4112" XH)

62' (147) 496' (88)

0.7 1/2

1,600 to 4,600

105/8 STC M70PX PDC

o to 25 o to 2,353 70 to 120 2

8x3 (6 5/8" H-90) 61/4 x 2 1/2 (41/2" XH)

62'

(147)

372' (88)

2.3 1/2

DRILLING MECHANICS COMMENTS/SPECIAL INSTRUCTIONS

1. Verify inspection of all dnll pipe, drill collars, changeover sUbs, bit subs, kelly, saver sub, etc. has been performed at time of rig acceptance of the contractor. Make sure that all stabilizing tools (if necessary) have been inspected prior to their use.

2. If any stabilizers or jars become necessary, inquire if connections are available to mate with the collars above and below the particular item. If available, this will eliminate the need for extra changeover subs.

3. Proper handling of BHA compcnents is essential to the longevity of the BHA. Make sure that thread protectors are used when picking up or laying down the individual components. Reface any gouges in the shoulders of BHA components or replace as necessary.

4. Lift sub pins should be cleaned, visually inspected and lubricated on each trip. Repair/replace accordingly as damaged pins will eventually damage all of the drill collar boxes.

5. Visually inspect and caliper 10 and 00 of all BHA fishnecks prior to picking up. Gauge 00 of any stabilizing tools used. Replace worn wear pads or cutters as necessary. Watch for excessive wear on tools.

6. Make sure that all connections (pin threads and shoulders) are being doped propeny when being made up.

7. Do not use any drill string or BHA component with external, coarse face hardbanding.

8. Verify all connections and make-up torques on drill collars and drill pipe. Verify accuracy of torque gauges and check tong arm length. Torque = Tong line pUll x number of lines x tong arm length. Use recommended makeup torques for all BHA components and drill pipe.

9. Make up torques for each end of changeover subs should be the same value as the recommended torque value of the collar it is made up to.

10. While drilling the 14 3/4-inch surface hole, adjust WOB accordingly to prevent deviation problems from occurring.

11. Assure that gauge rings are available for each size bit run. Check gauge of bits (stabilizers and reamers if used) on each trip and replace items as necessary to maintain a gauge hole.

ITEM 8" x 3" Drill Collars 61/4" x 21/2" Drill Collars 4 112", 20 Ib/ft nom. wt. DP 4", 14 Iblft nom. wt. DP

Copyright © 2006 by Terra Dynamics, Inc.

CONNECTION 65/8" H-90 41/2" XH 41/2"XH 4"FH

RECOMMENDED MIN. MAKEUP TORgUE 33,600 fl-Ibs (5,600 Ibs pUll x 2 lines x 3-foot tong arm) 25,000 fl-Ibs (8,400 Ibs pull x 1 line x 3-foot tong arm) 18,000 ft-Ibs (6,000 Ibs pUll x 1 line x 3-foot tong arm) 12,600 fl-Ibs (4,200 Ibs pUll x 1 line x 3-foot tong arm)

APPENDIXC MUD PROGRAM


Copyright © 2006 by Terra Dynamics Incolllorated DYNAIV1ICS INC 03/01/06

HALLIBURTON

Baroid

Terra Dynamics Inc. DWD#l

Magnolia, Arkansas Columbia County, Arkansas

PROGRAM OVERVIEW:

Hoom~~~~eIS.c;~e(jgG~Bllff&N

.. '. . Casing Size

0' - 1,600' 143/4" 11 7/8"

1,600' - 4,600' 10 5/8" 75/8"

Depth; ••. ... 'Weight ... Vis' ..••.. ¥p........ 'pH ··lfblidJsoss ·········>:K:lon ... 0' :';il~600"·8:().:.; 9.2 32-'50 10- 30' .'9.0 NiC"1;5 rOOO·JfQGJOppm

Build spud with AQUAGELlIime system. Add potassium acetate for +1- 1000 ppm K. Utilize high viscosity EZ-MUD slurries to ensure adequate hole cleaning. Add gypsum for additional inhibition and to increase the efficiency of the mechanical solids control equipment.

Set 11 7/8" casing @ 1,600'

Continue with non-dispersed EZ-MUD system. Continue potassium additions. Reduce fluid loss with POLY AC and/or PAC-RlPAC-L.

9~O 6

Control anhydrite contamination with treatments of soda ash and THERMA-THIN. Maintain potassium levels with additions of potassium acetate. Continue additions ofPOLY-AC, PAC-R, and PAC-L for fluid loss control.

-',' 'f' - .---.~- ...~, • "~,' ,.".-: '--'-'~"::'-"""",,_,",," "', ._~ "

BSmM.&'EE»fF(j~ml'(:j)N;':bB~lllS

1) BIAnnona Chalk 2,465' 2) T/Tokio Sandstone 2,899 3) T/Lower Cretacious 3,255' 4) BlMassive Anhydrite 3,650' 5) T/James Lime 4,349 6) Hogg 4,595'

Interval: 0' - 1,600' Mud Type: AQUAGEL@/EZ MUD®

• Lost circulation due to poor hole cleaning and packing off. • Seepage in coarse unconsolidated sands. • Solids contamination.

• Dual Baroid 8 G Linear Shakers- 175 - 210- mesh screens • Baroid Mud Cleaner • Dual Baroid Centrifuges andfloc system

AQUAGEL, caustic potash, potassium acetate, BAROID, CONDET, EZ-MUD, BARAZAN-D PLUS, lime, MICA, and WALLNUT.

···Il.epfh, Vis yp pH Fluid Loss

Spud with fresh water thickened with AQUAGELIlime to about 32 - 35 sec/qt. Begin additions of potassium acetate to help inhibit soft clays and "gumbo". Recommend 10002000 ppm K ion in filtrate to achieve maximum inhibition.

Control pH in the 8.5 - 9.0 range with small treatments ofcaustic potash.

Minimize AQUAGEL additions to assist mechanical solids control equipment. Recommend 0.5 - 1.0 ppb EZ-MUD for additional viscosity and shale inhibition. Additional viscosity may be achieved with small amounts ofBARAZAN-D PLUS. Due

to the large hole size, well bore cleaning could be a problem. Monitor hydraulics closely and adjust rheology as needed to ensure adequate hole cleaning.

This interval could experience seepage due to coarse sand sections, so excess mud weight should be avoided. Small additions of MICATEX will help control seepage.

If gumbo becomes a problem, WALLNUT sweeps in addition to small amounts of CONDET will help reduce bit and BRA balling.

Use EZ-MUD sweeps prior to short trip and before POOR to run surface casing to ensure the hole is clean. Recommend reducing fluid rheology prior to pulling out to run surface casmg.

Interval: 1,600' - 4,600' Mud Type: LSND

• Possible hole cleaning problems. Monitor hydraulics and adjust as needed. • Anhydrite contamination. • Possible seepage. Recommend BAROFIBRE and/or BARACARB as needed to seal

permeable zones.

• Dual Baroid 8 G Linear Shaker - 210 mesh screens • Baroid Mud Cleaner • Dual Baroid Centrifuges andfloc system

AQUAGEL, caustic potash, BAROID®, EZ MUD, PAC-R, Soda ash, potassium acetate, THERMA THIN, BARACARB, BARO-FIBRE, MICA, and BARAZAN-D PLUS.

. .. . . ."0"' •.•• , ••••• _,' ••

··])eptll. .. . :Weiglit, . Vis·· yp.•. ··pH':'Flttld']Loss .... :.K.ionm ••

1;.6Q()'.~·2;100'··'8.8-9:4·. 34 ... 6'5< ·10';·30: •. 9m·<20~·io 1000i-'2tieu:ppm 2J()0'~ 4;600'8.8:'9.4 34->65 10':'·30 ·9.0 JO.-b·· 1000;C·2000ppm

Maintain a non-dispersed mud system during this interval. Continue additions of EZMUD and/or BARAZAN-D PLUS for viscosity and rheology control. Small amounts of AQUAGEL may be needed for additional viscosity.

Recommend small tour1y treatments of fine LCM (BARACARB, BARO-FlBRE, MICA) to seal permeable zones and reduce seepage.

Control fluid loss with treatments ofPOLY-AC and/or PAC-R.

Treat anhydrite contamination with additions of soda ash. If thinning IS needed, recommend treatments ofTHERMA-THIN.

Maintain filtrate potassium in the 1,000 - 2,000 ppm range with treatments of potassium acetate. Maintain pH in the 8.5 - 9.0 range with additions of caustic potash.

Recommend reducing yield point prior to running casing and cementing to ensure proper cement displacement.

APPENDIXD DRILL PIPE - BLOWOUT PREVENTERS

99-177 DOW DWD No. 1 Well Plan .TERRA

Copyright © 2006 by Terra Dynamics Incorporated DVNAIVlICS INC 03/01/06

DRILL PIPE - BLOWOUT PREVENTERS

DATE: 2/12106PREPARED BY: R.F. Bielenda WELL NAME: DOW DWD No.1

DRILL PIPE

AVERAGE TENSILE

AIR (#l

ALLOWABLENOMINAL WEIGHT, STRING WT. ININTERVAL OVERPULL (#) STRENGTH" (1000 #)GRADE & ACTUAL WT. (PPFI

FROM LENGTH SIZE (FT)

TO (IN)(FT) (FT)

Preset (12' KB)

69,400# with Surface

74 62 16Surface

100,00014/G-105/15.9 314" BHA

108,100# with 1,600

1,600 143/4 52,800#, 558' 1,600

314

BHA 100,0003,186 14/G-105/1594,600 105/8 41,900#, 434'

-PREMIUM VALUES ARE 80% OF NEW PIPE TENSILE STRENGTH. BLOWOUT PREVENTERS

PRESSURE TEST CASING SIZE

INSTALLED ON WORKING BORE STACK ARRANGEMENT FREQUENCY PRESSURE

(IN.) PRESSURE SIZE (IN.)

(PSI)

11 7/8

(PSI) Installation and A-250/1,000 Daily and Trips

3,000 3,000 11 S

RR Bi-Weekly R-250/1,00011 3,000 11 A

ACCUMULATOR)CLOSING UNIT

NO. OF OUTLETS NO. OF STATIONS VOLUME OF LIQUID AND GAS ....... ...............:. .....:.. ;:;:;:;:::::;:;:::::::>:.:.:.....:::::;::::::::;:::::::~:f::; ):::):):~:r: :==: ijj)Milii~=;~ij6~~i~i6.in~tiitr:

PRECHARGED PRESSURE (BEFORE ADDING LIQUID) 1,000 psi FINAL PRESSURE (FULLY CHARGED WITH LIQUID) 3,000 psi TEST CHOKE AND KILL LINES, MANIFOLD, KELLY COCK & VALVES.

Copyright 10 2006 by Terra Dynamics, Inc.

DRILL PIPE - BLOWOUT PREVENTERS - TYPE, (CONTINUED)

TRIPS

NUMBER OF PUMP ALLOWABLE MAX MAX INTERVAL

NUMBER OF DROP ALLOW DIFF.WELL DEPTH DIFF. INFLUID STROKES TO FILL HOLE PULL RUNSTANDS IN VOLUME

STROKES,LEVEL GALLONS SPEED" SPEED" FILLS

(FT) BETWEEN ~o. 1 PUMP STROKES +or-10%(FTI GPS LINER 'IMIN 'IMINGAL +or-10%BBL

6" 44 410-4"DP 146 3.48 15 60 60 1,600

Surface to 15 6" 50 5

1 - 8" DC 2 - 6 1/4" DC 166 18 3.33.96 17

139 14 at 90% 42 43.31 18

6073 174 7 6" 22 2 60

4,600 1,600 to 5-4"DP 16

1.98 6" 25 3

1 - 8" DC 1 - 6 1/4" DC 83 18 8 3.3

139 3.31 14 6" 4230 at 90% 4

·or slower as dictated bv well conditions

1 STD COLLAR = 62' 1 STO DP - 62' PUMP TYPES: NO.1 - EMSCO F800 6x9, NO.2 - HOL 700 OPI 6x8 (03412 Cat) 1·CLOSED WITH STORED ENERGY IN ACCUMULATOR. 2-MAX. ALLOWABLE DIFFERENCE IN STROKES REQUIRED TO FILL THE HOLE BEFORE CHECKING FOR FLOW OR LOST CIRCULATION. THIS TO BE FOR THE SPECIFIC PUMP.

ITEM DISPLACEMENT CAPACITY 8" x 3" Drill Collars 0.05342 bbl/ft 0.00874 bbl/ft 6 1/4" x 2 1/2" Drill Collars 00319 bbl/ft 0.00607 bbl/ft 41/2",16.60 Ib/ft nom. wt. DP 0.00640 bbl/ft 0.0142 bbl/ft 4", 14.0 Ib/ft nom. wt. OP 0.00562 bbl/ft 0.01084 bbl/ft

PUMP SPECIFICATIONS

Number 1 Number 2

OPI700 DL AND 700 HDL TRIPLEX-7"x8"F-8CO TRIPLEX---9W'x9"-3 CYCLE SINGLE ACTING PISTON MAX.(Based on 100% Volumetric Efficiency end 90% Mechanical Efficiency) S.P.M. 150' 120 100 80 60 DISCH. GALMAX.

S.P.M. 160 150 140 130 120 110 UNERSIZE PRESS. PERDISCH. GAL OUTPUT, GALLONS PER MINUTE UNERSIZE

(Inches) P.S.1. REV. OUTPUT, GALLONS PER MINUTE

PRESS. PER P.S.1. REV.(Inches) 7 599 479 399 319 239 1690 3.99

6'12 516 413 344 275 206 1960 3.44585 543 502 459 1968 4.186'l4 669 627

6 440 352 293 234 176 2300 2.93 6'/2 620 582 543 504 466 427 2120 3.88

5'12 369 295 246 197 148 2737 2.466'14 574 538 502 466 431 394 2295 3.59

5 306 245 204 163 122 3312 2.04 6 529 496 463 429 397 363 2490 3.30

4V2 248 198 165 132 99 4089 1.65 5'12 444 416 389 361 333 305 2965 2.78

Max. Input HP 700 556 463 371 278 5 367 344 321 289 275 252 3590 2.29

242 223 204 4415 1.864'12 297 279 260 •Applications to be approved by OPI Engineering Max.lnputHP 853 800 747 693 640 587

Copyright (\) 2006 by Terra Dynamics, Inc.

APPENDIXE CASING AND ATLAS BRADFORD CALCULATED DUPLEX 2205

ST-L CONNECTION DATA



CASING

DATE: 2/12/06PREPARED BY: R.F. BielendaWELL NAME: DOW DWD No.1

CONDUCTOR - SURFACE CASING

INTERVAL IN FEET SIZE

SURFACE

liN.) CONDUCTORWEIGHT GRADE COUPLINGFROM LENGTH0.0. TO

(LBS.lFT.) Plain-end

fFT-KB) IFT-KB) 1FT.) RUNNING

16 MUD WEIGHT 8.8t09.0

12' AGL)

beveled and P12 74 62 IILBS.lGALl MAXFRAC.

11 7/8 Surface

welded

R 12.3to 12.5

114' AGL J-55 11 3/4" BTC GRADIENT1,600 71.81,600

IILBS.lGAL)

MAX TEST PRESSURE

Nom

E 1,000 PSI) 30 Minutes

CASING WEIGHT IN AIR - 114,900 LBS. USE API-MODIFIED OR BEST OF BURST LIFE 2000 THREAD COMPOUND FOR ALL NON-THREADLOCKED PRESSURE S 3,070 CONNECTIONS. IIPSI)

COLLAPSE PRESSURE E 1,510 PSI)

MAKE-UP Positional makeup with Thread-Lock

TORQUE T compound

RANGE Positional makeup with API Modified FT-LBS.) thread compound

PROTECTIVE CASING

INTERVAL IN FEET MAKE-UP SIZE TORQUE 0.0. FROM WEIGHT RANGETO LENGTH GRADE COUPLING DOPE (IN.) IFT-KB) (FT.) (LBS.lFT.)IFT-KB) (FT-LBS.)

RUNNING MUD WEIGHT LBS.lGAL)

FRAC. GRADIENT @ SHOE LBS.lGAL)

CASING WEIGHT IN AIR MAXIMUM TEST PRESSURE IIPSI) For 30 Minutes

LONGSTRING CASING

75/8 Surface 4,600 4,6000A RUNNING MUD WEIGHT = 9.2 to 9.5 As Spec.75/8 As Soec. -3,800 26.4 N-80 LTC-8rd 3,680 to 6,130 BOL20OC LBS.lGAL) As Spec. As Spec.75/8 26.4 N-80 3,680 to 6,130 ThdLockLTC-8rd

75/8 As Spec. As Spec. -800 25.54 0-2205 2,900 to 3,700 BOLPTe FRAC. GRADIENT @ SHOE - 14.4 to 15.4ABST-L As Spec.75/8 As Spec. 0-220525.54 AB ST-L 2,900 to 3,700 ThdLock LBS.lGAL)

MAXIMUM TEST PRESSURE - 1,500 CASING WEIGHT IN AIR -120,752 LBS. PSI) For 30 Minutes

PRODUCTION CASING OR LINER

RUNNING MUD WEIGHT -LBS.lGALl

FRAC. GRADIENT @ SHOE LBS.lGAL)

CASING WEIGHT IN AIR MAXIMUM TEST PRESSURE = PSI)

SPECIAL INSTRUCTIONS

1. Torque values specified for carbon steel tubulars are API Optimum torque values and account for the use of API Modified, Best Of Life 2000, SealLube or thread-lock thread compound. The 7 518-inch Duplex casing will be made up to the torque range specified by the Alias Bradford representative using API Modified or Best 0 Life Premium Thread Compound (PTC).

2. All BTC connections are positional makeups and need to be made up to the base of the stenciled triangle on the pin regardless of which thread compound is used. Note that the 11 7/8-inch surface casing has 11 3/4-inch BTC connections.

3. All API STC-8rd and LTC-8rd connections are to be made up to the last thread scratch (±) one turn regardless of which thread compound is used. The torque range shown in the well plan is API Optimum ±25%. Regardless of torque value specified, all Alias Bradford STL flush joint connections must be made up to the shouldered position then brought up to the optimum torque range as directed by the Atlas Bradford representative.

4. Mill end couplings for surface casing float equipment and longstring stage tool matings that have been thread-locked at the pipe yard for use in thread-locking float equipment, float joints and stage tools can be identified by the yellow painted couplings.

5 For 11 7/8-inch surface casing, the threads have been coated with Preserv-A-Thread compound prior to Shipment to site. Visually inspect all threads on the racks prior to running surface casing. Wipe off Preserv-A-Thread prior to applying API Modified thread compound. Dope box end of coupling thoroughly but sparingly.

6. For the 7 5/8-inch longstring carbon steel and alloy casing material, the threads have been coated with Preserv-A-Thread compound prior to shipment to site. Visually inspect all threads on the racks prior to running longstring casing. Wipe off Preserv-A-Thread prior to applying Best 0 Ufe (BOL) 2000, PTC or thread-lock compound. Atlas Bradford to apply BOL PTC and thread-lock compound as specified in well plan to 7 5/8-inch Duplex 2205 material. Best 0 Life 2000 thread compound to be used on all non-thread-Iocked 7 5/8-inchcarbon steel material. Note that 7 5/8-inch casing pups will be sent out fully doped without Preserv-A-Thread and the ones selected for use will need to be cleaned on site, visually inspected and the appropriate thread compound applied prior to running.

7. Make sure that circulating swages and any necessary valves are on location prior to running surface and longstring casings in case it becomes necessary to wash casing to bottom if you encounter fill.


ATLAS BRADFORD TECHNICAL SPECIFICATIONS

ST-L standard

SAF 220565 65,000

100,000

7.625 6.969 0.328 26.40 25.56 7.519

489,000 3,100 4,890 4,500

7.625 6.889 6.844 4.28

4.373 58.2

284,000 437,000

7,940 171,000

3,100 4,890

13.6

2,900 3,700

Casing 7·5/8 in 26.401b/ft SAF 220565

Material Grade

Minimum Yield Strength (psi.) Minimum Ultimate Strength (psi.)

Pipe Dimensions Nominal Pipe Body 00 (in.) Nominal Pipe Body 10 (in.) Nominal Wall Thickness (in.) Nominal Weight (Ibs./ft.) Plain End Weight (Ibs.lft.) Nominal Pipe Body Area (sq. in.)

Pipe Body Performance Properties

Minimum Pipe Body Yield Strength Minimum Collapse Pressure (psi.) Minimum Internal Yield Pressure Hydrostatic Test Pressure (psi.)

Connection Dimensions Connection 00 (in.) Connection 1.0. (in.) Connection Drift Diameter Make-up Loss (in.) Critical Area (sq. in.) Joint Efficiency (%) Connection Performance Properties

(1) Joint Strength (2) Reference Minimum Parting Load

Reference String Length eft) 1.4 Design Factor Compression Rating (Ibs.) Collapse Pressure Rating (psi.) Internal Pressure Rating (psi.) Maximum uniaxial bend rating [degrees/100 ft.] Recommended Torgue Values

(3) Minimum Final Torque (ft.-Ibs.) (3) Maximum Final Torque (ft.-Ibs.)

(1) Joint strength is the elastic limit or yield strength of the connection. (2) Reference minimum parting load is the ultimate strength or parting load of the connection. (3) Torque values are recommended and can be affected by field conditions.

Connection specifications within the control of Grant Prideco were correct as of the date printed. Specifications are subject to change without notice. Certain connection specifications are dependent on the mechanical properties of the pipe. Mechanical properties ofmill proprietary pipe grades were obtained from mill publications and are subject to change. Properties ofmill proprietary grades should be confirmed with the mill. Users are advised to obtain current connection specifications and verify pipe mechanical properties for each application.

APPENDIXF CEMENT AND EPSEAL COMPRESSIVE TEST DATA

99-177 DOW DWD No. I Well Plan eTERRA


CEMENT

DATE: 2/28/06PREPARED BY: R.F. BielendaWELL NAME: DOW DWD NO.1

COMPRESSIVE STRENGTH

(SX) TYPE WITH

THICKENINGWATER PUMPING TIME (1) CEMENT VOLUME SLURRY YIELD (PSI)

ADDITIVES

TIME (2) CUBIC FT. REQUIREDDENSITY 24 HOURS 48 HOURS

CEMENT DISP

CASING SIZE, INCHES

HOURS 12 HOURSPER SACK GAL.lSACK RATESLBS./GAL

5201.83 MINUTES 6:00+ 165 724

11 7/6 LEAD: 510 Sacks 12.8 9.69

24

SETTING DEPTH, FT-KB.

Light Standard with HOUR: MINUTES

1/4 Iblsk Pheno Seal 5% Salt and

0:24

1,600

STATIC TEMP. -94 OF BPM

7 I CIRCULATING TEMP. 2:17 994 1,732 2,491

-84OF or close to TAIL: 200 Sacks of 1.18 5.06 MINUTES15.6 Standard "A" with 8 3

ambient mud temperature 1% CaCI, and HOUR: MINUTES

COLUMN HT., FT. Total Job 0:35

Lead - 1,100 feet to surface 1/4 Iblsk Pheno Seal

Fine Tail-1,600 to 1,100 feet BPM

20% excess factor JP Displace: 15.8 bbls 5 I 5

CEMENT VOLUME PUMPING TIME (1) COMPRESSIVE STRENGTH

(SX) TYPE WITH

SLURRY YIELD WATER THICKENING (PSI)

ADDITIVES CUBIC FT. REQUIRED TIME (2) DENSITY PER SACK GAL.lSACK RATES HOURS

CEMENT DISP

CASING SIZE, INCHES

LBS./GAL

NIA MINUTES Shoe124 bbls 13.6 NlA 25

SETTING DEPTH, FT-KB.

75/6 Epseal RE System 12 hrs -6,000 1 drum/drum Epseal HOUR: MINUTES 6 hrs - 6,000 24 hrs - 6,000

RE,0.25 galsldrum 0:25

4,600 7:20Plastic Fixer Top 700 Ibsldrum SSA-1 Stage Tool

STATIC TEMP. & 1.5 gals/drum LC -148' F at Shoe 12 hrs-O 24 hrs - 6,000

-114°F at DV Tool Catalyst BPM 8 hrs - 0

5 I CIRCULATING TEMP. MINUTES

-115' F at Shoe Displace:

0:57 -95'F at DV Tool

Release Plug 10 bbls My-T-OiIIV HOUR: MINUTES

COLUMN HT., FT. 62 bbls Mud Total Job 1:22

1,906 feet assuming 45 bbls My-T-OilIV gauge hole with 20% 97 bbls Mud to displace cement plug to float collar BPM

excess factor Drop Open PluQ - ap~ rox. 14 min free-fall to open staQe tool I 5

COMPRESSIVE STRENGTH

(SX) TYPE WITH

CEMENT VOLUME YIELD WATER PUMPING TIME (1) THICKENINGSLURRY (PSI)

ADDITIVES

CUBIC FT. TIME (2) DENSITY REQUIRED 24 HOURS 48 HOURS

CEMENT DISP

CASING SIZE, INCHES

LBS.lGAL PER SACK GAL.lSACK RATES HOURS 12 HOURS

MINUTES 3:13 384 581 655LEAD: 365 Sacks 12.6 1.83 9.69 75/6 Light Standard with 25

SETTING DEPTH, FT-KB. 5% Sail and HOUR: MINUTES Stage Tool at 1/4 Ib/sk Pheno Seal 0:25

2,694 feet Fine

STATIC TEMP. -114° F Stage Tool BPM

-105'F LeadlTaillnterface 5 I 2,056 UST

-95° F or close to 1,322 1,852CIRCULATING TEMP. TAIL: 165 Sacks 15.6 1.16 MINUTES

2,230 Crush 2:165.02

ambient mud temperature Standard "A" 9 25

Release Closing Plug HOUR: MINUTES

COLUMN HT., FT. Pump 25 Sacks Total Job 0:59 Lead - 2,094 feet to surface Standard "A"

Tail- 2,694 to 2,094 feet Pump 122 bbls Mud to displace closing plug to stage tool BPM 5 I 5

1 PUMPING TIME BASED ON MIXING @ X BPM AND DISPLACING @ Y BPM INCLUSIVE OF DISPLACEMENT TO

ANTICIPATED PLUG BUMP.

. I I

2. THICKENING TIME TEST RUN AT BHCT, COMPRESSIVE STRENGTH TEST RUN AT BHST.

3. MEAN ANNUAL SURFACE TEMPERATURE IS APPROXIMATELY 65'F WITH A GEOTHERMAL GRADIENT OF 1.8°F/100 FT.


HALLIBURTON ENERGY SERVICES SOUTHEAST NWA LABORATORY KILGORE, TEXAS

Submitted by: B. BERTRAND Service Center: KILGORE, TX PROJECT NO: C-015101.Q072-2006

WELL INFORMATION JOB AND SCHEDULE INFORMATION TERRA DYNAMICS CASING BHST: 105'F DWD #1 lVD: 1400 ft BHCT: 84'F MAGNOLIA FIELD MD: 1400 ft Time to BHCT: 15 minutes COLUMBIA CO., AR Mud Weight: 8.33 Final Pressure: 900 psi RIG NAME NOT GIVEN FRESH WATER MUD SYSTEM

PILOT TEST BULKPLANT LOCATION: KILGORE, TX DATE 1/26/2006

TEST NO: 3 SLURRY INFORMATION ADDITIVES LOT NO.

Cement: HLC (KILGORE) 5.0 % BWOW SALT Using: HOLCIM TYPE 1 (MIDLOTHIAN) 0.25 LBS/SK PHENO SEAL Water: 9.586 gals/sk Source: LAB TAP WATER SlurryWt: 12.8Ibs/gal Yield: 1.818 cU.ft/sk

THICKENING TIME RESULTS TEST NO: 3

REQUESTED 4 - 5 HOURS PUMPING TIME (HOURS:MINUTES) 6:00+

COMPRESSIVE STRENGTH RESLILTS Temperature #1 = 80 'F HOUR 6 12 18 24 36 48 72 Time to 50 psi = 06:09 psi 43 185 438 520 642 724 811 Time to 500 psi =022:10 psi 43 185 438 520 642 724 811

AnalystRS; .IL; SO; DB J. R. SULLIVAN, SENIOR SCIENTIST NOTICE: This report is for information only and the content is limited to the sample described. Halliburton makes no warranties, express

or implied. as to the accuracy of the contents or results. Any user of this report agrees Halliburton shall not be liable for any loss or damage, regardless of cause, including any act or omission of Halliburton resulting from the use thereof.


Submitted by: B. BERTRAND Service Center: KILGORE, TX PROJECT NO: C-0151 01-0072·2006

WELL INFORMATION JOB AND SCHEDULE INFORMATION TERRA DYNAMICS CASING BHST: 105'F DWD #1 TVD: 1400 ft BHCT: 84'F MAGNOLIA FJELD MD: 1400 ft Time to BHCT: 15 minutes COLUMBIA CO., AR Mud Weight: 8.33 Final Pressure: 900 psi RIG NAME NOT GIVEN FRESH WATER MUD SYSTEM


rEST NO: 2 SLURRY INFORMATION ADDITIVES LOT NO.

Cement: STANDARD 1.00 % CALCIUM CHLORIDE Using: TEXAS-LEHIGH \ STANDARD 0.25 LBS/SK PHENO SEAL Water: 5.065 gals/sk Source: LAB TAP WATER Slurry Wt: 15.6 Ibs/gal Yield: 1.177 cu.fVsk

'. THICKENING TIME RESULTS

REQUESTED 2 - 3 HOURS PUMPING TIME

UNITS of CONSISTENCY(Bc's) 70

(HOURS:MINUTES) 2:17

TEST NO: 2

COMPRESSIVE STRENGTH RESULTS Temperature #1 = 80 'F HOUR Time to 50 psi = 03:07 psi Time to 500 psi = 007:10 psi

6 368 368

12 994 994

18 1445 1445

24 1732 1732

36 2165 2165

48 2491 2491

AnalystRS; JL; SO: DB J. R. SULLIVAN, SENIOR SCIENTIST NOTICE: This report is for information only and the content is limited to the sample described, Halliburton makes no warranties, express

or implied. as to the accuracy of the contents or results. Any user of this report agrees Halliburton shall not be liable for any loss or damage, regardless of cause, including any act or omission of Halliburton resulting from the use thereof.

HALLIBURTON ENERGY SERVICES

SOUTHEAST NWA LABORATORY

KILGORE, TX

Submitted by: KATY WRIGHT WELL INFORMATION

Service BOSSIER CITY, LA PROJECT NO: C-015101-0111-2006 JOB AND SCHEDULE INFORMATION

TERRA DYNAMICS DOW DWD # 1 NOT GIVEN FIELD COLUMBIA CO., AR NOT GIVEN

CASING (DV STAGE) TVD: 4630 ft MD: 4630 ft

Mud Weight: 9.5 Ibs/gal WATER BASE MUD

BHST: BHCT:

Time to BHCT: Final Pressure:

148'F 115'F 27 minutes 2650 psi

PILOT TEST BULKPLANT LOCATION: BOSSIER CITY, LA DATE: 2/15/2006

TEST NO: 1 SLURRY INFORMATION ADDITIVES LOT NO,

Cement: EPSEAL LC 51.0 GAL/DRU EPSEAL RE Using: HALLIBURTON 0.25 GAL/DRU PLASTIC FIXER Water: ogals/sk 700 LBS/DRU SSA-1

1.5 GAUDRU LC CATALYST Source: ALICE, TX, Slurry Wt: 13.8 Ibs/gal Yield: 84.67 GALS /DRUM

THICKENING TIME RESULTS UNITS of CONSISTENCY(Bc's) 70 TEST NO: 1

REQUESTED 6:00 + PUMPING TIME (HOURS:MINUTES) 7:20

COMPRESSIVE STRENGTH RESULTS Temperature #1 =114 'F HOUR 8 12 24

psi NMS NMS 6000 psi NMS NMS 6000

Temperature #2 =148 'F HOUR 8 12 24 psi 6000 6000 6000

Analyst: RS; JL; SO; DB J. R. SULLIVAN, SENIOR SCIENTIST NOTICE: This report is for information only and the content is limited to the sample described. Halliburton makes no warranties, express

or implied, as to the accuracy of the contents or results. Any user of this report agrees Halliburton shall not be liable for any loss or damage, regardless of cause, including any act or omission of Halliburton resulting from the use thereof.

SOUTHEAST NWA LABORATORYHALLIBURTON ENERGY SERVICES KILGORE, TEXAS

Submitted by: KATY WRIGHT Service Center: PROJECT NO: C-015101-0093-2006

WELL INFORMATION JOB AND SCHEDULE INFORMATION TERRA DYNAMICS PRODUCTION CASING BHST: 114'F DWD #1 TVD: 2722 ft BHCT: 95'F NG FIELD MD: 2722 ft Time to BHCT: 20 minutes COLUMBIA CO., AR Mud Weight: 9.5 Ibs/gal Final Pressure: 1650 psi RIG NAME NOT GIVEN WATER BASE MUD SYSTEM

PILOT TEST BllLKPLANT LOCATION: KILGORE, TX DATE 2/9/2006 TEST NO: 1 SLURRY INFORMATION ADDITIVES LOT NO.

Cement: HLC (KILGORE) 5.0 % BWOW SALT Using: TEXAS-LEHIGH \ STANDARD 0.25 LBS/SK PHENO SEAL Water: 9.586 gals/sk Source: LAB TAP WATER SlurryWt: 12.8 Ibs/gal Yield: 1.818 cu.ftlsk


REQUESTED 3 - 4 HOURS PUMPING TIME (HOURS:MINUTES) 3:13

COMPRESSIVE STRENGTH RESULTS Temperature #1 = 105 'F HOUR 6 12 18 24 36 48 72 Time to 50 psi = 03:27 psi 182 384 503 581 746 855 1043 Time to 500 psi = 17:56

RHEOLOGY RESULTS RPM 600 300 200 100 60 30 20 10 § ~ TEMPERATURE #1 = 80 'F 64 52 50 46 44 40 40 38 34 20 TEMPERATURE #2 = 95 'F 60 50 47 43 40 38 37 34 30 17

AnalystRS; JL; SO; DB J. R. SULLIVAN, SENIOR SCIENTIST NOTICE: This report is for information only and the content is limited to the sample described. Halliburton makes no warranties. express



Submitted by: KATY WRIGHT Service Center: PROJECT NO: C-0151 01-0093-2006

WELL INFORMATION JOB AND SCHEDULE INFORMATION TERRA DYNAMICS PRODUCTION CASING BHST: 114'F DWD #1 TVD: 2722 ft BHCT: 95'F NG FIELD MD: 2722 ft Time to BHCT: 20 minutes COLUMBIA CO., AR Mud Weight: 9.5Ibs/gal Final Pressure: 1650 psi RIG NAME NOT GIVEN WATER BASE MUD SYSTEM


TEST NO: 2 SLURRY INFORMATION ADDITIVES LOT NO.

Cement: STANDARD 0.25 LBS/SK PHENO SEAL Using: HOLCIM TYPE 1 (MIDLOTHIAN)

Water: 5.059 gals/sk Source: LAB TAP WATER Slurry Wt: 15.6 Ibs/gal Yield: 1.169 cU.ft/sk


REQUESTED 3 - 4 HOURS PUMPING TIME (HOURS:MINUTES) 2:18

COMPRESSIVE STRENGTH RESLILTS Temperature #1 =114 'F HOUR Time to 50 psi = 02:46 psi Time to 500 psi = 04:31

6 781

12 1322

18 1583

24 1852

36 2006

48 2058

CRUSH 2230

RHEOLOGY RESULTS TEMPERATURE #1 = 80 'F

TEMPERATURE #2 = 95 'F

RPM 600 126 118

300 90 83

200 80 75

100 70 65

60 62 56

30 56 50

20 52 48

10 44 43

§ 30 28

~ 22 21

AnalystRS; JL; SO; DB J. R. SULLIVAN, SENIOR SCIENTIST NOTICE: This report is for information only and the content is limited to the sample described. Halliburton makes no warranties, express


CALIBRATION OF SURFACE EQUIPMENT AND RECORD REQUIREMENTS

WELL NAME: DOW DWD No.1 PREPARED BY: R.F. Bielenda IDATE: 2/12106

EQUIPMENT TYPE FREQUENCY OUTLINE OF TEST

1. Weight Indicator

2. Choke Manifold

Check weight of empty blocks against indicator. Each trip Temperature changes may affect readings.

Record BHA weight each triP. Check operation of hydraulic control valve and

Daily adjustable choke Of applicable).

3. COz - HzS Detector Of available) Every 2 to 3 days Check operation and accuracy of equipment.

4. Chromatograph (if available) Run Carbide bomb lag check to verify time delay for depth

Every 12 hours correlations on cutting samples bottoms up.

5. PVT (if available) Daily Compare with pit markers and previous day's charts.

6. Flo-Sho (if available) Daily Compare actual flow rate calculated from pump rate.

7. Pump Stroke Counter Daily Compare to actual stroke count.

8. Reduced Circulation Rate and Pressures

9. Pressure Gauges

Daily Record time, SPM, Standpipe pressure and depth.

Compare all gauge pressures in the circulating system While testing BOPs and verify accuracy to within 5% of each other.

SPECIAL INSTRUCTIONS

1. All flow detection and control equipment provided by outside vendors should be checked at regular intervals by respective vendors. If any equipment malfunctions, get serviceman out ASAP. Record time trouble first identified, when service representative notified and time of serviceman arrival.

2. Daily IADC sheets must be completely and accurately filled out.

3. Conduct weekly blowout and fire drills on each tour and note on daily IADC sheet.

4. Note drag off bottom and amount of fill encountered when retuming to bottom on daily IADC sheet.

5. Records of all sampling, testing and analysis shall include: a) The date, exact place and time of sampling, testing or measurements; b) The individual(s) Who performed the sampling, testing or measurements; c) A precise description of sampling and testing methodology and the handling of samples thereof; d) The date(s) analysis were performed; e) The name(s) of individuals who performed the analysis; f) The analytical techniques used; g) The results of such analysis.

6. Function testing of BOP equipment should be reported on driller's IADC report.

7. All rig repairs will be noted in IADC reports and initialled by TDI site supervisor.

8. Fax all casing, cementing and test forms with morning reports.

Copyright <0 2006 by Terra Dynamics, Inc.

APPENDIXH COPY OF ADEQ PERMIT FOR DOW DWD NO.1



PERMIT ISSUED BY

STATE OF ARKANSAS DEPARTlVIENT OF ENVIRONNIENTAL QUALITY

8001 NATIONAL DRIVE, P. O. BOX 8913 LITTLE ROCK, AR 72219-8913 .

The Dow Chemical Company Pennit: 17-U P. O. Box 150 AFIN: 14·00416 Plaquemine, LA

Pursuant to the Arkansas Water and Air Pollution Control Act(fA.C.A.]§ 8-4-101 etseq.) and the Arkansas Undergrol:1nd Injection Control (UIC) Code, this permit is issued to The Dow ChemicaJ Company (hereinafter called the Permittee) to operate a Class f nonhazardous waste disposal well DWD #1 at the following location:

Nonhazardous waste disposal well DWO #1 located in the southeastern quarterofSection 18,Township18 South, Range 17South,approximatelyfour miles west of Magnolia, in Columbia County.

The Permittee must comply with a.1I the terms and conditions of this permit. This .pennit consists of the conditions contained herein and all applicable standards and specific facility conditions developed in accordance with the Arkansas UIC Code and the provisions of Tille 40 of the Code of Federal Regulations (40CFR), Parts 144, 146and 124, as specified in this permit. Applicable State and Federal Regulations are those which are in effect on the date of issuance of this permit, and such Federal Regulations adopted by reference in Section 3 of the Arkansas UIC Code (see 40 CFR 144.52 (b)(2».

This permit is based on the condition that all information submitted in the permit application dated August 7,2000 and subsequent amendments, is accurate and thatthe facility will be constructed and operated as specified in the application. Any misrepresentations found in this information may be grounds forthe termination ormodifICation of this permit (see 40 CFR 144.39, 144.40, and 144.41) and possible enforcement action.

This permit is effective as of October 3. 2002 and shall remah, in effect until October 3, 2012 unless revoked and reissued, or terminated (see 40 CFR 144.39

and 144.40) or continued in accordance with the Arkansas UIC Code.

Issued this -3 day of .~~Q"A" •2002

Chief, Water Division

TABLE OF CONTENTS

Part I Standard Conditions

A. Effect of Permit 1

B. Duration of PenTlit. 1 C. Continuation of Expiring Permit 1

D. Transfel'5 of Permit 10 ••••••••••••••••••••••••••••••••••••••••••••••••••••••••

1. Transfers by Modification 2

2. AutomaticTransters 2

E. PerrnitActions 2

1. Modification or Revocation and Reissuance ofthis Permit 2 2. Termination of this Permit ~.3

3. MinorModifications tothis Permit 3 F. PermitConditions 3

1. DutytoComply 3

2. Dutyto Reapply....................................................................................•.................•....4

3. Need to Halt or Reduce Activity nota Defense 4

4. Dutyto Mitigate........................•..................................................~ ............................•..4

5. Dutyto Provide Information 4

6. ProperMaintenance , 4

7. Inspection and EntJy , ~................•.................................................4

8. . Monitoring 5

9. Records ,..................................................................•.5 1O. Reporting Requirements 5

1. Planned Changesto Faciflty 5

2. Anticipated Noncompliance..•......................................................................5

3. Monitoring Reports ~ 6

4. Notification of Changes in Well Operations 6

5. Noncompliance Reporting 6

6. Other Information.....................•.....................................................................6

7. Conversion orAbandonment ofthe Injection Facility 6

11. Signatory Information:- 7

12. Confidential Information ~ 7

G. Severability 7

H. Corrective Action Plan 7

Part II Drilling and Completion Requirements for New Wells

A. Construction Requirements 8

1. Approved Plans and Specifications 8

2. Commencement of Construction 8

3. Cores of the Injection Intervals and Confining Zone 8

4. Requirements Priorto Commencing Injection ; 8

5. Well Construction Materials 8

B. Completion Reports 10

Part IIISpecific Conditions

A. Operational Requirements...........................................................................•........................12

1. Reconstruction, Recompletion, or Modification 12

2. Proposed Formation Permitted for Injection....•........................•...........................12

3. Authorization ofSpecific Injection InteNals 12

4. Casing and Cementing 12

5. . Waste tobe Injected............................................................•..•.............." 13 6. Proposed Operational Parameters 14

7. Instrumentation.............•............................................................................•.•.........14

8. Parameters to beMeasured ~ 14

B. Mechanical Integrity 15

1. Deillonstration ~ 15

2. Maintenance 15

3. Annulus Pressure Testing ~ 15

4. Loss of Mechanicaf Ihtegrity 16

C. Monitoring and Reporting 16

1. Monthly Reporting Requirements 17

2. Quarterly Reporting Requirements 17

3. Annual Reporting Requirements 18

4. Corrosion Monitoring ~ 19

5. Waste AuidsAnalysis 19

(a) Waste Analysis Plan 19

D. Plugging and Abandonment. 20

E. Rnancial Assurance 20

Part IV Other Conditions A. Variances 21

B. Compliance Schedules 21

C. OtherConditions Specifictothis Pennit.. 21

1

PART I " STANDARD"CONDITIONS

I.A EFFECT OF PERMIT

The Permittee is authorized to construct and operate the waste disposal well DWD #1 in accordance with the conditions set forth in this permit. Injection of any wastes not authorized by this permit is strictly prohibited.

In accordance with 40 CFR 144.35, compliance with this permit constitutes compliance with Part C of the Safe Drinking Water Act (SDWA) and the Arkansas Water and Air Pollution Control Act (Act 472 of 1949, as amended) for purposes of enforcement. Issuance of this permit does not convey property rights of any sort or any exclusive privilege, nor does it authorize any injury to persons or property, any invasion of other private rights, or any infringement of State or local laws or regulations. Compliance with the terms of this permit does not constitute a defense to any action brought underthe provisions of Act 472 of 1949, as amended, or any other law governing protection of public health or the environment.

The requirements of 40 CFR 144 SUbparts A, 8, 0 and E and 40 CFR 146 Subparts A and Bare incorporated by reference into this permit. Where there are individual provisions in this permit that differfrom the corresponding conditions in the above referenced regulations, the conditions of this permit will prevail.

I.B DURATION OF PERMIT

The requirements of 40 CFR 144.36 are incorporated by reference. This permit is effective for a period not to exceed ten years from the date of issue, unless terminated forcauses specified in 40 CFR 144.40 and Part I.E.2 of this permit.

I.e eONTlNUATION OF EXPIRING PERMIT

This permit will remain in effect beyond the expiration.date if the Permittee has submitted a timely, complete application and, through no fault of the Permittee, the ADEQ Directorhas not issued a new permit as set forth in Act 472 of 1949, as amended. Permits continued under this Part remain fully enforceable and are subject to those actions specified in 40 CFR 144.37.

1.0 TRANSFER OF PERMIT

This permit is not transferable to any person except after notice to the ADEQ Director. The ADEQ Director may require modification or revocation and reissuance of the permit to change the name of the Permittee and incorporate such other requirements as may be necessary under the SOWA.

2

I.D.1 Transfers by Modification

The requirements of 40 CFR 144.38(a) are incorporated by reference. This permit may be transferred by the Permittee to a new owner or operator if the permithas been modified or revoked and reissued pursuant to 40 CFR 144.39(b)(2), or a minor modification made under 40 CFR 144.41 (d), to identify the new Permittee and incorporate other requirements as may be necessary under the SDWA.

I.D.2 Automatic Transfers

The requirements of 40 CFR 144.38(b) are incorporated by reference. This permit may be automatically transferred to a new Permittee if:

(a) The existing Permittee provided written notification to the ADEQ Direetorat least thirty°(30) days in advance of the proposed transferdate referred to inPart I.D.2(b} of this permit; .

(b) The notice includes a written agreement between the existing and proposed Permittees, contains a specific date for transfer of permit responsibility, coverage, and liability between them, and demonstrates that the financial responsibility requirements of40 CFR 144.52(a)(7) will be metby the proposed Permittee;

. (c) TheADEQ Director does not notify the existing and the proposed Permittee of his or her intent to modify or revoke and reissue the permit. A modification under this condition may also be a minor modification under 40 CFR 144.41. If the notice from the ADEQ Director is not received, the transfer is effective on the date specified in the agreement mentioned in Part I.D.2(b) of this pennit.

I.E PERMIT ACTIONS

This permit may be modified, revoked and reissued, orterminated upon the request of any interested person, inclUding the Permittee, or upon the ADEQ's initiative. These actions shall be allowed only underthe conditions set forth in this permit and 40 CFR 144.39. All requests shall be in writing and shall contain facts or reasons supporting the request. The filing of a request by the Permittee for a permit modification, revocation and reissuance, termination or notification ofplanned changes or anticipated noncompliance does notstay any provision of this permit.

1.E.1 Modification or Revocation and Reissuance of this Permit

Based upon receipt of any information, that one or more of the causes specified under 40 CFR 144.39(a) or 144.39(b) exists, the ADEQ Director may modify, or revoke and reissue, this permit accordingly, subject to the limitations of 40 CFR 144.39. If this permit is modified, only those conditions subject to modification are reopened. If this permit is revoked and reissued, the entire permit is reopened, subjectto revision and issued for a new term.

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If cause does not exist, then the ADEQ Directorshall not modify, or revoke and reissue this permit. If a permit modification satisfies the criteria of 40 CFR 144.41 for minor modifications, this permit may be modified without a draft permit or a public review, specified under Part 1.E.3 of this permit.

1.E.2 Termination of this Permit

The ADEQ Director, in accordance with 40 CFR 144.40 by reference, mayterminate this permit during its duration as specified under Part 1.8 of this permit or deny any application for renewal of this permit for the following causes:

(a) Noncompliance by the Permittee with any condition of this permit;

(b) The Permittee's failure in the application or during the permit issuance process to disclose fully all relevant facts, or the Permittee's misrepresenta.tion 'of any relevant facts at any time;

(c) A determination that the permitted activity endangers human health or the environment and can only be regUlated to acceptable levels by permit modification or termination.

The ADEQ Director shall follow the applicable procedures in 40 CFR Part 124 in terminating this permit.

I.E.3 Minor Modifications to this Permit

Upon the consent of the Permittee, the ADEQ Director may make minormodifications to this permit as specified in 40 CFR 144.41 without following the procedures of 40 CFR Part 124. Any modification not determined to be a minor modification under40 CFR 144.41 must comply with the procedures of 40 CFR 124.5 and 144.39.

'.F PERMIT CONDITIONS

The requirements of 40 CFR 144.51 are incorporated by reference into this permit. The requirements of40 CFR 144.52, where applicable to Class I nonhazardous waste disposal wells, also are incorporated by reference into this permit. Where there are individuaJ provisions in this permit that differ from the corresponding individual provisions in 40 CFR 144.51 and 144.52, the provisions of ·this permit prevail.

1.F.1 Duty to Comply

The Permittee must comply with all conditions of this permit. Any permit noncompliance constitutes aviolation of the SDWA and is grounds for enforcement action, for permit termination, revocation and reissuance, or modification, orfordenial of a permit renewal application.

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I.F.2 Duty to Reapoly

If the Permittee wishes to continue an activity regulated by this permit after the expiration date of this permit, the Permittee must submit an application for a new permit at a minimum of one hundred eighty (180) days prior to the expiration date of this permit and obtain a new permit.

I.F.3 Need to Halt or Reduce Activity Not a Defense

It shall not be a defense forthe Permittee in an enforcement action that it would have been necessary to halt or reduce plant operations and/or the permitted activity in order to maintain compliance with the conditions of this permit. .

I.FA Duty to Mitigate

The Permittee shall take all reasonable steps to minimize or correct any adverse impact on the environment resulting from noncompliance with this permit.

I.F.5 Duty to Provide Information

The Permittee shall furnish to the ADEQ Director's request and within the specified times, any information which may determine whether cause exists for modifying, revoking and reissuing, orterminating this permit, or to determine compliance with this permit. The Permittee also shall furnish, to the ADEQ Director upon request, copies of records required to be kept by this permit.

I.F.6 Proper Operation and Maintenance

The Permittee shall atall times properly operate and maintain all facilities and systems which are installed or used by the Permittee to operate the system and to achieve compliance with the conditions of this permit. Proper operation and maintenance includes, but is not limited to, effective performance, adequate funding, adequate operatorstaffing and training, and adequate laboratory and process controls, including appropriate quality assurance procedures. This provision requires the operation of back-up or auxiliary facilities or similar systems only when necessary to achieve compliance with the conditions of the permit.

J.F.? Inspection and Entry

The Permittee shall allow the ADEQ Director, or authorized ADEQ personnel, upon the presentation of credentials' and other documents as may be required by law, to:

(a) Enter upon the Permittee's premises where a regulated facility or activity is located or conducted, or where records must be kept under the conditions of this permit;

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(b) Have access to and copy, at reasonable times, any records that must be kept under the conditions of this permit;

(c) Inspect at reasonable times any facilities, equipment (including monitoring and control equipment), practices, or operations regulated or required under this permit;

(d) Sample or monitor at reasonable times any substances or parameters at any location, for the purposes of assuring permit compliance or as otherwise authorized by Act 472 of 1949, as amended, and/or the SDWA.

l.F.a Monitoring

Samples and measurements taken for the purpose of monitoring shall be representative of1he monitored activity.

1.F.9 Records

The Permittee shall retain records of all monitoring information, including all calibration and maintenance records, all original chart recordings from continuous monitoring instrumentation, copies of all reports required by this permit, all sampling reports and records of all data used to comp1ete the application for this permit for a period of at leastthree (3) years from the date of the sample, measurement, report, orapplication. This period may be extended by request of the ADEQ Director at any time and will be extended automatically during the course of any unresolved enforcement action regarding this permit. The Permittee shall also retain records on the nature and composition of all injected fluids until three (3) years after the completion of any plugging and abandonment procedures specified under 40 CFR 144.52(a)(6), Part 111.0 of this permit and the permit application. The ADEQ Director may require the owner or operator to deliverthe records to the ADEQ at the conclusion of the retention period.

I.F.10 Reporting Requirements

(a) Planned Changes to Facility

The Permittee shall give notice to the ADEQ Director as soon as possible of any planned physical alterations or additions to the permitted facilities.

(b) Anticipated Noncompliance

The Permittee shall give advance notice to the ADEQ Director of any planned changes in the permitted facilities or activities which may result in noncompliance with permit requirements.

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(c) Monitoring Reports

Monthly, Quarterly and Annual Reports, including all monitoring results, shall be reported to the ADEQ at the intervals specified in Part III.C of this permit.

(d) Notification of Changes in Well Operations

The Permittee shalJ notify the ADEQ within twenty-four (24) hours of any change in well operations or monitoring parameters that reasonably could be attributed to a leak or other failure in well equipment.

(e) Noncompliance Reporting

The Permittee shall report all noncompliance incidents to the ADEQ Director. Incidents include those that may endanger health or the environment, any monitoring orother information which indicates that any contaminant maycause an endangerment to an Underground Source of Drinking Water (USDW), any noncompliance with a permitcondition, or malfunction of the injection systems which maycause fluid migration into orbetween USDWs. This informationshall be provided to the ADEQ within 24 hours from the time the Permittee becomes aware of the circumstances.

A written submission to the ADEQ Director shall be provided within 5 days of the time the Permittee becomes aware of the circumstances of the noncompliance incident. The written submission shall contain a description of the noncompliance and its cause, the name and quantity of any contaminant released, the actual and potential impact to health and the environment outside the plant site, the quantity and disposition of any recovered material, the period

.of noncompliance (including exact dates and times), the anticipated time the

. noncompliance is expected to continue if it has not been corrected, and the steps taken or planned to reduce, eliminate and prevent recurrence of the noncompliance.

(1) Other Information

The Permittee shall submit such relevant or corrected facts or information to the ADEQ Director within seven (7) days when it becomes aware that it failed to submit any relevant facts in a permit application, or submitted incorrect information in a permit application or in any report to the ADEQ.

(g) . Conversion or Abandonment of the Injection Facility

The Permittee shaH notify the ADEQ Director in writing at least ninety (90) days before the commencement of any conversion, recompletion, modification

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and/or abandonment of waste disposal well DWD #1. Any conversion, recompletion and/or abandonment of this well shall commence only after review and approval by the ADEQ Director.

1.F.11 Signatory Requirement

All applications, reports, or information submitted to the ADEQ shall be signed and certified as required by 40 CFR 144.32.

1.F.12 Confidential Information

The Permittee may claim as confidential any information required to be submitted by this permit in accordance with 40 CFR 144.5, with the exception of the name and address of any permit applicant or Permittee, and information which deals with the existence, absence, or level of contaminants in drinking water. Any claim must be asserted at the time of the submittal.

I.G SEVERABILITY

The provisions of this permit are severable, and jf any provision of this permit or the application of any provision of this permit to any circumstance is held invalid, the application of such provision to othercircumstances and the remainder of this permitshaIl not be affected.

I.H CORRECTIVE ACTION PLAN

The Permittee shall ensure that the requirements of 40 CFR 144.55 and 146.7 are met and carried out as specified therein.

The Permittee must submit a Corrective Action Plan that addresses any known well that is improperly plugged, sealed, completed or abandoned. This plan shall consist of the steps that the Permittee will take to prevent movement of fluids into a USDW. Upon approval of the Plan by the ADEQ Director, it will be incorporated into the permit as a condition.

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PART II DRILUNG AND COMPLETION REQUIREMENTS FOR NEW WELLS

ItA CONSTRUCTION REQUIREMENTS

The requirements of 40 CFR 146.12 are incorporated by reference.

II.A.1 Approved Plans and Specifications

Waste disposal well DWD #1 shall be constructed and completed to prevent the movement of fluids into or between USDWs or into any unauthorized zones, in accordance with 40 CFR 144.12.

Except as specifically required in the terms of this permit, drilling and completion of the well shall be done"in accordance with the plans and specifications submitted with the permit application. Any proposedchanges to the plans and specifications must be submitted in writing and be approved by the ADEQ Director priorto implementation. These changes mustbe equivaJent to the original design criteria in providing adequate protection standards.

11.A.2 Commencement of Construction

The construction of DWD #1 may not commence until a permit has been issued containing construction requirements. The necessary geophysical logs, as specified in Part 11.8.2, shalf be submitted in a timely manner to ADEQ, in order that the ADEQ has sufficient time to review the logs prior to completion of the welf.

1f.A.3 Cores of the Injection Intervals and Confining Zone

During the drilling of DWD #1, whole cores must be obtained from the proposed primary and secondary injection intervals and selected portions of the confining zone. These cores will be used for the core and formation fluid tests proposed in the permit application.

If.A.4 Requirements Prior to Commencing Injection.

The Permittee shall not commence injection of waste into DWD #1 until the ADEQ has evaluated the Completion Report to establish optima! operational requirements and the ADEQ Director has provided the Permittee with written authorization to commence injection.

II.A.S Well Construction Materials

The cement and casing to be used in DWD #1 will be designed for the life expectancy and closure period of the well.

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The casings and connections shall have sufficient structural strength to withstand burst and collapse pressures and tensile stress that may be experienced during well operations. DWD #1 will be constructed with the materials described below, as described in the permit application:

Surface Casing Carbon steel8rd ST&C 11 3// K-55 grade 471b/ft

Longstring Casing Mixed string carbon steel and corrosion-resistant alloy(CRA) 8rd LT&C 7%11 N-80 grade 26.4 Ibltt

Tubing Tubular Rberglass Company (TFC) Red Box 3~1I

2000 psi rated

Packer Carbon steel with corrosion-resistant alloy (eRA) surfaces Groundwater Protection System (GPS) Model '"12" 3 ~n x 7 5

/ S-

Waste fluids shall be injected through tubing with a packer set immediately above the injection interval. The tubing and packer shall be designed for the expected service of the well.

The pump and plug method will be used for cementing. The surface and longstring casing will be cemented from the base of the casing to the surface using a minimum of 120% of the annular volume calculated from the caliper logs. The cement properties are as follows:

Surface Casing

Lead Slurry: Standard (Class H) Lite Cement containing 8% bentonite, 2% CaCI2 (accelerator), 1/4 1blbbl fluid loss additives, to be mixed at 13.6 Ib/gal, 1.73 ft3/sk, 9.07 gal water/sk for 430 psi compressive strength in 24 hours at 800 F. The cement volume is designed to occupy·14 3/4 in x 11 3/4 in annular volume from 1085 feet BGL to surface.

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Tail Slurry: Standard (Class H) Cement containing 2% CaCI2 (accelerator), 1/4 Ib/bbl Fluid Loss additives, to be mixed at 15.6 Ib/gal, 1.18 ff/sk, 5.20 gal water/skfor2026 psi compressive strength in24 hours, 3835 psi compressive strength in 72 hours at 11 O°F. The cement volume is designed to occupy 14 3/ 4

in x 11 3/4 in annular volume from shoe at 1585 ft to 1085 ft BGL.

Longstring Casing

First Stage: Epseal synthetic cement, designed to occupy the shoe joint plus 10 sIB in x 7 SIB in annular volume from shoe at 4600 ft to stage tool at approximately 2700 ft BGL.

Second Stage: Lead SlUrrY: Standard (Class H) Ute Cement containing 8% bentonite, 1/4 1b/bbl flu id loss additives, to be mixed at 13.1 lb/gal, 1.92 'ff/sk, 10.4 gal waterlsk for 360 psi compressive strength in 24 hours at 800 F. Tile cement volume is designed to occupy 10 5/8 in x 7 sIB in annular volume from 2100 ft to the surface.

Tail Slurry: Standard (Class H) Cementwith 1/4 1blbbl fluid loss addi'tives, to be mixed at 15.6 Ib/gal, 1.18 ff/sk, 5.20 gal waterlsk for 2026 psi compressive strength in 24 hours, 3835 psi compressive strength in 72 hours at 11O°F. The cement volume is designed to occupy 10 5/s in x 7 518 in annular volume from stage tool at approximately 2700 ft to 2100 ft BGL.

Depths to be Set:

Surface Casing Longstring Casing Tubing 1585' 4600' 4300' (James)

U.8 COMPlE1"ION REPORTS

The Completion Report, upon submittal and approval by the ADEQ Director, will become an attachment document to this permit, subject to all applicable regulations.

JI.B.1 Within ninety (90) days after the new well completion, the Permittee-shall submit a Completion Report, signed by a registered professional engineer to the ADEQ Director, which will include the drilling and completion history of the well and the following:

(a) All casing and cementing records, copies of the logs run on the well, complete and accurate record of the depth, thickness and lithology of the penetrated formations and cross sections of the disposal area;

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(b) Adjusted pressure calculations and fluid front calculations;

(c) Results of injectivity tests, formation fluid compatibility tests, core analysis information including porosities, permeabilities and other information necessary

.to obtain a detailed analysis of the injection interval;

(d) Lithologic descriptions of the whole cores of the proposed injection intervals.

11.8.2 The following logs shall be submitted with the report also:

(e) Prior to Setting Surface Casing: Spontaneous Potential Resistivity Natural Gamma 4-arm Ca.liper

(f) After Setting Surface Casing: Cement Bond with Variable Density Log Temperature

(g) Prior to Setting Longstring Casing: Spontaneous Potential Resistivity Neutron Porosity and/or Compensated Density Fracture Finder Dipmeter Natural Gamma 4-arm Caliper

(h) After Longstring Casing set: -Cement Bong with Variable Density Log Temperature Casing Inspection Inclination Survey

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PART III SPECIFIC CONDITIONS

liLA OPERATIONAL REQUIREMENTS

1I1.A.1 Reconstruction, Recompletion,or Modi"fication

Any reconstruction, recompletion or modification of the injection facilities shall be done in accordance with the plans and specifications submitted with the permit application and the well completion report. Any proposed changes to the construction and operation of the well, prDor to im plementation, must be submitted in writing to, and approved by, the ADEQ Director as providing protection equivalent to or greater than the existing construction and operation.

JlI.A.2 Proposed Formations Permitted. For Injection

Injection mustbe into a formation that is beneath the lowermost formation containing, within 1/4 mile of waste disposal well DWD #1, an Underground Source of Drinking Water (USDW), Permitted injection shall be confined to the injection depths noted below: .

Proposed Injection Interval Injection Depths

Primary - James Limestone 4365 - 4475' BGL

Secondary - Tokio Formation 2915 - 3100' BGL

1IJ.A.3 Authorization of Specific Injection Intervals

The Permittee will receive authorization from the ADEQto inject fluids into the specific injection intervals described in Part HI.A.2 of this permit, Fluid disposal into permitted injection intervals other than those authorized by the ADEQ Director in Part IV.C of this permit shall be considered an unauthorized injection, a violation under 40 CFR 144.11 and shall be subject the Permittee to possible enforcement action. Specific intervals will be approved after the Completion Report is submitted and approved by the ADEQ Director.

1I1.A.4 Casing and Cementing

The well shall be cased and cemented as necessary to prevent the movement oUluids into or between USDWs, in accordance with 40 CFR 144.12(a), incorporated by reference. Tile cement and casing to be used In DWD #1 will be designed for the life expectancy and closure period of the well and in compliance with Part II,A.4 of this pennit.

III.A.S Waste to be Injected

(a) The Permittee is authorized to injectewaste as described in the permit application.

Specific Gravity: 1.05 Maximum Viscosity: 1.0 cp pH: 3.0 - 11.0 Compressiblity: 3.0 x 10-6

(b) The sources of the waste streams will be the ground water recovery system and the brine plant wastewater. A groundwater recovery system is currently in operationatthe plant, which collects contaminated groundwaterfrom a french drain system. The water is routed to· a steam stripper where hazardous chemicals"are separated into transfer vessels. The remaining non:'hazardous water is transferred to storage tanks for disposal into DWD #1.

(i) Chemicals; which exhibit hazardous characteristics, found in the contaminated groundwater include: ethylene dichloride (1,2 dichloroethane), ethylene dibromide (1,2 dibromoethane) and dibromochloropropane (1,2 dibromo-3 chloropropane).

(ii) Non-hazardo~ wastewaterfrom the bromine extraction facility is limited to boiler blow-down, cooling tower overflow and non-eontaet process water, rainfall from curbed areas and sumps at the plant, and product spills and wash water from the management of those spills.

(iii) Other waste streams are limited to minor amounts of the following: wastes generated during the closure of the well and associated facilities, groundwater and rainfaJl contaminated by the wastes listed above, and wash waters and solutions used in cleaning and servicing the well system equipment. These wastes may be restricted due to compatibility with the wastes listed above, the formation fluid and the well materials.

(c) The waste stream will be filtered to 10 microns.

(d) Maximum Constituent Concentration of Waste Stream

Ethylene dichloride (D028) 0.21 mg/f (40 CFR 268.40) Ethylene dibromide (U067) 0.028 mg/I (40 CFR 268.40) Dibromochloropropane (U066) 0.11 mgll (40 CFR 268.40)

Semivolatiles and Volatiles TCLP to regulatory levels Metals

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EPA Publication SW-846 shall be used in order to accurately obtain an analysis of the waste stream, with acceptable Detection Limits or Practical Quantitation Limits (POls).

The constituents of each waste stream must be non-hazardous and mustmeet the acceptable limits (with the exception of the chemicals listed above) designated under 40 CFR Subpart C, sections 261.20, 261.21, 261.22, 261.23 and 261.24. The waste streams must approximately meet the typical levels provided in Appendix I of the permit application.

Wastes not authorized to be stored, processed, disposed or otherwise handled as stipulated in this permit are not.authorized for injection.

1II.A.6 Proposed Operational Requirements

The Permittee shall operate waste disposal well DWD #1 according to the following projected parameters, which are subject to revision based upon the Completion Report:

Projected Maximum Surface Injection Pressure for James - 1130 psi Projected Maximum Surface Injection Pressure for Tokio - 670 psi Projected Maximum Rate of Injection - 100 gpm Projected Maximum Disposal Volume - 4,464,000 gaUmonth Projected Minimum Annulus Pressure - > injection pressure Projected Allowable pH Range - 3.0 - 11.0 Projected Annular Fluid - Inhibited Water

.111.A.7 Instrumentation

The Permittee shall ensure thatthe following instrumentation is properly installed and maintained at all times. The following instrumentation is based upon the information provided in the permit application and any changes or modifications shall be. equivalent to this instrumentation in order to properly monitor the parameters of DWD #1:

Annulus Pressure Monitor - 2 pen Foxboro Model NR, 0-1500 psi

Injection Pressure Monitor· 2 pen Foxboro Model NR, 0-1500 psi

Flow Meter - Foxboro Model 40, 0-15000 bbl/day

1I1.A.8 Parameters to be lVIeasured

The following parameters shall be measured with an appropriate continuous recording device(s) housed in a weatherproof enclosure at the wellhead:

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(a) Injection tubing pressure, annulus pressure, injection tubing flow rate, injection volume;

(b) Any other parameters as requested by the ADEQ or as specified by this permit.

ilLS MECHANICAL INTEGRITY

111.8.1 The Permittee shall maintain mechanical integrity ofthe injection well at all times. An injection well has mechanical integrity if there is no significant leak in thecasing, tubing or packer and there is no significant fluid movement upward out of the injection zone into the designated confining zone or USDWs ~rough anyvertical channels adjacent to the wellbore. The requirements of 40 CFR 146.8 are incorporated by reference.

111.8.2 MechanicaJ integrity shall be demonstrated by the following tests:

(a) A yearly annulus pressure test to be witnessed by the ADEQ or an authorized representative of the ADEQ.

(b) A yearly measurement of the pressure buildup in the injection zone, which includes shutting-in the weJl for a time sufficient to allow the pressure in the injection interval to reach equilibrium.

(c) The ADEQ Director may require tests (a) and (b) above wheneverthe well is worked over, the tubing is removed, the packer is replaced, or based on any information received by the ADEQ that may indicate such tests may be warranted.

(d) A Radioactive Tracer Test shall be made at least once every five years to determine the presenceor absence of fluid movement behind the well casing.

(e) Casing inspection logs shall be run at least once every five years unless the ADEQ Direetorwa.ives this requirement due to well construction or other factors that limit the reliabifity of this test.

(f) Any otller appropriate test approved by the ADEQ Director maybe used by the Permittee to evaluate mechanical integrity.

(g) The Permittee shall submit results of any of the above tests, including an interpretive analysis of each test, to the ADEQ within sixty (60) days ofthe date of completion of field measurements.

111.8.3 Annulus Pressure Testing

An Annulus Pressure Test (APD for waste disposal well DWD #1 well shall be conducted at least once each year. An APT shall be conducted after each workover involving tubing removal and/or packer placement, and after eachwell shut-down in

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excess of thirty (30) days. The test shall consist of pressu ring the annulus to 100 psi above the maximum surface injection pressure forthe well and holding that pressure for one hourwith a maximum allowable pressure variation ofp/us or rMinus 3% of the initially recorded test pressure.

111.8.4 Loss of Mechanical Integrity

(a) If a loss of mechanical integrity occurs, during testing orduring welloperations, the Permittee shall do the following:

0) Cease injection immediately;

(ii). Take all steps necessary to determine if a release of waste into any unauthorized zone? occurred;

(iiQ Notify the ADEQ within 24 hours after the loss of integrity was discovered and when injection is expected to resume;

(iv) Restore and demonstrate mechanical integrity to the satisfaction of the ADEQ Director prior to resuming injection;

(v) Approval by the ADEQ is required prior to any workover.

(b) If there is evidence of a release of waste into an unauthorized zone, the Permittee shall:

0) Immediately cease injection of fluids;

(iij Notify the ADEQ within 24 hours after discovery;

Qii) Take all necessary steps to characterize the extent of the release;

(iv) Complywith and implementthe remediation plan required bythe ADEQ Director;

(v) Where such a release is into a USDW, serving as a water supply, publish a notice into a newspaper of general circulation.

The ADEQ may allow the Permittee to resume injection prior to completing the remediation action, providing the Permittee is able to demonstrate that the injection operation will not endanger a USDW.

m.e MONITORING AND REPORTING

The requirements of 40 CFR 146.13 are incorporated by reference.

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'".C.1 Monthlv Reporting Requirements

The Permittee shall compile and submit Monthly Reports to the ADEQ containing the following information:

(a) Results of continuous monitoring, including:

(i) The monthly maximum, minimum, and average injection pressure;

(ii) The monthly maximum, minimum, and average injection flow rate;

(iii) The total injection volume for the month,

flV) The maximum and minimum annulus pressure for the month;

(v) The maximum, minimum and average pH of the injectedwaste stream for the month;.

(vi) The maximum, minimum and average temperatures of the injected waste stream for the month.

(b) The Monthly Reports shall be submitted to the ADEQ quarterly, within 20 days after the end of each quarter.

III.C.2 Quarterly Reporting Requirements

(a) The Permittee shall submit Quarterty Reports to the ADEQ, within 20 days after the end of each quarter. These Quarterly Reports shall contain the" following information:

(i) The Monthly Reports specified in Part III.C.1 of this permit.

(ii) Documentation of all noncompliance incidents or exceedances of operating parameters, all violations, excursions, equipment-malfunctions or events triggering an alarm or shut-down device, workovers, well testing, well stimulations and any otherpertinent information concerning well. operations during the quarter.

(iii) The Permittee shall analyze the injected waste stream quarterly and submit the results with the quarterly report. This analysis shall include the physical, chemical and other relevant characteristics of the injection fluids and be included in the Annual Report. A Waste Ana.lysis Plan (WAP) shaH be submitted and approved by the Department, which describes the procedures required to obtain a representative result of the waste, speci'fied in Part III.C.5(a) of this permit.

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.. III.C.3 Annual Reporting Requirements

The Permittee sha.1I submit an Annual Report, by March 1st of each following year, to the ADEQ that contains the following information:

(a) . Results of continuous monitoring, including:

(ij The maximum, minimum, and yearly average of the injection pressure;

(Ii) The maximum, minimum, and yearly average of the injection flow rate;

(iii) The maximum and minimum of the annulus pressure;

(iv) The maximum, minimum and yearly average for the pH of the injected waste stream;

(v) The injection volume total for the year and cumulative total for waste disposal well DWD #1.

(b) Documentation of all noncompliance incidents, violations, excursions, equipment malfunctions, and/orany otherpertinent information concerning well operations.

(c) A narrative covering all aspects of well operations for the year, including discussions of, and reasons.for, any excursions from permitted operational parameters, any violations, and actions taken to correct the violations.

(d) Discussion of any tests done to ensure the mechanical integrity of the weJI during the year, including the dates and times of those tests and certification by the Permittee that the wells have demonstrated mechanical integrity.

(e) The results and dates of any other tests performed on the well such as workovers or acid stimulations.

(f) A direct measurement of bottom-hole pressure ora calculation of bottom-hole pressure using the specific gravity of the fluid in the well and the static fluid level, discussion of pressure effects of disposal operations upon the injection zones and specific injection intervals, and a calculation ofpressure build-up within the injection intervals.

(g) An estimation of the distance from the well to the front of the injected fluids.

(h) To the extent such information is reasonably available, the report shall also include:

(D Locations of newly constructed and discovered wells with in the zone of endangering influence.

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(ii) Data for all newly constructed and discovered wells that penetrate to within 300 feet of the top of the injection zone and are located within a one (1) mile radius of waste disposal well DWD #1 .

(i) Results of corrosion monitoring, as specified in Part IIl.eA of this permit.

III.CA Corrosion Monitoring

(a) The Permittee shaH demonstrate that the waste stream will be compatible with the weH materials in which itwill be in contact and shall submit the methodology used in making that determination to the ADEQ. For purposes of this requirement, compatiblity is established if contact with the waste "fluids will not cause the well materials to fail.

(b) The Permittee shall be required to initiate continuous corrosion monitoring of the construction materials used in the well. Such a test may include the following:

(i) Placing coupons otwell construction materials in contactwith the waste stream;

(ii) Routing the waste stream through a loop ofwell construction materials;

(iii) Using an alternative method approved by the ADEQ Director.

(c) The Permittee shall monitor the materials for loss of mass and thickness, cracking, pitting or any other signs of corrosion on a quarterly basis to ensure the well components meet the minimum standards set forth in 40 CFR 146.65(b). Results of corrosion monitoring shall be submitted to the ADEQ with the Annual Reports.

HI.C.S Waste Fluid Analysis

Records of monitoring information shan include the location, time of sampling or measurements, the individual(s) who performed the sampling or measurements, the date(s) analyses were performed, the analyticaJ techniques or methods used, the results of such analyses, and any other information required by the ADEQ, in accordance with the approved Waste Analysis Plan (WAP).

(a) Waste Analysis Plan

The Permittee shall monitor the injected waste stream on a quarterlybasis, in accordance with a Plan that describes the procedures and methods used to obta.in a representative result of the waste stream. The Plan shall be submitted to the ADEQ Director for approval prior to implementation: The plan should include, at a minimum:

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(i) The parameters used to analyze the waste and reason for selecting these parameters;

(ii) The test methods used for these parameters;

(iii) The sampling method used to obtain a representative sample;

(iv) The location where the sample is to be taken.

(c) The Permittee shall conduct sampling on the waste stream when a process change occurs at the plant that could result in the waste stream being altered. The Permittee shall ensure that the WAP remains current and accurate, and shalf make updates orchanges when the ADEQ requires modification to keep the analysis representative of the waste stream.

m.D PLUGGING AND ABANDONMENT

The requirements ot40 CFR 146.1 aare incorporated byreference. Upon final abandonment, the Permittee shall ensure that the waste disposal well DWD #1 is plugged in accordancewith the approved plugging and abandonment plan submitted with the application, and made a condition of this permit. Prior to plugging, the Permittee must give the ADEQ Director notification of intent to plug at least seventy-two (72) hours prior to the commencement of plugging operations. The mechanical integrity of the wells shall be verified prior to plugging and approved by the ADEQ Director. Any proposed changes to the plugging and abandonment plans must be approved by the ADEQ Director after the Permittee demonstrates thatthe changes will provide protection equivalent to or greaterthan the original design criteria and standards. Any change to a plugging and abandonment plan shall be treated as a minor modification of the permit in accordance with 40 CFR 144.41 (g).

litE FINANCIAL ASSURANCE

The Permittee shall secure and maintain in full force and effect at all times a performance bond, in a form acceptable to the ADEQ, to provide for proper closing, plugging and abandonment of waste disposal well DWD #1 in the amount set forth below. The amolJntof financial assurance may, upon approv~1 of the ADEQ Director, be altered at a tutu're date to provide for plugging subject to prevailing general economic conditions. This permit does not authorize underground injection oUruids unless the Permittee has in effect a performance bond acceptable to the ADEQ.

Amount of Financial Assurance

DWD#1 $92,000

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PART IV VARIANCES, COMPLIANCE SCHEDULES, AND OTHER CONDITIONS

IV.A: VARIANCES

No variances were requested by the applicant and none are granted by the ADEQ in this permit.

IV.8: COMPLIANCE SCHEDULES

None

fV.C:OTHER CONDITIONS SPECIRC TO THIS PERMIT

Formation Intervals Aut~orized for Injection

Fluid disposed into waste disposal well DWD #1 shall be injected into the following authorized injection interval. No other injection interval is authorized for fluid disposal at this time. The injection interval approved for disposal is:

Iniection -Formation Perforated Interval James limestone 4365-4475 1 BGL

Additional injection intervals granted bythis permit are not authorized for injection at this time.

well plan for the drilling and completion of dwdno

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