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Home My WebLink AboutDIO 039 Image Project Order File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable b direct inspection of the file. Y C0 03 Order File Identifier Organizing (done) wo -sided (I` `II 11 111 II III ❑ Rescan Needed 1 (11111 1111 RE AN DIGITAL DATA OVERSIZED (Scannable) Color Items: ❑ Diskettes, No. ❑ Maps: ❑ Greyscale Items: ❑ Other, No/Type: ❑ Other Items Scannable by a Large Scanner ❑ Poor Quality Originals: OVERSIZED (Non - Scannable) ❑ Other: ❑ Logs of various kinds: NOTES: ❑ Other:: BY: Maria Date: 0 /s/ e Project Proofing • I lin lilt m e / 9 BY: s Maria Date: 10 62 0 /s/ Scanning Preparation x 30 = + = TOTAL PAGES — � / /0 (Count does not include cover sheet) BY: Date: IQ 6 /s/ Production Scannin g 11111111 I Stage 1 Page Count from Scanned File: 14 (Count does include cove eet) Number in Scanning Preparation: YES NO Page Count Matches u g p BY: Maria Date: i Q (/( /s/ p Stage 1 If NO in stage 1, page(s) discrepancie were found: YES NO BY: Maria Date: Is/ Scanning is complete at this point unless rescanning is required. 111 III ReScanned ll 11111111111 BY: Maria Date: /s/ Comments about this file: Quality Checked II I III 1,1111 10/6/2005 Orders Fife Cover Page.doc • Disposal Injection Order #39 1. July 15, 2008 ENI application for disposal of class II oilfield waste by underground injection for the Nikaitchuq development 2. December 18, 2008 ENI withdraw of application Disposal Injection Order #39 42 Page 1 of 3,, 0 0 Colombie, Jody J (DOA) From: Regg, James B (DOA) Sent: Friday, December 19, 2008 10:30 AM To: Colombie, Jody J (DOA) Subject: FW: ENI Class 2 Waste Fluids Application This should close out the Nikaitchuq DIO application (ENI) that was received on July 15, 2008 Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 From: Longo Joseph[mailto:joe.longo@enipetroleum.com] Sent: Thursday, December 18, 2008 9:58 AM To: Regg, James B (DOA) Subject: RE: ENI Class 2 Waste Fluids Application Jim, Thank you very much for clearing that up. ENI would like to officially withdraw the Nikaitchuq DIO application and we apologize for any efforts put forth during the permitting process. Thanks again. Joseph Longo Drilling Engineer Eni US Operating Co. Inc Anchorage, AK Office: (907) 865-3323 Cell: (504) 952-5520 Email: Jo_s�Lonao(a enir)etroleum.com From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Tuesday, December 16, 2008 9:13 AM To: Longo Joseph Cc: Maunder, Thomas E (DOA) Subject: RE: ENI Class 2 Waste Fluids Application Thank you for contacting the Commisisson regarding the need for a Class II disposal permit for Nikaitchuq operations. ENI submitted a disposal injection order application to the Commission on July 15, 2008 (simultaneously submitted an application to EPA for a Class I permit for same proposed disposal injeciton wells). You are correct that we put the permit process on hold after contact from Mr. Robert Britch on August 19, 2008; he stated that it appeared the Class II disposal injection order was unnecessary - initially because EPA would not allow ENI to drill the disposal well prior to issuance of the Class I permit; and subsequently because of EPA's expedited effort to issue the Class I permit. EPA has effectively made Class II a subset of Class I because of the fluids allowed for injection into a Class I well. Therefore, ENI_ does not need_ the Class II_permit _a_s long as EPA's Class_I permit authorization is active. It would be appropriate in this case to withdraw the Nikaitchuq DIO application; that will allow the Commission to formally close the file. If that is your intent, you can simply respond to this email. If in ENI's opinion there is still a desire to have a Class II permit, 12/19/2008 0 Page 2 of ,_Q,. the Commission would be happy to proceed with the permitting process (nothing needed from ENI at this point - application was deemed complete but not publicly noticed). Look forward to hearing how ENI would like to proceed. Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 From: Longo Joseph [mailto:joe.longo@enipetroleum.com] Sent: Monday, December 15, 2008 1:23 PM To: Regg, James B (DOA) Cc: Maunder, Thomas E (DOA) Subject: ENI Class 2 Waste Fluids Application Jim, I wanted to contact you about some information concerning the Class 2 Waste Disposal Application? The Waste Analysis Plan is currently being put together for the OP26-DSP02 disposal well and there was a question regarding the need to include the AOGCC Permit for Class 2 Waste injection. We currently have an EPA UIC Class 1 permit. I was under the impression that with a Class 1 permit the disposal well would be considered a Class1/Class 2 injection well. Is it necessary to have the AOGCC Class 2 permit as Well? From what I can recall we asked the AOGCC to back off the permitting process because it was no longer necessary. If it is necessary to include the AOGCC Class 2 permit in the waste analysis plan could you please let me know how to proceed? Thank you, Joseph Longo Drilling Engineer Eni US Operating Co. Inc Anchorage, AK Office: (907) 865-3323 Cell: (504) 952-5520 Email: Joseph.Lono a�enioetroleum.com This message may contain information that is confidential, and is being sent exclusively to the Recipient. If you are not the designated Recipient, you are prohibited from utilizing, copying or divulging the information contained in this message,or taking any action whatsoever on the basis of the information herein. If you have received this message by mistake, we ask you to kindly inform the Sender and to delete the message. It is understood that, with regard to messages sent by its network, the Company is not responsible for any statements made or opinions expressed, that are not strictly related to the Company's operations. This message may contain information that is confidential, and is being sent exclusively to the Recipient. If you are not the designated Recipient, you are prohibited from utilizing, copying or divulging the information contained in this message,or taking any action whatsoever on the basis of the information herein. If you have received this message by mistake, we ask you to kindly inform the Sender and to delete the message. It is understood that, with regard to messages sent by its network, the Company is not responsible for any statements made or opinions expressed, that are not strictly related to the Company's operations. 12/19/2008 Erwl Eni US Operating Co. Inc. Nikaitchuq Development Project Application for Authorization to Inject Class II Waste Fluids • • • • '�*' En! Petroleum ,w 3800 Centerpoint Drive, Suite 300 Anchorage, AK 99503 Phone: (907) 865-3300 Fax: (907) 929-5057 July 15, 2008 Alaska Oil and Gas Conservation Commission Attention: Mr. Daniel Seamount, Chairman 333 W. 7th Street Suite 100 Anchorage, AK 99501 JUL 1 5 2008 Alaska Oil & Gas Coots. Commission Subject: Application for Authorization to Inject Class II Waste Fluids Nikaitchuq Development Project Dear Mr. Seamount: Please find attached an application from Eni US Operating Co. Inc. (Eni) for authorization to inject Class II waste fluids into two proposed wells in the Nikaitchuq Development Project at Oliktok Point. This application was prepared in accordance with the requirements of 20 AAC 25.252. Eni firmly believes that this application demonstrates that the proposed disposal operations will not allow the movement of oil field wastes or hydrocarbons into sources of fresh water. If you have any questions please contact Joe Longo at 865-3300. Sincerely yours, Robert P. Britch, P.E. Regulatory Team Leader Nikaitchuq Development cc: Maurizio Grandi, Eni Joe Longo, Eni % • Ed Eni Petroleum Nikaitchuq Project 11 Class II Disposal Application Eni Class II Well Application-071508 July 2008 • • 11 Ed Eni Petroleum Nikaitchuq Project Class II Disposal Application TABLE OF CONTENTS 1. Project Description i 2. Well Locations [20 AAC 25.252 (c)(1)] i 3. Operators and Surface Owners [20 AAC 25.252 (c)(2 & 3)] 2 4. Geologic Details [20 AAC 25.252 (c)(4)] 2 S. Well Logs [20 AAC 25.252 (c)(5)] 6 6. Mechanical Integrity [20 AAC 25.252 (c)(6)] 6 7. Waste Types and Volumes [20 AAC 25.252 (c)(7)] 8 8. Injection Pressures [20 AAC 25.252 (c)(8)] 8 9. Waste Confinement [20 AAC 25.252 (c)(9)] 8 10. Formation Water Salinity [20 AAC 25.252 (c)(10)] 9 11. Fresh Water Exemption [20 AAC 25.252 (c)(11)] 10 12. Wells Penetrating the Disposal Zone [20 AAC 25.252 (c)(12)] 10 APPENDICES Appendix A - Injector Performance Potential Report, for Nikaitchuq by Advantek Appendix B - Simulation of Slurry Injection Report, for Oooguruk by ASRC Energy Services Eni Class II Well Application-071508 My 2008 fid Eni Petroleum Nikaitchuq Project Class II Disposal Application • LIST OF EXHIBITS 1. Nikaitchuq Project Location Map 2. Oliktok Production Pad Plat 3. Surface Owners/Operators 4. Affidavit of Notice to Surface Owners and Operators 5. Structure Map of Top of the Canning 6. Isopach Map of Upper Confining Layer Thickness 7. Structure Map of the Base of the Upper Confining Layer S. Isopach Map of the DCI Zone i Thickness 9. Isopach Map of Intermediate Shale Layer 2 Thickness 10. Isopach Map DCI Zone 2 Thickness 11. Structure Map of Base of DCI Zone 2 12. Isopach of DCI Zone 3 13. Structure Map on top of HRZ 14. Structure Map on Base of HRZ 15. Isopach of HRZ 16. Structure Map of the Base of Confining Layer 3 17. Isopach of Confining Shale Layer 3 Thickness 18. Base OA Sand Structure Map 19. General Geologic Stratigraphic Columns for Project Area 20. General Geologic Stratigraphic Columns for Project Area 21. Type Log 22. Cross Section Locator Map 23. South -to -North Cross -Section 24. West -to -East Cross -Section 25. Porosity and Water Salinity Information for Canning and Hue Shale Formations 26. Well Schematic for OP25-DSP01 27. Plot Plan for OP25-DSP01 28. Well Schematic for OP26-DSP02 29. Plot Plan for OP26-DSP02 30. No Underground Sources of Drinking Water Ruling Eni Class II Well Application-071508 July 2008 0 i Ell Eni Petroleum Nikaitchuq Project Class II Disposal Application 0 1. PROJECT DESCRIPTION • The Nikaitchuq Project is an oil discovery located on the North Slope of Alaska. The unit is offshore, 12 miles northeast of the Colville River Delta. Eni US Operating Co. Inc. (Eni) is operator and 100% working interest owner of the 34,000-acre field. The project will consist of the following: • Spy Island Drillsite (SID) an offshore drillsite with minimal production equipment, which was constructed of gravel near Spy Island, approximately 3 miles offshore from Oliktok Point in approximately 6 feet of water. • Oliktok Production Pad (OPP), an onshore facility with a drillsite, crude oil processing facility, power supply for the field, and a waste handling and injection facility; and • Nikaitchuq Operations Center (NOC), an onshore facility that will include a camp, helipad, and storage facilities. See Exhibit 1 for the location of the OPP and SID relative to surrounding oil fields. Up to a total of 76 wells are planned, including production wells, water injection wells, water source wells, and disposal wells. A buried flowline of pipe -in -pipe design will carry the produced fluids from the offshore SID to the onshore OPP. The flowline will be bundled with other lines, including water injection, diesel, and a spare line. The three phase flow from the onshore and offshore wells will be processed at OPP, which will have a capacity of approximately 40,000 bopd. A 14-mile, 10-inch diameter export line will take sales oil to the Kuparuk Pipeline, which carries oil to the TransAlaska Pipeline System. Produced water will be reinjected. Produced gas will be used as fuel gas. First oil from the onshore OPP is scheduled for the end of 2009. First oil from the offshore SID is scheduled for the end of 2010. 2. WELL LOCATIONS [20 AAC 25.252 (C)(1)] Two disposal wells are planned to be drilled from OPP. Exhibit 2 is a plat showing the locations of the proposed disposal wells and the existing wells that are within 1/4 mile of the proposed disposal wells. The two existing wells are part of the Nikaitchuq Development Project and are currently operated by Eni. The two existing wells do not penetrate the proposed disposal intervals. Following are the surface locations of the two proposed disposal wells: U.S. State Plane 1927, NAD 1927, Zone 04 OP25-DSP01 (Vertical to TVD 6336 ft subsea) Surface and bottom hole locations - E 516483.50 N 6036254.06 OP26-DSP02 (Deviated to TVD 6477 ft subsea) Surface hole location - E 516497.66 N 6036261.58 Bottom hole location - E 515712 N 6040552.04 Eni Class II Well Application-071508 1 July 2008 WA • • Ed Eni Petroleum Nikaitchuq Project Class II Disposal Application 0 3. OPERATORS AND SURFACE OWNERS [20 AAC 25.252 (C)(2 & 3)] The owner of the land at the surface locations of the proposed wells is the State of Alaska. The owner of the subsurface rights is the State of Alaska. Eni was issued a Land Use Permit and Easement ADL 417493 for the pads, pipelines, and well bores. Following is the contact for issues associated with both the surface and subsurface owner: Department of Natural Resources Division of Oil and Gas 550 West 7th Avenue, Suite 800 Anchorage, AK 99501 Eni is the 100% working interest owner of the Nikaitchuq Unit. The neighboring oil and gas leasees are shown in Exhibit 3. Although the OPP is located in the Kuparuk River Unit area, there are no adjacent active or abandoned wells within % mile of the proposed disposal wells. Following is contact information for ConocoPhillips, operator of the Kuparuk River Unit: ConocoPhillips Attn: John Cookson P.O. Box 100360 Anchorage, AK 99510-0360 Additionally, the U.S. Air Force owns land within % mile of the proposed disposal well locations. Following is contact information for the U.S. Air Force: U.S. Air Force, 611 CES/CERR Attn: Mr. John Smith 10471 20th Street, Suite 302 Elmendorf AFB, Alaska 99506-2200 Affidavits showing notification to surface owners and operators within a % mile radius of the proposed disposal wells is will be provided, and will be included as Exhibit 4. 4. GEOLOGIC DETAILS [20 AAC 25.252 (C)(4)] Canning and Hue Shale Formations —Geology and Description The proposed disposal intervals are the Canning and Hue Shale formations, which are late Cretaceous. The Canning and Hue Shale formations are located immediately below the Schrader Bluff (a.k.a. the West Sak formation) oil producing zone and well above the Kuparuk River oil producing formation. Note that the Kuparuk formation is not oil productive in the Nikaitchuq project area, although it is oil productive in the Kuparuk River Unit. The Kuparuk formation is likely oil saturated immediately under Oliktok Point and to a short distance north of Oliktok Point; however, the formation is tight and not capable of natural unassisted flow, but would require fracture stimulation. The top of the Canning formation is generally picked at the base of the Schrader Bluff formation. The base of the Hue Shale formation is generally picked at the base of the Highly Radioactive Zone (HRZ). The formations are marine in nature and very shale -rich, with several thick dominant shales Eni Class II Well Application-071508 2 July 2008 • LJ VA 0 l8d Eni Petroleum Nikaitchuq Project • Class II Disposal Application that can be correlated across the project area, including the upper and lower confining interval shales. Regional dip is down to the northeast. The Canning and Hue Shale formations are composed of thin sandstone intervals inter -bedded in thick massive shales, mudstones, and siltstones. The individual sand intervals, which are thin and isolated, cannot be correlated across the entire project area, as would be expected given the localized depositional environment of the sands. The sand intervals are suspected deep water base of slope fan systems and for the most part are thin -bedded distal levees, over bank deposits, and occasional small channels or crevasse splays. The Torok formation, or Torok equivalent, should be present in the Oliktok Point area, but is believed to shale out offshore. Stratigraphic markers were used to delineate the intervals and build the cross -sections and correlations. Overall, the combined Canning and Hue Shale formations are between 2800 and 3000 feet thick in the project area. Subsurface temperature and pressure gradients are both normal. The pressure gradient is 0.44 psi/ft and the temperature gradient is 2.5 degrees F per 100 feet below the base of the permafrost. The top of the Canning formation (the base of the Schrader Bluff formation) varies from -3600 feet subsea in the south project area to over -4200 feet subsea in the north project area. See Exhibit 5 for a structure map on top of the Canning formation. The upper confining layer varies slightly in thickness over the project area, ranging from 160 to 175 feet thick. The following figures show the formations of interest (Note: The term DCI zone refers to drill cuttings injection zones): • Exhibit 6 is an isopach map showing the thickness of the upper confining layer. • Exhibit 7 is a structure map on the base of the upper confining layer, which also structurally represents the top of DCI Zone 1. • Exhibit 8 is an isopach map showing the thickness of DCI Zone 1. It varies between 800 and 1000 feet thick in the project area. • Exhibit 9 is an isopach map showing the thickness of confining shale layer 2 that separates DCI Zone 1 from DCI Zone 2. It varies from 260 to 280 feet thick in the project area. • Exhibit 10 is an isopach map showing the thickness of DCI Zone 2. It varies from 900 to 1000 feet thick in the project area. • Exhibit 11 is a structure map on the base of DCI Zone 2 which structurally is also the top of confining shale layer 3. The top of confining shale layer 3 is at -5750 feet subsea in the south part of the project area and at -6300 feet subsea in the north part of the project area. • Exhibit 12 is an isopach of the DCI Zone 3, which is also the Torok equivalent in the project area. • Exhibit 13 is a structure map on the top of the HRZ, which is also confining shale layer 4. • Exhibit 14 is a structure map on the base of the HRZ. • Exhibit 15 is an isopach of the HRZ interval. The base of the Hue Shale formation (a.k.a., the base of the HRZ) which is the base of confining shale layer 4 varies from -6350 feet subsea in the south project area to -6800 feet subsea in the north project area. Exhibit 16 is a structure map on the base of confining shale layer 3. Exhibit 17 is an isopach map showing the thickness of the confining shale layer 3. The thickness of the confining shale layer 3 is 200 feet in the south project area and 300 feet thick in the north project area. Eni Class II Well Application-071508 3 July 2008 • i Eni Petroleum Nikaitchuq Project Class II Disposal Application The HRZ and other shales associated with the HRZ form the lower most confining layer. The HRZ shale is 100 feet thick in the south project area and 50 feet thick in the north project area. Additional shales associated with the HRZ are over 100 feet thick in the project area. While the HRZ is present in the north project area, the highly radioactive nature of the shale diminishes as you move northward. From a regional structural standpoint, the regional dip down to the northeast is consistent with the structural dip observed for the Schrader Bluff OA sand, which is found at approximately -3500 subsea in the south project area and approximately -4000 feet subsea in the north project area (See Exhibit 18). Exhibits 19 and 20 are general geologic stratigraphic columns for the project area. The exhibits show the current nomenclature being used to identify the various geologic formations in the area. Injection Zone and Confining Zones Exhibit 21 is a type log showing the upper, the two intermediate, and the lower confining shale zones; the arresting zones; and the three injection zones, DCI #1, DCI #2 and DCI #3. The DCI nomenclature is taken from the fracture simulation and injector performance report prepared for Nikaitchuq by Advantek (see Appendix A). Since the injection intervals do not have unique geologic names, Eni has referred to the injection intervals as DCI #1, DCI #2, and DCI #3, as defined on the type log. The proposed perforated interval is also shown on the type log. The actual perforated interval will be chosen once the wells are drilled, logged and evaluated. The injection zones, arresting zones and the upper, two mid and lower confining zones are all part of the overall Canning and Hue Shale formations. Exhibit 22 is a locator map for the two cross sections discussed below. Exhibit 23 is a south -to -north cross section showing these intervals with the projected location of the Oliktok Point disposal wells also shown. Exhibit 23 shows the good continuity of the Canning and Hue Shale south to north across the project area. Exhibit 24 is a west -to -east cross section and shows the good continuity of the Canning and Hue Shale formations west to east across the project area. Both cross sections illustrate the laterally -extensive nature of the thick upper and thick lower confining intervals. Injection will be into the many thin inter -bedded sand intervals found throughout DCI #3, the base of the DCI #2, and the base of DCI #1 portions of the Canning and Hue Shale formations. There is no single thick continuous clean sand body that will be used as the primary injection interval. The choice to use the many thin sand intervals for disposal rather than one single massive sand interval was made by necessity; there is no single massive sand available in the project area. Rather, injection will be spread across a vertical interval in the well that includes many thinner sand bodies inter -bedded with shales, clay layers, and mud stones. It is recognized that this injection interval is different in nature than the Ugnu and Schrader Bluff injection intervals used in many other North Slope disposal operations. Eni's proposed injection interval is more similar to the Torok disposal interval chosen by Pioneer at its nearby Oooguruk project, which Eni understands is performing very well. The Torok formation (or at least a sandy equivalent Torok formation) may or may not be present under Oliktok Point. The upper confining layer and the lower confining layer are both thick shale intervals that can be correlated across the project area. The intermediate (mid level) confining layers that separate DCI #1 Eni Class II Well Application-071508 4 July 2008 • 0 Od Eni Petroleum Nikaitchuq Project • Class II Disposal Application from DCI #3 can also be correlated across the project area, but in certain areas it is not as pronounced or dominant. Eni intends to first perforate wells in the approved injection interval DCI #2 or #3 near the base of the interval and start injecting into DCI #2 or #3. Should the lower injection interval in the future fail to take injected fluids in sufficient volumes then as needed the injection well could be perforated higher up hole in DCI #2 and then, if needed, in the lower DCI #1 interval near the base of the interval with injection then commencing into the DCI #1. Exact perforated intervals will be picked once the disposal wells have been drilled and the well logs analyzed. The exact perforated intervals in the proposed disposal wells may or may not correlate exactly with the depth interval shown on the type log, since the proposed wells are not located immediate to the type log. Small natural faults are present throughout the project area, as shown on the structure maps cited above. These small faults, with minimal vertical displacement relative to the thickness of the shale intervals, are not expected to affect the ability of the thick shale intervals to provide effective upper and lower confining seals, nor are they expected to interfere with injection of waste fluids. The faults are believed to be sealed, at least in the shale intervals. Infection Zone Properties —Porosity, Permeability, and Fracture Gradient Porosity information for the Canning and Hue Shale formations is also shown on Exhibit 25. These are log -derived values. Other than the ARCO Kalubik #1 well core measurements, we are not aware of any other core measurement porosity or permeability information for the proposed disposal formations in the project area. This scarcity of detailed core/rock property information for the disposal formations is largely due to the non -hydrocarbon -bearing and regional sand -poor nature of the disposal formations. Log -derived porosity ranges from 15% to 35% in the sandy intervals. Eni and Advantek used a porosity value of 15% in the disposal intervals in the calculations. Permeability is expected to be extremely low in the shale/clay/mudstone intervals and only poor to moderate at best in the more sandy intervals and the disposal intervals. For calculation purposes, Eni and Advantek used a permeability in the disposal interval of approximately 10 and for the matrix rock. Eni and Advantek used a thickness for the actual sand intervals exposed to injection volumes of 125 feet. Note that this is a composite thickness value not an individual sand layer thickness value. It was assumed that the sand interval was completely brine filled, although there may be a very small volume of gas dissolved in the brine. Due to the very shaley nature of the Canning and Hue Shale formations, vertical permeability is expected to be extremely low throughout the entire interval, and is expected to be much lower than the horizontal permeability. Fracture gradients: Upper confining shale layer 0.712 psi/ft (note: could be as high as 0.74) DCI Zone #1 0.652 - 0.700 Intermediate confining shale layers 0.68 - 0.69 DCI Zone #2 0.66 — 0.67 DCI Zone #3 0.65 — 0.67 Lower confining shale layer 0.72 - 0.74 Eni Class II Well Application-071508 5 July 2008 • 0 Ed Eni Petroleum Nikaitchuq Project • Class II Disposal Application The fracture gradient of the HRZ is 0.74 psi/ft. (See Appendix B, Simulation of Slurry Injection study prepared for Pioneer's Oooguruk project.) Fracture gradients of the injection intervals and confining zones and simulated fracture behavior in the DCI intervals #1 and #2 during simulated injection activities are discussed in detail in the Advantek report for Nikaitchuq (See Appendix A). The fracture gradient for the HRZ is taken from Pioneer's injection simulation study for the Oooguruk project (See Appendix B). Simulated fracture behavior for DCI #3 and the HRZ are discussed in detail in the Pioneer Oooguruk report. There are no significant sand bodies in the confining zones and the confining zones can be correlated across the project area. It is Eni's intent to inject at pressures above the DCI formation fracture gradient, if necessary. 5. WELL LOGS [20 AAC 25.252 (C)(5)] Exhibit 21 is a type log for the Canning and Hue Shale Formations in the project area. The type log display shows the disposal formations with the upper, two mid, and lower confining shale intervals; arresting zones; and DCI #1, DCI #2, and DCI #3. It also shows the proposed perforated intervals with the caveat that the perforated intervals may or may not be exactly the same in the proposed disposal wells relative to the type log, given the slight variations in geology across the project area. Initially only the lower portion of DCI #2 or #3 zone is expected to be perforated. The perforated interval will be picked once each well has been drilled, logged, and evaluated. Well logs will be provided when the disposal wells are drilled. 6. MECHANICAL INTEGRITY [20 AAC 25.252 (C)(6)] Well Construction The disposal wells will be designed and drilled in accordance with 20 AAC 25.412 and 20 AAC 25.252. OP25-DSP01 will be a vertical well drilled to a measured depth and true vertical depth of 6336 feet subsea. OP26-DSP02 will be a deviated well drilled to a true vertical depth of 6477 feet subsea and a measured depth of 8263 feet subsea. The well schematic and plot plan for the proposed well OP25-DSP01 are on Exhibits 26 and 27; the well schematic and plot plan for the proposed well OP26-DSP02 are on Exhibits 28 and 29. The surface casing will be cemented back to surface and the long string casing will be cemented 500 feet up past the surface casing shoe. The wells will be drilled to the base of the injection interval, then cased and cemented. The wells will be perforated at specific depths, based on log results for each individual well. All wells will be logged to assure that a good surface casing shoe point is chosen. Cement bond logs will be run after the long casing string is cemented to assure that good zonal isolation has been achieved. Both surface and long string casing integrity will be verified by pressure tests. Tubing and a packer will be run in each well. The injection interval will be isolated from the tubing by long string casing annulus by the packer. After the packer has been set, the tubing by long casing Eni Class II Well Application-071508 6 July 2008 • Ed Eni Petroleum Nikaitchuq Project • Class II Disposal Application string annulus will be pressure tested and filled with an inhibitive brine. The top portion of the annulus, the portion through the permafrost, will be filled with a non -gelled diesel. One of the two Oliktok Point disposal wells will likely be drilled part way into the HRZ interval to positively establish a depth reference point for the top of the HRZ interval at Oliktok Point. The lower open hole portion in the well will then be properly plugged back to the planned long string casing point. Well construction and drilling details will be provided to AOGCC in Eni's Applications for a Permit to Drill for each well. Following are the key casing program details. Surface Casing 10 % inch OD, 45.5 Ib/ft, 9.95 inch ID Pipe body yield - 1,040,000 Ibs Burst - 5210 psi Collapse - 2740 psi Long String Casing 7 5/8 inch OD, 29.70 Ib/ft, 6.875 inch ID Pipe body yield - 683,000 lb Burst - 6890 psi Collapse - 4790 psi Cementing data As shown on the well schematics in Exhibits 26 and 28, the 10-3/4 inch casing annulus will be cemented to the surface, and the 7-5/8 in casing will be cemented 500 feet up into the 10-3/4 inch annulus. Tubing Data 4 1/2 inch, 12.6 lb, L-80 Internal yield - 8430 Ibs Collapse - 7500 psi Pipe body yield - 288,000 Ibs Packer Specifications 4-1/2" X 7-5/8" Injection Packer Minimum 7500 psi pressure differential Minimum 100 degrees C temperature rating Before disposal injections begin in each well, the mechanical integrity of the well will be demonstrated as specified in 20 AAC 25.412(c). Visual and automatic monitoring of the inner annulus and tubing pressure will occur routinely with pre-set, out -of -limit alarms to inform supervisory personnel. Eni Class II Well Application-071508 7 July 2008 r� f li Eni Petroleum Nikaitchuq Project • Class II Disposal Application 7. WASTE TYPES AND VOLUMES [20 AAC 25.252 (C)(7)] The wastes to be injected are exempt, as listed in the EPA guidance booklet, EPA 530-K-95-003. Following are the estimated volumes of wastes expected from the various major sources: Drill Cuttings, mud, flush water 1,200,000 bbls (7 years) Well workover fluids and flush 250,000 bbls (30 years) Sand slurry 825,000 bbls (30 years) Other exempt fluids 30,000 bbls (30 years) Total (30 years) 2,305,000 bbls The majority of the waste will be generated during development drilling. The subsequent years of production operations will generate less waste, with most coming from sand slurry and infrequent well workover operations and drilling of additional wells. A total of about 2.3 million barrels of exempt waste could be disposed of over the entire life of the project. Based on the types of fluids to be disposed, their sources, past North Slope experience and the formation characteristics, no compatibility issues are anticipated between the fluids or between the fluids and the formation. 0 S. INJECTION PRESSURES [20 AAC 25.252 (C)(8)] Based on an injection simulation study performed for Eni by Advantek, the estimated average injection pressure would be expected to be 3,000 psi later in field life, and the maximum injection pressure would be expected to be 3,500 psi later in field life. Injection pressures early in field life are expected to be lower than those cited above. 9. WASTE CONFINEMENT [20 AAC 25.252 (C)(9)] Reservoir Fracturing To investigate fracturing effects, a modeling study was performed by Advantek on Eni's behalf to help quantify the behavior of injecting solids slurry into the Canning and Hue Shale formations (See Appendix A). Through the use of a three-dimensional hydraulic fracturing simulator, sensitivity analyses were performed to determine the maximum possible fracture dimension, analyze worst -case scenarios, and recommend injection parameters. Pioneer performed a similar study for the Torok formation and the Hue Shale for its Oooguruk project (See Appendix B). Rock properties used in the model were based on laboratory core data and log data from near -by wells. Based on the Advantek report, the recommended injection batch size is 1,050 bbls of slurry containing approximately 10% by volume of solids, injected at a rate of 5 bpm. After injection of a batch of slurry, the well would be shut in for a period of time before another batch of slurry is injected. The model Eni Class II Well Application-071508 8 July 2008 0 0 5d Eni Petroleum Nikaitchuq Project 11 Class II Disposal Application showed the maximum fracture height would be created should a single continuous injection of 1,000,000 bbls of slurry be injected at the very high injection rate of 20 bpm. This worst -case scenario far exceeds the planned operations. With the batch type operation that is planned, there will be ample time for any fracture to heal between injection cycles, and ultimately for a radial type fracture domain to develop as the project proceeds. Reservoir Faulting There are no transmissive faults, open well bores, un-cemented wells, or other conduits within % mile of the proposed wells that would permit movement of waste injectant outside of the disposal intervals. The Schrader Bluff OA sand production wells and water injection wells drilled from Oliktok Point will not penetrate the upper confining shale layer or any deeper intervals. Eni plans to drill water supply wells from OPP through the upper and lower confining shale layers and disposal intervals to the Ivishak formation. These wells will be fully cased and fully cemented through the upper and lower confining shale layers and disposal intervals to prevent any unwanted movement of injectant out of the disposal intervals. The closest abandoned wells to OPP are located over one mile southeast from OPP and, due to the distance between those wells and the OPP disposal wells, they are not considered to be relevant to the Area of Review analysis. Likewise, the closest existing drill site to OPP is the Kuparuk River Unit (KRU) 3R drillsite located over one mile southeast of OPP. Due to the distance away, it is not • considered relevant to the Area of Review analysis for the OPP disposal wells. No Kuparuk or Sag River formation production or injection wells are planned by Eni from OPP. Conclusions: • Confinement problems will not occur due to hydraulic fracturing during waste disposal operations. • There are no fault transmissibility issues. • There should not be any uncemented wellbore problems. 10. FORMATION WATER SALINITY [20 AAC 25.252 (C)(10)] Water salinity was calculated using the Archie Equation with the Humble coefficients. Exhibit 25 shows these calculations. The log calculations were performed in one well in the project area, Nikaitchuq #1, and in two wells immediately adjacent to and south of the project area, wells KRU 3Q-01 and KRU 3R-10. The nature of the disposal intervals is such that finding clean thick sands to use to calculate water salinity from well logs is difficult, as was the case for Pioneer at Oooguruk. The Torok sand disposal interval evaluated by Pioneer at Oooguruk is also representative of water salinity in the Canning and Hue Shale formations at Oliktok Point. Pioneer's log calculations show salinities in the range 17,000 to 24,000 ppm Total Dissolved Solids (TDS). A water sample from the ARCO Kalubik #1 well from the Torok sand had a TDS level of 24,300 ppm, which is consistent with Pioneer's calculations and Eni's calculations. Previous work done by Kerr McGee for the Ugnu formation (above the Canning formation) and the Ivishak formation (below the Hue Shale formation) show water salinities in excess of 10,000 ppm TDS. Eni Class II Well Application-071508 9 July 2008 • • • n U Willi Eni Petroleum Nikaitchuq Project Class II Disposal Application 11. FRESH WATER EXEMPTION [20 AAC 25.252 (C)(11)] On May 19 2008, the U.S. Environmental Protection Agency issued a No Underground Sources of Drinking Water Ruling for Nikaitchuq Development Area disposal wells in the Canning and Hue Shale formations (See Exhibit 30). The area covered by the EPA ruling includes the Oliktok Point area. 12. WELLS PENETRATING THE DISPOSAL ZONE [20 AAC 25.252 (C)(12)] No wells have penetrated the disposal zone within 1/4 mile radius of the planned disposal wells. Nearby wells are shown in Exhibit 31. Eni Class II Well Application-071508 10 July 2008 EXHIBITS Nikaitchuq Project Location Map -_Sny Island Spy Island Drillsite (SID) r I SID -� - *Gravel pad Thetis 3.8 mrleeDrillsite �... Island — • Water depth N6 feet I� Op - • Accommodate barge accessti_ Flowrline Bundle • 3.8-mile buried flowline ..4.:+sy.. , ! r- w _d'� / r�` '•' { - I FIl rfn e- • Pipe -in -Pipe Production I i ...•. 7-1�.'1 ... I` I.•. p•. r" 1_'.E=CItJT J� ' 4-1 Pi e-in-Pi e Diesel Injection Water/ Fuel Gas • Power & comms cable ,� + ,�r r• H ... ,+� ,�.I. - ylt: --: N oliktok Production Pad ( \.% P P) i'..-4` �.... r r„ ,,, y ....'�.ti .- r� J� R ', ,:. ,.. -..I • ti _.. Y• � I� � r. w• „ J- I 'rh i -72 *Process 3 phase flow-- •Drillsite '�+# i} Y" :✓� t T� + r ?t� 'j ��' I • s.. . , y,. j • r.- r Export Line i - ,'`ylRiver-Uhit- � '�. ,�� ♦-� �- �_ � • 14-mile 10" export line to Kupa�prruk Pipeline on new\/ N S t - I s I �:.. ...�'°. K i 1•• �/�_ ..+I f `. i i l•• •p ,I„ Rl..,.. - ��, r _ 1 - •� _ '� - �j , - r•• •. ,f `•.. �r., ;�{p.- a I j" .�.yr,. � �•,. M. r.. y, r ram- ..� •, I X p I � i Exhibit 1 DATE BY I CK I APP DESCRIPTION IREVI DATE IBYI CK APP DESCRIPTION 0 7/11/08 RLS I MJH I I CHECK DWG N d OLIKTOK 0 y POINT R\ -� V4t** THIS 5 PROJECT DEW LINE SITE f 0 1" 300' 5 BEAUFORT SEA QPy ,• DS-3R P PJ OLIKTOK 04N� STAGING EA•• DS-30 OLIKTOK '$ - I' \ 45 DOCK DS�30 sTP MODULE 19 20 �. 21 \22 \ T13N, R9E �\ I /\ VICINITY MAP STP PAD / n-�\ \ SCALE: 1" = 1 Mile op-ni • As Built Conductor a'-zs—I POINT P o Proposed Disposal Well lop—w Exhibit 2 �C STAOTMU �\ Aso Y\ \ J LOUNSBURY & ASSOC TO, INC. 8UEY6YOR8 Imcum CR8 PIANNSRS SEE SHEET 2 FOR NOTES - AREA: - MODULE: XXXX UNIT:OPP En! .0troleum PAD PROPOSED WASTE DISPOSAL WELLS OP-25 & OP-26 CAD601 D714 07 11 08 DRANANG N0: N SK 6.01— d 714 PART: 1 of 2 REV: 0 10 17/11/081 RLS I MJH I I CHECK DWG I I I I I I I NOTES 1. COORDINATES SHOWN ARE A.S.P. ZONE 4, NAD 83. DISTANCES SHOWN ARE TRUE HORIZONTAL DISTANCES. 2. GEODETIC COORDINATES SHOWN ARE NAD 83. 3. BASIS OF LOCATIONS ARE DERIVED FROM OPUS SOLUTIONS. 4. CONDUCTORS ARE LOCATED WITHIN PROTRACTED SECTION 5, TOWNSHIP 13 NORTH, RANGE 9 EAST, UMIAT MERIDIAN. 5. AS BUILT INFORMATION FOR OP-11 & OP-12 FROM DRAWING NSK 6.01—d674 Rev. 1. PROTRACTED SECTION 5, T. 13 N., R. 9 E., UMIAT MERIDIAN Well Na. Ak State Plane '' 'Y' X LATITUDE(N) LONGITUDE(W) Sec Line Offset PAD E EV. EO LEV. F.N.L. F.E.L. P— 1 6.036.332.70 1,656,791.89 70° 30' 39.015" 149' 51' 57.587' 2,052' 1,519' 12.1' 4.0' OP—I2 6,036,328.85 1 656 784.8 70' 30' 38.977' 149' 51' 57.795' 2 056' 1,526' 12.2' 4.0' PROPOSED DISPOSAL WELLS OP-25 6,036,006.04 1,656,514.94 70° 30' 35.808' 149- 52' 05.767' 2,378' 1,798' OP-26 6,036 013.56 1,656,529.09 70- 30' 35.881" 149- 52' 05.349' 2,370' 1,784' 9 LOUNSBURY & ASSOCIATES, INC. SURVEYORS ENGINEERS PLANNERS AREA: - MODULE: XXXX UNIT:OPP AD - Ed irol um PROPOSED WASTE DISPOSAL WELL OP-25 & OP-26 CADD FILE NO. DRAWING NO: PART: REV: LK601D714 07/11/08 1 NSK 6.01-014 1 2 of 2 1 0 OH and Gas Lessees jnhe Vicinity ®f O tok Punt AD L391283 ENf % 0% 0% 0% i t a r tk f ADL355024 CPAI 55.402367% k BPXA 39.282233% UNOCAL 4.9506% EXXON MOBIL AK 0.3648% AD L.390616 ENI US 100% 0% 0% OP26-DSP02_BHL 0% i 'I'y�y-- LIKTOK POINT Ll' K POINT OP26-DSP02 SH P45SP01_SF P25=D 1 BH C ADL373301 CPAI 55.402367% 1 BPXA 39.282233% UNOCAL 4.9506% EXXON MOBIL AK 0.3648% AKFF 014589 t M25,2004 RKFF 0145$9 a SLM SDMS 018125t2004 BLM SD MS F Alaska State Plane Zone 4 NAD 1927 1:25000 0 0.25 0.5 1 Was AD L390615 ENI US 100% 0% 0% 0% ADL355023 CPAI 55.402367% BPXA 39-282233% UNOCAL 4.9506% EXXON MOBIL AK 0.3648% KUPARUK RIV UNIT 3R-100LIK K POINT STATE 1 KUPARUIC RIV UNIT 3RPA UK RIV UNIT 3R-26 KUPA K RIV UNIT 3R-19 f<UPARUK RIV UNIT 3R- }<UPAR RIV UNIT 3R-21 KUPARUK RIV UNIT 3R-20 KUPAR RIV UNIT 3R-22 AD L35 5018 BPXA 100% 0% 0% 0% Native Allotments 7/9/08 • • 0 • Structure Map of Top of the Canning Depth 77- 0 is • i • �sopach Map of Upper Confining Layer Thickness I* Structure Map of the Base of the Upper Confining Layer ./bliklok Pt 1 Exhibit 7 • 4425 P-! Ri 1-Li • Ou �sopach Map of the DU Zone 1 Thicknes-91. � /4,943.96 '/, 0 0 0 I tudiness r7-,- 2110 0 0sopach Map of 0ntermediate Shan e Layer 2 Thickness It k I - ----- Ot22.04 ............. - ---- --- --4197.34 Z, 0 17-j 0 9 0 Isopach Map of DCZone 2 Thickness Depth 77-- �luu - 4uu 400 61 Ug -6uu 7oub ''DO -- ------ -- 1000 - ------------- 8OU ----------- FUV -------------- 500 Qu Exhibit 10 �lm *I Structure Map of Base of DC� Zone 2 Depth Depth LiUU AUOU • P�l Feli-LI —Cook Omr 0 11 0 Depth A UL T Ou Ai 01, A OD -b5tm r 7fjuu Thickness unu 6uv 460 401) Au ;UL, Z60 'OU 0 0 Bsopach of M Zone 3 0292.4 ,0494.5 pe.0 0284.4 0344.6 Ou"Osm to if 9 234 104, ExhNt 12 0 0 Depth ; lWI Structure KI/ap on top of HRZ AMP( ---- — ----- ExNbft 13 0 0 0 • Structure Map on Base of HRZ ---------- SOM PI I Exhibit 14 0 � ]l • 1�1 0 • Depth MOD 7UUD Depth auuu AIW -4WU -sum 5500 OU90 05uu Structure Map of Base of Confining Layer 3 -026 % -LI ..................... 11 ...... aw Pt I ExNbft 16 L Ilwkness P-91— 360 —:;15 — 3OU —275 2w �sopach of Confining Sha0e Layer 3 Thickness ExhUt 17 0 1721 0 • Base OA Sand Structure Mal 0 • • E 0 0 .7 -------------- U) 0 U -5� U < Soot W Tuluvak Fm-!!!`-""'�� V CL CL anfle Poffn"5'10 Imest"afe 7-) Torok Formation Fw; c<," U Torok Cr Er JWJ)I� stin;1" Ivill Figure 3. Chronostratigraphic column for the Colville basin, northern Alaska, showing the revised Brookian sequence stratigraphic nomenclature and ages (from Mull and others, 2003). See the original reference for detailed explanation of abbreviations and symbols. PIR 2007-2 Brookian sequence stratigraphic correlations Exhibit 19 • NATURAL .# - RES0 URCES DIVISION OF OIL & GAS CONOCOPHILLIPS ALASKA KRU Tabasco 2T-210 KB=117ft Spud 11/18/1999 Y ARCO West Sak River St 1 KB=84ft Spud 1/20/1971 SP Milne Pt Unit KR A-01 KB=42ft Spud 26/1980 a - -� vo— °'"" N 500 Ir ae eal -�7 =? Sea Level 6 * 500 3 _ J -1000 .T :.. __ i 1500 Fm -2000 ------ - -2500- t - x Ir- vv s>k sands ea `? 4 is _ �'_ Jvn 'di �_ _ 3 •_- � -3000 -3500 -4000 N UN _ Schrader Bluff Fm -4500 7abaeco'St :agar (C¢mpanranA;;- I _ Prg•n nd .¢navina: acne _ i . f - '- _� �_ _ --'- isidy TD =5340 ft .y� tsloRt ;nP1 muds, - is I 5000 _ : :aP. usurq.uw,:aem,aMcm�r;rns.>i. -- � ! Lower Canning Fm ^distal Seabee Fm <� - - --. 5500 8 Hue Sh undift. � - � ' f !. t.rnuds, U ba in? �- 1 �r _ Hr�?&pebble sh-#..i.-. _' '. _ -600 i 4e�V 0 ;ice 8.b -�^- U_pper Kuparuk Fm LCU f .�_ lower Kupansk Fm~ ' i; .+•s.+s+� .. _ _X—_.- ! _- -6500 *bale sh Nlluveaoh Fm- f LCu - -7000 __-..__...__ Lower Ku piimk Fm KingeKFm Nma:m •-- _ - sits Miluvezch Fm -7500 - NechelYc addimnel log dal not plotted additional IN tlera na plotted ---- Kingak Fm —, Exhibit 2® I REVISED 02-2007 PL Decker, Petroleum Geologist 1 0 I• 0.00 14000 OLT-CPI 4000 N Sand Top — 4000 _ - -- N Sand Top OA Sand Top OA Sand Top OA Base OA Base CoSh1 Top CoSht Top 4250 `: DZ 1 Top DZ 1 Top 4500 9 5/8" I 9 5/8„ 4750t 5000 DZ 1 Base DZ 1 Base 5250 ro DZ 2 Top 5500 5 - 1DZ 2 Top 5750 6000 0250 DZ 2 Base 6500 _ _ DZ 2 Base 6750 CoSh 3 Base CoSh 3 Base HRZ Top HRZ Base Kuparuk Top 7000 s- c 1 r r , HRZ Top f ( HRZ Base _ Kuparuk Top 7250 Kuparuk Base Ku ar1,k Bas L s� Exhibit 21 • i! k- -- 'A— Tlaacs r 1 d17 •Y 1. .9639 OPVetvcah— �we4at< 0 • ti \ E �d21a� t 10 Exhibit 22 W 0 0 ExhNt 23 South -to -North Cross -Section OA Base Olik a 1 Oliktok Pt.1 Dis OP Vertical Nik-03 • 4_g Nik-01 7 ExhibR 24 0 West -to -East Cross -Section 2000 2DOO I20M 600 W ; Tuvaaq j 25,00 -2® 2500 LOO r2500 I OA Base 3000 3000 3000 r3aoo 3500-3500 3500 I35M t.3500 3500 ..DO -4000-- �00 4000 -� ftnj_- CO �- _ -45W -4500 5w 45W 500 - 4500 Shale 2 5000 �- --� _..__— _SooO—_� -5000 �f 0 ` 5000 15000 -�-� -�-( I- 5000 L\--- Confining Shale DO Z2 .55W -5500 HRZ Torok Eq_,_— Y Thetis island 1 soo �--- 65pp 500 8500� 7000 _7000 -7000 7000 �7D0____ -- - Dis SI Ver --1 NW Milne 1 7500 -7500 .7500 [7500 j7500 k I aj 8000 8000 -8" Nik-l73 ±-8000 II jl x Tuvaaq 8500 i8500 Thetis Island 1 r '-9000 Kigun it l N ik-02 0 E Canning and Hue Shade Rock Properties and Water Salinity Well Depth Depth Formation Calc. form Den Por Rwa 0 75 TDS Rwa @ form temp RT @ form temp MD TVD Temp. (F) temp (F) % ohms ppm ohms ohms Nikaitchuq #1 6380 5214 162.7 110.0 18.3 0.2 30,882 0.09651 2.86 6390 5222 162.8 110.2 16.5 0.154 41,421 0.07436 2.71 6400 5230 162.9 110.4 22 0.287 20,808 0.138 2.83 6410 5239 163 110.6 25.1 0.296 20,106 0.1424 2.25 6755 5524 167.5 116.9 16.5 0.146 44,438 0.06832 2.49 8096 6643 184.9 141.5 21.3 0.178 35,366 0.0757 1.669 0.022 KRU 3R-10 7577 5468 171.5 152.3 17.1 0.263 22,855 0.1203 2.991 7587 5471 171.7 152.4 17.8 0.228 26,722 0.1044 2.579 7597 5476 171.9 152.5 18.41 0.272 22,030 0.1244 2.752 KRU 3Q-01 5040 4313 99.1 126.9 19.5 0.099 69,837 0.07621 2.629 5050 4321 99.2 127.1 22 0.141 46,043 0.1088 2.241 5146 4399 100.5 128.8 25.4 0.219 27,979 0.1677 2.586 5156 4407 100.7 129 25.1 0.269 22,273 0.2043 3.226 5195 4438 101.2 129.6 16.2 0.09 77,512 0.06796 2.567 5205 4446 101.3 129.8 16.9 0.114 58,947 0.0863 2.989 5225 4463 101.6 130.2 21.1 0.169 37,468 0.1268 2.828 5235 4471 101.7 130.4 21.7 0.172 36,620 0.1294 2.745 5245 4479 101.9 130.5 20.5 0.148 43,448 0.1113 2.636 5557 4730 106.2 136.1 19.8 0.136 47,948 0.09851 2.506 5567 4738 106.3 136.2 19.8 0.136 48,083 0.09827 2.492 6486 5482 118.9 152.6 17.1 0.114 58,927 0.07397 1.944 6496 5490 119 152.8 16.3 0.099 69,877 0.06406 1.868 6516 5506 119.3 153.1 20.3 0.338 13,665 0,2199 5.323 6596 5572 120.4 154.6 15.2 0,099 69,530 0.6382 2.229 6606 5580 120.5 154.8 16.9 0.148 43,415 0.09556 2.69 6616 5518 120.7 153.4 16.5 0.123 53,880 0.07861 2.312 6859 5868 121.3 161.1 16.1 0.253 23,902 0.1616 1.258 Archie Equation: Rwa= (Rt*PorAM)/a Humble Coefficiente: a=0.62 m=2.15 Temperature Gradient below Permafrost: 0.022 deg F/ft Formation Temperature F Tf = 32+ (TVDepth -Permafrost Depth) * .022 Rwa 75F Rwa75=Rwa * (Tf+6.77) / (75 + 6.77) Total Dissolved Solids ppm TDS NaCI Equivalent = 10 ^ (( 3.562 - log10 (Rwa75 - .0123)) / 0.955) • Exhibit 25 4 4 4 Nikaitchuq ®Iiktok Point rnll1ls fe2tlrollau� n� Meld North OP25-DSP01 Slope - Alaska DIR I LVVD FORM DEPTH --j HOLE CASING MUD INFO MD TVD MWD SIZE SPECS INFO Top of Permafrost 0' 0' m 0 20" i X-65 20" Conductor Shoe 160' 160' ; D ; N/A Welded / Driven N/A NIPPLE ; �O y Surface Csq r r i r 10-3/4" LWD/MWD/GR/ _ 45.5lbs/ft Wellbore Stability Res i r L-80, BTC +/-9.7 ppg Lost Circulation Hole Cleaning Base Permafrost 1,912' 1,912' ; ; Casing Sections r r - Casing Wear Top of Tail 2,247' 2,247' BHA Expense i n i Pick Casing Point 'r- ____Toe of Cement 3,247' 3,247' vi T/ CoSh 1 3,670' i 3,670' 1131/ 10-314" Casin Point 3,74T 3,74T 0 74` F WBM BI Cosh 1 - T/ DZ 1 s,e20' 3,820• i i Inter. Casing i r 7-5/8" 29.7 Ibs/tt L-80, BTC-M B/ DZ 1 - T/ CoSh 2 4,850' 4,850' i i i i T/ DZ 2 S•102' S 102' 0- i i ' i r +/-11.5 ppg Wellbore Stability i Lost Circulation LWD/MWD/GR/ Disposal Tubing Hole Cleaning Res/ Neutron/ r 4-1/2" Casing Sections Density ; 12.6lbs/ft Casing Wear L-80,IBT-M BHA Expense Pick Casing Point B/ DZ 2 - T/ CoSh 3 5,800' 5,800' B/ CoSh 3 6,000, r"0 0' i i ' i NIPPLE i ' i PACKER r i i NIPPLE v r i r 30' Perforation Interval i 8-12 SPF 45' Phasing — Primary Disposal — ` Largest shape charge available VVBM Top of HRZ 6,323' 6,323' ; i OR 7-518" CSG Point 6,388' 6,388' T ' 9-7/8" 117 F SBiVi Exhibit 26 wo En! PWirolleuim ° J;l 20' 500 1000 1500 2000�Base of Permafrost C 2500 1Z O O O 3000 L a W CoSh 1 Top m 3500 U N > 2 4000� DZ 1 Top DZ 1 Base/Cosh 2 Top DZ 2 Top DZ 2 Base/Cosh 3 Top 10 3/4 b000 - CoSh 3 Base 7 5/8'f HRZ To lit 6500 HRZ Base -500 -400 -300 -200 -100 0 100 200 Vertical Section at 270.00' (200 ft/in) i Project: NIKAITCHUQ 0 Site: OLIKTOK POINT Well: OP25-DSP01 PROJECT DETAILS: NIKAITCHUQ Geodetic System: US State Plane 1927 (Exact solution) Datum: NAD 1927 (NADCON CONUS) Zone: Alaska Zone 04 System Datum: Mean Sea Level CASING DETAILS TVD MD Size 120.0 120.0 20 3668.0 3668.0 10-3/4 6336.0 6336.0 7-5/8 WELLBORE TARGET DETAILS (MAP CO-ORDINATES) Name TVD +N/-S +E/-W Northing Easting OP25-DSP01 6336.0 -323.9 -270.5 6036254.06 516483.50 300 400 500 * I Exhibit 27 4 F- L i Nikaitchruq ®liktok Point EndPaLI�dCum Field N o rt h OP26-DSP02 Slope ® Alaska DIR / LWD DEPTH HOLE CASING MUD INFO FORM MD TVD MWD SIZE SPECS INFO Top of Permafrost 0' 0' m 0 20" i A X-65 20" Conductor Shoe 160' i 160' ; ; ; N/A Welded / Driven N/A NIPPLE y15 Surface Csq i 10-3/4" LWD/MWD/GR/ 30' 45.5lbs/ft Wellbore Stability Res i r i L-80, BTC +/-9.7 ppg Lost Circulation 40' ; Hole Cleaning Base Permafrost 2,072' 1,912' ; ; Casing Sections i Casing Wear Top of Tail 2,529' 2,192' 50, BHA Expense C1 ; Pick Casing Point Top of Cement 4,529' 3,465' T/ CoSh 1 4,913' 3,728' i O i 10-3/4" Casing Point 5,029' 3,802' 50 i 13-112" 74' F WBM i B/ CoSh 1 - T/ DZ 1 5,156' 3,883' i Inter. Casing i 7-5/8" i 29.7 Ibs/ft L-80, BTC-M BI DZ 1 - T/ CoSh 2 6.618' 4,697' 50, 'i T/ DZ 2 6 920' 5.163' 25- i i +/-11 5 ppg Wellbore Stability i Lost Circulation LWD/MWD/GR/ i Disposal Tubing Hole Cleaning Res/ Neutron/ i 4-1/2" Casing Sections Density 12.6 Ibs/ft Casing Wear L-80,IBT-M BHA Expense 5` i Pick Casing Point B/ DZ 2 - T/ CoSh 3 7.701' 5,915' B/ CoSh 3 7,922' 6 136' W IL i NIPPLE PACKER t i i NIPPLE i � 30' Perforation Interval 8-12 SPF 45' Phasing Primary Disposal Largest shape charge available WBM Top of HRZ 85' 6,464' T"!;:!T OR 8.3 i 0 Z8 h SBM7-6l Exhibit 28 En! Poearolleunn-in Cfn�ii o 20" 0° 500 ` 5° 10° 15 1000 �, 20 ' 25 10 c 2500 CASING DETAILS TVD MD Size 120.0 120.0 20 3750.0 4977.0 10-3/4 6477.0 8263.0 7-5/8 35 R� �O 0 O 3000 OA Base o 4 h a N 0 3500 CoSh1 Top 10 3/4" j a000 DZ 1 Top � Ph asoo DZ 1 Base 5000 DZ 2 Top Zo 5500 DZ 2 Base 15° 10° 6000 CoSh 3 Base HRZ Top yRZ Base 7 5/8 6500 -500 0 500 1000 150C 2000 2500 3000 3500 4000 4500 5000 Vertical Section at 349.61° (1000 ft/in) i a= 0 0 0 N t r 0 z s 0 07 Project: NIKAITCHUQ • Site: OLIKTOK POINT Well: OP26-DSP02 PROJECT DETAILS: NIKAITCHUQ Geodetic System: US State Plane 1927 (Exact solution) Datum: NAD 1927 (NADCON CONUS) Zone: Alaska Zone 04 System Datum: Mean Sea Level -900 -750 -600 450 -300 -150 0 West( -)/East(+) (300 Win) Exhibit 29 -9- f1AY-�U-�UUU I UE 1 U 2a AM e°o ,3 I� • �eea sr�' 9 x REGION 10 1200 Sixth Avenue, Suit® 900 Seattle, Washington 98101-3140 1 9 MAY -08 Reply To: OCE-127 Mr. Robert 13ritch, P.E. Regulatory Team Leader Eni US Operating Co. Inc. (Eni) 101 West Benson Boulevard, Suite 201 Anchorage, Alaska 99503-9377 Re.: No Underground Sources of Drinking Water (USDW) Ruling Nikaitchuq Development Area (NDA) Class I Well Application, Beaufort Sea and Oliktok Point, North Slope, Alaska Dear Mr. Britch: The U.S. Environmental Protection Agency, Region 10 (EPA), Office of Compliance and Enforcement has received Eni's letter and related material dated May 9, 2008. The letter requested that EPA confirm that portions of aquifers do not qualify as underground sources of drinking water (USDWs) as defined in 40 Cl«R§ 144.3. Based on data submitted by Kerr McGee Oil and Gas Corporation ( G) on December 15, 2005, EPA granted K.MG an aquifer exemption for the Ugnu and Sagavanirktok formations below approximately - 3100 feet TVDss and a "No USDW" ruling for the Ivishak formation below approximately - 9150 feet TVDss within the NDA (based on the Nikaitchuq # 1 'Type Log). After additional technical analysis and a review of operational considerations, Eni intends to utilize the Canning and flue Shale formations for its disposal interval (instead of the Ivishak and Ugnu intervals proposed earlier by KMG). Based upon a review of the information provided by Eni on the Canr ing and the flue Shale formations, EPA confirms the "No USDA" ruling for the portions of aquifers requested by Eni. In summary, the aquifers in the approximately 12,800 acres, in the twenty section NDA (T 13N R9E Ulf Sections 3, 4, 5 and 6; T 14N R8E Sections 13, 24 and 25; T 14N R9E, UM Sections 9, 16, 17, 18, 19, 20, 21, 28, 29, 30, 31, 32 and 33) between the top of the Cajjiming formation, and the base of C. Hue S `�al.�e¢ fog^& 3on as tho�s1:et form1 a?ions xrke rt ci?t fi fall �T, ihw 1` ikai t ch L)_q T'h , Typc_- 7 C.g — .Ire J� "1311 77 iC,� r'�� gb �l. :..: VS:l�``y\I �C'SMN" r0ing n.pplies to the interval bttwleen the top or th3: Ca nuning formation (0b.ict vailes from approximately 3500 feet TVDss in the soutfi project area to appmximapely - L1200 feet T- �9� :� the, :' or,-�a "�! �ecl area c .-he base o r 7h'a .. 1l �`fla.'', y fc:-n1swin--- �? s" iini cu -cuuo IUC IU-i tO HH 0 FAX NQ* P. 02 of the HRZ zone which varies from apmxi>rnately — 6500 feet TVDss in the south project area to approximately — 7050 feet TVDss in the north project area). These aquifers exhibit total dissolved solids concentrations that significantly exceed the 10,000 milligrams per liter (mg/1) TDS threshold for a USDW. The "Rio USDW" ruling is granted to Eni for the above area _with the stipulation that once the Class Y wells are drilled, the "No USDW" ruling will ax)roly to the area underlying (togs of the Canning to the base of the Slue Shale) and within a'/ mile radius aro-and each of the drilled Class 1 wells. If you have any questions or need clarification, please contact Mr. norr Cutler of my staff at (206) 553-1673. Sinc y, . , aj�, �A, Michael A. Bussell, Director Office of'Compliance and Enforcement cc: Jinn Regg, A®GCC, Anchorage, AK Talib Syed, EPA Consultant, Denver, CO • U 1:80,000 Alaska State Plane Zone 4 NAD 1927 13 0.5 1 2 3 4Mies i APPENDIX A INJECTOR PERFORMANCE POTENTIAL REPORT BY ADVANTEK FOR ENI'S NIKAITCHUQ PROJECT • PROJECT SUMMARY REPORT ENI Nikaitchuq Injector Performance Potential during DCI Operations Prepared for Mr. Jeff Miller, Reservoir Project Leader ENI Petroleum Co., Inc. Prepared by 0 4 4 0 dV 2-44- tNT E • a " mrsrnnnov�t ' " • Table of Contents ExecutiveSummary and Recommendations..................................................................3 Introduction................................................................................................................... 6 Scopeof Work and Objectives........................................................................................ 7 Overview of Drill Cuttings Injection Scheme.................................................................................. 7 Scope of Task 1: Formation Evaluation and Verification................................................................ 8 Selection of Potential Disposal Formation..................................................................................... 8 Candidate Disposal Formations Comparison ................................... ................................................ 9 Scopeof Task 2: Fracture Geometry.............................................................................................16 Fracture Simulation Overview.................................................................................................... 16 Assurance and Fracture Containment......................................................................................... 16 Maximum Possible Contained Growth (Lateral Extent)................................................................. 18 Maximum Possible Uncontained Growth (Vertical Extent)............................................................. 19 Implications of Maximum Extent to Well Selection....................................................................... 19 BatchInjection Parameters....................................................................................................... 20 Factors Affecting Batch Injection............................................................................................... 26 FractureOnentatron......................................................................................................26 Shut -In Time and Operational Procedure.........................................................................27 SlurryDesign................................................................................................................27 DisposalDomain...........................................................................................................29 Scope of Task 3: Surface Injection Pressure nad Volume Plots ................................................... 30 Scopeof Task 4: Sensitivity Studies............................................................................................. 35 Fracture Sensitivity to Injection Rate.......................................................................................... 35 Fracture Sensitivity to Solid Concentration.................................................................................. 36 Scope of Task 5: Disposal Well Design and Disposal Formation Preparation ............................... 37 Recommended Disposal Well Configuration................................................................................ 37 Erosion Wear Evaluation and Tubular Bursting Rate.................................................................... 39 Best Practices for Cementing and Perforating............................................................................. 40 Cementing.................................................................................................................... 40 Perforationsand Guns...................................................................................................40 Scopeof Task 6: Assessment of Environmental Risks.................................................................. 41 Scope of Task 7: Data Requirements for Monitoring and Assurance Plan .................................... 42 AppendixA: Injection Test Pressure........................................................................... 41 Appendix13: SPE Paper 72308.....................................................................................49 Appendix C: DCI Tasks & Deliverables........................................................................ 50 �1 0 �rorceruuon�� .t-a � v`eaU 0 Executive Summary and Recommendations The following report summarizes the results of a study conducted by Advantek International Corp. on behalf of ENI. The study assesses potential injector well performance during drill cuttings injection (DCI) operations in the Nikaitchuq field located on the Central North Slope, Alaska. The preliminary conclusions and recommendations from this study are: 1. Data from wells in the Nikaitchuq field were analysed and compared with worldwide large DCRI projects. The feasibility study indicates that drill cuttings re -injection (DCRI) in the Nikaitchuq field is likely to be an operationally safe and environmentally acceptable /ong-term solution for disposal of drilling waste from the planned drilling operations. 2. In this study, it is assumed that some 30,000 and 65,000 barrels of solid cuttings waste are generated from drilling of Oliktok Point and Spy Island wells respectively. Two dedicated injector wells are recommended, one for wells drilled from Oliktok point and the other for wells drilled from Spy Island. The total injection solid volume after bulking and before slurrification is 70,000 barrels per disposal well of Oliktok point and 150,000 barrels for disposal well of Spy Island. 3. A number of potential disposal zones are identified and two disposal zones were selected as most appropriate. The first selected target zone is Zone 1, at a depth of 5,200 ft, between two thick shale bodies. A second zone, Zone 2 was also selected. It lies at a greater depth of 6,400 ft and is further away from the production horizon. Hence the risk of breach to the surface from any slurry fracture started at the second zone is lower than for the shallower zones. 4. It is recommended to /nrt/ate injection into Zone 2, as it is the deeper of the two zones. This allows for a fail safe operation in case that this initial target horizon (zone 2) is plugged during injection. The plugged zone can then be bridged and a shallower (backup) zone can be perforated, allowing further use of the disposal well for injection. This completion scenario would mitigate the risk of abandoning the well due to plugging in the wellbore. 5. A maximum theoretical fracture half-length and height are obtained as an assurance process for the injection process. These values are obtained from simulation of continuous injection of the entire volume of disposed wastes into a single bi-winged and uncontained fracture at a constant disposal rate of 20 bpm. This is NOT the recommended injection procedure, nor is it feasible to implement such a procedure; therefore these theoretical maxima exceed the fracture extent that can be achieved in field operations. Fracturing simulations were compared after 1.0 million barrels waste slurry injection per disposal well. These simulations indicated that disposed washes can be safely contained in either zone Between the two zones, the disposed wastes are more safely contained in Zone Z. The theoretical maximum possible fracture half length achieved after injection of that volume is 2500 ft for Zone 1 and less than 1300 ft for Zone 2; while the theoretical maximum possible fracture upward growth is 2000 ft for Zone 1 and 2500 ft for Zone 2. Although the fracture height is greater in Zone 2 than in Zone 1, injection in the deeper Zone 2 reduces the risks of the fracture reaching the production horizon. 6. The extent of the disposed waste domain achieved during batch or periodic injection would be considerably smaller than the maximum theoretical extent obtained from single bi-winged fracture simulation when continuous injection is assumed. This is because periodic injection creates multiple and smaller fractures. The estimated disposed wastes extent also depends on geologic characteristics such as Young's modulus and formation permeability and on operational procedures such as injection rate and batch size. 7. For a range of 600 and 1050 bbls of solids batch sizes used in this study, the maximum fracture up -growth and the maximum fracture horizontal extent were 670 ft and 420 ft, respectively. These maximum values were obtained from a solids batch size of 1050 bbls. 0 • • dvantek __ ,.� iwrcrw�nownr 8. Recommended Batch Design: • Batch Size (Barrels of Solids) : 1050 bbls • Injection Rate : 5bpm • Volumetric Solid Concentration : 10% • Batch Duration : 35hrs K w,_ 9. Injection Procedures: Injection rate and duration of each injection period depend on formation characteristics, estimated waste generation rate and other parameters. For higher concentrations a smaller batch or higher injection rates are required. The recommended injection duration per batch is about 35 hours when a batch size of 1050 barrels of softfs is used. 10. It is recommended to thoroughly grind the injected solids to attain the smallest injection particle size possible (<300 micron). Sufficiently small particle size may leakoff with the injection fluid from the fracture therefore creating lower concentrations inside the fracture. This delays the onset of tip screen out and decreases the pressure increase required from injecting one batch to the next. 11. Wellhead and Pump Requirements: For the recommended batch design it is recommended that the surface facility is raged to or 3500 psi and the injection pumps should have a capacity of 400 HHP. Alternative batch designs may require greater surface facility rating and power requirements up to 4000 psi and 500 HHP respectively. 12. Recommended Disposal Well Design and Completion: Considering the large amount of waste to be disposed over a long period of time and the separation of the two drill sites, two dedicated waste disposal wells are recommended. Erosion evaluation compared several tubing sizes and concluded that the injection tubing should be 4.5ry Erosion protection of the wellhead is recommended. 13. A minimum of two shoes are required above the perforations, excluding the surface casing, Thus the suggested well completion incorporates both the 9 5/8" casing and the 13 3/8" casing. 14. A minimum distance of 500 ft is required from the top of the created fracture domain (5400 ft for Zone 2) to the first casing shoe above it (9 5/8"). 15. Cementing between the 7" and 9 5/8" casings must go beyond the 9 5/8" casing shoe. The cementing job must be quality assured. Cementing between the 9 5/8" and 13 3/8" casing must extend at least 500 ft above the 9 5/8" shoe. Cementing Best Practices should be used to ensure the 13 3/8" shoe is adequate to support injection in Zone 1. If a zone switch is required from Zone 2 to Zone 1, it should only be undertaken after a thorough evaluation of the cement across the zone and the condition of the 13 3/8" shoe. 16. Contnuous pressure monitoring over the inner annulus and outer annulus is highly recommended. Pressure monitoring over the inner annulus (between the intermediate casing and the injection casing) can detect possible casing erosion or cement failure. An open annulus between the 13 3/8" casing and the 9 5/8" casing would allow for pressure monitoring over the outer annulus and detection of excessive fracture height growth should the fracture reach the open annulus. The injection casing should have a burst rating of 3500 psi. 17. A HaaID study is required to identify any operational risks such as possibility of disposed waste interception with faults, high pressure shallow gas zones, underground drinking water, hydrates, permafrost, or other geo-hazards. 18. Specific design requires accurate input parameters such as fracture gradient, Young's modulus, and fluid loss coefficients. The current logging program appears to be adequate, but more FIT/LOT tests are required to calibrate the log analysis results. Core analysis and rock mechanics testing are recommended for the proposed disposal well. • r 1 U • I1 19. Injection test is recommended at the target injection zone to obtain fracture closure pressure and leak -off property. The most effective means of ascertaining the leakoff characteristics is by performing an injection test with the intended injection fluid. Leakoff coefficient is a function of both the injection fluid and the target horizon permeability. Caliper logs over the target injection zone are recommended to obtain fracture orientation. 20. It is critical in DCI operations to adopt an inclusive monitoring scheme. This should include, but is not limited to daily recording of the injection rate, volume, pressure and temperature. Some measure of the fluid viscosity, density and solid concentration should also be recorded. Annual testing including Step Rate Tests and Pressure Fall -Off Tests should be conducted on a periodic basis (annual, semi-annual or quarterly depending on the applicability). E dvantek J El,alua?:4n:9 NNT Introduction 0 The Nikaitchuq field is a unitized production area located on the Central North Slope of Alaska. Production is scheduled to begin in 2009. Figure 1.1 shows the Nikaitchuq field location between several established fields that also utilize produced water injection and/or drill cuttings injection. Kwnr.or 14+f ♦r+�+ 1f r.t rr(nrt7 ArNA SM! .. srlR lfA a'tr �r Stnevl ' V!/t .i M11(A �..1_N_...., e e � J�CfM��w?J!K Figure 1.1: North Slope Production Units Outline Map Production is scheduled to begin in 2009. 48 wells are to be drilled from Spy Island and 16 from Oliktok Point. Drilling and production wastes such as oily contaminated drill cuttings and produced water must be handled in an economically sound and environmentally friendly manner. Waste disposal into a suitable geological formation has been adopted by companies as a routine disposal method and operated worldwide. At the request of ENI, Advantek International conducted this feasibility study to evaluate the suitability of this technology for handling the generated wastes in the Nikaitchuq field and its possible risks. A separate report was prepared by Advantek International, Inc. covering injector performance potential during water flood operations; however, the water source was assumed to be filtered sea water rather than oily/sandy produced water. The waste water generated from drilling operations is incompatible with injection for enhanced recovery from the producing reservoirs. 3300 S. Gessner Rd., Suite 257 Houston, TX 77063 US www.Advantelcinternational.com • . Scope of Work and Objectives The scope of the work covered by this report is a feasibility study to identify candidate disposal formations in the Nikaitchuq field appropriate for drill cuttings injection (DCI). The deliverables are: • To deliver a report with full evaluation of the project feasibility • To provide the list of data, specific testing, and logging program required to implement and complete the evaluation for Task II • To present detailed plots of relevant offset well data and calculated geomechanical parameters data to be used in the hydraulic fracture simulations • To identify document and procedure requirement to issue a proposal for permit application when the study is completed Overview of Drill Cuttings dnjertion Scheme The discharge of contaminated drilling wastes may be governed or managed through regional agreements or through national legislation, depending on the location of the project. In all cases, the general waste management guidelines should follow the hierarchy of minimization, reduction, recycling, recovery, treatment, and finally disposal or discharge. Within this framework of available options, the most acceptable form of waste management is to actually minimize the amount of waste being produced. The next most favored option would be to convert it into a usable product, then to treat it to make it non -harmful. Disposal of waste is seen as the least preferable solution. It can be justifiably argued that drill cuttings injection (DCI) (also called re -injection or DCRI) is a means of waste reduction as no drilling waste is left at the end of operations. Furthermore, in a broader sense, the waste material has been returned to its place of origin. The drill cuttings from shale shaker are milled to small particles (300 microns or less), in the presence of water, •usually seawater or other waste streams. The resulting waste slurry is pumped into sub -surface fractures created by injecting the slurry under high pressure into the disposal formation. Depending on drill cuttings generation rate, the waste slurry is injected either continuously or intermittently in batches. A continuous slurry injection scheme is expected to lead to an extended disposal fracture, while periodic re -injection would promote the development of multiple fractures and thus a compact domain of smaller multiple fractures close to the wellbore. The batch process consists of intermittent injection of roughly the same volumes of slurry and shutting -in the well after each injection. This allows the disposal fracture to close onto the waste and to dissipate any build-up of pressure in the disposal formation. Each batch injection may last from a few hours to several days, depending upon the batch volume and the injection rate. To create a compact disposal domain, it is critical when following the periodic re -injection design basis that the well is shut-in between batches so that the created fracture can "heal" completely before pumping in the next slurry batch. This may be impractical when re -injecting into the low leak -off shale as the target disposal horizon, while processing cuttings from surface sections where the drilling rates are relatively high. In practice, therefore, re- injections may shift from essentially continuous mode to periodic as the cuttings generation rate declines. Drill cutting re -injection into subsurface geological formation is one of the preferred options for handling drilling waste. The most significant reasons for this are: • The waste disposal into subsurface geological formation through slurrification and injection can achieve zero waste emission. • Future liability is eliminated when the injection loop is closed. Costly drilling waste transportation and spill risks can be minimized or eliminated. • • • Drilling waste is handled on drilling locations and the drilling operator has total control over the drilling waste handling - it does not depend on the weather or the availability of a boat for managing it. • It has been successfully applied in all parts of the world and a number of service companies offer DCRI services worldwide. This process often offers good overall economics. Drill cutting re -injection is becoming a routine drilling waste disposal method for complying with environmental legislation and company policies. There have been many successful injection operations conducted by major oil companies. A number of papers on this technology have been published since the late 1980's to address case studies, equipments, economics, regulations and permitting issues. Laboratory testing on large blocks (1 meter cube) was performed to understand the importance of fracture containment mechanisms and to verify the multiple fracture creation during the periodic injections of drilling waste. Field trial of cuttings slurry injections and coring from near -by wells confirms creation of multiple fractures from periodic slurry injections into sandstone or shale formations. Best practice guidelines on DCRI engineering design and operational procedures have been provided based on projects experience and lessons learned by Abou-Sayed and Guo (2000, 2001) as a result of a DCRI ]IP project. Most drill cuttings re -injection operations have been safely conducted in an environmentally acceptable manner. However, problems can still occur. For example, a number of operators experienced premature plugging and loss of injectivity during slurry injection. One operator, after injecting over 800 million pounds of waste slurry in one well during their pit closure project, decided to halt the injection process to avert communication to the surface when the cuttings path intersected an existing open conduits to a near -by well. It is imperative that DCRI operations be properly engineered to ensure that full integrity is maintained both at the surface and in the downhole. Successful drilling cuttings re -injection projects involve many phases of this technology, such as careful planning, proper design, engineering, permitting, monitoring, operation assurance, risk management and contingency operational procedures. scope of Task 1; Formation Evaluation and Verricabon Selection of Potential Disposal Formations • The following issues need to be addressed for the identification and selection of the disposal zones, according to the world-wide experiences and precedents of other large waste disposal projects: Considerable volumes of drilling waste may require injection; therefore safe containment is of high importance. A number of fracture containment zones should be identified to assure operating flexibility over the life of the project. It is assumed in the present case that: o No long term waste disposal operations will occur in formations shallower than approximately 3000 ft. below the surface (if onshore) or the mudline (if offshore). o Selected target zone(s) will have adequate thickness of overlying "arresting and confining zones" to prevent upward migration of injected material into fresh water aquifers or the permafrost zone. Formations with reasonable permeability and porosity are often preferred disposal zones for dedicated disposal wells. However, the disposal rates must be designed accordingly. For lower disposal rates of high solid concentration, slurry into highly permeable sands can cause premature screen -out and thus loss of injectivity. Loss of injectivity is either due to solids plugging the near wellbore region or due to fracture tip screen -out which is one of the frequently occurring operational problems in the DCI process. Avoid injecting into high -reactive shale formations. Reaction between the shale and the water causes clay swelling which can lead to loss of injectivity resulting in high surface injection pressure. 9 • ■ The recommended disposal zones for dedicated disposal wells are mostly the permeable sandstone formations with some fracture containment formations above the disposal zones, such as formations with larger fracture closure pressure, elastic modulus or with lower porosity / permeability. ■ The recommended disposal formations can be of varying lithology but must satisfy the following operating criteria: o Storage capacity — able to accommodate the planned volume of solids o Allow for volume leakoff during shut-in to decrease the pressure build-up over time o Presence of confining layer above/below that restricts significant vertical fracture growth thereby containing the waste in the target horizon ■ The recommended disposal formations must also satisfy the following safety criteria: o Avoid over -pressured shallow gas formations that can present potential well control problems o Avoid faulted and fractured formations that might provide conduits for slurry waste to reach shallower formations and other wells Candidate Disposal Formations Comparison Advantek reviewed logging analysis and formation characteristics from Well NIK1, the only well with a complete suite of available data in the horizons of interest; we recommend two drill cuttings disposal zones for the assessment and review. The first zone is below the production horizon (around 5200 ft, TVD) and the second zone is a much deeper formation (around 6400 ft, TVD). Figure 2-1 displays the gamma ray for the candidate disposal zones. Gamma ray logs and compressional wave velocity are provided for the entire lithological column of interest, while density, porosity and shear wave velocity are partially available. The first potential DCI interval (Interval 1) is located from 4360 to 5200 ft TVDSS in well NIK-1. The top of the zone is directly below a relatively continuous 200-ft thick shale barrier at the base of the Schrader Bluff production interval, as shown in Figure 2-1(a). In addition to the requirement for a continuous shale barrier, drill cuttings disposal should avoid injecting into any zone having the potential for oil or gas production, so layers with oil saturation should be avoided. Limestone formations pose uncertainty in their lateral distribution of permeability and porosity, so these formations are less suitable for DCI. The second potential DCI interval (Interval 2) is located beneath the shale barrier that forms the lower boundary of interval 1, from 5480 to 6600 ft TVDSS in well NIK-1, as shown in Figure 2-1(b). Interval 2 has a higher average gamma ray value than interval 1 (indicating a potentially tighter zone) and it exhibits more variation in gamma ray from well to well. Despite the higher pressure that will be needed to accomplish injection into interval 2, this zone is attractive for DCI because it is further from any potentially productive horizon. 0 dv�nivrerxnno�ani 3600 3800 4000 4200 r 4400 a d 4600 v g 4800 a �= 5000 5200 5400 5600 6? a t`WAk. REPORT —GRNIK1—GRNIK2 —GRTS1 J Gamma Ray (a) Upper Candidate Zone 1 (b) Lower Candidate Lone 2 Figure 2-1: Gamma Ray for DO disposal interval 3300 S. Gessner Rd., Suite 257 Houston, TX 77O63 US www:AdvantelZlritern ational.com s�arr&a �E3w��. 0 • 0 • • • dv�lntek....�' �nrcrrar�avnt LINT Niruei'& Spy"'q r4Ll,-ch 203:: Figure 2-2 and Figure 2-4 show the saturation and lithology of the two candidate disposal zones, respectively. Yellow and gray streaks represent the sequence of target sands and shale barriers within the interval of interest. Green streaks indicate presence of limestone in certain regions. Purple streaks in the saturation plot indicate presence of oil. Figure 2-3(c) and Figure 2-5(c) depict the estimates of the in -situ minimum horizontal stress and the possible target zones, obtained from log data. The stress profiles shown in Figure 2-3(a) and Figure 2-5(a) are derived from the interpretation of the raw logs (Gamma Ray, Bulk Density and Sonic Velocity logs). These stress profiles and the accompanying mechanical properties are used throughout the report as the basis for the analysis. 4100 4195 4288 4383 4479 4575 a4672 E 4770 4868 4968 5069 5172 5276 5380 5483 5586 Saturation 0 0.2 0.4 0.6 0.8 1 4100 4195 4268 4383 4479 4575 4672 d 4770 4868 4968 5069 5172 5276 5380 5483 5586 LithologV 0 0.2 0.4 0.6 0.8 1 (a) Oil -Water saturation (b) Lithology colurnn Figure 2-2: Candidate Zone Y formation content Figure 2-2 and Figure 2-3 illustrate the first identified target zone is within the depth interval 4360 ft to 5200 ft TVD, with the best injection depth preferably at 5160 ft. Several factors combine to make Zone 1 a good candidate horizon for DCI, with the exception of the lowest 40 ft.: Low stresses within Zone 1 mean lower requirements for the initial injection pressure. Saving on both the surface facility and the tubing requirements. Lower initial stresses in comparison to confining shale layers ensure fracture containment. Higher permeability within Zone 1 allows higher leakoff rates causes the injection pressure to dissipate quickly after shut-in resulting in a decrease in the shut-in time required between batches. Higher permeability formations also tend to have relatively larger pore throats thus decreasing the plugging propensity by allowing smaller particles sizes to leakoff from the fracture with the injection slurry. However higher leakoff rates also lead to smaller fracture sizes, smaller batch sizes, and finally higher stress build up over the well life. This may eventually lead to greater horse power requirements. zar4 'WIRE,s< vuwwAduantel<Intern�tfon�lcpm 0 • • Several layers of shale formations above the intended injection horizon provide the presence of stress barriers. • Stress barriers act to contain fractures vertically by restricting height growth in the more competent rock. High stresses require greater injection pressure to penetrate through the barriers. ® Multiple permeable sand layers above the intended horizon provide permeability barriers. Permeability barriers act to arrest and/or slow down vertical growth by absorbing all the fluid from the fracture thereby reducing the amount of fluid available to propagate the fracture further. Zone 1 is within close proximity to the production horizon at 4100 ft. There may be a small possibility the propagating fracture due to DO could break through the shale barriers and reach that production horizon. Given this risk to the production horizon, a deeper zone, Zone 2 was selected as the primary injection target. Zone 2 is located directly below Zone 1 at a depth of 5480 ft to 6600 ft TVD, with the best injection depth preferably at 6400 ft. This zone is characterized by: s A more uniform stress variation along depth in the candidate interval. • Lower permeability than found in Zone 1. This would mitigate the high permeability issues that arose in Zone 1. Namely larger batch sizes can be targeted creating fewer batches and ultimately less stress increase. Shut-in time, on the other hand, would increase. This can be offset by designing larger batch sizes and allowing for fracture growth into RIII to bleed off the pressure during the shut-ins. • All the permeability and stress barriers available to Zone 1 would still be available to Zone 2 formation. Selecting Zone 2 as primary injection horizon could extend the disposal well life by having a second chance in case of plugging, as the lower annulus of the well could be sealed and the upper formation (the Triassic) would be a possible target horizon. Shallower zones above the production horizon were not considered for DCI disposal. Is ® No long-term waste disposal operations will occur in formations shallower than approximately 5,000 ft, referring back to the brief review of world-wide large waste disposal projects. Fracture is close to the permafrost layer and the surface. It is difficult to predict fracture behavior and may breach to surface. ® Presence of substantial oil content. This may become potential completion zones for future oil recovery plans. J.)VU 3. Ue.%31ICr 11U., 3UIIe LJ/ rlUU3LU/7, IA/IUO3 U3 VVVVVV.'UVO I ILCIUI I LCI I IOLIVI IO L LUF 11. ¢r • • • dvantek i��rr� �rorcnrvwrrowu (a) Gamma Ray & Bulk Density (c) minimum nonzontai stress, Pore Pressure & uverouroen Stress (a) rracture vrament Figure 2-3: Candidate Zone 1 log data & mechanical properties W-7�1 �www_Aejvantgklnternatign�l,com 4%NLV—�nr Saturation 0 0.2 0.1 0.6 0.8 1 5000 S102 5205 5309 5413 5515 5619 5724 A 5830 a 5938 6045 6152 6254 6353 2 6455 6558 6664 6769 6873 6979 DC' Ev--Av'a"Nop (a) Oil -Water Saturation (b) Lithology Column Figure 2-4. Candidate Zone 2 formation content 3300 S. Gessner Rd., Suite 257 Houston, TX 77063 US www.Advantel(international.com �14�rrIl q0;)P' 0 • • 0 lr� u dv�ntek INTCf :Ail O:Ul ka) L3amma Kay & WK uenslty Pois4ion's Ratio 0.1 0.2 0.3 0 4 5000 5200._— 5400 xw.ewlo. 5600 v -_'r-- 5300 6000 6400 �. 61100 srrl.s..lsr 7000 0.5 1 1.5 2 2.5 3 3.5 Young's Modulus, Stab,. 04psi) (b) Poisson's Ratio & Young's Modulus Fracture Gradient (psiift) 0.62 0.64 0.66 0.68 G.,• 0.72 5000 5400 5600 v 5600 6000 _ 6200 1 6400 M- 6600 6800 7 000 m"i=--- Figure 2-5: Candidate lone 2 log data & mechanical properties 3300 S. Gessner Rd., Suite 1$; f* iOori =17063 US www Ad_uc)nteklntLN ernationaLcom, 40dy ...�.,.. ivrecvnnovai Scope of Task 2; Fracture Geometry This task produced 3-D fracture geometries for evaluation and visualization of the maximum possible extent of the disposal domain. The generated fractures incorporated appropriate vertical variations of offset well geo-mechanical properties. The simulator assumed batch slurry properties were clearly identified. Through the use of a state-of-the-art, fully/partially coupled fracture and reservoir simulator, sensitivity analyses were performed to determine the range of optimized batch injection parameters and maximum slurry volume injectable in order to maximize safe slurry containment. Batch injection sensitivity analyses have been carried out. Output data is provided to ENI in tabular and plot format. The following agreed deliverables are presented to ENI at the conclusion of this task: 3D (color) plots of the various fracture geometries for each sensitivity case. ® Formation minimum horizontal stress is plotted against the fracture visualization. ® Tables of all relevant data to justify and accompany the 3D fracture plots. • Slurry/filtrate invasion plot for each sensitivity analysis performed. • Plots of simulated Shut-in Pressure vs. time for the total number of batches that can be injected for the batch cases studied. • All graphical 3D color representation of fractures created by initial and final batches at the beginning and end of the project are plotted on a consistent scale. ® Horizontal stress showing contrasting properties of the in situ geology are plotted in a unified scale against each fracture plot. Fracture Simulation Overview Hydraulic fracturing simulations during drill cuttings slurry injection have been carried out using @FracTM to predict the maximum possible fracture dimension and to recommend injection parameters. @FracTM is a three- dimensional numerical hydraulic fracturing simulator specially developed for modeling waste disposal operations such as drill cuttings and produced water re -injection. @FracTm has been specifically tuned to soft formations allowing for both elastic and plastic fracture growth. The simulation incorporates changes in stresses due to thermal and poro-elastic effects. Most notably the simulation allows for the changes in stresses due to solid deposition inside the fracture. The code fully accounts for leakoff and Tip Screen Out effects. Solids are treated as a separate phase and are assumed to be retained within the fracture. Hence the concentration of solids within the fracture increases as leakoff from the fracture takes place. Injection fracture simulation was conducted for the two recommended drill cuttings disposal zones described in section 3.2 above. Injecting in Zone 2 would incorporate all the benefits of injecting into Zone 1 but would be situated an additional 1200 ft (2300 ft in total) below the production horizon. The selection of these zones is based primarily on the analysis of Well NIK1. Both zones existed in other wells and with similar characteristics as observed from the raw logs. Assurance and Fracture Containment The maximum theoretically possible fracture extent occurs when a single bi-winged fracture is assumed to accommodate ALL the injection slurry volume from one or all wells depending on the time between well drilling periods of the entire development. Figure 2-6 shows the drilling schedule and Table 2-1shows the estimated waste to be disposed. For the purposes of estimating the maximum possible fracture extents, continuous injection of 1 million barrels is assumed. This value is approximately four times the 223,000 bbis planned from the Nikaitchuq • • 0 • 0 4gVVantek uacrxnnorvni drilling program. The maximum possible fracture height can be estimated when no fracture containment is assumed and the maximum possible fracture length can be estimated when the fracture is contained within the disposal formation. Identifying the maximum possible fracture extent is a critical step in ensuring the safe containment of the disposed waste. This process quantifies the risks of intercepting near -by wells, faults and other hazards. Oliktgk Point Wells —Spy Island Wells 70000 60000 50000 40000 0000 J 20000 10000 0 - �- - T - —�- --- — -- T -- -- --� -- 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 Time (days) Figure 2-6: Drilling Schedule Table 2-1: 70 — — -- Estimated) injection parameters - Bulking Fai 28596 64253 2.9 2A 68630 154208 Total Cuttings [)ur� 5E? 1356 Number of Dispo,, 600 600 I =: 25: 5.1 5.3 (a) 600 bbis solids batch size (b) 1050 bbls solids batch size 3300 S. Gessner Rd., Suite 25i 171111 www Adva�teklnt�Inationdjl cqm • 4%Ardy rN�en�rnnoani Marim "m Possible 1Cont�7rilned Growth (Literal Ertent) '-NX WkailTvf,. ",, ai' h !•"00rl This simulation is intended to estimate the maximum fracture extent if the fracture was to remain contained within the injection horizon of Zone 1 and Zone 2. Figure 2-7 shows the fracture geometry after 1,000,000 bbls of slurry injection continuously. In this simulation the stress variations between the different lithologies are honored. The scenario assumes that all the injected waste is injected into a single fracture which would only be possible from a continuous injection process. Since the recommendation is for batch injection this scenario would be highly improbable. In a batch injection scenario multiple fractures would be created with each injected batch. These fractures are much smaller than those shown below. It is also important to note that the injection is considered without any solid retention within the fracture. As is addressed later in the report, solid retention within the fracture leads to fracture growth retardation and plugging. Both of which are not considered here thus the large fracture size. The volume was not completely contained within Zone 1 or in Zone 2, but the risks of penetration are lower with Zone 2 due to the larger proximity from the production horizon. Fractures were initiated at the bottom of the zone to increase the distance of the fracture from the production horizon. As illustrated below, the maximum possible fracture half length is 2500 ft for Zone 1 and less than 1300 ft for Zone 2. It is also significant to note that Zone 2 stress barriers were not sufficient to contain the fracture thus the fracture dimensions for with and without stress barriers were the same. -na - .031),^160imm51 hi Fl:crC VOI i" = 10114.07 312 ;IwTe;St 6500. Zone I maximum fracture length total disposal volume (a) Contained Fracture Geometry Zone 1 Inle;6¢•11'Wuax , 100C10218i2NtaneK) �000 r Zone 2 maximum fracture length total disposal volume (b) Fracture Geometry Zone 2 Figure 2-7: Fracture Geometry showing the maximum possible fracture length in a contained fracture after 1,000,000 bbls of waste slurry injection within a single bi-winged fracture • 1 40 INfCf NATIONAL .. ,. •.... .. Maximum Possible Unconiahia6 Growth (Veruicaan Exten'~ ) The maximum possible fracture height created during waste injection is when there is no stress barrier above the injection. Both the assumptions of continuous injection and no solid retention are carried over in this simulation. To increase the quality assurance of fracture containment, we assumed that there is no stress barrier above the disposal zone. This scenario would cause maximum possible breach of the upper barrier and/or the surface. Figure 2-8 shows the fracture geometry after 1,000,000 bbls of slurry injection continuously at a disposal rate of 20 bpm. The maximum possible fracture upward height for this scenario from Zone 1 is 2000 ft and 2500 ft from Zone 2. The extent of penetration past the production horizon for Zone 1 is greater due to the shallower injection depth. Geological boundary depths represent the formation tops and do not indicate here the presence of stress boundaries, which have been removed for the purposes of this simulation. i.-nth hG127G1i2rtin;' mlEa.4n volume = 1000263 3l"[,iCdrtels' 7�me - 5ei�ltv�?,e,.rs� Inl2clwn Volume i00v1:V 812 ,,Wi ilsj 30u0 30a 0 3300 c O _.ux 5b%0 .t u > U > i5CO 7 Zone 1 maximum g �j ��qq��gg y ap L �— I. e Z ■ aximu nt fracture tlei�llit o s�k;o fracture height ris�:a total cli��+��al c Lo total disposal volume volume (a) Contained Fracture Geometry Zone 1 (b) Fracture Geometry Zone 2 Figure 2-8: Fracture Geometry showing the maximum possible fracture height in an uncontained fracture when a uniform fracture gradient is used and a single bi-winged fracture is considered llr pficaatoutvs & M aai�iraun-k i xtz!"t tag Wen eci uv'g Zone 2 is recommended as the primary injection zone while Zone 1 is recommended as the backup zone. However, Zone 1 is close enough below the productive formation to generate a DO fracture that may grow to within the 500 It vertical exclusion zone of the productive formation. To mitigate this risk, it is recommended to select the location for the disposal well that ensures the well is down dip of the oil/water contact in the productive formation, so that transmitted wastes which may reach the productive formation will only encounter the water leg, not the oil leg of the field. 3300 5;.. h +" ' " w.ww�P�dvaIjjlilnre ratio a emr ��"�dvantek ' I.ttf 4P110:1P1 witch InJerrion Parameters Batch injection or periodic injection refers to the intermittent injection of approximately equal slurry volumes followed by a shut-in stage. The shut-in stage allows the created fracture to close as fluid leaks off into permeable formation layers, leaving solids trapped within the fracture as it closes. The fracture takes more time to close in shales than in sandstone formations, due to the low permeability of shale. Closure time also depends on the injected volume and solids' content of the slurry. Multiple fractures have been observed both in laboratory tests (Wilson et al, 2000 and Guo et al, 2000) and in field trials such as the Mounds Field Drill Cuttings Re -Injection experiments (Mounds AP Committee, 2000; Abou-Sayed and Guo, 2000). Beyond multiple fractures, the geometry of individual components can be complex for injection into soft sands. Fracture propagation does not appear to be planar. Short branches or sub -parallel fractures appear to form along the length of the main fracture. Batch injections promote additional propagation and deposition of slurry in the branched fractures. Disposal fractures during batch injections are smaller than in continuous injection because the lateral extent of the fracture is determined by the batch volume rather than by the total volume of waste injected. The total slurry volume is accommodated in the smaller, multiple fractures within a disposal domain. Periodic injection of small slurry volumes promotes the creation of smaller multiple fractures within the disposal domain because the fractures can "heal" during the shut-in phase. Injection into an interval with a healed fracture could either reopen the healed fracture or could create a completely new fracture in a slightly different orientation to the original fracture. Deposition of cuttings in a fracture system locally increases the minimum horizontal in situ stress, making the horizontal stresses more isotropic with the introduction of more cuttings. This idealized "ball of fractures" or "fan -shaped domain" of fractures develops (shown schematically in Figure 2-9), depending on the degree of initial anisotropy of the 2 horizontal stresses. Figure 2-9: Schematic of the Disposal Domain Concept 3300 S. Gessner Rd., Suite Z57 Houston, TX 77063 US www.Advariteldnternational.com • • IN fif NAT10 VAl Figure 2-10 shows the fracture geometry created with batch size of 1050 bbls with an injection rate of 5 bpm. The slurry is assumed to have a solid loading of 10% by volume with 5% of the solids remaining in the fracture and 5% leaking off with the injected fluid. The chosen injection rate for the simulations was based on several factors. First, from an assurance point of view simulating at higher rates gives larger fracture extent. This ensures that during the design and planning of the disposal process adequate tolerances are allowed for the distances to neighboring wells, faults, or other potential hazards. Second, the injection rate must be designed in such a way so as to prohibit tip screen out. Larger injection rates mean larger fracture volumes and larger fracture volumes that have a smaller propensity for screen out. Hence to increase the solid loading the injection rate must be increased. Larger rates are associated with larger horse power requirements and greater wellhead erosion. In order for the rate to be decreased the particles injected has to be ground finely enough so as to assure that a larger percentage of the solid volume escapes the fracture with the leaked -off fluids. Smaller batch sizes with smaller rates and higher concentrations may also be considered although such a scenario is not highly recommended since it will lead to larger injection pressure increases from one batch to the next. As more cuttings are injected into the formation, the fracture closure pressure increases. This increase of fracture closure pressure depends on batch size. Smaller batches create smaller fractures and thus larger fracture closure pressure increases for a given total cuttings volume. As illustrated in Figure 2-10, the fracture horizontal extent is 380 ft for the first injected 1050 bbls batch. Stress (psi) 2000 3000 4000 5000 6000 7000 8000 5800 t , i 5900 6000 6100 6200 6300 - 6400 6500 6600 6700 6800 J=EWtch 1 Time = 2202.6929;minsi InjectlonVolums = 10953.E135ibarrels; 5800 5900 ai j .a 6000 S 6100 m 6=00 Q i . M 6400 1: 6400 ` 6600 6E000 100 200 2.00 400 500 600 Fracture Length Iftl Figure 2-10: Fracture geometry during batch injection 3300 S. Gessner Rd., Suite 257 Houston;, X63 7,70US w,ww Advant�k,lnternational.com 11 • dvantek ..�.,.— IMt�N�Ti0Yl1l As injection continues the injection pressure increases and the fracture breaks out of the stress barrier into the over -burden as shown in Figure 2-12. Removal of the stress barriers above the target zone was simulated to study fracture containment, Figure 2-11 shows the sequence of the cases simulated for fracture containment and the removed stress barriers. The initial stress profile, denoted by "MHS", is derived from the log analysis. With the injection of each batch the stress profile is increased slightly within the injection layer, as defined by the shown stress profile, receiving the injection slurry. At some given time, the stress gradient within this layer approaches the stress gradient in the layer above it or below it. It is at this point that the fracture geometry is significantly altered by the injected slurry. Stress (psi) 2000 3000 4000 5000 6000 7000 8000 5800 1-- - 5900 —Batch 1 —Batch 2 —Final 6000 6100 6200 6300 n 0 6400 —� 6500 6600 6700 6800 Figure 2-11: Stress profile before and after the removal of various stress barriers As illustrated in Figure 2-10 through 2-12, the fracture is initially contained in the disposal zone because of the stress barriers above and below the disposal zone. As disposal operations continue, the fracture closure pressure in the disposal zone gradually increases. The injection pressure will increase with multiple batches to overcome the initial stress barrier. After this point, further injections will create larger fractures without the 300 �. Lessner Rd„ Suite 257 Houston, TX 77063 US www.Advantelclnternational.com • • • • dvantek IN(Cf NATIONAL stress barriers. Figure 2-12 shows the fracture geometry created with batch size of 1050 bbis solids after the fracture closure pressure increase overcomes the stress barrier. Stress (psi) 2000 3000 4000 5000 6000 7000 8000 5800 5900 - Batch 1 — Batch 2 6000 6100 6200 n 6300 0 6400 6500 6600 6700 6800 Time = 2'.35.6406omins, Injection Volume = I i I58.2754tbarrels, 5800 1diu:mitrcccldC 5900 ]5 6000 ] 35 J3 06200 o l0 u 6300 t 06400 , 6600 C 6700 68000 I too 1100 300 400 500 600 Fracture Length (ft) Figure 2-12: Fracture and stress profile after batch 2 T -- www.Adv�nteklntcrnatio77m, , F;Ficl�ors Weicting Say r_h Injection fracture Orients Lion Injection fracture orientation was estimated based on the regional faulting shown in Figure 2-17 and a wellbore stability analysis provided by ENI. These data indicate the dominant maximum horizontal stress direction is NW. Some local variation is expected to occur, with certain regions showing a NNE direction. Fracture propagation would preferentially occur along the direction of the maximum horizontal stress. The maximum horizontal direction appears to be perpendicular to the major faulting direction. This would indicate that the faulting system is likely a thrust fault. It would be prudent when planning the injection wells under this scenario to locate injector wells as far from fault as possible. Fractures would tend to move towards the fault and can lead to the slung escaping through the fault to the surface or to the other layers. f gv:W M. 24 Pmd .-PC lnjrc DE p.: )Pmducers-Plnpcbre 7F iMabmuln F1nrltorXal \Q., '¢ �) fires 9 FraCure R• Prupagatbn - _- l Direction a OA nand drainage Figure 2-17: Regional Depth and Fault Map for top of the Schrader Bluff formation and minimum horizontal stress direction based on provided wellbore stability analysis Shut — In Time And ®2eratRonel Procedure The batch process consists of intermittent injection of roughly the same volumes of slurry and shutting -in the well after each injection. This allows the disposal fracture to close onto the waste and to dissipate any build- up of pressure in the disposal formation. The larger the batch size, the bigger the disposal domain extent and that leads to more disposal capacity and bigger volume of cutting disposal in one well horizon. To create a compact disposal domain, the following design basis are critical during the periodic re -injection: maximum batch size, avoidance of screen -out, allowance of sufficient well shut-in time between batches so that the created fracture can "heal" completely before pumping the next slurry batch. Optimizing both batch size and shut-in time depend on the formation permeability and leak -off characteristics and the drilling waste volume generated. The maximum batch size is controlled by leak off and pumping rate and slurry solids concentration. Shut-in time varies with the injected batch volume. The larger the batch volume the longer the time the fracture will take to heal. The ratio of shut-in time to injection time at high rates is approximately 2 to 1. In other words, for every hour of injection two hours of shut-in time are required to dissipate the pressure build up. For injection at lower rates this ratio would decrease substantially. 3300 S. Gessnet Rd.,!Wte2ST Houston,TX 717063, US,, , www:AdvantekinternationaLcom • • • • • dV�nt�k Z> a Vsditka t 4i urernario�vni Pil6al b'ILP'OI?y '•dws'�a'r yESt F For formations with more shale content this ratio would increase further. Injection cycle time is sufficient for the fracture to heal and is therefore assumed to be the shut in time. . '®carte LSO_ i n The drill cuttings will be mixed with water to form injectable slurry. The slurry properties will change according to the water source, mixing ratio and the solid concentration in this slurry. Figure 2-18 shows the change of the slurry viscosity and density with the volumetric solid concentration. 1.8 1.6 1.4 m 1.2 Z 1 e 0.8 v W 0.6 0.4 0.2 0 0 10 20 30 40 50 Volumetric Solid Concentration Figure 2-18: Slurry Density vs. Volumetric Solids Concentration The viscosity model which is most applicable to drill cuttings slurry is the power law model. In the power law model the apparent viscosity of the slurry varies with the shear rate applied to the fluid. The first parameter is the flow behavior index (n') and the second parameter is the consistency index (k'). The two indices vary with the change in solid concentration within the slurry. This allows for the viscosity of the injected fluid to vary during the injection process within the fracture. As the concentration of solids increases in the fracture due to fluid leakoff the viscosity increases as well. This decreases the mobility of the slurry within the fracture and more accurately simulates the actual physical behavior. In general, the higher the viscosity, the wider and shorter the resulting fracture. High viscosity decreases the leakoff rate and at the same time makes the solid hard to deposit due to gravity. In addition, high viscosity slurry requires high injection pressure to make the fluid flow. 3300 S. Gessner Rd., Suite 257 Houston, TX 77063 US www Adv�intei(IntcrnationdLcom :7 %Adv_antek INTEfM�TIO CNI *Nihaitc..40f, !` Z1 E Figure 2-19 shows how the apparent viscosity changes with volumetric solid concentration. 180 160 140 a 120 100 80 I a 60 40 20 0 0% 10% 20% 30% 40% 50% Volumetric Solid Concentration (%) Figure 2-19: Apparent Viscosity versus Volumetric Solid Concentration 0 • • r-1 L_J DISVO5ai Domair, Figure 2-20 represents the fracture domain. This is the affected zone around the well and should be used to select the well location such that the affected zone does not intersect with neighboring wells. Typically, intersection of a disposal fracture with a cased and cemented section of a producing well should not pose a problem. The fracture will merely skirt the well and continue propagating in the direction of the maximum horizontal in situ stress. Similarly, intersecting an old (not live) disposal fracture while drilling a new well does not cause a drilling problem; at worst the fracture appears as a form of soft inclusion. Clearly, however, drilling into a fracture propagating from a nearby injection well can cause considerable problems. Although not a threat to well control, the well being drilled could take a pressure kick from the slurry -filled fracture and excess fluid returns may occur at surface. Remedial action may take several days of rig time. It is a good operational practice to monitor the annular and tubing pressures of all wells adjacent to the disposal well for any pressure increases throughout the re -injection operation. This can give an early indication of excessive fracture height growth or over -pressuring of an intermediate formation. Also potential over -pressurization of intermediate sands will occur if the disposal fracture intersects permeable sand intervals. Fluid Leak -off can over -pressurize such formations and may cause well control problems for future wells drilled through the formation. There is little risk of localized pressure build-up in sandstone formations that have good permeability and are thick and laterally extensive. N X M T 400 '\ I`200 -8 0 -400 -200 400 610 200 -400 -690 x axis (ft) Figure 2-20: Disposal domain ?s , ;3 i10S.t ieiS!te,; HOLL5tQa1X 77063 US www.Adv�ntel<Iptc,rnjti,on�l com • • dv�ntek hr ' ` 1r x0§<ix` a? i9 4�SKt 9n'C:'s"fSx53 'R`: r r Fr "rr�, MTCf7dAli0YAL ° ` •' ' Scope of Task 3: Surface Injection Pressure and Volume Plots The intent of this task was to correlate (plot) the calculated injection pressure vs. the optimized cumulative volume injected for each studied batch case. Surface pressure plots were based on simulator -generated Initial Fracture Closure Pressure and Net Pressure. The representation of these results will allow for the proper scoping of surface facilities, specifically pumps, in terms of pressure and hydraulic horse power (HHP) requirements. Injection Pressure ®derviemi The well head injection pressure may be estimated from the following equation: PWHIP — Pnet + Pdosure + Pf + PH Where: PWHIP Wellhead injection pressure (psi) P„et Net pressure within the fracture (psi) Pc, ... r. fracture closure pressure (psi) Pf Frictional pressure drop in the casing/tubing annulus (psi) PH Hydrostatic head at the injection zone (psi) Net pressure depends on the disposal zone, fracturing fluid characteristics, injection rate and fracture geometry. It can be determined from fracturing simulations or shut-in tests. Fracture c%sure pressure is the minimum pressure required to keep the fracture open. It can be estimated as the product of the fracture gradient and the true vertical depth at the injection center. The recommended disposal fracture initiation location is at a depth of 6400 ft MD/TVD (a vertical well is targeted for injection). The fracture closure pressure increases from the first to the last batch as the injection progresses as a result of two factors. The first is the solids deposition into the formation due to drill cuttings injected. The second is the formation pressurization due to large volumes of injected fluids. Fnctsona/ pressure drop in the tubing/casing annulus is estimated from the cutting slurry flow down a casing/tubing annulus or down the tubing. It is a function of fluid rheology, injection rate, injection cross -sectional area and measured depth (MD). The friction pressure drop over 6400 ft was calculated considering three scenarios a 4.5", 5.5", and 7" tubing that maybe required for higher injection rates. The three diameters cover the possible tubing size range. A more detailed assessment of the tubing size is addressed in Task 5. For a 4.5" tubing diameter and an injection rate of 5 bpm the frictional losses are estimated at 110 psi. For 5.5" tubing the frictional losses are estimated at 41 psi. Finally for a 10 psi loss is anticipated for a 7" tubing. Hydrostatic /lead is the effect of weight of the fluid inside the wellbore. It depends on the fluid density and the vertical distance from the injection zone to the wellhead. Stress Increase and Batch Injection Optimization The current section presents the results of modeling the pressure -time profile and its evolution during injection operations. The figures depict the impact of batch size, tubing dimensions and fracture geometry propagation in different layers on the injection pressure. • •0 v�ntek FDU h' WL 6R t5na Rii0 wrcrw.rwNni 10 Figure 3-1 shows the increase in the fracture closure pressure over time for two batch volumes of 600 bbis and 1050 bbls. The increase in stress is attributed to the solid deposition and the increase in pore pressure. The effect of solid deposition is usually more dominant than pore pressure build up. This is apparent from the difference between the two curves. For smaller batches the fracture geometry is smaller hence the solid disposal domain is smaller. This leads to higher stress build ups and greater stress increase in the long term. Therefore although the stress increases due to pore pressure build up is equivalent for both curves the increase in minimum in situ stress due to solid deposition is much greater for the smaller batch volume of 600 bbis. • • 8000 7000 a 5000 N 4000 0 = 3000 .92000 c 1000 — 600 bbis batch solids volume --1050 bbls batch solids volume 0 r -� — - 0 20 40 60 80 100 120 140 160 Thousands Solids Injection Volume (bbls) Figure 3-1: Minimum Horizontal Stress increase versus Injected Volume • • dvantek �.t INttftJATi O`!Al s'et?� n30n-ai�cE�a,,, The sensitivity of well head pressure and bottom hole pressure to tubing size were calculated for 4.5", 5.5" and 7" tubing. Figure 3-2 and Figure 3-3 below show the well head (WHIR) and bottom -hole (BHP) injection pressure increase over time, for the two batch sizes of 600 bbis or 1050 bbis per batch. The injection pressure reflects the increase in the minimum horizontal stress as well as the variations in the net pressure. This explains the rapid increase or decrease at certain points in time. As the fracture enters a softer (lower Young's Modulus) or harder (greater Young's Modulus) formation layer the net pressure adjusts accordingly. Net pressure is directly proportional to the Young's Modulus and inversely proportional to the fracture height. Figure 3-2 and Figure 3-3 also show the impact of the tubing size on the predicted wellhead and bottom -hole pressures. There was virtually no difference between using 4.5" and 5.5" tubing. Using the larger 7" tubing diameter in the well design reduces the frictional pressure drop slightly, thus decreasing the surface pump requirements. Note that the drop in the pressure corresponds to fracture height growth during the injection operation. --BHP—WHP4.5"—WHP5.5" —WHP7" 7000 6000 5000 10- 4000 a� L 3000 a 2000 1000 0 0 200 400 600 800 1000 1200 Time (day) Figure 3-2: Bottom -hole and Wellhead Pressure Increase versus Injected Volume considering three (3) varying tubing diameters for 600 bbis solids batch volume f , • 0 L71 0 4g4V IN1C_F��' 7000 6000 5000 .N a 4000 v U) 'n 3000 a 2000 1000 0 0 Lk"_" d �. w.veC- Few 1a �:im — BHP — WHP4.5" — WHP5.5" — WHPT e d<EChi Elty`. 200 400 600 800 1000 1200 Time (day) Figure 3-3: Bottom -hole And Wellhead Pressure Increase versus Injected Volume considering three varying tubing diameters for 1050 bbls solids batch volume • 44NLV irorerrrnw4 o�ne Table 3-1 shows a comparison between the two batch scenarios for three injection rates and three slurry concentrations. Under recommended grinding and/or sizing conditions for the cuttings (>300 microns), only half of this volume is expected to remain inside the fracture while the other half will leakoff from the fracture into the formation with the injected fluid. This would require grinding of the injected solids by the surface facility to limit the particle sizes injected such that they are, in the most part, small enough to pass through the pore throat of the intended injection formation. Table 3-1: Summary of the results and requirements for the surface equipment specification • . i • • um Horizontal Stress si 4.5 .e S.S ,e 7 .e 4.5" 7676649 4.ee m 7 re 6723 6723 6723 6151 9 Surface Pressure (psi)2088 Ltart 2073 2066 1940[2398 1840 2461 2146 2033 500 bbls urface Pressure (psi)4373 4358 4351 3396 3296 5277 4962 4849 PumpHHP 102 102 101 238 225 904 789 747 End PumpHHP 214 214 213 416 404 1940 1824 1782 Minimum Horizontal Stress (psi)6167 6167 6167 5756 5756 5109 5109 5109 Start Surface Pressure (psi)2089 2074 2067 2467 2367 2663 2349 2236 050 bbis End Surface Pressure si 3622 3607 3599 3001 2901 2742 1427 2314 tart Pum HHP 102 102 101 302 290 979 863 822 End PumpHHP 177 177 176 368 359 355 1008 892 851 • •I•••rye1Ir 5 bpm 600 bbis • rRK41179TIMMIA OStress Horizontal (psi 10% 1S% 20p/o 6151 6151 6151 al 6836 I/ 6836 t1q.5 6836 M".5 " 5 7Minimum 7r;17 75117 7517 tart Surface Pressure si 19401 1871 1840 1808 1591 1559 1487 1407 1373 End Surface Pressure (psi)3396 J326 3296 4054 3868 3835 4472 4392 4358, tart Purne HHP 238 229 225 222 195 191 182 172 168 End Pump HHP 416 403 404 500 474 470 548 538 534 1050 bbls Minimum Horizontal Stress(psi) 5756 5756 5756 6292 6292 6292 7383 7383 7383 Start Surface Pressure(psi) 2467 2398 2367 1946 1871 1838 1937 1574 1540 End Surface Pressure si 3001 2931 2901 3401 3326 3294 4672 4308 4274 Start Pum HHP 302 294 290 238 229 225 237 193 189 End Pump HHP 368, 359 155 417 408 404 1 572 528 524 Assuming the smallest tubing size of 4.5" is used, our analysis indicates that the minimum requirements for the slurry injection pump are to deliver a surface injection pressure of 3396 psi for a batch size of 600 bbis and a capacity of 416 HHP. It is recommended that the surface facility be rated at 4000 psi and the injection pumps should have a capacity of 500 alp • • I�\/clirltC-'�i :vmlta �.¢z:•; E tz•:p93i ) ' amr,:, INtc f NATlO VAl • For a batch size of 1050 bbls, the minimum requirements for the slurry injection pump are to deliver a surface injection pressure of 3001 psi and a capacity of 368 HHP. It is recommended that the surface facility he rated at a minimum of 3500 psi and the injection pumps should have a capacity of at least 400 HP Scope of Task 4: Sensitivity Studies The purpose of this task was to evaluate the injection batch size, rate, and solids loading on fracture spatial dimensions and overall well disposal capacity using the Advantek 3-D fracture model. Hydraulic fracturing simulations during drill cuttings slurry injection have been carried out using @FracT" to determine the influence of the varying batch parameters on the fracture geometry including containment. For two batch volumes (600 and 1050 bbls), we conducted sensitivity analyses on both batch injection rates (2, 5, and 15 bpm) and volumetric solid concentration (10%, 15% and 20%). Fractare scensitivitV to M jlecdDn kaze Injection rate variation has a major effect on the fracture geometry and on the solid distribution inside the fracture. For the study, we chose the base case to have a volumetric solid concentration of 10% (this is representative of the solids remaining in the fracture only). Three different injection rates of 2, 5, 15 bpm were considered. The resulting fracture geometries and solids distributions are shown in Figure 4-1, below. As can be seen, the fracture at low injection rates demonstrates poor solid distribution with the solids tending to settle to the bottom of the fracture as well as plugging. With higher injection rates (15 bpm) using the same solid concentration (10 %), the fracture shows a better solid distribution and less tip screen -out. This allows sustained fracture growth and injection of larger batch volumes. The plots below show the fracture geometry for the first injected batch during multiple batch injection and not the maximum fracture dimensions for comparison purposes. 6 �J�an va„niF = 1G^Y 191ab��zt.; AN ,00 •, lV0 - aG'C+J C ..VV t j •im(q H Fl aCnxu length (fl) 2 bpm Inec•11 .11�.. I.;M _ III;;,. ((;4R�Iyi.4li� In;:Ctl011V01'Jn>B+ 9i.m UzU6 Ur1Qli; ' r.FC+i 5 K ,fit •� ,�sc y ii•J hW3V - �'ft00 ... .... .. .. . Filcc L L I k4'Mh•x v a '. [q jy h�JQ I �6'00 7uivU l F F � �.SUU 4010 55'D GJV cY4V„ i l l t 5 bpm Fl act, i , lanryth {ft) 15 bpm Figure 4-1: Fracture profile for 1050 bbis solids batch size and 10% solid concentration 300 S Lessner Rd., Suite 257 Houston, TX 77063 US w.wv✓ Adyantelctnternation�l tom 0 .7 dv�ntek inncrynno^rnl Table 4-1 summarizes the fracture geometry sensitivity to injection rate. Higher injection rates will increase the fracture geometry (length specifically) i.e. creating larger fractures and disposal zones. It should also be mentioned that the fracture and height extents in the table are the maximum fracture and height extents for multiple batch injection and not for the first batch shown in Figure 4-1. Table 4-1: Fracture geometry variation with injection rate Injection ' • • '' n time (hrs) bpm 5G 5 bprn 20 1.5 bpm ycle Time (days) 2 2 2 inimum Horizontal Stress (psi) 672_.1 6151 6649" aximum Fracture Half -Length (ft) 335 372 390 ljection aximum Fracture Height (ft) 587 650 460 niection time (hrs) 87.5 35.0 11.7 ycle Time (days) 3 3 3 inimum Horizontal Stress (psi) 6167 5756 5109 aximum Fracture Half -Length (ft) 365 420 492 aximum Fracture Height (ft) 1 685 670 950 Firacture Sensit'ivitV to Solid (Corncentrzation The effects of varying the solid concentration on the fracture geometry and on containment are shown in Figure 4-2. A base injection rate of 5 bpm was studied using three different volumetric solid concentrations (10%, 15% and 20%). T I'I'-'I: _ -' rirc - •f'_- I;.L]Ilil: rr•n M,1:1 = It"_ ['°s...iT"1• •1?D TI'n: 11/ -.tT r.S� .11 :�["�Ml� 8:0I�GC'IN1. VI'1[ll�rl'.'ORi1'.f0' 5-ncn--�h_w;, Cil( _ 041DD - _ I i61Ce c U 6tee � 6L•ce Y b.0i =fec 61ev e+ce h a•.rz yaPe Frodlea length Lpl SOD !00 ib 6f[D0 10.1 00 d'9 400 '00 CA Frotllnn L;n(ih (it) Frachife Len!ph (ft) 10% solid concentration 15% solid concentration 20% solid concentration Figure 4-2: Fracture profile for 1050 bbis solids batch size and 5 bpm injection rate ��» •�• ��•«<�� .-1VuIwn, 1r /Ivo3 w www.Acivanteklnternational.com is • • 4%Adv .�-- INiEF7:Ai�U)J/1L The effect of solid concentration is significantly reflected in Table 4-2. A 20% concentration with a batch size of 1050 bbis is not achievable due to fracture tip screen out and eventual fracture and injector plugging. Hence at higher concentrations smaller batch sizes need to be planned. The recommendation here being to inject higher concentrations at larger batch sizes within this specific formation higher injection rates are required. It is also the recommendation that solids are well grinded such that the solid concentration left within the fracture is closer to 10% than to 20% thereby prohibiting fracture plugging. High injection rates coupled with the increased solid concentrations have a major effect on the fracture geometry. The high rate tends to carry the solid particles further towards the fracture tip. Furthermore, the fracture at high concentration will plug up (at the tip) and prevent any further length growth. Table 4-2: Fracture geometry variation with solid concentration • 5 bp1)'i 600 (ibis Injection time (hrs) 10% 150/6 20% =0 14 10 Cycle Time (days) 2 2 2 Minimum Horizontal Stress (psi) 611::1 6836* 7383* Maximum Fracture Half -Length (ft) 372 295 292 Maximum Fracture Height (ft) 650 650 555 1050 bbis Injection time (hrs) 35.0 23.3 17.5 Cycle Time (days) 3 3 3 Minimum Horizontal Stress (psi) 5756 6292 7S111 Maximum Fracture Half -Length (ft) 420 320 290 Maxiinum Fracture Height (ft) 670 710 575 *Final Value of Minimum In situ Stress is not viable; this case is therefore excluded as a practical option. The storage capacity of the well would be reached before the intended solid volume is disposed. Scope of Task 5. Disposal Well Design and Disposal Formation Preparation ke;coramerucle'd Disposal 14' efl Coh-uGw"Lwaltion Advantek International recommends the use of two dedicated disposal wells in the Nikaitchuq field. A dedicated disposal well offers considerable flexibility to tailor well design to meet the specific disposal objectives. The criteria used to select / design a dedicated disposal well were detailed by Abou-Sayed and Guo (2001)' in a recent DCRI JIP Best Practice Document. The best practice summary is outlined below: • Safe containment of drilling waste is always important. It is suggested that a number of fracture containment zones be identified during the planning stage to create an extra operations assurance factor. • The basic design for a dedicated injection well is a vertical well (if feasible) drilled through the target injection horizon which is a vertically and laterally extensive formation. This will reduce the drilling cost of the dedicated disposal well. • The well location and trajectory should be selected so as to avoid interference with potential future drilled wells or intervention operations. Hence deviated wells may be used some of the time to avoid risk of interference. 3300 5. Gessner Rd., Suite 257 Houston, TX 77063 US ww.w_Advanteklni rnation�l;com i • IMICfkATIOVAI • The well location should also be selected with consideration to minimize surface transport of drilling and other oilfield wastes. • The injection wellhead should also be specifically designed to minimize erosion from prolonged slurry injection. The installation of a crown plug on top of the wellhead is recommended for regular inspection and measurement of material reduction. • It is a good design to have a narrow, mono -bore injection string (or as close as possible to mono -bore) from the surface to the target disposal depth. The injection string should be sized to ensure a high slurry velocity while injecting. There should be a balance between the risk of solids settling from suspension due to large injection string and the risk of excessive erosion wear if the string is too small. • A good well configuration also helps maximizing the effectiveness of cleaning the completion using coiled tubing in the event of plugging of perforations. • There should preferably be at least two substantial cemented casing shoes barriers between the disposal location and surface, or any zone requiring isolation. Good casing cement practices are very important in DCRI well construction. • If necessary for monitoring containment of the injected waste, it is valuable to design the disposal well with an open surface annulus for pressure monitoring, although this flexibility may increase the cost of the well. Monitoring of surface annulus pressure may give an early indication of possible breach of the disposal fracture to shallow sediments. An ability to monitor its upward growth would be highly beneficial in this situation to ensure that the fracture does not breach to surface. • In a dedicated injection well, both casing and tubing annulus should be monitored. Even with a packer above the injection interval, monitoring should be performed. In addition, the tubing annulus should be shut-in at all times to prevent any upward displacement if the packer fails. The following list provides the recommended completion strategy: • Perforations should be at 8 — 12 shots/foot (-30 shots/meter) with 45o phasing. It is good practice to perforate only about 30 ft (-10 m) of the target zone selected for re -injection close to the base of the well, leaving a shallow rat hole of about 70 ft. This selection should provide sufficient open interval to accommodate waste injection at typical pump rates. The lower perforation section allows the operator to progressively re -perforate slightly shallower intervals if the original perforations should become plugged by solids and coiled tubing is ineffective in cleaning out the completion. Indeed, running through -tubing guns and re -perforating may be a more cost-effective alternative to attempting to clean out a blocked re -injection completion using coiled tubing. • It is recommended to use through -tubing guns with the biggest available shaped charges to give the largest perforations diameter possible with a reasonable perforation tunnel. This is standard practice for hydraulic fracture stimulation of cased and cemented wells to prevent solids bridging and plugging of perforation apertures in the casing string. • The packer should be rated to a differential pressure corresponding to the maximum predicted bottomhole injection pressure The main advantages of the proposed well design are: Ability to monitor annular pressure between the intermediate casing and the injection tubing, to detect signs of tubular failure resulting from excessive wear or packer failure. Risks of erosion failure are high if the diameter of injection tubing is smaller than 7 inch. 0 dvantek k� r. IMCFhAT10NAi - ,. °.u'•."_ .'JS F ..�ti Ability to monitor annular pressure at the open surface casing, to get an early indication of possible breach of the disposal fracture to shallow sediments. An ability to monitor its upward growth would be highly valuable in this situation to ensure that the fracture does not breach the surface. • Ability of running temperature and other logs for possible monitoring of fracture growth in the near -well region around the liner. Upward growth of the fracture can be monitored by a temperature log (or PNQ that rely upon injection of a dense tracer, such as borate, with the cuttings slurry. It is expected that in a vertical well the disposal fracture will propagate along the liner/casing and the injected waste will cool the formation close to the well. Erosion Wear Evaluation & Tubular Bursting Rate Wellhead and tubing erosion during prolonged slurry re -injection may affect the mechanical integrity of a disposal well. The relative magnitude of erosion effects depends principally on the oxygen content of the slurry make-up water and the lithology of cuttings in the pumped slurry. Two erosion models are used in the design here, The Statoil Erosion model and the BP RCS models. A brief description of the two models and their governing equations are outlined below. Statoi/recommends the following empirical relationship for assessing the maximum erosion wear (E, in mm) of carbon -steel during cutting slurry injection (see Sirevag and Bale, 1993)2: E=1.1x10-5xCxtxV2.1 Where: C is the API test sand concentration (% by volume), t is the injection time in hours, and V is the injection velocity in m/sec. The AT Mode/ for pipe erosion from sand production states that pipe erosion rate R in mm/year due to sand production can be estimated from the following equation: R = 4.1xMxQ2.5/d2 Where: M is the solid production rate in g/sec, Q is slurry velocity in m/sec, and d is the pipe internal diameter in mm. 0 • 45dvantek:anoua, uner> Table 5-1 shows the estimated tubing erosio considered tubing sizes, and several injectio between the two models. Both consider flow diameter and solids mass rate. Its values ar recommended for use in this case. n e Al Nb It , ..., arfl' Inn, n after injecting 1.5 MMbbls of slurry using both models, three rates and solid concentrations. There is a clear discrepancy velocity and injection time. The AT model also considers tubing larger than those for Statoil and are therefore safer and are Table 5-1: Predicted total erosion (4.5" Tubing OD) • Total Injection Volume (MM bbl) 2 hpm 7.0 1.5 1.5 1.5 5 hpm 4,S" 5 51 70' 15 bpm 4.5" I 5.51 i 7.0" 1.F 1.5 Total Erosion - Statoil Model (mm) 0.459 0.187 0.065 1.257 0.513 0.177 4.209 1.716 0.592 Total Erosion - 8P Model (mm) 0.148 0.n33 0.006 1.459 0.32? RO55 22.736 5.09E 0.1n5 • • • Total Injection Volume (MM bbl) 4 5" 10010 5.5" 7.0" 1 4.5" 150/0 5.5" 7.0" 4.5" 200ko 5.5" 7.0" 1.5 -- 1.5 1.5 1.0 Ln JL0 075 0.?5 0.?5 Total Erosion - Statoil Model (mm) 1.25 0.51 0.17 1.25 0.51 0.17 1.25 0.51 0.17 Total Erosion - SP Model (mm) 1.45 0.32 0.05 1.45 0.32 0.05 1.45 0.32 0.05 Based on this erosion evaluation, it appears that the tubing size should be larger than 178 mm (7 inch). However a tubing size of 4.5"is recommended due to its higher burst rating and cost. Slurry injection rate should be limited to 5 barrels per minute for a maximum solid concentration of 10%. These injection rates and maximum solid concentration values are recommended because they gave the optimum results for fracture geometry, minimal plugging, acceptable tubing erosion, and a satisfactory project time duration. i essf Practices for Ceraer Unq. and Perforating C--iaCaff`9Td2ii Best Practice: • A minimum of 500 ft distance between the top of the fracture and the top of cement (TOC) is required. • Another 500ft are required between the TOC to the bottom of the casing shoe. • If the TOC extends to the next shoe then the cement must extend another 500 ft above and outside of the shoe. Recommendation: There should preferably be at least two substantial cemented casing shoes barriers between the disposal location and surface, or any zone requiring isolation. Petfor tion,- A• Gvr.,,; Best Practice: • Perforations should be at 8 - 12 shots/foot with 45o phasing. e Perforate only about 30 ft of the target zone selected for re -injection close to the base of the well, • Leave a shallow rat hole of about 70 ft. This selection should provide sufficient open interval to accommodate waste injection at typical pump rates. 3300 S. Gessner Rd., Suite 257 Houston, TX 77063 US www.Advantekinternational.com • • The lower perforation section allows the operator to progressively re -perforate slightly shallower intervals if the original perforations should become plugged by solids and coiled tubing is ineffective in cleaning out the completion. Recommendations: • Use through -tubing guns with the biggest available shaped charges to give the largest perforations diameter possible with a reasonable perforation tunnel. • This is standard practice for hydraulic fracture stimulation of cased and cemented wells to prevent solids bridging and plugging of perforation apertures in the casing string. Scope of Task 6: Assessment OfEnvironmenta/ Risks Assessment of any potentially adverse environmental impact of a drill cuttings injection operation is an essential part of the DCI Assurance Process. Key considerations are: Possible breaching of shallow aquifers or the surface by the fracture. Possible channeling of cuttings slurry to surface through a poorly cemented casing annulus. Good quality cement bond isolation of the disposal zone is required from the disposal zone to an adequate safety margin above the anticipated top of the disposal fracture. Usually there must be at least one fully cemented casing string between the injection point and surface. Defining an exclusion zone around the injector well to prevent intersection of the disposal fracture with open annuli or active zones of adjacent wells. A "spider" plot of the location of adjacent wells across a horizontal plane at the injection horizon, together with the predicted size and direction of the fracture, will indicate likely intersection of other wells. Typically, intersection of a disposal fracture with a cased and cemented section of a producing well should not pose a problem. The fracture will merely skirt the well and continue propagating in the direction of the maximum horizontal in situ stress. Similarly, intersecting an old (not live) disposal -fracture whilst drilling a new well does not cause a drilling problem; at worst the fracture appears as a form of soft inclusion. Clearly, however, drilling into a fracture propagating from a nearby injection well can cause considerable problems. Although not a threat to well control, the well being drilled could take a pressure kick from the slurry -filled fracture and excess fluid returns may occur at surface. Remedial action may take several days of rig time. It is a good operational practice to monitor the annular and tubing pressures of all wells adjacent to the disposal well for any pressure increases throughout the re -injection operation. This can give an early indication of excessive fracture height growth or over -pressuring of an intermediate formation. • Potential over -pressurization of intermediate sands will occur if the disposal fracture intersects permeable sand intervals. Fluid Leak -off can over -pressurize such formations and may cause well control problems for future wells drilled through the formation. There is little risk of localized pressure build-up in sandstone formations that have good permeability and are thick and laterally extensive. 0 • 11 4%,kV- INf€ft:ATlOtl�l Scope of Task 7; Data Requirements for Monitoring R Assurance Plan ® Adopt an inclusive monitoring scheme o Daily/Hourly/Minute-by-minute sampling • Injection rate • Injected volume • Injection pressure (wellhead and/or bottom -hole) • Injection temperature (wellhead and/or bottom -hole) • Annulus pressure o Frequent sampling • Fluid viscosity • Fluid density • Solid concentration o Periodic testing (annual/semi-annual/quarterly) • Step Rate Tests • Pressure Fall -Off Tests • • iarcrranomn� Appendix A: Injection Test Pressure UWidential Information Injectivity Tc" s.t for IENI for use in DO Injector Test Introduction The present procedure outlines the steps of an injectivity test for the determination of formation leak -off and fracturing pressure in predominently Shale formations. Field Procedures The proposed injectivity test, sometimes referred to as a mini-frac test (MM, may consist of a three -step field procedure and special log runs. The logs (temperature and gamma ray) will be required before and after the field test, if injection is in a dedicated well, to. assess fluid leak -off characteristics, fracture height containment and injection pressures. However, these logs may not be possible, or practical if annular injection is planned. The three -step procedures are referred to as CST (Closure Stress Test), SRT (Step Rate Test) and FLT (Fluid Loss Test). The CSTand the SRTwould help in the determination of the closure stress (minimum in situ stress) within the disposal horizon. Downhole pressure monitoring, if feasible, is preferred for all tests. Low pumping rate is required for the CST. The SRTrequires injection at variable rates and the FLTwould take place at the designated disposal rate. If mechanical difficulty arises due to such requirements (such as lack of accurate control of constant, but low, rate injection) the CSTmay be performed within the pumping rate range of the available equipment on -site. Closure Stress Test, CST, Procedures for IForniation Break -Down • Pump a limited volume of fluid (seawater) at low rate (2-5 bpm). Care should be given to get rid of any gas trapped in the injection conduit (tubing or annulus). • Perform an instantaneous shut in (I51) and record the ISlpressure (ISIP) after end of pumping of 20-40 bbl of seawater at 2-5 bpm rate. Record the value of the ISIP. • Repeat above steps 2-3 two more times (if necessary). Wait between pumping steps for pressure to stabilize. Approximate wait time depends on injection formation but for sand it should be about 3 to 4 times the injection period. Shales may require more waiting time. • After shut down and until the pressure falls well below the closure stress estimated from the CST, pressure should be monitored continuously. Step -Bate Vest, SRT, Procedures The step rate test (5R7) is the most commonly used test for estimating injectivity and fracturing pressure in disposal operation. Here we will provide field procedures and operational steps. A more detailed discussion of the interpretation and methodology of that test is included in the next chapter. • Inject seawater at a constant low rate (0.5-.075 bpm) for several minutes • Monitor pressure until its level stabilizes • Quickly raise the injection rate to a higher level and continue pressure monitoring • Increase the injection rate in steps and repeat the above steps • Record injection rate and stabilized pressure at each step • Create a plot of injection rate vs stabilized pressure and use the attached procedures for interpretation �J Fluid Loss Test, lFLT, Procedures A more comprehensive test, the FLTrequires a larger pumped volume than the CST. An accurate estimate of the leak off coefficient of the formation requires injection of the actual drilling cuttings slurry. However, a less risky test can be carried out using viscofied seawater of wash water with equivalent viscosity to the planned cutting slurry. The simulated injected slurry, including loss additives, may then be used in the FLT. Results of this test are used to calculate a realistic value of the leak -off coefficient as well as the closure stress. The FLTtest procedures include: • Pump a total of 100-200 barrels of viscofied seawater or wash water into the disposal formation at a rate equivalent to pumping rate during actual disposal operation (generalyy 2-8 bpm, for Alwyn/Dunbar well at 5 bpm) • Downhole pressure should be monitored, whenever possible, during pumping • Instantaneously shut-in the well and start shut-in pressure recording • After shut down and until the pressure falls well below the closure stress estimated from the CST, pressure should be monitored continuously Logs and Monitoring The pressure decline (fall -off) curves during the shut -down portions of both CST and FLT are used to give a measurement of the closure stress along with calculating other fluid leak -off characteristics. To achieve both objectives, an estimate of created fracture height during injection would be required. Temperature logs and gammy ray logs (for depth verification) are needed before and after the test. The logs help estimate the cooled section of the formation where pumped fluid has penetrated. Field Procedures for the Tests • Rig up well and move surface equipment to site, (connections and pressure and rate monitoring devises) • Run gamma ray and temperature logs, as applicable Fill -up hole between TD and surface and ensure no gas is present in the column ® Run CST as described above: • Connect downhole or accurate surface pressure gage to readout and test • Connect low -rate pumps to tubing or annulus • Start pressure monitoring prior to pumping • Pump 20-50 bbl of gelled water at 5-10 BPM • Observe formation breakdown and continue injection afterward for 2-3 minutes before shuting-in well and monitor ISIP pressure • Repeat steps 4 and 5 for two to three more times and record the pressure -time data • Shut -down the CST test Resume pumping and conduct the SRT as per schedule below: • Pump 5 bbl gelled water or mud at 0.5 BPM • Pump 5 bbl gelled water or mud at 1 BPM • Pump 8 bbl gelled water or mud at 2 BPM • Pump 9 bbl gelled water or mud at 3 BPM ■ Pump 10 bbl gelled water or mud at 4 BPM • Pump 15 bbl gelled water or mud at 56PM • • l� • 4%A,dv • Choke down pump to reach total shut -down. Continuously monitor pressure for at least a time period 3 times the total injection period and/or until pressure -time curve shows a reverse in curvature of decline • Shut down the SRT test • Rig up for FLT • Run gamma ray and temperature logs, unless already done earlier • Connect injection pump to tubing or annulus • Circulate to fill simulated injection slurry (viscofied fluid) down to injection horizon • Run FLT test per steps outlined above • Re -test pressure gage • Pump 100-200 barrels of viscofied fluid or mud into disposal formation at 5 bpm injection rate and allow for wellbore storage volume and column compressibility • Instantaneously shut in the well • Continue to monitor the pressure fall off until pressure declines below the estimated closure stress from the above steps (CST and SRT) and shows a reverse in slope of decline • Continue to monitor the pressure at longer intervals for a periods equals at least three times the injection period • Shut down after the pressure stabilizes • Run gamma ray and temperature logs, if applicable and feasible • Rig off well and rig down surface equipment Please note that in general pressure recording should be at 1 reading/second and that a wait time of at least 1-2 hours should be observed between the last CSTand the SRTtests as well as between the SRTand the FLTtest Also note that the SRTstages may be used to fill the annulus or the tubing with the viscofied fluid or mud prior to the FLT(i.e„ run the SRTwith the viscofied fluid or mud). Guide/roes for Inject/an Testing Interpr+eetation An injectivity test, which consists of a combination of a step -rate portion and an injection period at a constant rate, is recommended prior to initiation of the drilling cuttings injection (DCI) operations. Injection is carried out at a number of rates below and above the fracturing pressure. At each rate injection continues until stabilization appears to occur. The test objective is to estimate the transition from matrix flow where the bulk of the fluid leaves the well in the radial direction to a fracture -dominated injection where the slurry travels along the fracture away from the wellbore before entering the formation. The pressure levels are plotted against the corresponding rates and the change in the slope of the plot defines the transition pressure. This allows for determination of the pressure range within which a hydraulic fracture occurs and/or when a pre-existing fracture opens/propagates. The fracturing pressure is inferred from a significant change in slope of the plot of pressure versus injection rate (e.g., Figure A-1). The step rate portion of the test may not be practical when DCI is planned in shale layers. The constant rate injection period is normally analyzed to determine the leak -off character of the disposal horizon and provide an estimate of the injection pressure that might need to be sustained throughout the initial part of the DCI operations. • • dvantek ---`inner,»nnoun� 1800 a 1600 v 1400 U g 1200 O a N 1000 3 C E 800 m N m 600 0_ m r 400 E m° 200 0 I� i I I � I I i i i I I� I I I I' 0 5 10 15 20 25 30 35 40 Injection Rate (MBWPD) Figure A-1: Step rate test on C7 Precautions for Step Rate Test Procedures • If possible, identify an initial guess of what the in -situ stresses are so that the step rate test can be appropriately designed. Be certain that there will be adequate data points before breakdown or reopening of the fracture. • Prepare a conversion table between surface and bottomhole injection pressure (estimate pipe friction). In addition to determining in -situ stress levels, this test can be useful for evaluating the accurate values of friction pressure drop. • Under certain, restricted circumstances onshore, dead string calibration for relating BHIP to WHIP may be possible if the backside has enough integrity. • If possible, obtain bottomhole pressure measurements but have continuous surface readout under all circumstances (what if some of the injection is on vacuum?). • Check and calibrate all rate meters prior to testing and ensure that the pressure gauges are calibrated and will accommodate the largest anticipated pressures. • Be certain there is enough injection fluid (water) on location and use uniform rates and time steps. Record pressure and time information throughout the test. • Ensure that there is sufficient pumps available to fracture the well initially. If breakdown is required, mud or cement pumps are often used. Assess what will happen during the fracturing operation from the test data. Can the injection interval accept the required rates? If not, out -of -zone fracture growth can occur. Ol • E E 444CLV- uurcrrwnowu o Each time step should be long enough to ensure pressure stabilization. Obviously, this may not always be practical. Shorter times may be used due to economic or operational limitations or longer times might be required to allow for thermal stabilization. At a minimum, consider these issues before the test. Attempt to obtain at least three readings above and three readings below the fracturing pressure. After the rate increasing segment, back down on the rates to assess if the cement has been damaged. Finish the test by injection for an extended period of time at a constant rate equivalent to the DCI planned rate. Compile all data to determine if there is a consistent relationship between apparent in -situ stress, reservoir pressure, injection pressure and pumping requirements. Where possible, combine falloff testing with the measurements. pittiaGGs to Avoid The signature on the pressure -rate curve can be anomalous if there are reservoir variations or if mechanical failure occurs during the testing. For example: Different fluid Goss. If the fracture grows out of zone into a different fluid loss regime, the slope of the post fracturing curve can vary and may not be constant. If step rate data from different tests are being compared, recognize that the slopes can be different if the slurry properties are different. This is shown in Figure A-2. Some people only show the fracturing behavior changing (not behavior during radial flow - matrix injection). Strictly, this is not true. Slight changes can also be seen in the portion of the curve before fracture opening/reopening. Recognize that slope changes can be associated with different slurry or mud/fluid characteristics. s 46 8 7 Bo tto 6 mh ole 5 Pr es sur 4 e 3 2 1 0 "False" Pressure Increasing viscosity or concentration (i.e. reduced fluid loss) Fracture Opening/Reopening ' _ Reservoir Pressure 0 2 4 6 S 10 12 Rate Figure A-2: A schematic variation of houv pressure profile can vary for different slurry charac`ceriAics s3crtr Rei« ,. d � 4h r1_" w;wvv A u n ek lni�erY a -io �I.caoi • 0 1 Different fracture geometry. As a note of caution, this behavior is contingent on a fracture that is contained within one zone. Much more complex behavior can occur if out -of -zone growth occurs. If the fracture grows out -of -zone dramatically, the excess pressure may decrease because of the growth more than the change in pressure due to friction in the fracture. A negative slope may appear in the post -fracturing regime. This is illustrated schematically in Figure A-3. Possibly different perforation friction in dedicated disposal wells. If at all possible, bottomhole pressures should be used. For example, in a layered situation, one zone may fracture and the conformance can be changed completely. Damaged cement bond. The inflection point can indicate failure of the cement sheath. It can be possible to diagnose this if rates are reduced during the test (step-down after the highest rate of injection). Injectivity will remain high (along the second slope) even at rates below the original inflection point. Packer bypass in dedicated disposal wells. Determining the potential for exceeding the differential pressure limits of isolation devices (if any) depends on the configuration. It may be possible to monitor backside pressure or have a bomb below the lower packer (if used in a straddle configuration). Open/ pre-existing fracture. Ideally, the pressure time plot for a step -rate test would look like that shown in Figure A-4. However, if there is a pre-existing fracture, it will always have conductivity, even at pressures below the reopening pressure. This is particularly true if it is self -propped (jammed open). Under these circumstances, inflection may not be seen or there may be a slight curvature followed by a straight line linear or bilinear flow regime. To detect linear and bilinear flow regimes, log -log pressure -time plotting may be helpful. Examples of behavior for a pre-existing, closed and a pre-existing, self -propped fracture are shown in Figure A-S and Figure A- 6. 8 "False" Pressure 7 6 4) �i 5 N m 4 E g 3 2 1 0 Thickening Slurry (i.e. reduced fluid loss) j Fracture Opening/Reopening I I Reservoir Pressure �>I I Contained Fracture Growth � I Slight Out -of -Zone Growth or Change in Conformance Significant Out -of - Zone Growth or Change in Conf orm arx 4 0 2 4 6 8 10 12 Rate Figure A-3: A schematic indicating how pressure and rate may be affected by out -of -zone growth is 3300 S. Gessner Rd., Suite 257 Houston, TX 77063 US www.Advantelclnternationaf.coff J L 0 • 7 6 5 w N a 4 a_ v E 3 0 0 ro 2 1 0 7 6 5 a N 4 a- d 0 L E 3 x m0 2 1 0 "False" Pressure - -- Fracture Opening/Reopening ILI' �2 Reservoir Pressure 0 2 4 6 8 10 12 Rate Figure A-4: An idealized, readily -interpretable Step -Rate Test "False" Pressure Open/Reopened " Fracture 77 Conductivity existing, Nominally Associated With Closed A Pre- Fracture r Reservoir Pressure 0 2 4 6 8 10 12 Rate Figure A-5: An idealization of a dosed (but still conductive) pre-existing hydraulic fracture 3300 S. Gessne► Rd., guril;tei tt3ftT 3 , www Adv,<rate°I<Iniern�Ugnal com dvantek IMifygTtONRI 7 6 5 o� 4 a a� 0 L E 3 0 19 0 m K 1 0 0 "False" Pressure A�t_ Fracture Open/Reopened - - conductivity existing, Self Associated With -Propped Fracture A Pre- �� Reservoir Pressure 2 4 6 8 10 12 Rate • Figure A-6: An idealization of a self -propped, pre-existing hydraulic fracture 0 Different Stress Levels. In comparing consecutive step -rate test programs, be certain that you are aware of any stress field alterations that have occurred due to poroelastic and/or thermoelastic effects. Measured differences can in fact be diagnostic of the stress changes associated with temperature fluctuations. There is a substantial amount. �-+�� •+• �.�»�� 1 u,. UILCZal rlUU]IOn, IA //U63 Ua www.Advantel(international.corn pxa��m�wm�� Appendix B: SPE Paper 72308 Abou'Sayed, A.S., and Quo, O, "Design Considerations in Drill Cuttings Re -Injection Through Downho|e Fracturing," paper SPE 72308 presented at the lAD[/89E Middle East Drilling Technology Conference in Bahrain, October 22-24,2UU1. 0 0 4%Ad _.....�- .� innearanov�i Appendix C: DCI Tasks & Deliverables DCI-Suecific Tasks Task 8: Identify potential injection zones and rank them based on injection capacity, waste containment assurance and operability • Identify and rank appropriate injection zones, highlighting potential limitations on DCI disposal posed by the specific formation characteristics • Identify candidate wells for annular or dedicated injection • Identify volume, trajectory and equipment limitations for injection option • Design disposal well requirements based on the field -specific data and DCI Best Practices Guidelines • Identify key containment characteristics required of the bounding formations, above and below injection Task 9: Design injection procedures for operation parameters and slurry properties • Construct a 3D fracture model to evaluate possible disposal extent, fracture geometry (fracture length, width and height) and disposal storage capacity under the two (2) potential disposal methods, at two (2) recommended well locations • Identify the potential for fracture generation in the desired injection zone under given stress, leak -off, flow -rate and other related parameters. The primary and secondary target zones for DCI will be modeled • Compare simulated fracture geometries to the local fault patterns and regional fracture orientations to determine potential fault/fracture interaction and to assess risk of injected material breaching to the surface Task 10: Assess surface/topside equipment requirements for DCI operations • Study well treating pressure and their impact on the mechanical integrity of the disposal wells • Identify equipment requirements, such as footprint, wellhead and casing rating and pump horsepower (in terms of pressure and erosion) Task 11: Provide well construction proposal (cementing and completion requirement for disposal well) Task 12: Conduct risk assessment • Generate a risk matrix for waste management and safety • Conduct hazards identification (HAZID) • Prepare hazardous protocol (HAZOP) Task 13: Propose DCI monitoring program for operation assurance and regulatory verification Task 14: Project updates, meetings (three (3) progress meetings and a final workshop in Houston) and reporting Deliverables • Final ranking for main injection targets and backup horizons • Recommended injection batch design (injection rate, solid concentration & batch volume) • Recommended disposal domain • Scenarios and maximum capacity • Identification of HAZID/HAZOP • Recommended operational procedures and monitoring program • Recommended facility requirements • Task completion technical memos (PPT format) • Two project review meetings with project team • Formal presentation of project findings during full -day instructional workshop • Final report consisting of an executive summary, findings, results and task completion technical memos • E 0 APPENDIX B SIMULATION OF SLURRY INJECTION REPORT BY ASRC ENERGY SERVICES FOR PIONEER'S OOOGURUK PROJECT • Simulation of Slurry Injection: Ooorguk Beaufort Sea Offshore Drilling Island Injection into Torok Sand Prepared for: PIONEER NATURAL RESOURCES ALASKA, INC. 700 G Street, Suite 600 Anchorage, Alaska 99501 0 Prepared by: ASRC Energy Services E&P Technology, Inc. C, AESET-07-R1 January 2007 0 TABLE OF CONTENTS I. Background...........................................................................................3 II. Matrix of Simulations............................................................................ 3 III. Results...............................................................................................5 Appendix A (Input Parameters)..................................................................... 10 Appendix B (Waste Stream)......................................................................... 23 AppendixC (Results)................................................................................... 26 • • • BACKGROUND Pioneer Natural Resources is considering injecting cuttings slurry into a dedicated disposal well in the Oooguruk Beaufort Sea Offshore development drilling island (Oooguruk Drill Site (ODS)). Hydraulic fracturing simulations were carried out using commercial and proven software (MFracTM) to assess the evolution of fractures associated with injection into this well. The location of the well is in State of Alaska waters approximately 6 miles offshore in the Beaufort Sea, near the mouth of the Colville River. "The Class I well is planned as a straight hole vertically below the island."' "Injection would be into the Torok Formation at approximately 5030 feet. There would be 48 development wells. The fluid would typically be well treatment and workover fluids and drill cuttings and mud. Minor amounts of non-exempt, non -hazardous liquids would be disposed of; mainly camp wastewater treatment plant effluent, camp gray water and the island sumps that catch storm water."' A MATRIX OF SIMULATIONS Appendix A summarizes the input material properties. A typical new well would provide between 12,000 and—15,100 bbl of slurry. Estimates are provided in Appendix B. 0 The variables adopted in the simulations were: Four completion schemes. Perforations are shown in Figure 1 and Table 1. They are based on the offset logs from Kalubik #1. A barefoot completion is planned. It would be possible to move uphole and complete with perforations in the upper part of the Torok if the barefoot section becomes filled with solids. The well is assumed to be straight hole. Table 1. Perforated and Barefoot Intervals Measured Zone Depth of Comments Depth of Perforations Perforations (feet TVD RKB) feet RKB 5009.5-5105.5 1 5009.5-5105.5 Perforations (Upper Torok Sand) 5164.5-5269 2 5164.5-5269 Barefoot (Lower Torok Sand) Initial simulations did not discriminate any preferential zone - i.e., it was considered that injection was into the entire Torok sequence, including the intermediate shale as illustrated on the following schematic. 1 Oooguruk development Project - No Underground Source of Drinking Water Ruling Request, August 8, 2006. 9 • Kalubik # 1 [50103201650000] Porosity (fractional) 0.00 0.25 0.50 0.75 4750 4850 4950 L 5050 5150 5250 �T ---- D PH I —NPHI -- Gamma 4750 Iff-Me 4950 0 L 5050 5150 5250 0 50 100 150 Gamma Ray (GAPI) A barefoot completion is currently planned. If the barefoot section fills with solids, options include cleanout and/or perforating uphole. Cases are run for various completion schemes. • 0 • Subsequent simulations looked at more specific injection situations. The four situations considered were as follows. 1. Injection into the entire Torok interval (open to injection from-5009.5 to -5269 ft through the perforations indicated in 2) to 4) below. 2. Injection into the Lower Torok sand (barefoot 5164.5-5269 ft) 3. Injection into the Upper Torok sand (perforated 5009.5-5105.5 ft) 4. Injection into the intermediate shale (5105.5 - 5154.5 ft). Three fluids were used in the simulations. These were neat produced water or seawater (no solids) at an estimated temperature of 70OF (at the sandface), a 9.5 ppg slurry [equivalent to a base fluid with approximately 1.5 ppa (pounds of proppant - solids - added)], and a 10.1 ppa slurry [equivalent to a base seawater fluid with approximately 2.4 ppa solids]. Power law rheologies for these fluids were specified and these are shown in Table 2. Table 2. Fluid Rheology Fluid n' K' (lbf-s"'/ft2) Weight (ppg) Specific Gravity Seawater/PW (base fluid) 1.0 1.313 x 10"5 8.66 1.04 9.5 ppg slurry 0.7 1.022 x 10-3 9.5 1.14 10.1 ppg slurry 0.7 7.156 x 10-3 1 10.1 1.21 Several schedules were adopted for assessing slurry injection. Various parametric simulations were run and key results are reported for the following scenarios. 1. Case 1 (Base Case): a. 1000 bbls of 9.5 ppg slurry with a spearhead and flush at 2.5 BPM. b. 2500 bbis of 9.5 ppg slurry with a spearhead and flush at 2.5 BPM. 2. Case 2: a. 1000 bbls of 9.5 ppg slurry with a spearhead and flush at 4 BPM. b. 2500 bbls of 9.5 ppg slurry with a spearhead and flush at 4 BPM. 3. Case 3: a. 1000 bbls of 10.1 ppg slurry with a spearhead and flush at 2.5 BPM. b. 2500 bbls of 10.1 ppg slurry with a spearhead and flush at 2.5 BPM. 4. Case 4: a. 1000 bbls of 10.1 ppg slurry with a spearhead and flush at 4 BPM. b. 2500 bbls of 10.1 ppg slurry with a spearhead and flush at 4 BPM. The methods for developing the input data are included in Appendix A. A RESULTS Results of the fracturing simulations are summarized in Table 3. Figures for the various cases are provided in Appendix C. Based on the results, the anticipated dimensions for a batch injection are shown in Table 4. 0 Table 3. Summary of Fracture Dimensions at the End of Injection Case Completion Zone Rate (BPM) Injection Fluid Total Volume ° (bbl Fracture Half- s Length (ft) Upper Heighe (ft) Lower Height' (tt) Maximum Wellbore Width (inches)e EO39 Net Pressure (psi) la All 2.5 9.5 ppg slurry 1,000 Upper 46 16 15 0.029 105 Shale 0 0 0 0.000 0 Lower 440 33 55 0.103 156 lb Lower Lower 2.5 9.5 ppg slurry 1,000 453 33 55 0.104 158 lc Upper Upper 2.5 9.5 ppg slurry 1,000 374 86 33 0.088 126 ld Shale Shale 2.5 9.5 ppg slurry 1,000 348 112 17 0.067 70 le All 2.5 9.5 ppg slurry 2,500 Upper 103 21 21 0.040 117 Shale 0 0 0 0.000 0 Lower 650 34 56 0.114 168 if Lower Lower 2.5 9.5 ppg slurry 2,500 688 34 56 0.117 172 lg Upper Upper 2.5 9.5 ppg slurry 2,500 558 87 35 0.100 134 1h Shale Shale 2.5 9.5 ppg slurry 2,500 529 113 17 0.076 78 2 This designates which zone is open. The upper zone would be perforated. The Lower Sand will tentatively be barefoot. Perforations are also potentially open in the shale (above the shoe and below the perforations in the Upper Sand). 3 Designates zone where fracture growth occurs. 4 Excluding displacement volume (spearhead and flush). 5 Fracture half-length is the length from the wellbore to the tip of one wing of an assumed symmetrical fracture (i.e., the modeling presumes that two identical fracture wings grow diagonally away from the wellbore in the direction of the maximum horizontal principal stress. 6 Designates the vertical upwards growth at the wellbore from the center of the specified zone. Designates the vertical downwards growth at the wellbore from the center of the specified zone. 8 Maximum wellbore width is the maximum fracture width at any position along the wellbore. 9 EOJ (end of job) implies after flush, at shut-in. Net pressure is the difference between the sandface injection pressure and the in -situ stress at the mid -depth of the completed zone. • • Case Completion z Zone 3 Rate (gPM) Injection Fluid Total Volume a (bbl) Fracture Half- Lengths 00 Upper Height6 (�) Lower Height 7 (�) Maximum Wellbore Width (inches)8 EO39 Net Pressure (psi) 2a All 4 9.5 ppg slurry 1,000 Upper 91 21 21 0.042 121 Shale 0 0 0 0.000 0 Lower 523 34 56 0.118 172 2b Lower Lower 4 9.5 ppg slurry 1,000 554 34 57 0.121 176 2c Upper Upper 4 9.5 ppg slurry 1,000 451 87 36 0.104 137 2d Shale Shale 4 9.5 ppg slurry 1,000 424 113 17 0.078 81 2e All 4 9.5 ppg slurry 2,500 Upper 152 23 22 0.051 135 Shale 0 0 0 0.000 0 Lower 782 35 58 0.132 187 2f Lower Lower 4 9.5 ppg slurry 2,500 836 35 58 0.136 192 2g Upper Upper 4 9.5 ppg slurry 2,500 681 88 38 0.118 147 2h Shale Shale 4 9.5 ppg slurry 2,500 626 117 18 0.088 88 3a All 2.5 10.1 ppg slurry 1,000 Upper 93 31 30 0.071 158 Shale 0 0 0 0.000 0 Lower 327 43 63 0.167 214 3b Lower Lower 2.5 10.1 ppg slurry 1,000 346 47 66 0.176 218 3c Upper Upper 2.5 10.1 ppg slurry 1,000 320 94 40 0.152 170 3d Shale Shale 2.5 10.1 ppg slurry 1,000 304 119 19 0.112 112 3e All 2.5 10.1 ppg slurry 2,500 Upper 161 58 33 0.085 145 Shale 0 0 0 0.000 0 0 • Case Completion z Zone 3 Rate (BPM) Injection Fluid Total Volume 4 (bbl) Fracture Half- Lengths (ft) Upper Het) (� Lower Height (�) Maximum Wellbore Width (inches)8 EO39 Net Pressure (psi) Lower 405 49 72 0.165 201 3f Lower Lower 2.5 10.1 ppg slurry 2,500 481 52 73 0.198 226 3g Upper Upper 2.5 10.1 ppg slurry 2,500 476 96 41 0.174 183 3h Shale Shale 2.5 10.1 ppg slurry 2,500 449 120 24 0.132 126 4a All 4 10.1 ppg slurry 1,000 Lower 110 38 33 0.083 166 Shale 0 0 0 0.000 0 Lower 347 50 72 0.191 224 4b Lower Lower 4 10.1 ppg slurry 1,000 384 52 73 0.203 231 4c Upper Upper 4 10.1 ppg slurry 1,000 376 96 41 0.178 187 4d Shale Shale 4 10.1 ppg slurry 1,000 353 120 24 0.135 129 4e All 4 10.1 ppg slurry 2,500 Lower 293 89 39 0.130 157 Shale 0 0 0 0.000 0 Lower 349 50 72 0.180 215 4f Lower Lower 4 10.1 ppg slurry 2,500 531 62 73 0.228 239 4g Upper Upper 4 10.1 ppg slurry 2,500 565 98 43 0.204 203 4h Shale Shale 4 10.1 ppg slurry 1 2,500 980 1 128 97 1 0.258 128 • 9 • 0 Table 4. Average Fracture Dimensions (vary according to how the well is completed) • 0 Scenario Expected Volume Maximum Volume 1,000 bbl of Slurry 2500 bbl of Slurry Fracture Half -Length (ft) [approximate] 440 550-700 Fracture Total Height (up and down) (ft) [approximate] 120 130 Fracture Width [inches, approximate] 0.1 0.11 Fracture Half -Length (ft) [approximate] 550 700-830 Fracture Total Height (up and down) (ft) [approximate] 125 130 Fracture Width [inches, approximate] 0.12 0.14 Fracture Half -Length (ft) [approximate] 350 480 Fracture Total Height (up and down) (ft) [approximate] 100 160 Fracture Width [inches, approximate] 0.17 0.18 Fracture Half -Length (ft) [approximate] 380 570-980 Fracture Total Height (up and down) (ft) [approximate] 140 140-230 Fracture Width [inches, approximate] 0.2 0.22-0.24 L_J APPENDIX A INPUT PARAMETERS • • • • • A.1. Well Information: Currently considerations for completion are: "...the lower half of the zone being completed as open hole with the possibility of perforating the upper part as needed." io "The disposal well be a straight hole with casing set in the middle of the Torok with an open hole completion in the lower half. The upper part can be perforated if needed. Most probably the well will fill up with solids except for a short interval below the shoe and injection will be into the middle of the Torok. Tubing will be 4.5 inch so friction losses will be minimal." The completions considered are shown in Table A-1 and Figure A-1. Table A-1. Perforated and Openhole Sections Measured Depth of Zone Depth of Comments Perforations Perforations (feet RKB) (feet TVD RKB 5009.5-5105.5 1 5009.5-5105.5 Perforations 5164.5-5269 2 5164.5-5269 Barefoot Another situation considered was where the intermediate shale was perforated above the shoe and below the shots in the Upper Sand. A.2 Survey Information: The planned injector is straight hole. A.3 Stress Information Figure A-2 shows a type log (ARCO Kalubik #1). "The intended disposal zone ... is the Middle Cretaceous Albian-aged Torok Sand. The Torok was deposited within the Hue Shale as a deep water slope fan system. It consists of thin -bedded to laminated very fine to fine-grained sands ... between 200 and 300 feet in thickness."' "... the Torok dips regionally to the east and is somewhat broken up by small down -to -the -east normal faults."' Based on this alone, one would suspect that the minimum horizontal stress is directed normal to the faults. If a disposal domain develops it will be skewed in the direction normal to the minimum horizontal principal stress. is" E-mail personal communication from D. Andrews 0 Ol 0.00 4750 4850 4950 ►M C CL 5050 0 5150 5250 Kalubik #1 [50103201650000] Porosity (fractional) 0.25 0.50 0.75 — DPHI — NPHI —Gamma Ray Perforated if Needed Shoe —�C—rising Barefoot I -lit _Tz 4750 4850 4950 5050 0 5150 0 50 100 150 Gamma Ray (GAPI) 5250 Figure A-1. A barefoot completion is currently planned. If the barefoot section fills with solids, options include cleanout and/or perforating uphole. DSTs tested oil in the Torok in offset wells.' "The planned disposal well is downdip and/or fault separated from those wells [Arco Kalubik #2 and Texaco Colville Delta #3], with the wet Arco Kalubik #1 located between the updip Kalubik #2 and the downdip disposal location, directly beneath the development pad. DSTs and formation tests in the Pioneer Ivik #1, Arco Kalubik #1, and Texaco Colville Delta #2 proved to be water productive."' • • CJ • U 4900 4950 5000 5050 5100 5150 5200 0 5250 L a v 5300 0 5350 5400 5450 5500 5550 5300 J' — - 5600 -50 50 150 Gamma Ray (GAPI) Figure A-2. iNPHI and DPHI (calculated using a grain density of 2.68 gm/cm3) and gamma ray for Kalubik #1. A.4. Injection Volumes and Fluid Rheoiogy "The waste stream will be typical drilling slurry from 39f wells, disposed in batches, say f 1000 barrels each injected at 2-4 BPM as would likely happen in the field, with spearhead and flush."10 0 Kalubik #1 [50103201650000] Porosity (fractional) 0.00 0.25 0.50 0.75 1.00 4900 4950 5000 5050 0 5100 s L a v 0 5150 5200 5250 DPHI NPHI '- Perforations Gamma Ray 0 , 0 • "A big case would need to be looked at - volume to be up to 2,500 barrels. 10 Volume estimates are provided in Appendix B. From the available estimates, two different batch sizes were considered (1,000 and 2,500 bbl). A.S. Fluid Loss Properties The permeability was estimated using available core analysis data (Figure A-3) where the relationship with porosity is:" k (md) = q x 0.0014e42.5330 (fraction) The coefficient in the equation above was imposed so that the average permeability in the Upper and Lower Torok sands would be approximately 10 md.iz Uncorrected logging predictions using this formula underestimated the zone's anticipated permeability and this correction was required. Figure A-4 shows the inferred permeability. To be conservative, spurt loss (instantaneous loss in fluid when new fracture surface is created) was taken as being zero. The wall building fluid loss coefficient was estimated as follows (analog situations) C, = 0.00196loglok + 0.00004 ft/minute'/2 Fluid loss coefficients are shown in Figure A-5. A.6. Mechanical Properties and Stress Synthesis Laboratory values for Young's Modulus were available. The available data are shown in Figure A-6 and Table A-2. The laboratory data were used to calibrate the raw modulus predictions derived from compressional and shear wave slownesses (Figure A-7). Moduli were also estimated from inferences of the shear wave slowness (Figure A- 8). The correction from dynamic (logging) to static (for simulation) values was based on a crossplot of laboratory measurements (Figure A-9). Poisson's ratio is shown in Figure A-10. The stresses were then estimated using Poisson's ratio, bulk density, moduli and local information (values at Alpine) [refer to Figure A-11] 11 PowerPoint slides were provided by Pioneer Natural Resources --- Ooorguk Perm Data.PPT (November 14, 2006). 12 Teleconference with D. Andrews and K. Schmidt. 0 0 Table A-2. Laboratory Mechanical Properties Data Sample Grain Dynamic Static Dynamic Static , Permeability Porosity Density Modulus Modulus Poisson Poisson and % cm3 s s CONFIDENTIAL INFORMATION • Figure A-3. Permeability correlations based on laboratory testing. 0.1 4900 5( 52 5? Kalubik #1 [50103201650000] Permeability (md) 1 10 100 1000 10000 4900 ---- Permeability Gamma Ray —Perforations 00 00 --- -- J�E — - ---- 00 nn 0 75 Gamma Ray (GAPI) 5000 0 5100 L 0 5200 5300 150 Figure A-4. Permeability with a sandstone grain density of 2.68 g/cm3 and increased to give an average permeability of 10 and in the Upper and Lower Torok sands. • 0 0 10 0 • 0 Kaiubik #1 [50103201650000] Wall Building Fluid Loss Coefficient (ft/minutel/2 0.00001 0.0001 0.001 0.01 0.1 1 4900 5000 C� L IV 5100 s n v 5200 5300 Fluid Loss Coefficient Gamma Ray Perforations A. J Y 4 s� i a 0 75 Gamma Ray (GAPI) 4900 5000 c� G 5100 df n 5200 5300 150 Figure A-5. Wall building fluid loss coefficient with a sandstone grain density of 2.68 g/cm3 and increased to give an average permeability of 10 and in the Upper and Lower Torok sands. 1] • Plug I.D. in Report well AEPT-1 Texaco C.D. No. 2 AEPT-2 Texaco C.D. No. 2 AEPT-3 Texaco C.D. No. 2 AEPT-4 Texaco C.D. No. 2 AEPT-5 Texaco C.D. No. 3 AEPT-6 Texaco C.D. No. 3 AEPT-7 Texaco C.D. No. 2 Depth 6403.25' 64 0 3.7 5' '�'°� 6240.25' .�,w%j—. 6240.75' 5137.25' 7u,Lcrt 5137.75' 6301.00" Figure A-6. Young's modulus measurements had been made in the laboratory on the samples indicated here. Those values are summarized in Table A-2. 2.80 2.60 2.40 N a 0 2.20 2.00 0 E o, 1.80 c 0 0 U 1.60 17 1.40 1.20 Modulus Crossplot y = 0.8022x + 0.1157 RZ = 0.4548 •00, • • 1.00 1.00 1.20 1.40 1.60 1.80 2.00 2.20 2.40 2.60 2.80 3.00 Dynamic Young's Modulus (106 psi) Figure A-7. Correction of logging values of Young's modulus to their static equivalents (required for simulation). The raw logging values for Young's modulus were corrected to the required static values using the linear relationship shown here. • 0 • r� U • • 3500 3750 4000 4250 4500 4750 0 e 5000 a 5250 5500 5750 6000 6250 6500 Kalubik # 1 [50103201650000] 0 100 200 300 400 Gamma Ray (GAPI) Figure A-8. Compressional and shear wave slowness. Kalubik #1 [50103201650000] Young's Modulus (psi) 0.0E+00 2.0E+06 4.0E+06 6.0E+06 8.0E+06 1.0E+07 3500 3750 4000 4250 4500 4750 0 5000 0 5250 5500 5750 6000 6250 6500 I ' ' ' 6500 0 100 200 300 Gamma Ray (GAPI) Figure A-9. Young's modulus (calculated from the bulk density and the P- and S-wave slownesses, and calibrated using laboratory data). 3500 3750 4000 4250 4500 4750 , 0 5000 s n 5250 5500 5750 6000 6250 r 1 is 0 • • r� Kalubik #1 [50103201650000] Poisson's Ratio 0.00 0.20 0.40 0.60 0.80 1.00 3500 3750 4000 4250 4500 4750 0 E 5000 s n 5250 5500 5750 6000 6250 6500 — Poisson's ratio —Gamma Ray -200 -100 0 100 Gamma Ray (GAPI) Figure A-10. Poisson's ratio. 3500 3750 4000 4250 4500 4750 0 5000 t a 5250 5500 5750 6000 6250 6500 200 300 Kalubik #1 [50103201650000] Stress Gradient (psi/ft) 0.25 0.50 0.75 1.00 3500 — Vertical 3500 — Formation Pressure 3750 -- Horizontal 3750 —Gamma Ray 4000 4000 -- 4250 4250 4500 4500 4750 4750 - 0 0 Itf 5000 L 5000 s n 5250 - a 5250 or — 5500 5500 5750 5750 -- 6000 6000 - - 6250 6250 -- 6500 6500 0 100 200 300 400 Gamma Ray (GAPI) Figure A-11. Stresses and formation pressure gradients. The low value at about 5670 feet was adjusted to be similar to the adjacent zones (shown later). 0 • PJ r� APPENDIX B WASTE STREAM (After PNR, January 2006) • • The following is based on a Pioneer Natural Resources Alaska internal • document provided to develop input for the simulations. Forecasted Drilling Wastes Oooguruk Project (1-13-06) Forecasted drilling wastes are based on the 41 well directional development program provided by Sperry Sun (1-9-06) using the 12 1/4, 8 1/2, 6 1/8 bit schedule provided by Pioneer. The ... average development well will have the following profile. Surface Hole 12 1/4 3712 feet MD Int. Hole Length 81h 6980 feet MD Prod. Hole Length 6 1/4 6120 feet MD Average Well Length 16,812 feet MD Cumulative footage drilled on 41 wells 689,310 feet Borehole volume generated on wells (cuttings) 52,019 barrels • • Several cases were calculated to investigate the range of waste volumes that might have to be dealt with. • Waste volumes were investigated based on both general North Slope experience and on the very similar ongoing Alpine operations which includes recovery of oil base mud used in the production hole. • It is estimated that development drilling will generate the following volumes. The "cuttings" content in the expected case would be 10.2% of the total fluids injected (52,019/500,000). The rest of the barrels would be mud and dilution fluids used as carrier in the injected slurry; plus water to clean equipment and flush water to clear the wellbore. Some details are included in the following table. Total Drilling Mud/Cuttings/Slurry/Fluids Injected (Barrels) Avers a Well Total 41 Wells Expected Case 13,220 500,000 Minimum Case 12,000 450,000 Maximum Case 15,000 550,000 • If the bit/borehole/casing program changes, these numbers will need to be altered to fit the situation. • If the Torok disposal well has 580 barrels of borehole volume, and it is assumed 1160 barrels of mud/cuttings go directly to the pit (dry cuttings), • followed by1150 Bbls mud from surface tanks, (750 surface hole change - out and 400 during completion), and 300 Bbls cement/other, this generates 2600 barrels of storage that could be required before the disposal well can be used. • r� Expected Injection Well Disposal Case: Average Well Total41 Wells Slurry: (mud/cuttings/dilution for injection). Does not assume any surface gravel recovery. (Cuttings 14% of stream). Surface Hole 3000 Int Hole 4500 Prod Hole 1500 9000 —369,000 Well Flush Water/ -Rig Wash/Freeze Protection 3500 —103 000 Cement and Rinsates 120 N4 900 Completion Fluids etc. 600 —24 600 Totals 13,220 N500 000 Minimum Injection Case: 12 000 —450 000 Maximum Injection Cases: N 550,000 Notes: 1. The variation between cases is a function of dilution, well flushing, and freeze protection activities. 2. No recovery of surface gravel assumed. 3. Recovery of OBM in production hole assumed at 60% per MI Swaco. APPENDIX C RESULTS • • • • • 1] Stress Width Profiles ■0 S 20 ■ 40 60 80 90 -- 95 } 5190 5220 4� 5250 —�7 5290 01 Width Contours Width (in.) 0 _ -- 0.91 — _ _ �.___ __.__.�—. • _- —. ._ _. ___ t---- — — -- 0 02 _ ._.. 0.03 0.04 0 35 0.36 0.07 —.---•—_—•-- __ ___ .... ___..—_-—- 0.09 _ 0.1 3000 3500 4000 -0.1 0-- --— Stress (psi) Width (in.) Length (ft) Figure C-1. This is the inferred geometry after flush (displacement volume) at shut-in for Case 1a (2.5 BPM, 9.5 ppg slurry, 1,000 BBL, injection into all three zones (barefoot lower section, upper Torok sand, shale above the shoe). ctrAcc Width profiles Width Contours ao ®10 ■ +4 p co CI 80 010 093 ■ 99 i _... _..... �1 AAl A Al AAi $47 AAe is yl � Al All 50 stre55 (psi} width (in.) Length (ft) Figure C-2. This is the inferred geometry after flush (displacement volume) at shut-in for Case lb (2.5 BPM, 9.5 ppg slurry, 1,000 BBL, injection into all barefoot lower section, lower Torok sand). Stress Width Pro 1a& ;■ 0 ■ «o ■w ■ sA ■ 99 Width Contours 3® :I= ® .0.1 0 0.1 0 im 2M ID a Stress (Psi) Width (in.) Length (ft) Figure C-3. This is the inferred geometry after flush (displacement volume) at shut-in for Case 1c (2.5 BPM, 9.5 ppg slurry, 1,000 BBL, injection into upper Torok sand. Stress Width Profiles Width Contours Y.laagm ■0 ■ Io ■w pw C3 00 ■ 90 © 97 ■ 99 3w ® 4 Stress (psi) Width (in.) Length (ft) Figure C-4, This is the inferred geometry after flush (displacement volume) at shut-in for Case id (2.5 BPM, 9.5 ppg slurry, 1,000 BBL, injection into shale/silt above the shoe). • 0 1 9 1 • • 1 0 I * • a Q H Stress Tidth Profil( T�agm m sa to � e 99 3® M 1® -01 a 0.1 Width Contours Stress (psi) Width (m.) Length (ft) Figure C-5. This is the inferred geometry after flush (displacement volume) at shut-in for Case le (2.5 BPM, 9.5 ppg slurry, 2,500 BBL, injection into all three zones (barefoot lower section, upper Torok sand, shale above the shoe). Stress Width Profiles Width Contours Y. Lag® e0 e 10 e to t0 ® 90 ® 90 93 Y 99 u�as�my 8 OA1 dA2 IAS IAV A/7 J/9 q J /12 JIl 3M MM im -0.1 o 3.1 o an tm Stress (psi) Width (in.) Length (ft) Figure C-6. This is the inferred geometry after flush (displacement volume) at shut-in for Case if (2.5 BPM, 9.5 ppg slurry, 2,500 BBL, injection into all barefoot lower section, lower Torok sand). M Stress • ! Vidth Profiles Width Contours ram, ■ 20 ._ ■ 10 ® CO 30 90 93 ■ 99 iff FW-. m SM w Stress (psi) Width (in.) Length (ft) Figure C-7. This is the inferred geometry after flush (displacement volume) at shut-in for Case ig (2.5 BPM, 9.5 ppg slurry, 2,500 BBL, injection into upper Torok sand. Stress Width Profiles Width Contours LA 2M = J® 10M -0.1 0 0.1 0 m Jm Om 7m AID Stress (PSO Width (in.) Length (ft) Figure C-8. This is the inferred geometry after flush (displacement volume) at shut-in for Case 1h (2.5 BPM, 9.5 ppg slurry, 2,500 BBL, injection into shale/silt above the shoe). • 0 � 0 1 • • 1 0 1 0 1 0 Stress lidth Profil, -AM Width Contours 0 ----- - ----------- _.__..— ..._ ..._... 0A3 ._,...._.... iA1 A AS OA[ u7 to O A9 ,eu u3 >x An 213 m 1m sa Stress (psi) Width (u1.) Length (ft) Figure C-9. This is the inferred geometry after flush (displacement volume) at shut-in for Case 2a (4 BPM, 9.5 ppg slurry, 1,000 BBL, injection into all three zones (barefoot lower section, upper Torok sand, shale above the shoe). Stress Width Profiles Width Contours 3M 36M ® -0.1 0 a1 A O71 am ZIl Stress (psi) Width Cm.) Length (ft) Figure C-10. This is the inferred geometry after flush (displacement volume) at shut- in for Case 2b (4 BPM, 9.5 ppg slurry, 1,000 BBL, injection into all barefoot lower section, lower Torok sand). Stress Width Profiles Width Contours 31M 35M ® .0.1 0 0.1 Stress (psi) Width (in.) Length (ft) Figure C-11. This is the inferred geometry after flush (displacement volume) at shut- in for Case 2c (4 BPM, 9.5 ppg slurry, 1,000 BBL, injection into upper Torok sand. Stress Width Profiles Width Contours a 'II 25M J= ism t® -0 1 0 0.1 Stress (psi) Width (M.) Length (ft) Figure C-12. This is the inferred geometry after flush (displacement volume) at shut- in for Case 2d (4 BPM, 9.5 ppg slurry, 1,000 BBL, injection into shale/silt above the shoe). 0 0 � 0 1 1 0 1 0 Stress 0 Idth Prof 0 Width Contours uaa�(my / OA2 O US 0 04 ODS 7 007 A8 $09 O1 ._ Oil �'" 132 _______w_________ . _ __* ___ _--- __—.-_ 013 I30 L 3M am Stress (psi) Width (in.) Length ln) Figure C-13. This is the inferred geometry after flush (displacement volume) at shut- in for Case 2e (4 BPM, 9.5 ppg slurry, 2,500 BBL, injection into all three zones (barefoot lower section, upper Torok sand, shale above the shoe). Ctri>QQ Width Profiles Width Contours wiL&(:) a / Dt 0 AI IAS IAO - IA7 OA9 01 r 011 913 n ?m 1m ® 4 Stress (psi) Width (in.) Length (tt) Figure C-14. This is the inferred geometry after flush (displacement volume) at shut- in for Case 2f (4 BPM, 9.5 ppg slurry, 2,500 BBL, injection into all barefoot lower section, lower Torok sand). • • Stress 33M 35M i® -1 idth Profi ® /0 M. . 90 011 ,.:r.E.. Width Contours Stress (psi) Width (m.) Length (ft) Figure C-15. This is the inferred geometry after flush (displacement volume) at shut- in for Case 2g (4 BPM, 9.5 ppg slurry, 2,500 BBL, injection into upper Torok sand. Stress Width Prnfiles Width (7nntnnrs Y.InagA ®0 � 20 ® +0 El go ® ao ■ 90 a93 O➢ 0 OA2 OA{ eA� 0A8 el 011 O1� k�ele Stress (psi) Width (in.) Length (ft) Figure C-15. This is the inferred geometry after flush (displacement volume) at shut- in for Case 2h (4 BPM, 9.5 ppg slurry, 2,500 BBL, injection into shale/silt above the shoe). • 0 � 0 1 • `J • 0 Stress rdth Prot71f 3M ism 1® -02 0 02 1 Stress (psi) Width (n.) Length (ft) Figure C-17. This is the inferred geometry after flush (displacement volume) at shut- in for Case 3a (2.5 BPM, 10.1 ppg slurry, 1,000 BBL, injection into all three zones (barefoot lower section, upper Torok sand, shale above the shoe). Stress Width Profiles Width Contours Width Contours a® vm e a A: 09« O3T uc ela fm Zm ID Im vi®is) 0 ee :e ae eaa u „ e3T O1� O38 0 flu 2M an Stress (psi) Width (in.) Length (ft) Figure C-18. This is the inferred geometry after flush (displacement volume) at shut- in for Case 3b (2.5 BPM, 10.1 ppg slurry, 1,000 BBL, injection into all barefoot lower section, lower Torok sand). Stress a a F � Width Profi 0 Width Contours IM Stress (psi) Width (m.) Length (ft) Figure C-19. This is the inferred geometry after flush (displacement volume) at shut- in for Case 3c (2.5 BPM, 10.1 ppg slurry, 1,000 BBL, injection into upper Torok sand. Stress Width Profiles Width Cnntnrm vas(sy e 1 Ax eA� eAi eA8 I1 I1x Ilf � Ili 018 el Stress (psi) Width (m.) Length (ft) Figure C-20. This is the inferred geometry after flush (displacement volume) at shut- in for Case 3d (2.5 BPM, 10.1 ppg slurry, 1,000 BBL, injection into shale/silt above the shoe). 0 � 0 1 0 1 W] 1 0 1 0 Stress 2M Jon 13M 9 Vidth Prol 0 Width Contours WAS(-) 0 0 02 0 AV OOc 0A8 O1 012 O1V 018 e tm 3M IM m M Stress (psi) Width (in.) Length (ft) Figure C-21. This is the inferred geometry after flush (displacement volume) at shut- in for Case 3e (2.5 BPM, 10.1 ppg slurry, 2,500 BBL, injection into all three zones (barefoot lower section, upper Torok sand, shale above the shoe). Stress Width Profiles Width Contours Y. SsagA ■0 ® !0 ® 0 CO 90 93 Stress (psi) Width (in.) Length ln) Figure C-22. This is the inferred geometry after flush (displacement volume) at shut- in for Case 3f (2.5 BPM, 10.1 ppg slurry, 2,500 BBL, injection into all barefoot lower section, lower Torok sand). • • Stress 51al1 .__" 1 Vidth Protih 3ID 13M 11M �2 0 02 Width Contours Stress (psi) Width (in.) Length (ft) Figure C-23. This is the inferred geometry after flush (displacement volume) at shut- in for Case 3g (2 BPM, 10.1 ppg slurry, 2,500 BBL, injection into upper Torok sand. Stress Width Profiles Wirith f nntnnrs nw .� e® -0.1 0 0.1 Stress (psi) Width (in.) Length (ft) Figure C-24. This is the inferred geometry after flush (displacement volume) at shut- in for Case 3h (2.5 BPM, 10.1 ppg slurry, 2,500 BBL, injection into shale/silt above the shoe). • • 0 • • � 9 I * 1 0 Stress lidth Profit Width Contours waA,(aj a eA2 e oe OAS . ..... _......._. .............. ......__. .._ ...___...._. .. .._..._. .,. AA8 012 u� olA es Stress (psi) Width (m.) Length (ft) Figure C-25. This is the inferred geometry after flush (displacement volume) at shut- in for Case 4a (4 BPM, 10.1 ppg slurry, 1,000 BBL, injection into all three zones (barefoot lower section, upper Torok sand, shale above the shoe). Stress Width Profiles Width C ontntm Y. LagA .0 � 20 0,0 ■ 80 �90 .... _._... _....... 97 � 9➢ Stress (psi) Width (in.) Length (ft) Figure C-26. This is the inferred geometry after flush (displacement volume) at shut- in for Case 4b (4 BPM, 10.1 ppg slurry, 1,000 BBL, injection into all barefoot lower section, lower Torok sand). im Stress • Width Pro. .row - ■9 ■ 20 ■ ® to ■ 9� i�40 • Width Contours e e A� eAe el elt 014 O3L :SD J Stress (psi) Width (in.) Length (ft) Figure C-27. This is the inferred geometry after flush (displacement volume) at shut- in for Case 4c (4 BPM, 10.1 ppg slurry, 1,000 BBL, injection into upper Torok sand. Slresc Wirlth PrnfilpQ 1Ahrlth r nntAll— 2rM ZIM s® t J Wid9(a) 0 OA2 OA4 ODL OD8 el 012 814 OSL e18 al ] Im 2m MI Lm Stress (psi) Width (ul.) Length (ft) Figure C-28. This is the inferred geometry after flush (displacement volume) at shut- in for Case 4d (4 BPM, 10.1 ppg slurry, 1,000 BBL, injection into shale/silt above the shoe). �-M �10 • • Stress Width Profile Width Contours ..._.__..... ...... ..._ _. ..... ._.. _.,.. _... __. .. _. ___.._ . __.. _..._...._� m an an un Stress (psi) Width (in.) Length (ft) Figure C-29. This is the inferred geometry after flush (displacement volume) at shut- in for Case 4e (4 BPM, 10.1 ppg slurry, 2,500 BBL, injection into all three zones (barefoot lower section, upper Torok sand, shale above the shoe). arm Stress Width Profiles Width Contours Y. Lsgp ■/ ■ 18 $1 ■ 0 p CO ■ M ■ 98 s ■99 . .--�] AID M -02 0 R2 Stress (psi) width (m) Length (ft) Figure C-30. This is the inferred geometry after flush (displacement volume) at shut- in for Case 4f (4 BPM, 10.1 ppg slurry, 2,500 BBL, injection into all barefoot lower section, lower Torok sand). • Stress Width Pro4i � ■17 , m- a:A �30 ■ 90 ■ 99 aau .>ID 1® -02 ❑ 02 Width Contours a o02 OAS OAS OA8 O1 012 O1� Ili B18 B1 B12 NONE"- Afl 4n an Stress (psi) Width (in-) Length (ft) Figure C-31. This is the inferred geometry after flush (displacement volume) at shut- in for Case 4g (4 BPM, 10.1 ppg slurry, 2,500 BBL, injection into upper Torok sand. Stress Width Prnfiles ulirl4h r nntnnra 0 00) OAS O A9 012 $13 O18 011 B2r ore B7 033 ri aau J® 1® -02 0 02 Stress (psi) Width (in.) Length (ft) Figure C-32. This is the inferred geometry after flush (displacement volume) at shut- in for Case 4h (4 BPM, 10.1 ppg slurry, 2,500 BBL, injection into shale/silt above the shoe). • • •