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Home My WebLink AboutDIO 041DISPOSAL INJECTION ORDER NO. 41 Umiat Exploration National petroleum Reserve - Alaska Disposal Well: Umiat DSP-01 1. November 1, 2012 Link Energy Operations' Application for Disposal Injection for Disposal Well Umiat DSP-01 -------------------- Confidential emails held in secure storage 2. November 18, 2012 Notice of Public Hearing, Affidavit of Publication, Affidavit of Bulk Mailing and Email Distribution Lists 3.-------------------- Public emails re: Public Notice Umiat 4. December 18, 2012 Sign -in sheet, hearing transcript and presentation 5. January 16, 2013 AOGCC's email to Dave Whitacre re: Umiat DSP-01 (Class II disposal Well) DIO DISPOSAL INJECTION ORDER NO. 41 0 0 0 0 Wallace, Chris D (DOA) From: Wallace, Chris D (DOA) Sent: Wednesday, January 16, 2013 5:12 PM To: Dave Whitacre Cc: Stan Porhola (stan.porhola@lincenergy.com) Subject: Umiat DSP-01 (Class II disposal Well) DIO Dave, As may have been relayed to you already, AOGCC will evaluate the well information prior to making a decision on the DIO. The permit to drill will also spell out the required information, and the DIO will look for answers such as: 1. Information from gamma ray, resistivity, porosity, and mud logs to ensure that: the injection zone sands exist and they are porous; the injection zone sands are not faulted, do not contain commercial quantities of hydrocarbons, and do not contain formation waters having TDS concentrations less than 10,000 mg/I; and the upper and lower confinement zones are sufficiently continuous, thick, and impermeable. 2. Casing and cementing reports and the cement bond log to ensure well integrity. 3. An explanation as to how will Linc's proposal to dispose of crude oil complies with Alaska Statute Sec. 31.05.095, Waste prohibited. The BLM has been requesting information from the AOGCC relating to the Permit to Drill and the DIO application (Louis.niglio@bsee.eov) and so I trust you are keeping them informed. We are not discussing pending AOGCC orders with BLM. Thanks and Regards, Chris Wallace Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1250 (phone) (907) 276-7542 (fax) chris.wallace@alaska.sov 0 1 ALASKA OIL AND GAS CONSERVATION COMMISSION 2 Before Commissioners: Cathy Foerster, Chair 3 Daniel T. Seamount 4 John K. Norman 5 6 In the Matter of Linc Energy's ) 7 Request for a Disposal Injection ) 8 Order, Umiat DSP-01. ) 9 ) 10 Docket No.: DIO-12-003 11 ALASKA OIL and GAS CONSERVATION COMMISSION 12 Anchorage, Alaska 13 December 18, 2012 14 9:00 o'clock a.m. 15 VOLUME I 16 PUBLIC HEARING 17 BEFORE: Daniel T. Seamount, Commissioner 18 John K. Norman, Commissioner 1 TABLE OF CONTENTS 2 Opening remarks by Commissioner Seamount 03 3 Comments by Mr. Winslow 06 4 Comments by Mr. Porhola 34 01 1 P R O C E E D I N G S 2 (On record - 9:08 a.m.) 3 COMMISSIONER SEAMOUNT: I'd like to call this 4 hearing to order. Today is December 18th, 2012, it is 5 9:08 a.m. We're located at 333 West Seventh Avenue, 6 Anchorage, Alaska. This is the offices of the Alaska 7 Oil & Gas Conservation Commission. 8 I'd like to introduce the bench. To my right 9 is John Norman, Commissioner. I'm Dan Seamount, 10 Commissioner. Our Chair, Cathy Foerster's out of the 11 country right now, she's in Texas visiting her 94 year 12 old mother, but we do have enough for a quorum. 13 If anybody has any special needs please see our 14 Executive Secretary, Ms. Samantha Fisher, who's waving 15 right there in the front. 16 Computer Matrix will be recording the 17 proceedings. You can get a transcript of the 18 proceedings from R & R Court Reporting to my left. 19 These proceedings are being held in accordance 20 with 20 AAC 25.540, those are regulations governing 21 public hearings. 22 This hearing is regarding Docket No. DIO-12- 23 003, that is Linc Energy Operations, Incorporated has 24 applied for a disposal injection order for well Umiat 3 1 Alaska. The disposal injection order, if approved, 2 would authorize the injection of used drilling mud and 3 underground injection control program class II eligible 4 fluids into the Torok formation in the Umiat field 5 penetrated by the Umiat DSP-01. 6 The surface, injection and bottom hole 7 locations of the Umiat DSP-01 are as follows. The 8 surface is 839 feet from the south line, 1,189 feet 9 from the east line of Section 5, Township 1 South, 10 Range 1 West, Umiat Meridian. The top of the injection 11 interval is proposed to be 158 feet from the south 12 line, 768 feet from the east line of Section 5, 13 Township 1 South, Range 1 West, Umiat Meridian. And 14 the reason -- and I'll get to the reason why it's 15 proposed or postulated in a second. The bottom hole 16 location is 59 feet from the north line and 628 feet 17 from the east line of Section 8, Township 1 South, 18 Range 1 West, Umiat Meridian. 19 Notice of the hearing was published in the 20 Journal of Commerce November 18th, 2012, State of 21 Alaska online notices as well as the AOGCC website. 22 The AOGCC has not received any comments, 23 protests or questions for a public hearing at this time 24 except for one question about the presence of potable 25 water in the section. 4 1 The hearing record will be left -- will 2 probably be left open to allow Linc to respond to 3 questions from the AOGCC and possibly others at this 4 time. 5 The reason why I say that it's a proposed top 6 -- the location of the proposed top of the injection is 7 this is a strange application for us in that there's 8 been no application for a disposal well at this time 9 nor is there a disposal well that has been drilled at 10 this time. So we're sort of going in reverse order. 11 Normally there is a well that's drilled and the 12 application for the disposal injection well is -- the 13 disposal injection well exists at the time. So that 14 will be part of the discussion today. 15 This hearing will be recorded and we'll hear 16 from the applicant first. Let me look at the -- let's 17 see, we have looks like according to the sign in sheet 18 we have one person testifying and that is from Paul 19 Winslow at Linc Energy. Is there anyone else in the 20 audience that's planning to testify, if not then I 21 won't go through the process of explaining if there's 22 anyone from the public that has any questions or wants 23 to testify or make any other comments, but if someone 24 does show up then I will ask if this person does want 25 to testify. G 1 (No comments) 2 COMMISSIONER SEAMOUNT: So we'd like to remind 3 the person testifying to please speak clearly so that 4 the court reporter can hear you and make sure your 5 microphone's turned on so that we can get a clear 6 recording. 7 And will you be giving sworn testimony? 8 MR. WINSLOW: Yes, I will. 9 COMMISSIONER SEAMOUNT: So please raise your 10 right hand. 11 (Oath administered) 12 MR. WINSLOW: I do. 13 COMMISSIONER SEAMOUNT: And would you like to 14 be considered as an expert witness? 15 MR. WINSLOW: Yes, I would. 16 COMMISSIONER SEAMOUNT: And which discipline? 17 MR. WINSLOW: Reservoir Engineering. 18 COMMISSIONER SEAMOUNT: And please state your 19 qualifications. 20 MR. WINSLOW: My name's Paul Winslow. I've got 21 a bachelor and master's of science in petroleum 22 engineering from the Colorado School of Mines. I've 23 spent the last 25 plus years working in petroleum 24 engineering, the last 11 and a half years have been 25 here in Alaska working in Cook Inlet and this North 0 1 Slope project. I've worked overseas for four years, 2 worked Rocky Mountains, five, six, seven years, Gulf of 3 Mexico, all over the U.S. and Asia Pacific mostly as a 4 reservoir engineer. 5 COMMISSIONER SEAMOUNT: Commissioner Norman, do 6 you have any protests, comments, objections to Mr. 7 Winslow being considered as an expert witness? 8 COMMISSIONER NORMAN: I have no objection. 9 COMMISSIONER SEAMOUNT: And, Commissioner 10 Norman, do you have any comments before we proceed? 11 COMMISSIONER NORMAN: And no comments. 12 COMMISSIONER SEAMOUNT: Okay. I don't have any 13 objections either. You are -- Mr. Winslow, you are 14 considered as or designated as an expert witness. 15 Please proceed. 16 PAUL WINSLOW 17 previously sworn, called as a witness on behalf of Linc 18 Energy, stated as follows on: 19 DIRECT EXAMINATION 20 MR. WINSLOW: Okay. I'm going to go through a 21 fairly short presentation, just outlining this Umiat 22 project and the disposal injection order that we've 23 applied for. I will try and reference the slide 24 numbers, if I forget let me know. 25 The first slide is just an introduction slide, FI 1 this is for Umiat DSP-01, disposal injection order 2 application. 3 The application was submitted, slide 2, was 4 submitted November 1st, 2012. 5 Slide 3 is just a location map. Umiat field is 6 in the southeast corner of the National Petroleum 7 Reserve Alaska on the west side of the Colville River 8 roughly 88 miles west of the Trans Alaska Pipeline 9 System, Pump Station 2, 64 miles south/southwest of 10 Nuigsut, 86 miles north of Anaktuvuk Pass. 11 Slide 4, Umiat -- brief Umiat history. The 12 Umiat structure was first discovered or drilled by the 13 U.S. Navy in 1945. The Navy drilled 11 wells between 14 1945 and 1953. These 11 legacy wells produced oil via 15 rod pump at rates from zero up to 400 barrels per day. 16 This was from the upper and lower Grandstand 17 formations. There was also a twelfth well drilled by 18 Husky Oil in 1979, it was drilled for the U.S. Geologic 19 Survey. The Grandstand formations in the Seabee number 20 1 well were wet, the well did however test gas from 21 lower Torok sand and I'll get into that a little bit 22 more later. 23 Slide 5. This just shows a map of the field, 24 it shows in -- outlined in yellow are the two federal 25 leases that Linc Energy holds. The legacy wells are in Eta 1 purple. There's 11 original Navy wells plus the Seabee 2 well. The map also shows Umiat camp and the runway. 3 Slide 6 is a brief narrative of Linc's 4 exploration plans for this upcoming winter season. 5 Linc plans to drill four wells, the first one will be 6 the disposal well, DSP-01. Following that Linc plans 7 to drill a vertical shallow lower Grandstand well, the 8 Umiat number 16 well. Then the rig will be skid a 9 minimal distance, probably 10 to 15 feet and then we're 10 going to -- we plan to drill a horizontal well into the 11 lower Grandstand so that we can test the vertical and 12 horizontal wells back to back. And then finally we 13 plan to drill a deeper Torok exploration well, the 14 Umiat number 23. 15 Again I mentioned Linc plans to test the lower 16 Grandstand wells, the vertical and horizontal wells 17 back to back. If time allows and the logs indicate 18 potential pay in the lower Torok we may test the Umiat 19 number 23 well. Basically the goal of this exploration 20 season is to gain more information to try and make a 21 decision on whether we can develop this Umiat field. 22 So it's to gain new core, we're going to cut new core 23 data, gather fluid data, log data to supplement what 24 was gathered by the Navy in the 1940s and '50s. 25 Slide 7 again is a Umiat just field map. The 6 1 legacy wells are in yellow, they're a little bit hard 2 to see, but the things to point out, the disposal well 3 is on the same Seabee pad that the Seabee number 1 -- 4 the test well number 1 was drilled on. The exploration 5 wells, the number 16 and 16H are going to be from the 6 16 pad and then the deeper Torok will be from the 23 7 pad. We've also permitted a second well on the 23, 8 just depending what the results are on the 16 and we've 9 also permitted well pads for well number 18 and 19. 10 But again..... 11 COMMISSIONER NORMAN: Mr. Winslow, could I..... 12 MR. WINSLOW: Yes, Commissioner Norman. 13 COMMISSIONER NORMAN: .....if it won't break 14 your train of thought could you back up to 5 for just a 15 second and..... 16 MR. WINSLOW: 5? 17 COMMISSIONER NORMAN: Yes, uh-huh. So the 18 Seabee 1 is -- roughly equates with the proposed 19 location of the disposal well as I'm understanding? 20 MR. WINSLOW: Yes, sir. 21 COMMISSIONER NORMAN: Okay. Thank you. 22 MR. WINSLOW: The other thing to point out 23 here, again I mentioned the two federal leases, this 24 outline in gray is land owned by the Department of 25 Transportation and Public Facilities. I'll mention 10 1 that a little bit later, but it's land surrounding the 2 Umiat camp and the runway. 3 In the DIO application we're required to 4 identify and submit copies of the proposal to all the 5 land surface owners within a quarter mile of the 6 proposed disposal well. The only surface owner within 7 that quarter mile is the BLM. But again the Department 8 of Transportation and Public Facilities owns the land 9 around the Umiat camp and airport and surface location 10 there within 2,475 of the disposal well, proposed 11 disposal well. They were provided a copy of this 12 application. The only well within a quarter mile of 13 the proposed disposal well is the Seabee test well 14 number 1. 15 Slide number 9 goes through our selection of 16 the disposal interval. Number 1, the interval was 17 chosen because it was below the known oil reservoirs 18 which in the case of Linc's development plans are the 19 upper and lower Grandstand formation. So we definitely 20 wanted a disposal interval that was below the oil 21 reservoirs. We wanted a disposal zone that was below 22 freshwater aquifers, ideally it has formation water 23 salinities greater than 10,000 parts per million. We 24 picked this interval because it was above the Torok 25 sand that tested gas in the Seabee number 1 well. This 11 • 0 1 -- the disposal -- proposed disposal interval is 2 relatively low resistivity rock, 14 to 20 ohms, as 3 compared to the zone that flowed gas in the Seabee well 4 has about 35 ohms so it's quite a bit lower 5 resistivity. The neutron and density curves have 6 fairly consistent or constant separation between two 7 curves. A good indication if there's potential or gas 8 pay in he zone you would see the neutron and density 9 curves either coming together or in some cases crossing 10 over. The fact that they stay fairly constant 11 separation is a good indication that there's not gas 12 pay here. So fairly consistent background gas on the 13 mud log and no significant gas influx during drilling 14 as compared to that zone that flowed gas, they had a 15 lot of gas influx and had well control issues and had 16 to weight up from 10.1 pound per gallon mud up to 14.3. 17 This whole disposal interval there was no gas control, 18 no well control issues. 19 Slide number 10. The zone that was picked is a 20 relatively thick interval in the Seabee number 1 well, 21 you're looking at about 650 feet thick, it has several 22 higher porosity sands within the gross interval. 23 Relatively thick confining intervals both above and 24 below the disposal zone, it's about 600 foot confining 25 above and 350 foot below as seen in the Seabee number 1 12 1 well. Seismic data indicates good lateral continuity 2 of the disposal and confining zones across the Umiat 3 structure, also the seismic data does not show any 4 major faulting in close proximity to the proposed DSP- 5 01 wellbore at least at the disposal zone intervals. 6 COMMISSIONER NORMAN: Mr. Winslow, could you 7 address for me to what extent is the Seabee number 1 a 8 proxy for your proposed -- the wellbore trajectory for 9 the proposed disposal well? 10 MR. WINSLOW: Okay. The disposal well will be 11 drilled from the same pad so the surface location is 12 about the same. The bottom hole location at the 13 disposal zone depth is going to be about 1,000 feet 14 offset from the Seabee number 1 well drilled to the 15 southeast. It's going to come in about 95 feet lower, 16 our projected depth is about 95 feet lower than the 17 Seabee 1 well so it's down dip and offset by about 18 1,000 feet. 19 COMMISSIONER NORMAN: And the trajectory is a 20 curve in your..... 21 MR. WINSLOW: The Seabee number 1 well is 22 vertical, basically a straight hole so we're going to 23 be directionally drilling slightly to the southeast and 24 like I say at the disposal zone depth will be off about 25 1,000 foot lateral distance. 13 1 COMMISSIONER NORMAN: Thank you. 2 Slide number 11. This is the open hole logs 3 from the Seabee number 1 well. And I'm not going to 4 spend a lot of time on this, but the disposal zone is 5 outlined here between the yellow lines, there are a 6 couple of higher streaks, a little bit cleaner sands 7 and by looking at the gamma ray here this upper porous 8 sand, little bit cleaner sand here, we call this a 9 lower porous sand. And then the confining zones are at 10 the -- the top of the upper confining zone is this red 11 line at 31 -- at 3,550 and then the lower at 5,150, the 12 base of the lower confining interval. 13 Slide number 12 is just a comparison of depths 14 from the Seabee number -- tested well number 1 to 15 projected depths for our proposal well. When we met 16 with Commission staff early October, I think it was 17 October 2nd, our draft proposal had all the depths 18 based on the Seabee 1 well and they wanted to see 19 projected depths for the disposal well. So I put this 20 table in here. Biggest thing to note is our projected 21 depths are coming out about 95 feet as I mentioned, 95 22 feet lower than the Seabee test well. 23 Log number 13. The open hole logs that link 24 plans to run within the Umiat DSP-01 disposal well will 25 just be a quad combo, gamma ray, resistivity, neutron 14 1 density and sonic logs. The cased hole logs will be a 2 cement bond log run in the seven inch casing from plug 3 back total depth up to the casing shoe of the surface 4 casing which is planned to be about 1,700 feet. So 5 that's well above the confining and disposal zones. 6 Slide 14 shows the proposed casing program for 7 the disposal well. We'll have conductor casings set at 8 100 feet, a nine and five -eights surface casing set to 9 1,700 feet cemented to a surface, a seven inch 10 production casing set at -- plan set at 5,100 feet 11 measured depth which is 4,912 TVD and it'll be cemented 12 with two cements, a 15.8 tail cement and a 12.5 pound 13 per gallon lead cement with a projected top of cement 14 of 2,000 feet measured depth. Again we'll be well 15 above both the confining and disposal zones. The 16 proposed schematic is in the applications, it's figure 17 seven in the DIO application. 18 Slide 15. Anticipated injection pressures and 19 rates from the modeling that was done which I'll 20 discuss in later slides. All the modeling shows 21 anticipated injection pressures less than 2,500 psi. 22 Maximum injection rate for equipment limitations is 23 going to be six barrels per minutes. We actually 24 modeled -- did some modeling on two, four and six 25 barrels per minute, but we're looking at a maximum rate 15 1 of six barrels per minute and injection pressures of 2 less than 2,500 psi. The equipment limitation will be 3 5,000 psi injection pressure and again six barrels per 4 minutes injection rate. 5 Slide number 15, waste types and sources. 6 Class II fluids including, but not necessarily limited 7 to drilling, completion and workover fluids, cement 8 returns and rinsate, rig wash, tank bottoms, surface 9 well test equipment flush, flowline pigging waste, 10 formation fluids brought to the surface during drilling 11 and testing operations which will include crude oil, 12 produced water and formation sediments. There is a 13 more detailed list in the DIO application. 14 COMMISSIONER NORMAN: Could I ask on..... 15 MR. WINSLOW: Yes, sir. 16 COMMISSIONER NORMAN: .....the equipment 17 limitation, the 5,000 psi, what is it that sets that 18 limitation, is it integrity pipe or is it a compressor 19 or what is it that..... 20 MR. WINSLOW: I can guess, I could probably let 21 Stan answer that in more detail, he..... 22 COMMISSIONER NORMAN: It isn't a critical 23 question. 24 MR. WINSLOW: .....is a drilling engineer, but 25 it's piping and the pumping -- the pumps. 16 • 1 COMMISSIONER NORMAN: Okay. 2 MR. WINSLOW: Wellhead. Slide 17, waste 3 volumes. For the first exploration season this year, 4 2012, the winter 2012/2013, we're looking at up to 5 2,000 barrels of mineral oil based mud, 1,000 barrels 6 of used water based mud, 2,000 barrels of water/brine, 7 this is kind of a mix of snowmelt, your flush -- 8 flushes, rig wash, this is kind of a catch-all 2,000 9 barrels. And then up to 10,000 barrels of crude oil 10 from the production tests of the Umiat 16 and 16H 11 wells. 12 Anticipated volumes from the second season 13 which is the 2013/2014 winter season will be 5,000 14 barrels of used mineral oil base mud, 10,000 barrels of 15 slurrified cuttings, 4,000 barrels of water/brine 16 flushes and rigwash, whatnot. And then up to 20,000 17 barrels of crude oil from well tests. 18 I want to spend a little bit of time talking 19 about crude oil disposal, this is slide 19. I want to 20 emphasize that Linc Energy's preference and intention 21 is to reinject the produced oil back down the formation 22 from which it was produced which most likely will be 23 the lower Grandstand formation. There may however be 24 circumstances unique to this field which dictate the 25 disposal of the produced oil into the disposal well. 17 1 These may include number 1, severe formation 2 permeability damage due to reinjection of the oil at a 3 slightly higher temperature than reservoir temperature. 4 I want to make note that the upper Grandstand and a 5 portion of the lower Grandstand are within the 6 permafrost, the lower portion of the lower Grandstand 7 has a reservoir temperature of about 36 degrees. Stuff 8 within the Grandstand, upper Grandstand, will get as 9 low as like 25 degrees. Test oil at the surface at the 10 surface will be kept in heated tanks, but when we go to 11 reinject the temperature will probably be about 40 12 degrees. So physical limitations we can't get it down 13 to probably reservoir temperature so it'll be 14 reinjecting at slightly higher temperature than actual 15 reservoir temperature. This may cause problem. 16 Bullet point number 2. Batch reinjection may 17 create ice sheathes across the injection interval due 18 to the thawing and refreezing which could physically 19 prevent the reinjection of the oil into the reservoir. 20 Basically what this is is when you inject something at 21 a warmer temperature it's going to -- it could thaw the 22 reservoir and when you shutdown if that refreezes it 23 may block the permeability around the wellbore, 24 physically preventing you from injecting the next time 25 you go to reinject some oil. 18 • • 1 Slide 20, bullet point 3. Crude oil during -- 2 crude oil storage during testing operations will be 3 limited. As I had mentioned previously Linc plans to 4 test Umiat number 16 and the horizontal well Umiat 5 number 16H back to back. And the whole reason for 6 being out there this season is to get good data to try 7 and help us make a decision whether to develop this 8 field. So we want to get good test data, stabilized 9 rates, from both the vertical and horizontal wells for 10 comparison. Previously all the wells that have been 11 drilled have all been vertical wells. So development 12 will most likely be on a horizontal drilling basis so 13 we need good test data from these two wells for 14 comparison. Linc plans to have -- at the moment we 15 have plans for 31 storage tanks on location which 16 totals about 15,000 barrels of capacity. Anticipated 17 flow rates are four to 500 barrels per day from the 18 vertical well and we're thinking up to 1,500 barrels a 19 day from the horizontal well. Again we like to get -- 20 we would like to get stabilized rates so we're looking 21 at up to four or five day tests. If we do not have 22 stable tests and we're running out of storage, there 23 may be a need to reinject or to inject some of the oil, 24 dispose of it down the disposal well just to free up 25 tank space. Due to the remoteness of this location we 19 • • 1 can't, you know, last minute bring out more tanks. 2 Bullet point 4, reinjection of the oil will 3 have to be done after the conclusion of both well tests 4 because the two wells are basically side by side we 5 will not be able to inject into one while we're testing 6 the other well. That will severely compromise the test 7 data. 8 Bullet point 5. The winter exploration season 9 at Umiat is directly dependent on ambient temperature 10 and snow and ice conditions. If the ambient 11 temperature rises like it did this morning over a long 12 period of time it may force us to end the season and 13 pull out of Umiat earlier. If that's the case and we 14 have a bunch of oil on lease we need to be able to get 15 rid of it. Leaving crude oil, I made this final bullet 16 point there, that leaving crude oil in tanks at Umiat 17 until the following season is not an option, there's 18 too many environmental concerns and risks with leaving 19 oil out there. So we need to -- we have to have it off 20 the surface which will mean ideally again injecting it, 21 reinjecting it into the lower Grandstand, but if we 22 can't we need the option to be able to dispose of it in 23 the disposal well. 24 Slide 21, continuing with crude oil disposal. 25 Bullet point 6, injection rates down the disposal well 20 • • 1 likely will be significantly higher than reinjection 2 rates down the exploration well or may be. Again if we 3 are forced to reinject the oil in a hurry it may be -- 4 we may be better off doing it in the disposal well than 5 reinjecting in the Grandstand formation. 6 Bullet point 7. If and when we inject the -- 7 reinject the oil into the Grandstand formations we need 8 to be extremely careful in doing so. These are the 9 reservoirs that if development is done at Umiat it will 10 be to develop the Grandstand formations. We don't want 11 to be fracking them so we've got to be extremely 12 careful injecting to not -- you know, to not damage 13 that formation and not fracture it. 14 Final bullet point 8. The remoteness and 15 expense of transporting the oil to a sales point 16 prohibits the sale of produced oil. There's also a 17 sizeable amount of risk, environmental risk involved 18 with transporting the oil. Again we're about -- 19 Umiat's about 88 miles west of the Haul Road and the -- 20 you know, the TAPS, plus it would have to be hauled up 21 to the North Slope to a refinery. 22 Linc has had discussions with potential 23 purchasers, but again due to the relatively small 24 volumes of oil we're looking at and the extremely high 25 transportation costs we have not been able to come to 21 1 any kind of agreement for purchase of this oil. Linc 2 has also considered donating the oil to various native 3 regional or village corporations, but again the small 4 oil -- small volumes of oil, the remoteness, the high 5 transportation costs and the environmental risk 6 precluded this option. 7 Just a couple things to point out. Steiger 8 loads, if we to transport the oil to the Haul Road 9 Steiger loads would be limited to about 5,000 gallons 10 or roughly 120 barrels. Ten thousand barrels would 11 equate to 80 plus loads. Each Steiger load would take 12 36 plus hours just to get from Umiat to Pump Station 2, 13 not to mention transporting it to the North Slope to a 14 refinery. 15 Slide 22, waste confinements. From a geologic 16 standpoint again I mentioned previously that in the 17 Seabee number 1 well this disposal interval is 18 relatively thick, it's about 650 feet thick and has 19 relatively thick confining zones both above and below. 20 Again the seismic data shows lateral continuity across 21 the Umiat structure and also the seismic data does not 22 show any significant faulting in the proximity of the 23 disposal well. 24 From a fracture modeling analysis standpoint a 25 reservoir fracture model was built using the program 22 1 FracproPT, which used rock properties that were 2 calculated from the electric logs in the Seabee number 3 1 well. 4 Numerous -- excuse me, slide 23. Numerous 5 cases were run, simulating fracture heights, widths and 6 lengths while varying injection rates from two to six 7 barrels per minute. Injection volumes, batch volumes 8 up to 1,000 barrels, fluids, slurry weights from seven 9 pounds per gallon crude oil up to 10 pound per gallon 10 mineral oil based mud with and without cuttings. Four 11 different perforation scenarios were run, the first one 12 perforating the top 20 feet of the disposal zone, the 13 second scenario the top 20 feet of the upper porous 14 sand, the third scenario is perforating the bottom 20 15 feet of the lower porous sand and finally the fourth 16 scenario perforating the bottom 20 feet of the disposal 17 zone. All cases run show containment of the fluid -- 18 of the disposal fluids and cuttings within the disposal 19 and confining zones, even the extreme cases which would 20 be case one and case four above do not show any growth 21 of the fractures outside of the containment zones or 22 containing intervals. 23 Slide 24. Even though we modeled the extreme 24 cases Linc's plans are to perforate within the higher 25 porosity streaks so we do not plan to perforate either 23 1 the very top of the disposal zone or the very base. 2 The second bullet point, if you look at 3 perforations within these porous -- these higher porous 4 streaks, modeling shows fracture growth does not even 5 grow outside the disposal interval, it does not grow 6 into the confining intervals at all. 7 Slide 25. I put in a couple tables, this is 8 table four of the DIO. This is for -- if you look in 9 the upper left-hand corner this is for perforations in 10 the top of the upper porous sand so these are cases two 11 and three on a previous slide that I talked about. The 12 columns here, if you look at the fracture top over here 13 on the right, the proposed disposal interval is from 14 4,150 to 4,800 feet in the Seabee number 1 well. 15 Looking at these fracture tops for various slurries and 16 densities that we modeled, no where does it grow above 17 4,150 feet. So we're strictly contained within the 18 disposal interval. Also note again we modeled seven 19 pound per gallon crude oil, eight and a half pound per 20 gallon bring, nine and a half and 10 pound per gallon 21 mineral oil and water based mud and then also 10 pound 22 per gallon mineral oil and water based mud with 23 cuttings. 24 Slide 26 is the same thing, but for the 25 perforations at the base of the lower porous sand. 24 1 Again the disposal interval is from 4,150 to 4,800 and 2 if you look at the fracture growth, the base of the 3 fracture, fracture bottom, nowhere does it exceed 4 4,800. So again if Linc's plans are to perforate in 5 the better porosity streaks within the disposal 6 interval and fracture modeling does not show any growth 7 outside this disposal zone. 8 Slide 27, water salinity analysis. Our water 9 salinity analysis indicates that formation water 10 salinities across the entire disposal interval exceed 11 10,000 parts per million in order to get water 12 salinities below the 10,000 part per million threshold 13 you'd have to go above about 4,004 feet, that's looking 14 at our salinity analysis log which was included as 15 attachments or excuse me, it was -- yeah, attachment 5 16 in the DIO. The water salinities above this 4,004 TVD 17 depth appear to be below 10,000, everything below that 18 depth appears to be above 10,000 parts per million. So 19 again the entire disposal zone between 4,150 and 4,800 20 feet TVD in the Seabee number 1 wellbore appear to be 21 above 10,000 parts per million. As such, no aquifer 22 exemption is required. 23 The last bullet point on slide 27, there are no 24 water samples that have been gathered from the proposed 25 disposal zone in any of the legacy Umiat wells. 25 • • 1 Slide 28, a continuation of water salinity 2 analysis. First bullet point, there is however a water 3 sample that was collected from the Seabee test well 4 number 1 which shows a salinity of nearly 11,000 parts 5 per million. This water sample was gathered from the 6 zone that produced -- that flowed gas which is roughly 7 580 TVD below the base of the proposed disposal 8 interval. Again I mentioned earlier that when they 9 drilled this zone, when Husky drilled this zone, they 10 were taking gas kicks, they had well control issues, so 11 they weighted up from 10.1 to 14.3 pound per gallon. 12 Also note that this 14.3 pound per gallon mud was 13 freshwater mud with about 5,000 parts per million 14 chlorides. So getting a water sample from this 15 interval when it was drilled with a 14.3 pound per 16 gallon freshwater mud at 5,000 parts per million 17 chloride, a water sample of 11,000 was probably lower 18 than actual formation water salinity due to invasion 19 from the drilling muds. 20 Last bullet point, just as a comparison, the 21 salinity log calculation that we presented in the BIO 22 which is attachment 5 shows -- again shows water 23 salinities well above 10,000 parts per million across 24 the entire disposal interval. This lower Torok sand 25 that flowed gas, our calculations do show the salinity OU 1 dropping down to about 5,000 parts per million which is 2 indicative of the freshwater mud that was used to drill 3 that formation most likely was severe fluid invasion 4 from this overweight mud and also long exposure time to 5 this mud. The Seabee number 1 well was drilled down to 6 15,000 feet so they drilled an additional 10,000 feet 7 with this higher mud exposed to the formation. 8 Finally slide 29, DIO requires a wellbore or 9 mechanical integrity review of all wells within a 10 quarter mile radius of the proposed disposal well. The 11 only well within this quarter mile radius is the Seabee 12 test well number 1. Records indicate good mechanical 13 integrity. The well had 30 inch casing down to 115 14 feet cemented to surface, 20 inch casing also cemented 15 to surface, 13 and three -eighths casing to 3,983 feet 16 cemented to surface, production casing nine and five 17 eighths went down to 9,980 feet. The estimate top of 18 cement was 2,200 feet which is well above the -- both 19 the disposal and the confining zones. There was a 20 seven and five -eighths inch liner set from 9,601 to 21 12,814. This liner was cemented, but subsequently 22 squeezed off. Note that the Seabee 1 well has been 23 plugged back to 1,478 feet and is currently used by the 24 USGS as a temperature monitoring well. 25 And with that I'll leave it up to questions 27 • 1 from the Commissioners. 2 COMMISSIONER SEAMOUNT: Do you have any 3 questions, Commissioner Norman? 4 COMMISSIONER NORMAN: Well, I'll start out I 5 think with kind of a fundamental or an over -arching 6 question that Commissioner Seamount began with and to 7 the extent that you could address it I think it would 8 be helpful to us. Generally as Commissioner Seamount 9 indicated we do first get an application for permit to 10 drill and we have a well and then we're approached and 11 asked for a disposal injection order. So in this 12 instance we have somewhat the cart coming before the 13 horse and if you can it would be helpful if you could 14 address your reasons for approaching it this way? 15 MR. WINSLOW: Yes, sir. First of all we do 16 have a drill -- permit to drill that will probably be 17 submitted today or was submitted yesterday, excuse me. 18 We agree normally you do have the disposal well first 19 and then you apply for the application. Because of the 20 limited winter season at Umiat and the fact that we're 21 drilling -- plans to drill four wells back to back, 22 that kind of dictated why it was done this way. The 23 disposal well will be the first well drilled and then 24 we'll immediately move the rig to the number 16 25 location and start drilling the Grandstand wells. So I 28 1 agree with you normally it's done differently, due to 2 the circumstances of this field, the fact that it has 3 not been developed, hasn't been drilled since the 79 4 and there are no wells available for disposal, we will 5 be drilling that first and so we are kind of asking for 6 the disposal order ahead of time. Now having the 7 Seabee number l well there and the fact that we're 8 basically almost sidetracking it, I mean, it's a direct 9 offset to that well and we're only 1,000 feet from it. 10 We're not expecting any surprise as far as strata so 11 we're fairly confident in what we're going to find and 12 the fact that we're down dip of that well, again we're 13 not expecting any hydrocarbons surprises. If they do 14 that -- you know, it'll have to be addressed at that 15 point. 16 Does that answer your question, Commissioner 17 Norman? 18 COMMISSIONER NORMAN: It does. Thank you. 19 COMMISSIONER SEAMOUNT: You mentioned the 20 Seabee number 1 is a temperature monitoring well. Have 21 you seen any of the temperature data from this well? 22 MR. WINSLOW: I have not looked at it, I think 23 -- I know Stan has. 24 MR. PORHOLA: We only have data from the 1980s 25 that's public information and they did do some PA 1 temperature measurements this summer and they said that 2 they will not be released until probably March of next 3 year. 4 COMMISSIONER SEAMOUNT: But there are real data 5 from that well that..... 6 MR. PORHOLA: From the -- early 1982. 7 COMMISSIONER SEAMOUNT: Okay. We would really 8 like to see those data. 9 MR. PORHOLA: It's publicly available to you. 10 COMMISSIONER SEAMOUNT: Okay. Now as far as 11 the seismic data, have you shared the seismic data with 12 our staff between the Seabee well and the DSP number 1 13 well, your disposal well? 14 MR. WINSLOW: When we met with your staff early 15 October, I believe it was October 2nd, we brought our 16 geophysicist up, Wayne Wilson, up from Denver and we 17 did review the seismic data with the staff, with Jim 18 Regg, Steve Davies and Chris Wallace. If they have -- 19 certainly if they have more questions, they did have a 20 few questions which we tried to address in the DIO 21 application, you know, certainly if they or yourselves 22 have additional questions we'll probably have to get 23 back, that's not my field of expertise. But we did go 24 over the data and let them view the seismic data early 25 October. 30 • 0 1 COMMISSIONER SEAMOUNT: Okay. And these are 2 fairly shallow formations, I'm wondering if the data 3 are pretty high quality at those depths? 4 MR. WINSLOW: We had the 3D data reprocessed 5 this year and we're very pleased with the quality of 6 the data, the quality that the reprocessing made on the 7 data. 8 COMMISSIONER SEAMOUNT: And I did have a 9 question, you know, I -- a number of years ago I went 10 to see Congressman Young to complain about the legacy 11 wells and he got fairly upset with me, he said why do 12 you want to plug those wells, why can't you use them to 13 produce someday and he basically threw me out of his 14 office saying why do you want to plug a good well that 15 some day you could produce. And now -- so, you know, 16 one of the things I was thinking of well, why don't you 17 just use an existing well as a disposal well and I 18 guess you answered my question saying that none of 19 these wells are reusable; is that correct? 20 MR. WINSLOW: That's correct. 21 COMMISSIONER SEAMOUNT: Okay. 22 MR. WINSLOW: And Stan Porhola, our drilling 23 engineer, actually worked for the BLM and worked on 24 abandoning some of those wells. So if you have 25 specific questions he's probably a good source to ask 31 1 about that. 2 COMMISSIONER SEAMOUNT: Okay. And then you say 3 that any production you get is not economic and it may 4 not -- you may not even be able to give the oil away 5 and this is probably confidential information so you 6 don't have to answer my question, but why are you even 7 out there then, are you thinking that maybe you can 8 find something new? 9 MR. WINSLOW: Well, I mean, the Umiat structure 10 is a big structure and the volumes of oil that have 11 been calculated over the years are large so..... 12 COMMISSIONER SEAMOUNT: Okay. 13 MR. WINSLOW: .....it is an economic project, 14 but using steigers to haul the oil out when you're 15 looking at 36 plus hour round trip just to get to the 16 Haul Road and the cost of the steigers, the cost -- the 17 physical cost to take the oil is way more than what we 18 could sell the oil for, not to mention getting 19 contracts just to give the oil away, to put it into the 20 system. So and that doesn't address the economic or 21 the environmental risk of doing so. But if the 22 project, if the Umiat field is developed then a pipe 23 line will be put in and your transportation costs are 24 totally different, but it's physically -- because we're 25 going in on a snow road and so hauling the oil out in 32 1 120 barrel loads, the physical cost prohibits this from 2 being economic oil. 3 COMMISSIONER SEAMOUNT: Are there any -- I 4 mean, there are no existing boreholes out there right 5 now that you could use for disposal injection, are 6 there any existing boreholes out there that you could 7 use temporarily for annular disposal? 8 MR. WINSLOW: I don't believe so. 9 MR. PORHOLA: The only wellbores left that 10 haven't had a plug put in them are 1 and 11 and number 11 1 is five miles northwest, number 11 is two and a half 12 miles northeast. 13 COMMISSIONER SEAMOUNT: And could you identify 14 yourself, please. 15 MR. PORHOLA: Stan Porhola, drilling engineer 16 with Linc Energy. 17 COMMISSIONER SEAMOUNT: And you guys have 18 decided that that's not an option? 19 MR. WINSLOW: Slide number 5 is a well map. 20 Stan Porhola pointed out that the only wells available 21 would be the number 1 and the number 11 wells. Let me 22 go to slides -- yeah, this doesn't show it quite as 23 well. The number 11 well is up here. We're going to 24 have ice roads going from Umiat camp up to the number 25 16 and number 23 wells. So we will not have an ice 33 1 road that gets up to 11. So we physically can't even 2 get there. The number 1 well is off this map, it's way 3 to the west. So we physically can't even get to those 4 wellbores even if they were in such shape that we could 5 do annular disposal. And Stan wants to address the 6 annular disposal. 7 STAN PORHOLA 8 called as a witness on behalf of Linc Energy, stated as 9 follows on 10 DIRECT EXAMINATION 11 MR. PORHOLA: Yeah. So my name's Stan Porhola, 12 drilling engineer with Linc Energy. Just a background, 13 prior -- I first started my industry about 10 years ago 14 working for the Bureau of Land Management as a 15 petroleum engineer. My first project with the Bureau 16 of Land Management was actually at Umiat doing plug and 17 abandonment back in 2004. During that winter season we 18 plugged the Umiat 3, 4, 8 and 10 with just a surface 19 plug in there and left the wellheads in place. Prior 20 years I was doing other abandonments up the North Slope 21 for legacy wells. 22 And just a quick summary on the Umiat wells. 23 The number 1 well is about five miles to the northwest 24 of the Umiat camp. And right now it -- it was drilled 25 to about roughly 6,000 feet and there's no plug in the 34 0 1 well, it's just a piece of casing at the surface with a 2 flange and a watertight gate valve and there is a ice 3 plug in the well at surface, roughly about 15 feet down 4 in that well. 5 Next well number 2 was fully plugged and 6 abandoned by the Corps of Engineers back in 2002. 7 The number 3 well is a shallow well drilled 8 down to I think roughly 800 feet, we set a surface plug 9 in that one. There's roughly I believe,only about 70 10 feet of casing in that well and then the rest is open 11 hole. So if we did do any kind of disposal down that 12 well it would be down -- it's roughly about 70 feet 13 into the permafrost. And we did put a cement plug in 14 that hole, I think it was just past 70 feet in that 15 well. 16 The number 4 well was also -- it was drilled 17 also shallow, I believe about 800 feet and we also put 18 a surface plug on that well. And that one I think also 19 has a single string of casing, shallow set. 20 The number 5 well was fully plugged and 21 abandoned by the Corps of Engineers back in 2002. 22 The number 6 well was just recently fully 23 plugged and abandoned by the Bureau of Land Management 24 in 2012. 25 Number 7 was fully plugged and abandoned by the 35 1 Bureau of Land Management in 2012. 2 The number 8 well has a christmas tree on it 3 and the Bureau of Land Management back in 2004 we 4 pumped cement down the tubing, up the backside, it has 5 no packer and we pumped cement down the tubing and up 6 the backside of that well. And it was a well that had 7 tested gas up to 6 million cubic feet a day back in the 8 late 1940s, early 1950s. So that wellbore is 9 inaccessible right now, the tree was left on. 10 The number 9 well was fully plugged and 11 abandoned I think by the Corps of Engineers back in 12 2011. 13 The number 10 well was drilled to a shallow 14 area, about 1,200 feet on the north side of that fault 15 block where number 8 well is and they -- you set a 16 inflatable bridge plug in that well and cement -- 100 17 feet of cement on top of that one so that well's also 18 non -accessible. 19 And which leaves only the number 11 well which 20 has a string of 11 and three-quarter inch casing open 21 to surface. It has an ice plug near the surface and 22 also has a cement plug near about 500 feet. 23 And then the Seabee number 1 well as Paul had 24 mentioned, it's been plugged back to about 1,478 feet 25 and currently being used by the USGS for temperature in 1 surveys. And I was actually out there this August when 2 the USGS crews were out there doing their temperature 3 measurement and requested their temperature information 4 from them and they said that they would not be able to 5 provide that information until March of 2013 at the 6 earliest. 7 COMMISSIONER SEAMOUNT: The number 1 well way 8 off to the west, did that test any hydrocarbons? 9 MR. PORHOLA: That one they had oil shows, but 10 they did not test any hydrocarbons and it was 11 determined to be a wet well. And it was the first well 12 drilled back in 1945 by the U.S. Navy out in Umiat 13 area. 14 COMMISSIONER SEAMOUNT: I see an outline a 15 couple of leases there. Does the productive area go 16 beyond those leases? You don't have to answer the 17 question if it's confidential. 18 MR. WINSLOW: The mapping that was done by 19 Renaissance who was the former owner of these leases 20 does show extension to the west and slightly to the 21 east of these leases. 22 COMMISSIONER SEAMOUNT: So it was a big 23 structure? 24 MR. WINSLOW: Yeah. 25 COMMISSIONER SEAMOUNT: Okay. 37 0 1 MR. WINSLOW: I mean, you're looking -- I mean, 2 there's a main -- main fault here to the north, but the 3 structure does appear to go slightly to the east and 4 west. There are no tests out there. 5 COMMISSIONER SEAMOUNT: Okay. I have no other 6 questions. I think we should take a 15 minute recess. 7 COMMISSIONER NORMAN: I want to just ask a 8 quick question of this witness. COMMISSIONER 9 SEAMOUNT: Okay. 10 COMMISSIONER NORMAN: Were there PCBs 11 associated with any of these wells in the wellbore 12 areas? 13 MR. PORHOLA: Yeah, the Umiat number 9 well 14 drilled by the U.S. Navy I believe in 1950, they used 15 air chlor (ph) which is a PCB in their drilling fluid. 16 They were using an oil based drilling mud and the air 17 chlor chemical was used as a tracer fluid for their 18 coring program. They used it to be able to tell how 19 much filtrate went into the cores. And air chlor is a 20 PCB chemical that was used and wasn't regulated until 21 the late 1960s and it was used in that wellbore. And I 22 think they also during other cleanup operations, you 23 know, the -- right now the March Creek has been 24 cleaning up dirt laced with PCBs around the Umiat 25 number 9 well for the last four years, in and around 38 1 the Umiat number 9 wellbore. 2 COMMISSIONER NORMAN: And is remediation work 3 underway now on..... 4 MR. PORHOLA: The -- they -- March Creek is 5 planning to be out there again this winter for 6 additional remediation work to do additional dirt 7 removal this winter. 8 COMMISSIONER NORMAN: And on the plug that's in 9 the number 1 well, I think you said there's an ice plug 10 at 15 feet? 11 MR. PORHOLA: Uh-huh. 12 COMMISSIONER NORMAN: Any other plug? 13 MR. PORHOLA: There's no other plugs..... 14 COMMISSIONER NORMAN: So..... 15 MR. PORHOLA: .....known or left in the 16 wellbore. 17 COMMISSIONER NORMAN: .....in simple terms then 18 an ice plug is just what it means? 19 MR. PORHOLA: Just water had, you know, gone 20 into the wellbore and went out there, I believe it was 21 2006 and me and another BLM person we went out there 22 and took a long stick in order -- well, a long metal 23 rod and were trying to see how -- how far, if there was 24 ice in the wellbore and we could actually visibly -- 25 physically see the ice in the wellbore as well. And WE 1 other plug and abandonment projects in the Umiat area 2 showing other wellbores have been left open to surface 3 like that they've also historically had ice plugs built 4 up in the casing. 5 COMMISSIONER NORMAN: So if, for example, if Al 6 Gore was right and it warmed about 32 degrees down to 7 15 feet, then there wouldn't be a plug depending on how 8 far it goes down, I mean, the plug would disappear? 9 MR. PORHOLA: Yeah, seasonally with the cold 10 temperatures at Umiat it's going to get cold down deep 11 enough where it's going to freeze down there, 12 especially if any moisture gets down there. 13 COMMISSIONER NORMAN: For the foreseeable 14 future. 15 MR. PORHOLA: Yeah, and I believe when the BLM 16 plugged back or when they plugged and abandoned the 17 Umiat 6 and 7 earlier this -- back in March, 18 April/2012, they -- when they steamed through those 19 wells they had roughly 100 foot ice plugs that were in 20 those wells. And they had similar surface conditions 21 to what the number 1 well was where number 6 was just 22 an open piece of casing cemented to ground and number 7 23 I think also had a -- just a stub of casing seen up 24 above the ground. And I -- when I went out in 2006 I 25 actually was out there and confirmed that those ice 40 1 plugs existed and tried to actually drill through them 2 with a small ice drill for about 10 feet and it was at 3 least continuous for at least 10 feet. 4 COMMISSIONER NORMAN: Okay. I don't have any 5 further questions. Thank you. 6 MR. WINSLOW: Permafrost in this area is 7 anywhere from 700 to 1,100 feet so it's fairly thick. 8 COMMISSIONER SEAMOUNT: Are there any methane 9 hydrates? 10 MR. PORHOLA: Looking into the -- all the 11 offset wells drilled here it doesn't appear that 12 there's any hydrate issues. When they drilled some of 13 these wells below the permafrost, they're actually 14 drilling just with a cable tool rig and we're just 15 using brine. So well control was not anything main 16 there and the reservoir's actually sub -normal pressure. 17 So it didn't appear from any of the Navy wells or the 18 Seabee well that there was any issues with gas 19 hydrates. 20 COMMISSIONER NORMAN: Okay. Thank you, Mr. 21 Porhola and Mr. Winslow. And we'll take a -- it's 22 10:08, we'll take a 15 minute break, we'll be back at 23 eight plus 15, whatever that is. We'll be back at 24 10:23. 25 MR. WINSLOW: Thank you. 41 1 (Off record) 2 (On record) 3 COMMISSIONER SEAMOUNT: We have -- in 13 years 4 doing this we've only been on time from recess twice so 5 it is now 10:32 and we're back on the record. 6 Okay. Is there anyone else that wants to 7 testify? 8 (No comments) 9 COMMISSIONER SEAMOUNT: Okay. Hearing none, 10 I'd like to ask a question of Mr. Winslow. When do you 11 plan to drill your disposal well? 12 MR. WINSLOW: We're starting to mobilize the 13 rig, I think, right now. Spud date is January 23rd. 14 COMMISSIONER SEAMOUNT: Okay. Very good 15 answer. You mentioned the disposal of produced oil. I 16 don't believe that that was mentioned in your 17 application, produced oil into your disposal zone. I 18 want you to keep in mind that there may be an issue of 19 waste, disposing of produced oil into a disposal zone 20 and I think that we think that you need to think about 21 that to see if -- that that is authorized. There may 22 be a waste issue and it may not be a big deal, you 23 know, there may not be a lot, but when you're talking 24 about waste there may be penalties involved. We've got 25 our reservoir engineer in here, I asked him to come in 42 • • 1 and -- Dave Roby, to sit and we'll just be thinking 2 about that. We do have instances where we have 3 disposed of produced oil back into the produced 4 reservoir and we haven't had a problem with that, but 5 when you talk about produce -- disposing of it into a 6 waste zone and not being able to recover it again then 7 there is a waste issue involved in that. 8 Do you have any comments to make on that? 9 MR. WINSLOW: We did ask for permission to 10 dispose of crude oil in the DIO application..... 11 COMMISSIONER SEAMOUNT: Okay. 12 MR. WINSLOW: .....on page 19, the first bullet 13 point at the top of page 19 of the DIO, is produced 14 crude oil and gasses from production stream. 15 COMMISSIONER SEAMOUNT: Okay. 16 MR. WINSLOW: So specifically second bullet 17 point, waste crude oil from primary field operations. 18 We did -- so we did ask for permission to dispose of 19 the crude and when we talked about the volumes, I'm not 20 sure what page number that was on, but we did talk -- 21 we did mention the 10,000 barrels of oil the first 22 season and up to 20,000 barrels of crude oil the second 23 season. So..... 24 COMMISSIONER SEAMOUNT: Okay. 25 MR. WINSLOW: .....we did ask for it in the 43 1 DIO. 2 COMMISSIONER SEAMOUNT: Okay. Well, I was 3 mistaken, but it still may go against regulation..... 4 MR. WINSLOW: That's fine. 5 COMMISSIONER SEAMOUNT: .....and statute so 6 it's something to think about. 7 After you drilled -- after we -- I'd like to 8 commend you on being proactive in getting this 9 application in early and we'll await the results of the 10 well before issuing a decision on the order. And 11 before we'd adjourn I'd ask Commissioner Norman if he 12 has any comments or any additional questions? 13 COMMISSIONER NORMAN: No, I think it was a 14 good, well prepared, well delivered presentation. 15 MR. WINSLOW: Thank you. 16 COMMISSIONER NORMAN: We understand it and I 17 think we've indicated just it's the order that is 18 troubling to the Commission. Not necessarily 19 troubling, but we always keep an eye also on the 20 precedent we're setting and others watch the order we 21 do things. And so when we get out of order sometimes 22 then it begins to set a precedent. And so that's why 23 we try to keep things in a certain sequence. 24 But as Commissioner Seamount said we appreciate 25 you being proactive, we'll keep an eye closely on this 44 1 and be prepared to move expeditiously. 2 MR. WINSLOW: What will the Commission be 3 looking for once we've drilled the disposal well, will 4 it be logs which will then -- you'll make the decision 5 after you receive logs from the disposal well? 6 COMMISSIONER SEAMOUNT: That's correct. 7 MR. WINSLOW: All right. 8 COMMISSIONER SEAMOUNT: I -- logs are 99 9 percent I believe. 10 COMMISSIONER NORMAN: And, of course, well 11 integrity. 12 MR. WINSLOW: Okay. 13 COMMISSIONER SEAMOUNT: Yeah, logs and well 14 integrity. 15 MR. WINSLOW: Okay. 16 COMMISSIONER SEAMOUNT: Thank you very much. 17 This hearing is -- I believe it's called adjourned. 18 This hearing is adjourned at 10:37. 19 MR. WINSLOW: Thank you, Commissioners. 20 COMMISSIONER SEAMOUNT: Thank you. 21 (Adjourned - 10:37 a.m.) 22 (END OF PROCEEDINGS) 45 1 TRANSCRIBER'S CERTIFICATE 2 I, Salena A. Hile, hereby certify that the 3 foregoing pages numbered 02 through 46 are a true, 4 accurate, and complete transcript of proceedings in re: 5 Docket No.: DIO-12-003 transcribed under my direction 6 from a copy of an electronic sound recording to the 7 best of our knowledge and ability. 8 9 10 Date Salena A. Hile, Transcriber 11 :r zinc EnERGY • Umiat DPS-01 Application for: Disposal Injection Order Submitted: � November 1,, 2012 (DI EnE�nsv • r 0 Urniat Location Map Figure 1 of DIO Application SE Corner of NPR -A West side of Colville River -88 mi west of TAPS PS#2 -64 mi SSW of Nuiqsut -86miNof Anaktuvuk Pass -V105miSWof Deadhorse E ErR Y • 0 Umiat History ➢ Umiat structure discovered (first drilled) by the U.S. Navy in 1945 ➢ The Navy drilled 11 wells between 1945 and 1953 ➢ The 11 legacy wells produced oil (via rod pump) at rates from 0 to � 400 bopd from the Upper and Lower Grandstand formations ➢ Husky Oil drilled (for the U.S. Geologic Survey) the Seabee Test Well No.1 in 1979 ➢ Grandstand formations were wet ➢ Tested gas from deeper Torok sand. enE�C n Cis vD Dv > N 0 0 11 .. 00 O 10 8 i 3 4 --a 9 5 n _. , N Seabee 1 2 f n }' } Legacy Wells UIC Camp D p o 00 Umiat • "••"� •;�,. Umiat Airstrip b N Federal BLM Leases State of Alaska Leases Umiat 2012/2013 (planned) Exploration 1. Drill Umiat DSP-01 disposal well 2. Drill shallow Lower Grandstand vertical well (Umiat #16) 3. Skid the rig and drill shallow Lower Grandstand horizontal well � (Umiat #16H) from same ice pad � 4. Drill deeper Torok exploration well (Umiat #23) ➢ Perform well tests on the Lower Grandstand vertical and horizontal wells (Umiat #16 and Umiat #16H), back to back ➢ Well test potential Torok pay in Umiat #23, given time ➢ Recover core, fluid, and log data to add to and supplement available Umiat data gathered by the U.S. Navy in the 1940 s and 1950's 6 Q EnE�C • • Surface Owners &Wells within %mile of DSP-01 A Well 16 Well23 Well16H Well23H t`^ �,Well9 �tii WeIls78.' � Well' __^^• .. ^". DSP-01.......................... .•' _ ^..� Umiat� ,,• . E' 4 dnmi - Proposed Well Locations ---- Proposed Snow Road Federal Lands _ Legacy Wells - - Optional Colville Crossing' State Submerged Lands N EOERGY --::: 114 Mile Radius -- Infield Ice Road ADOT&PF Airport Boundary 0 Existing Gravel Pads Gravel Road ASRC Lands l Surface Owners and Operators C Federal Lease Boundary ® Native Allotment 2012-2013 Winter Season o State of Alaska Lease 1 i Northeast NPR -A, North Slope, Alaska 'The Ccidne Ri•-- na locafion roll oe de!ermined E'y field ccndit-s. 0 0.25 0.5 M1.1 le s Figure 5 Figure 5 of DIO Application LIHC 7 enencY • • Surface Owners &Wells within %mile of DSP-01 Surface Owners within % mile of the proposed Umiat DSP-01 well: ➢ Bureau of Land Management (BLM) i • ➢ Alaska Department of Transportation and Public Facilities (AKDOT&PF) owns land surrounding the Umiat camp and runway n u ➢ AKDOT&PF Boundary is—2,475' from surface location of Umiat DSP-01 ➢ AKDOT&PF Boundary is—1,416' (offset) from the planned bottom -hole location of the Umiat DSP-01 wellbore ➢ Both BLM and AKDOT&PF were provided copies of the Umiat DIO Application Wells within % mile of the proposed Umiat DSP-01 well: ➢ Seabee Test Well No.1 (Seabee #1) s v enl�C 11 Disposal Interval Selection: 1. Below the known oil reservoirs (Upper and Lower Grandstand) 2. Below any freshwater aquifers 3. Formation water salinity greater than 10,000 ppm across the � disposal interval 4. Above the Torok sand in Seabee #1 that flowed gas 5. Low resistivity (14-20 ohms) rock • Torok zone that flowed gas had 35 ohms 6. Relatively constant separation between Neutron and Density curves 7. Fairly consistent background gas on mud log 8. No significant gas influx during drilling • Did not have to weight up the mud • Had no well control issues OLIRC 9 EOERGY 0 • 0 Disposal Interval Selection (continued): 9. Relatively thick gross disposal interval (650 ft), with several higher porosity sands 10. Relatively thick confining intervals above (600 ft) and below (350 ft) the proposed disposal interval 11. Seismic data indicates that the disposal and confining zones are laterally continuous across the Umiat structure 12. Seismic data doesn't show any major faulting in close proximity to the proposed Umiat DSP-01 wellbore (at the disposal zone depth) 10 Ll 11L EIIER6Y 0 r� n u Il 111 li l:Efl t ■liifli t 1�t111 iplll � -i1ti1 ■I111!I 111 ��11111 ",a„'.Il �Illlll Ill ■iliill �- ':Illl ■illlll `ic ► • ► �Il� ��glll � i��Al) �1i111 fw II� �Illill ,;�I�EIi �111ii1 • • � II! Oplii iltil3 1111111111111 iiil� � m �E►u�� iiim ►ia►►Y III ■ UE ':i11111 t lliii �1: • • •. �1l ■illlllIIIIII illlli 11 ■R11111 �111111 �11111 ii�iE7: • ► �illll ■�iilli w�� '�� ii� ilii Hilt" HIM ii iq Will ■illili = 411111 ■illlll IM i milli ■Illill ■1llill Ill milli ■111!Il ■il111! 111 Milil ■1!1!I ■i11N! iII ill! ■111'll ■illlll ll� Ilill: alUill MEN 1111 ■milli' ■1l1111 ■illill 11 M M .M1 AMI g�I �fi�i Urniat DSP-01 Disposal & Confining Zones Umiat DSP-01 Disposal & Confining Zones - PROJECTED Depths • Upper Confining Zone Top Base Disposal Zone Top Upper Porous Top Interval Base Lower Porous Top Interval Base Disposal Zone Base Lower Confining Zone Top Base Seabee Test Well No.1 ft MD ft TV ft SSTVD 3,550 3,550 -3,228 4,150 4,150 - 3, 828 4,150 4,150 - 3, 828 4,410 4,410 -4,088 4,500 4,500 -4,178 41620 4,620 -4, 298 4,675 4,675 -4,353 41800 4,800 -4,478 4,800 4,800 -4, 478 5,150 5,150 - 4, 828 Ground Level Elevation Rotary Kelly Bushing Elevation (RKB) Table 1 of D10 Application 292 ft 322 ft Umiat DSP-01(Projected) ft MD ft TVD ft SSTVD 3,743 3,645 -3,332 4,386 41245 - 3, 932 4,386 4,245 -3,932 4,664 4,505 -41192 4,760 4,595 -4, 282 41889 4,715 -4,402 4,948 4,770 -4,457 5,082 41895 -4, 582 5,082 4,895 -4, 582 5,457 5,245 -4,932 292 ft 313 ft OLIK 12 EIIERGY 0 0 • 0 Umiat DSP-01 Proposed Logging Program Open -Hole Logs: ➢ Quad Combo — Gamma Ray, Resistivity, Neutron, Density, & Sonic logs ➢ Log copies will be provided to the AOGCC Cased -Hole Logs: ➢ Cement Bond log in the 7" casing, from PBTD to above the previous casing shoe (planned to be at—1,700' MD/TVD) ➢ Log copies will be provided to the AOGCC 13 ETC 0 0 0 0 Umiat DSP-01 Proposed Casing Program ➢ Conductor casing set at 100' MD/TVD ➢ 9-5/8" Surface casing set at 1,700' MD/TVD ➢ Cemented to surface ➢ 7" Production casing set at 5,100' MD (4,912' TVD) ➢ 15.8 ppg tail cement to 4,000' MD (N386' above Top of Disposal Zone) ➢ 12.5 ppg lead cement to 2,000' MD (N1,743' MD above Top of Upper Confining Interval &—2,386' MD above Top of Disposal Zone) ➢ Note: the proposed Umiat DSP-01 wellbore schematic was included in the DIO application (Figure 7) 14 LIRC EIIERGY 0 0 Urniat DSP-01 Injection Pressures & Rates Anticipated Injection Pressures and Rates: ➢ Anticipated injection pressure < 2,500 psi • Based upon fracture modeling, • Formation rock properties derived from open -hole logs, and • Anticipated fluid (&/or slurry) densities. ➢ Maximum injection rate = 6.0 bpm Etc uipment Limitations: ➢ Maximum injection pressure = 5,000 psi . ➢Maximum injection rate = 6.0 bpm • 15U nc EIIER6Y Waste Types & Sources ➢ Class II fluids including (but not limited to): ➢ Drilling, completion, and workover fluids, ➢ Cement returns & rinsate, ➢ Rig wash fluids, ➢ Tank bottoms (including BS&W), ➢ Surface well testing equipment wash/flush, ➢ Flowline pigging waste, ➢ Formation fluids brought to surface during drilling and testing operations, including: . ➢ Crude Oil, ➢ Produced water, and ➢ Formation sediments. ➢ Amore detailed Class II fluid list is included in the DIO Application. 16 (JLEEnC Waste Volumes Anticipated Volumes for the 2012/2013 Exploration Season: ➢ 21000 bbls of used Mineral Oil Base Mud (MOBM), ➢ 11000 bbls of used Water Based Mud (WBM), ➢ 21000 bbls of water/brine from pre and post -flushes, completion fluids, and minor volumes of other Class II fluids (including rig wash, cement returns, snowmelt, etc.), and ➢ Up to 10,000 bbls of crude oil from well tests. E 17 C ETC 9 0 C7 C] Waste Volumes (continued) Anticipated Volumes for the 2013/2014 Exploration Season: ➢ 5,000 bbls of used Mineral Oil Base Mud (MOBM), ➢ 10,000 bbls of slurrified cuttings, ➢ 41000 bbls of water/brine from pre and post -flushes, completion fluids, and minor volumes of other Class II fluids (including rig wash, cement returns, snowmelt, etc.), and ➢ Up to 20,000 bbls of crude oil from well tests. ETC Crude Oil Disposal ➢ Note that Linc Energy's preference and intention is to re -inject the produced oil back into the formation from which it was produced. ➢ There may however be circumstances, unique to the Umiat � oilfield, which dictate the disposal of the produced oil into the � Umiat DSP-01 disposal well. These may include: 1. Severe formation permeability damage due to re -injection of the oil at a temperature slightly above reservoir temperature • The Upper Grandstand and a portion of the Lower Grandstand are contained within the Permafrost • The lower portion of the Lower Grandstand has a reservoir temperature of ^'360 F • The tested oil will be kept in heated storage tanks and will likely be re -injected at "460 F i 2. Batch re -injection may create "ice sheathes" across the injection interval (due to thawing and re -freezing), which could physically prevent the continued injection of oil back into the reservoir. U--- En��n� 19 Crude Oil Disposal (continued) 3. Crude oil storage during testing operations will be limited. Umiat #16 and Umiat #16H will be tested back to back and Linc desires to get representative, stabilized rates from each well for comparison. There may be a need to dispose of some oil during testing, in order to free up tank space to achieve stabilized test rates. • Plans are to have 31 storage tanks on location, totalling—15,000 bbls of capacity • Anticipated flowrates of 400-500 bopd from #16 and 1,000-1,500 bopd from #16H 4. Re -injection of the produced oil can't be initiated until the completion of both Umiat #16 and #16H well tests (referring to the 2012/2013 exploration program). Injection into either well, while the other is being production tested, will severely compromise the test data. 5. The winter exploration season at Umiat is directly dependent upon the ambient temperature and ice/snow conditions. An unexpected increase in i area temperature, may dictate an earlier than anticipated end to the exploration season. If the produced oil can't be re -injected, the oil may have to be disposed of in the Umiat DSP-01 well. • Leaving the crude oil in tanks at Umiat until the following winter season is not an option! C) U K 20 EnERGY • Crude Oil Disposal (continued) 6. Injection rates down the disposal well may be significantly higher than re- injection rates down the exploration wells. 7. Extreme care will need to be taken when re -injecting crude oil into the frozen (or nearly frozen) Grandstand formation(s), in order to avoid any chance of fracturing the formation(s). 8. The remoteness of the Umiat oilfield and the expense to transport the oil to a sales point, prohibit the sale of the produced oil. There is also a sizeable amount of environmental risk involved in transporting the produced oil. • Linc Energy has had discussions with potential purchasers of the test oil, but failed to reach an acceptable agreement, due to the relatively small volumes and high transportation costs. • Linc Energy also considered donating the produced oil to a native regional or village corporation, but again the relatively small volume, the remoteness, the high transportation cost, and high environmental risk, precluded this option. , • Note: - Steiger loads would be limited to —120 bbls (5,000 gals) - 10,000 bbls would require 80+ loads - Each load would take 36+ hours round trip from Umiat to PS#2 (not to (mention transport to a North Slope refinery) LIK 2 EnE Waste Confinement Geologic: ➢ Seabee #1 electric logs show a thick (650') disposal zone, with thick confining zones above (600') and below (350') ➢ Seismic data shows lateral continuity of the proposed disposal and confining intervals across the Umiat structure ➢ Seismic data does not show any significant faulting in close proximity to the Umiat DSP-01 well (at the disposal zone depths) Fracture Analysis/Modeling: • ➢ A reservoir fracture model was built (in FracproPT) using rock + properties calculated from the Seabee #1 electric logs _ Unc 22 3 EIIERGV Waste Confinement (continued) Fracture Analysis/Modeling_(continued): ➢ Numerous cases were run simulating fracture heights, widths, and lengths, while varying: • • Injection rates from 2.0 — 6.0 bpm • Batch injection volumes up to 1,000 bbls • Fluid/slurry weights from 7 ppg crude oil to 10 ppg MOBM (with and without cuttings) • Different perforation intervals 1. Top 20' of Disposal Zone 2. Top 20' of the Upper Porous Sand 3. Bottom 20' of the Lower Porous Sand 4. Bottom 20' of the Disposal Zone • ➢ All cases show containment of the disposal fluids (&cuttings) within � � the disposal and confining zones. ➢ Even the extreme cases (perforating the very top 20' or the bottom 20' of disposal interval) show containment within the disposal and confining intervals. Q unc 23 .�EIIERGY Waste Confinement (continued) Fracture Analysis/Modeling (continued): ➢ Linc Energy plans to perforate the Umiat DSP-01 wellbore within the higher porous intervals (as seen in the Seabee #1 well logs), � starting from the lower interval and then moving upward, as � needed. ➢ Fracture modeling assuming perforations within these higher porosity intervals, shows no fracture growth outside the gross disposal zone. Fractures do not grow into the confining intervals at all. 24 EnERGY • • Waste Confinement (continued) Top of Umiat DSP-01 Projected Perfs: 4,505' - 4,525' TVD (equivalent Seabee #1 Perfs: 4,410' - 4,430' TVD) Upper Porous Sand Fracture Half Rate Fracture Top Bottom Net height Length Fluid type (bpm) (TVD ft) (TVD ft) (ft) (ft) Crude 7ppg 6 4341 4493 152 75 Crude 7ppg 4 4349 4489 139 70 Crude 7ppg 2 4359 4479 120 60 Brine 8.5ppg 6 4339 4491 152 76 Brine 8.5ppg 4 4348 4487 139 70 Brine 8.5ppg 2 4359 4479 120 60 MOBM 9.5ppg 6 4295 4538 242 118 MOBM 9.5ppg 4 4298 4534 236 114 MOBM 9.5ppg 2 4309 4521 211 101 WBM 10 ppg 6 4343 4493 150 74 WBM 10 ppg 4 4350 4488 137 69 WBM 10 ppg 2 4360 4479 119 59 MOBM 10 ppg 6 4294 4539 244 119 MOBM 10 ppg 4 4279 4535 238 115 MOBM 10 ppg 2 4307 4522 215 102 Drill Cuttings MOBM 10ppg 6 4329 4510 181 90 Drill Cuttings MOBM 10ppg 4 4334 4504 170 84 Drill Cuttings MOBM 10ppg 2 4345 4495 150 72 Drill Cuttings WBM 10ppg 6 4369 4468 99 50 Drill Cuttings WBM 10ppg 4 4372 4462 90 45 Drill Cuttings WBM 10ppg 2 4377 4453 76 37 Table 4 of DIO Application Note: The proposed disposal zone is from 4,150' — 4,800' TVD (in the Seabee #1 wellbore) UnC 25 EIIERGY 0 • 0 • Waste Confinement (continued) Base of Umiat DSP-01 Projected Perfs: 4,750' - 4,770' TVD Lower Porous Sand (equivalent Seabee #1 Perfs: 4,655' - 4,675' TVD) Fracture Half Rate Fracture Top Bottom Net height Length Fluid type (bpm) (TVD ft) (TVD ft) (ft) (ft) Crude 7ppg 6 4578 4737 159 75 Crude 7ppg 4 4585 4732 148 68 Crude 7ppg 2 4598 4724 126 58 Brine 8.5ppg 6 4576 4735 158 75 Brine 8.5ppg 4 4583 4730 147 69 Brine 8.5ppg 2 4597 4723 125 58 MOBM 9.5ppg 6 4539 4778 239 114 MOBM 9.5ppg 4 4541 4774 233 109 MOBM 9.5ppg 2 4550 4761 211 96 WBM 10 ppg 6 4582 4740 158 74 WBM 10 ppg 4 4588 4733 146 67 WBM 10 ppg 2 4599 4724 124 58 MOBM 10 ppg 6 4538 4779 242 115 MOBM 10 ppg 4 4540 4775 235 110 MOBM 10 ppg 2 4549 4762 213 97 Drill Cuttings MOBM 10ppg 6 4571 4755 184 89 Drill Cuttings MOBM 10ppg 4 4577 4749 171 81 Drill Cuttings MOBM 10ppg 2 4588 4739 151 70 Drill Cuttings WBM 10ppg 6 4613 4718 106 51 Drill Cuttings WBM 10ppg 4 4617 4714 96 48 Drill Cuttings WBM 10ppg 2 4625 4706 81 40 Table 5 of DIO Application Note: The proposed disposal zone is from 4,150' — 4,800' TVD (in the Seabee #1 wellbore) 26 Ennc ERGY I ], • 1 4 Water Salinity Analysis ➢ Water salinity analysis indicates that the formation water salinity across the entire disposal interval exceeds 10,000 ppm. ➢ Formation water salinities below 10,000 ppm appear to be present above-4,004" TVD (as seen in the Seabee #1 wellbore) • ➢ Note that the proposed disposal zone is from 4,150' — 4,800' TVD (in the Seabee #1 wellbore) ➢ No Aquifer Exemption is required. ➢ There have been no water samples gathered from the proposed � disposal zone in any of the Umiat wells. � 27 � ERER,G Water Salinity Analysis (continued) ➢ There is however a water sample that was collected from the Seabee #1 well (during DST #3, 5,366'-5,394' TVD), which shows a salinity of nearly 11,000 ppm. This sample was gathered from the Torok formation, roughly 580' TVD below the base of the proposed i disposal interval (to the top of the best pay within the tested interval). • The mud was weighted up from 10.1 to 14.3 ppg at this depth (well control) • Interval (& below) drilled with 14.3 ppg, freshwater mud (5,000 ppm chloride) ➢ The salinity calculations (as seen in the Salinity Log — Attachment 5 in the DIO) shows this lower Torok interval to have far lower salinity (as low as 5,000 ppm) than the entire proposed disposal interval. This lower apparent salinity is likely a result of: 1. Severe fluid invasion as a result of weighting up the mud (10.1 to 14.3 ppg) 2. Long exposure time (weeks) that this high porosity sand was exposed to the 14.3 ppg freshwater mud UflC 28 EnERGY I Area of Review ➢ DIO requires a wellbore/mechanical integrity review of all wells within a % mile radius of the proposed disposal well. ➢ Seabee Test Well No.1 is the only wellbore within % mile of the proposed Umiat DSP-01 disposal well. ➢ Records indicate good mechanical integrity ➢ 30" casing to 115' — cemented to surface ➢ 20" casing to 1,617' — cemented to surface ➢ 13-3/8" casing to 3,983' — cemented to surface ➢ 9-5/8" casing to 9,980' — TOC estimated @ 2,200' (well above disposal zone) ➢ 7-5/8" liner from 9,601' to 12,814" — cemented and then squeezed off • ➢Seabee #1 has been plugged back to 1,478' � ➢ Seabee #1 currently used by the U.S Geologic Survey as a temperature monitoring well OM LI HC 29: EIIER6Y • Questions? • "M s � en��nc�ir • s FRO" STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Docket No. DIO-12-003. Linc Energy Operations, Inc. Disposal Injection Order (DIO) for well Umiat DSP-01 December 18, 2012 at 9:00 a.m. AFFILIATION PHONE # TESTIFY (Yes or No) a ✓(� o `� - (�C �viGl� 3 i 2-6 1 S ®\/ro ':�75- p-2 " to �V1Ca,n�i�ir�er' i�'C)G C� 7q� 12�3 N v h s lJa f lacC, /1-06C._ c, — Aln Colombie, Jody J (DOA) From: Foerster, Catherine P (DOA) Sent: Friday, November 09, 2012 11:43 AM To: Colombie, Jody J (DOA) Subject: RE: Public Notice Umiat .pdf I talked with Chris about this. Lately we have been holding a hearing on area injection orders whether or not there are any objections. Chris supports that as a good idea. So, it doesn't matter whether or not JM objects and no response to him is necessary. From: Colombie, Jody J (DOA) Sent: Friday, November 09, 2012 11:14 AM To: Foerster, Catherine P (DOA); Wallace, Chris D (DOA) Subject: FW: Public Notice Umiat .pdf From: jerry mccutcheon [mailto:susitnahydronow@yahoo.com] Sent: Thursday, November 08, 2012 3:43 PM To: Colombie, Jody J (DOA) Subject: Re: Public Notice Umiat .pdf Is there pot able water in the strata where they are going to inject waste? If so I object. From: "Colombie, Jody J (DOA)" <jody.colombie@alaska.gov> To: "Singh, Angela K (DOA)" <angela.sing h@alaska.gov>; "Ballantine, Tab A (LAW)" <tab.ballantine@alaska.gov>; "Brooks, Phoebe L (DOA)" <phoebe.brooks@alaska.gov>; "Colombie, Jody J (DOA)" <jody.colombie@alaska.gov>; "Crisp, John H (DOA)" <john.crisp@alaska.gov>; "Davies, Stephen F (DOA)" <steve.davies@alaska.gov>; "Ferguson, Victoria L (DOA)" <victoria.ferguson@alaska.gov>; "Fisher, Samantha J (DOA)" <samantha.fisher@alaska.gov>; "Foerster, Catherine P (DOA)" <cathy.foerster@alaska.gov>; "Grimaldi, Louis R (DOA)" <lou.grimaldi@alaska.gov>; "Johnson, Elaine M (DOA)" <elaine.johnson@alaska.gov>; "Jones, Jeffery B (DOA)" <jeff.jones@alaska.gov>; "Laasch, Linda K (DOA)" <linda.laasch@alaska.gov>; "Bender, Makana K (DOA)" <makana.bend er@alaska.gov>; "McIver, Bren (DOA)" <bren.mciver@alaska.gov>; "McMains, Stephen E (DOA)" <steve.mcmains@alaska.gov>; "Mumm, Joseph (DOA sponsored)" <joseph.mumm@alaska.gov>; "Noble, Robert C (DOA)" <bob.noble@alaska.gov>; "Norman, John K (DOA)" <john.norman@alaska.gov>; "Okland, Howard D (DOA)" <howard.okland@alaska.gov>; "Paladijczuk, Tracie L (DOA)" <tracie.paladijczuk@alaska.gov>; "Pasqual, Maria (DOA)" <maria.pasqual@alaska.gov>; "Regg, James B (DOA)" <jim.regg@alaska.gov>; "Roby, David S (DOA)" <dave.roby@alaska.gov>; "Scheve, Charles M (DOA)" <chuck.scheve@alaska.gov>; "Schwartz, Guy L (DOA)" <guy.schwa rtz@alaska.gov>; Seamount, Dan T (DOA)" <dan.seamount@alaska.gov>; "Wallace, Chris D (DOA)" <chris.wallace@alaska.gov>; Aaron Gluzman <aaron.gluzman@gmail. com>; Aaron Sorrell <Aaron.Sorrel l@BP.com>; Bruce Williams <bruce.williams@bp.com>; "Bruno, Jeff J (DNR)" <jeff.bruno@alaska.gov>; "caunderwood@marathonoil.com" <caunderwood@marathonoil.com>; Casey Sullivan <Casey.Sullivan@pxd.com>; Dale Hoffman <dale.hoffman@pxd.com>; David Lenig <lenigdc@bp.com>; Donna Vukich <dvukich@nea.coop>; Eric Lidji <ericlidji@mac.com>; Erik Opstad <Erik.Opstad@savantalaska.com>; "Franger, James M (DNR)" <mike.franger@alaska.gov>; Gary Orr <ORRGA@chevron.com>; "Smith, Graham 0 (PCO)" <graham.smith@alaska.gov>; Greg Mattson <greg.mattson@bp.com>; "Heusser, Heather A (DNR)" <heather.heusser@alaska.gov>; James Rodgers <James.T.Rodgers@conocophillips.com>; Jason Bergerson <Jason.Bergerson@north-slope.org>; Jennifer Starck <Jennifer.Starck@bp.com>;"jill.a.mcleod@conocophill ips.com" <jilt.a.mcleod@conocophillips. com>; Joe Longo <joe.longo@enipetroleum.com>; "King, Kathleen J (DNR)" <kathleen.king @alaska.gov>; Lara Coates <Lara.Coates@kiewit.com>; Lois Epstein <lois_epstein@tws.org>; Marc Kuck <Marc.kuck@enipetroleum.com>; "Steele, Marie C (DNR)" <marie.steele@alaska.gov>; Matt Gill <mattgill@gci.net>; Melissa Okoola <Melissa.Okoola@us.mwhglobal.com>; "Ostrovsky, Larry (DNR sponsored)" <Larry.Ostrovsky@alaska.gov>; "Bettis, Patricia K (DOA)" <patricia.bettis@alaska.gov>; "Perrin, Don J (DNR)" <donald.perrin@alaska.gov>; Peter Contreras <contreras.peter@epa.gov>; "Pexton, Scott R (DNR)" <scott.poexton@alaska.gov>; Richard GZ* <rgarrard@talisman-energy.com>; Rya*niel <Ryan.Dan iel@bp.com>; Sandra Lemke <Sandra.D.Lem ke@conocophillips.com>; Talib Syed <talibs@ecentral.com>; Terrace Dalton <T•erence.j.dalton@us.mwhglobal.com>; Wayne Wooster <wwooster@asrcenergy.com>; "Woolf, Wendy C (DNR)" <wendy.woolf@alaska.gov>; William Hutto <w.hutto@hotmail.com>; William Van Dyke <bvandyke@petroak.com>; "(michael.j.nelson@conocophill ips.com)" <michael.j.nelson@conocophill ips.com>; AKDCWeIIlntegrityCoordinator <AKDCWeIIlntegrityCoordinator@bp.com>; "alaska@petrocalc.com" <alaska@petrocalc.com>; Anna Raff <anna.raff@dowjones.com>; Barbara F Fullmer<barbara.f.fullmer@conocophillips. com>; bbritch <bbritch@alaska.net>; "bbohrer@ap.org <bbohrer@ap.org>; Bill Penrose <bill@solstenxp.com>; Bill Walker <bill-wwa@ak.net>; Bowen Roberts <Bowen.E.Roberts@conocophillips. com>; Bruce Webb <bwebb@aurorapower.com>; Claire Caldes <Claire_Caldes@fws.gov>; Cliff Posey <cliff@posey.org>; "Crandall, Krissell" <Krissell.Crandall@bp.com>; D Lawrence <DLawrence4@slb.com>; Daryl J. Kleppin <KleppiDE@BP.com>; Dave Harbour <harbour@gci.net>; Dave Matthews <dmatthews@pricegregory.com>; David Boelens <dboelens@aurorapower.com>; David Duffy <dduffy@hilcorp.com>; David House <dhouse@usgs.gov>; "Scott, David (LAA)"<david_scott@legis.state. ak.us>; David Steingreaber<david.e.steingreaber@exxonmobil. com>; Davide Simeone <Davide.Simeone@enipetroleum.com>; "ddonkel@cfl.rr.com" <ddonkel@cfl.rr.com>; "Elowe, Kristin" <Kristin.Elowe@mms.gov>; Francis S. Sommer <SommerFS@BP.com>; Gary Laughlin <galaughlin@marathonoil.com>; "schultz, gary (DNR sponsored)" <gary.schultz@alaska.gov>; ghammons <ghammons@aol.com>; Gordon Pospisil <PospisG@BP.com>; "Gorney, David L." <dgorney@marathonoil.com>; Greg Duggin <greg_duggin@xtoenergy.com>; Gregg Nady <gregg.nady@shell.com>; Gregory Geddes <GregoryGeddes@us.mwhglobal.com>; gspfoff <gspfoff@aurorapower.com>; "Jdarlington Qarlington@gmail. com)" <jarlington@gmail.com>; Jeanne McPherren <jmcpherren@brenalaw.com>; "Jones, Jeffery B (DOA)" <jeff.jones@alaska.gov>; Jerry McCutcheon <susitnahydronow@yahoo.com>; Jill Womack <JWomack@MarathonOil.com>; Jim White <jimwhite@satx.rr.com>; Jim Winegarner <jinegarner@brpcak.com>; Joe Lastufka <lastufjn@bp.com>; "news@radiokenai.com" <news@radiokenai.com>; "Easton, John R (DNR)" <john.easton@alaska.gov>; John Garing <garingJD@bp.com>; John Spain <jps@stateside.com>; Jon Goltz <Jon.Goltz@conocophillips.com>; "Jones, Jeffrey L (GOV)" <jeffrey.jones@alaska.gov>; Judy Stanek <stanekj@chevron.com>; Judy Stanek <jstanek@hilcorp.com>; "Houle, Julie (DNR)" <julie.houle@alaska.gov>; Julie Little <Julie.D.Little@conocophillips.com>; Kari Moriarty <moriarty@aoga.org>; Kaynell Zeman <kjzeman@marathonoil.com>; Keith Wiles <kwiles@marathonoil.com>; Kelly Sperback <ksperbeck@slb.com>; "Gregersen, Laura S (DNR)" <laura.gregersen@alaska.gov>; Luke Keller <Ikeller@hilcorp.com>; Marc Kovak <yesnoak@gmail.com>; Mark Dalton <mark.dalton@hdrinc.com>; "Mark Hanley (mark.hanley@anadarko.com)" <mark.hanley@anadarko.com>; Mark P. Worcester <mark.p.worcester@conocophillips.com>; "Kremer, Marguerite C (DNR)" <meg.kremer@alaska.gov>; Michael Jacobs <Michael.W.Jacobs@conocophillips.com>; Mike Bill <Michael.Bill@bp.com>; ' mike@kbbi.org <mike@kbbi.org>; Mike Morgan <mike.morgan@pxd.com>; Mikel Schultz <Mikel.Schultz@BP.com>; Mindy Lewis <mlewis@brenalaw.com>; MJ Loveland <N1878@conocophillips.com>; mjnelson <mjnelson@purvingertz.com>; mkm7200 <mkm7200@aol.com>; "knelson@petroleumnews.com" <knelson@petroleumnews.com>; Nick W. Glover <GloverNW@BP.com>; NSK Problem Well Supv <n1617@conocophillips.com>; Patty Alfaro <palfaro@yahoo.com>; "Decker, Paul L (DNR)" <paul.decker@alaska.gov>; Paul Figel <paul_figel@xtoenergy.com>; Paul Mazzolini <pmazzolini@hilcorp.com>; Randall Kanady <Randall.B.Kanady@conocophillips.com>; Randy L. Skillern <SkilleRL@BP.com>; "Delbridge, Rena E (LAA)" <rena_delbridge@legis.state.ak.us>; Renan Yanish <renan@astercanyon.com>; Robert Brelsford <robert.brelsford@argusmedia.com>; Robert Campbell <Robert.Campbell@reuters.com>; Ryan Tunseth <ryan_tunseth@xtoenergy.com>; Scott Cranswick <scott.cranswick@mms.gov>; Scott Griffith <scott_griffith@xtoenergy.com>; Shannon Donnelly<shannon.donnelly@conocophillips.com>; Sharmaine Copeland <copelasv@bp.com>; "Shellenbaum, Diane P (DNR)" <diane.shellenbaum@alaska.gov>; "Slemons, Jonne D (DNR)" <jonne.slemons@alaska.gov>; Sondra Stewman <StewmaSD@BP.com>; Stephanie Klemmer <sklemmer@hilcorp.com>; "Moothart, Steve R (DNR)" <steve.moothart@alaska.gov>; Steven R. Rossberg <RossbeRS@BP.com>; Suzanne Gibson <sgibson@ciri.com>; "sheffield@aoga.org" <sheffield@aoga.org>; "Davidson, Temple (DNR)" <temple.davidson@alaska.gov>; Teresa Imm <timm@asrc.com>; Thor Cutler <Cutler.Thor@epamail.epa.gov>; Tim Mayers <mayers.timothy@epa.gov>; Tina Grovier <tgrovier@BHB.com>; Todd Durkee <todd.durkee@anadarko.com>; Tony Hopfinger <topfinger@gci.net>; trmjr1 <trmjr1@aol.com>; Vicki Irwin <virwin@kakivik.com>; Walter Featherly <WFeatherly@Patton Bog gs.com>; "yj rose n @ak. net" <yjrosen@ak.net> Sent: Thursday, November 8, 2012 9:30 AM Subject: Public Notice Umiat.pdf - Adobe Acrobat Professional 0 0 r� • STATE OF ALASKA NOTICE TO PUBLISHER Vw ADVERTISING ORDER NO. ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF /� �� w�ol�� AO-OnG 4 F G ORDER ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE BOTTOM FOR INVOICE ADDRESS F AOGCC AGENCY CONTACT DATE OF A.O. November 7, 2012 R D 333 W 7th Ave, Ste 100 Anchorage, AK 99501 Jody Colombie PHONE PCN M DATES ADVERTISEMENT REQUIRED: November 18, 2012 o Alaska Journal of Commerce 301 Arctic Slope Avenue, Suite 350 Anchorage AK 99518 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Type of Advertisement SEE ATTACHED DIO-12-003 SEND INVOICE IN TRIPLICATE TO AOGCC, 333 W. 7th Ave., Suite 100 Anchora e AK 99501 PAGE 1 OF 2 PAGES TOTAL OF ALL PAGES$ REF TYPE NUMBER AMOUNT DATE COMMENTS 1 VEN 2 ARD 02910 FIN AMOUNT SY CC PGM LC ACCT FY NMR DIST LID 1 12 02140100 73451 z REQUI IT10 7L" I DIVISION APPROVAL: 02-902 (Rev. 3V+ v YuTilisher/Original Copies: Department Fiscal, Department, Receiving AOTRM Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Docket No. DIO-12-003. Linc Energy Operations, Inc. has applied for a Disposal Injection Order (DIO) for well Umiat DSP-01, located within the Umiat Field, Northeast NPR -A, Alaska. The DIO — if approved — would authorize the injection of used drilling mud and other Underground Injection Control program Class II eligible fluids into the Torok formation in the Umiat field penetrated by Umiat DSP-01. The Surface, Injection, and Bottomhole locations of Umiat DSP-OIare as follows: Surface: 839 ft FSL, 1189 ft FEL Section 5, T1 S, R1 W, U.M. Top of Injection: 158 ft FSL, 764 ft FEL, Section 5, T1S, R1W, U.M. Bottomhole: 59 ft FNL, 628 ft FEL Section 8, TIS, R1 W, U.M. The Commission has tentatively scheduled a public hearing on this application for December 18, 2012 at 9:00 a.m. at the Alaska Oil and Gas Conservation Commission, at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, a written request must be filed with the Commission no later than 4:30 p.m. on December 4, 2012. If a request for a hearing is not timely filed, the Commission may consider the issuance of an order without a hearing. To learn if the Commission will hold the hearing, call 793- 1221 after December 6, 2012. In addition, written comments regarding this application may be submitted to the Alaska Oil and Gas Conservation Commission, at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on December 18, 2012, except that, if a hearing is held, comments must be received no later than the conclusion of the December 18, 2012 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the Commission's Special Assistant, Jody Colombie, at 793-1221, no later than December 10, 2012. Cathy P oerster Chair, Commissioner E • STATE OF ALASKA ADVERTISING ORDER SEE BOTTOM FOR " I AOGCC NOTICE TO PUBLISHER ADVERTISING ORDER NO. INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED �AO-02-3-14-023 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE R 333 West 71h Avenue. Suite 100 0 Anchorage. AK 99501 M T Alaska Journal of Commerce 0 301 Arctic Slope Avenue, Suite 350 Anchorage AK 99518 RECEIVED NOV 2 0 2012 AQGCCDATES AGENCY CONTACT Jody Colombie DATE OF A.O. November PHONE PCN ADVERTISEMENT REQUIRED: November 18, 2012 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: AFFIDAVIT OF PUBLICATION United states of America State of Alaska ss Third Judicial division. Before me, the undersigned, a notary public this day personally appeared Tracy Allison who, being first duly sworn, according to law, says that he/she is REMINDER INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. ATTACH PROOF OF PUBLICATION HERE. Notice of Public Hearing the Circulation Manager of The Alaska Journal of Commerce Published at STATE OF ALASKA Alaska Oil and Gas Conservation Anchorage in said division Third Judicial District and state of Alaska Commission Re: Docket No. DIO-12-003. Line En - and that the advertisement, of which the annexed is a true copy, was publishE ergy Operations, Inc. has applied for a Disposal Injection Order (DID) for thin the in said publication on the Eighteenth day of November 2012, and thereafter f Um atlField, Northeast NPR-A,miat DSP-01, locatedI Alaska. The DID - if approved - would author - consecutive days, the last publication appearing on the Eighteenth day 1 ize the injection of used drilling mud and other Underground Injection Con- trol program Class II eligible fluids November 2012, and that the rate charged thereon is not in excess of the rat, into the Torok formation in the Umiat field penetrated by Umiat DSP-01. charged priva in ividuals. ^ The locations Um at DSP 01 Injection, Bottom- holare as ---- i follows: Surface: 839 ft FSL, 1189 ft FEL Sec- tion 5, T1S, Ri W, U.M. Top of Injection: ft FSL, 764 ft Subscribed and sworn to before me FEL, Section 5, T1S, R1W, U.M. Bottomhole: 59 ft FNL, 628 ft FEL This 19th day of November 2012, Section 8, T1S, RIW, U.M. The Commission has tentatively scheduled a public hearing on this ap- plication for December 18, 2012 at Notary public for state of Notary Public 9:00 a.m. at the Alaska Oil and Gas Conservation Commission, at 333 BELINDA CUMMINGS My commission expires State of Alaska West 7th Avenue, Suite 100, Anchor - age, Alaska 99501. To request that My Commission Expires Jun 14, 2016 the tentatively scheduled hearing be held, a written request must be filed with the Commission no later than 4:30P.m. on December 4, 2012. If a request for a hearing is not timely tiled, the Commission may consider the issuance of an order without a hearing. To learn if the Commission will hold the hearing, call 793-1221 after December 6, 2012. In addition, written comments regard- ing this application may be submitted to the Alaska Oil and Gas Conserva- tion Commission, at 333 West 7th- Avenue, Suite 100, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on December 18, 2012, except that, it a hearing is held, comments must be received no later than the conclusion of the De- cember 18, 2012 hearing. If, because of a disability, special ac commodations may be needed to comment or attend the hearing, con- tact the Commission's Special Assis- tant, Jody Colombie, at 793-1221, no later than December 10, 2012. By:/s/Cathy P. Foerster Chair, Commissioner Pub:11/18/2012. Ad#10169560 f ! STATE OF ALASKA NOTICE TO PUBLISHER ADVERTISING ORDER NO. ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED A 0�02�•�� 1 A�On� AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF /1 G `t G ORDER ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE BOTTOM FOR INVOICE ADDRESS F AOGCC AGENCY CONTACT DATE OF A.O. R 333 West 7th Avenue. Suite 100 0 Anchorage_ AK 99501 PHONE PCN M DATES ADVERTISEMENT REQUIRED: o Alaska Journal of Commerce November 18, 2012 301 Arctic Slope Avenue, Suite 350 Anchorage AK 99518 United states of America State of THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: AFFIDAVIT OF PUBLICATION REMINDER SS INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. division. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. Before me, the undersigned, a notary public this day personally appeared ATTACH PROOF OF PUBLICATION HERE. who, being first duly sworn, according to law, says that he/she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2012, and thereafter for consecutive days, the last publication appearing on the day of , 2012, and that the rate charged thereon is not in excess of the rate charged private individuals. Subscribed and sworn to before me This _ day of 2012, Notary public for state of My commission expires - Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston St., Ste. 200 5333 Westheimer, Ste.100 Denver, CO 80201-3557 Ft. Worth, TX 76102-6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton in 40818 St. President 6900 Arctic Blvd. Golden, CO 80401-2433 P.O. Box 1655Colorado Anchorage, AK 99502 Springs, CO 80901 Bernie Karl CIRI Baker Oil Tools K&K Recycling Inc. Land Department 795 E. 94`n Ct. P.O. Box 58055 P.O. Box 93330 Anchorage, AK 99515-4295 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Richard Wagner Gordon Severson Planning Department P.O. Box 60868 3201 Westmar Cir. P.O. Box 69 Fairbanks, AK 99706 Anchorage, AK 99508-4336 Barrow, AK 99723 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchik, AK 99639 Soldotna, AK 99669 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 • • Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, November 08, 2012 9:30 AM To: Singh, Angela K (DOA); Ballantine, Tab A (LAW); Brooks, Phoebe L (DOA); Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Ferguson, Victoria L (DOA); Fisher, Samantha J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Bender, Makana K (DOA); McIver, Bren (DOA); McMains, Stephen E (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Wallace, Chris D (DOA); Aaron Gluzman; Aaron Sorrell; Bruce Williams; Bruno, Jeff J (DNR); caunderwood@marathonoil.com; Casey Sullivan; Dale Hoffman; David Lenig; Donna Vukich; Eric Lidji; Erik Opstad; Franger, James M (DNR); Gary Orr; Smith, Graham O (PCO); Greg Mattson; Heusser, Heather A (DNR); James Rodgers; Jason Bergerson; Jennifer Starck; jill.a.mcleod@conocophillips.com; Joe Longo; King, Kathleen J (DNR); Lara Coates; Lois Epstein; Marc Kuck; Steele, Marie C (DNR); Matt Gill; Melissa Okoola; Ostrovsky, Larry (DNR sponsored), Bettis, Patricia K (DOA); Perrin, Don J (DNR); Peter Contreras; Pexton, Scott R (DNR); Richard Garrard; Ryan Daniel; Sandra Lemke; Talib Syed; Terrace Dalton; Wayne Wooster; Woolf, Wendy C (DNR); William Hutto; William Van Dyke;(michael.j.nelson@conocophillips.com); AKDCWelllntegrityCoordinator; alaska@petrocalc.com; Anna Raff; Barbara F Fullmer; bbritch; bbohrer@ap.org; Bill Penrose; Bill Walker; Bowen Roberts; Bruce Webb; Claire Caldes; Cliff Posey; Crandall, Krissell; D Lawrence; Daryl J. Kleppin; Dave Harbour; Dave Matthews; David Boelens; David Duffy; David House; Scott, David (LAA); David Steingreaber; Davide Simeone; ddonkel@cfl.rr.com; Elowe, Kristin; Francis S. Sommer; Gary Laughlin; schultz, gary (DNR sponsored); ghammons; Gordon Pospisil; Gorney, David L.; Greg Duggin; Gregg Nady; Gregory Geddes; gspfoff; Jdarlington Qarlington@gmail.com); Jeanne McPherren; Jones, Jeffery B (DOA); Jerry McCutcheon; Jill Womack; Jim White; Jim Winegarner; Joe Lastufka; news@radiokenai.com; Easton, John R (DNR); John Garing; John Spain; Jon Goltz; Jones, Jeffrey L (GOV); Judy Stanek; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty; Kaynell Zeman; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Luke Keller; Marc Kovak; Mark Dalton; Mark Hanley (mark.hanley@anadarko.com); Mark P. Worcester; Kremer, Marguerite C (DNR); Michael Jacobs; Mike Bill; mike@kbbi.org; Mike Morgan; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; knelson@petroleumnews.com; Nick W. Glover; NSK Problem Well Supv; Patty Alfaro; Decker, Paul L (DNR); Paul Figel; Paul Mazzolini; Randall Kanady; Randy L. Skillern; Delbridge, Rena E (LAA); Renan Yanish; Robert Brelsford; Robert Campbell; Ryan Tunseth; Scott Cranswick; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Sondra Stewman; Stephanie Klemmer; Moothart, Steve R (DNR); Steven R. Rossberg; Suzanne Gibson; sheffield@aoga.org; Davidson, Temple (DNR); Teresa Imm; Thor Cutler; Tim Mayers; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjr1; Vicki Irwin; Walter Featherly; yjrosen@ak.net Subject: Public Notice Umiat.pdf - Adobe Acrobat Professional Attachments: Public Notice Umiat.pdf 0 0 • 0 RECEIVED NOV 0 1 AOGGG Application for Disposal Injection Order UMIAT EXPLORATION National Petroleum Reserve — Alaska Disposal Well: Umiat DSP-01 Ll nc EIIERGY Linc Energy Operations, Inc. 3000 C Street Suite 103 Anchorage, Alaska 99503 November 1, 2012 • Umiat Dispu�al Injection Order Application November 1, 2012 Table of Contents 1.0 INTRODUCTION.................................................................................................................................3 2.0 WELL LOCATIONS..............................................................................................................................4 3.0 SURFACE OWNERS AND OPERATORS................................................................................................7 3.1 Offset Surface Owners and Operators..........................................................................................7 3.2 Affidavit for Offset Operators and Surface Owners......................................................................8 4.0 GEOLOGIC DETAILS..........................................................................................................................10 4.1 Umiat Geologic Overview and Description of Disposal Zone......................................................10 4.2 Geologic Data on Disposal and Confining Zones.........................................................................12 4.3 Seismic Interpretation of Disposal and Confining Zones............................................................13 5.0 WELL LOGS......................................................................................................................................14 5.1 Selection of the Disposal Zone....................................................................................................14 5.2 Proposed Umiat DSP-01 Open -Hole Logs....................................................................................15 5.3 Proposed Umiat DSP-01 Cased -Hole Logs...................................................................................15 6.0 WELL CONSTRUCTION.....................................................................................................................16 6.1 Proposed Casing Program...........................................................................................................16 6.2 Proposed Directional Plan...........................................................................................................18 7.0 WASTE TYPES, SOURCES, AND COMPATIBILITY..............................................................................18 8.0 INJECTION PRESSURES AND RATES.................................................................................................21 9.0 WASTE CONFINEMENT....................................................................................................................21 9.1 Disposal Zone Fracture Analysis..................................................................................................21 10.0 WATER SALINITY..............................................................................................................................27 11.0 AQUIFER EXEMPTION......................................................................................................................29 12.0 AREA OF REVIEW.............................................................................................................................29 12.1 Seabee Test Well No.1................................................................................................................29 12.2 Wells within a % Mile Radius.......................................................................................................29 P a g e I Umiat Dispfal Injection Order Application November 1, 2012 List of Figures Figure1— Regional Map................................................................................................................................4 Figure 2 — Umiat Area and Seabee Location.................................................................................................5 Figure3 — Seabee Pad...................................................................................................................................6 Figure 4 — Proposed Umiat Wells for 2012-13 Season..................................................................................6 Figure 5 —Surface Owners and Operators near Umiat.................................................................................7 Figure 6 — Seabee Test Well No.1 electric log display of proposed disposal zone and confining layers ....11 Figure 7 — Proposed Umiat DSP-01 Wellbore Schematic............................................................................17 List of Tables Table 1— Umiat DSP-01 PROJECTED Disposal and Confining Zone Depths................................................10 Table 2 — FracproPT Fluid Properties..........................................................................................................22 Table 3 — Fracture Modeling for Perforations at the Top of the Disposal Interval.....................................23 Table 4 — Fracture Modeling for Perforations at the Top of the Upper Porous Sand.................................24 Table 5 — Fracture Modeling for Perforations at the Base of the Lower Porous Sand...............................25 Table 6 — Fracture Modeling for Perforations at the Base of the Disposal Interval....................................26 List of Attachments Attachment 1— Umiat DSP-01 Directional Plan Attachment 2 — FracproPT Fracture Modeling Outputs Attachment 3 — Seabee Test Well No.1, DST #3 Water Analysis Report Attachment 4 —Seabee Test Well No.1 Due Diligence Summary with Schematic Attachment 5 — Seabee Test Well No.1 Water Salinity Log Pa ;e 12 Umiat Distal Injection Order Application November 1, 2012 1.0 INTRODUCTION The following Disposal Injection Order (DIO) application details Linc Energy Operations, Inc.'s (Linc's) plans for the 2012/2013 winter Umiat exploration program disposal well. The 2012/2013 exploration drilling program is being conducted to achieve the following objectives: • Drill a disposal well (Umiat DSP-01) to handle the first exploration season fluids as well as the second season fluids and drilling solids. • Drill one (1) vertical shallow oil exploration/delineation well (Umiat #16) through the Upper and Lower Grandstand formations. • Skid the rig a minimal distance and drill a second Lower Grandstand horizontal well (Umiat #16H). • Drill one (1) deeper (-6,500 ft MD) well (Umiat #23), targeting potential gas pay in the Torok formation. This deeper well will likely be plugged back to the shallow Lower Grandstand formation. • Flow test both of the shallow Grandstand wells using artificial lift into a well test unit. • Depending upon results (shows, electric logs, etc.) from the deeper well (and available time), flow tests of potential Torok pay may also be conducted. • Recover core and log data to add to and supplement the available Umiat data gathered by the U.S. Navy in the 1940's and 1950's. The Umiat reservoir was discovered by the U.S. Navy in the late 1940's, during early exploration in the Naval Petroleum Reserve #4. The Naval Petroleum Reserve #4 is now under the direction of the Bureau of Land Management, and is now called the National Petroleum Reserve — Alaska (NPR -A). Umiat production tests found a light, 37' API gravity oil in several shallow reservoirs, much of which is within the permafrost. The largest accumulations were found in the Lower and Upper Grandstand members of the Nanushuk Formation. Due to the low bottom -hole pressure and low associated gas volumes, methods for extracting the oil have focused on pressure maintenance and artificial lift methodology. These exploratory wells are being drilled to increase the knowledge of the Upper and Lower Grandstand oil accumulations (and reservoirs), and to gain critical information necessary for any potential shallow oil development scenario. Umiat is located along the Colville River, approximately 88 miles west of Pump Station #2, 105 miles southwest of Deadhorse, 64 miles south of Nuiqsut, 86 miles north of Anaktuvuk Pass, and 170 miles southeast of Barrow. A regional map of the Umiat area is found in Figure 1. i>aFe 13 Umiat Disp .al Injection Order Application November 1, 2012 Figure 1— Regional Map 2.0 WELL LOCATIONS The locations of all wells drilled in the Umiat area are found in Figure 2. A total of twelve wells have been drilled in the immediate Umiat area. Eleven wells (Umiat #1— Umiat #11) were drilled by the U.S. Navy between 1945 and 1952. The twelfth well, Seabee Test Well No.1 (Seabee #1, PTD 100-223), was drilled in 1979 under direction of the U.S. Geological Survey contracting to Husky Oil. The original eleven U.S. Navy wells were left un-plugged after completion. Several wells have since been plugged or had some level of remediation conducted at the wellsite (since 2002). Those wells are Umiat #2, Umiat #3, Umiat #4, Umiat #5, Umiat #6, Umiat #7, Umiat #8, Umiat #9, and Umiat #10. The remaining two Umiat wells, Umiat #1 and Umiat #11, were dry holes and no down -hole work has been performed on these wells. The Seabee #1 well was plugged back to 1,478' and filled with diesel to allow temperature logging of the well by the U.S. Geological Survey since 1980. The proposed Umiat disposal well, Umiat DSP-01, is to be drilled from the existing Seabee pad, at 839' FSL, 1,189' FEL of Section 5, T1S, R1W, Umiat Meridian. The proposed well will be located on BLM Lease I'ap(2 14 Umiat DispRal Injection Order Application November 1, 2012 AKAA-081726. Figure 4 shows the relative location of the Umiat DSP-01 disposal well, along with the other planned 2012/2013 winter exploration wells. The % mile area of review, required for this DIO application, is centered at the top of the proposed injection interval at a Umiat DSP-01 projected depth of 4,386' MD/4,426' TVD (-3,932' SSTVD). The Seabee #1 well is the only well that lies within the % mile area of review. Extending the % mile area of review out to %2 mile would also include the Umiat #9 well. This well does not penetrate the proposed disposal interval. Umiat #9 was drilled to a total depth of 1,257' MD/TVD, which is well above the proposed disposal interval top, which is projected at 4,245' TVD in the proposed disposal well (equivalent to 4,150' TVD in the Seabee #1 wellbore). Note that there are only two wells in the Umiat area, which have penetrated the proposed disposal interval. These are the Seabee #1 (included in the % mile well review) and Umiat #2, which is approximately 2.25 miles east of the proposed Umiat DSP-01 disposal well. Figure 2 — Umiat Area and Seabee Location Page 15 • Umiat Disp sal Injection Order Application November 1, 2012 PLAN VIEW Figure 3 — Seabee Pad Y- ,." *R '� i .- yr$ w`•"y `� ., �.�.}' 6l � . �.ni �fr� �J W T.r.�y'� �r a fixla'ry{ :;'l LJ"7• M ,•w"! ''S ellWell WelVe11Wk 1 `=.:.o 16H ... •«7 i` r $1 J 77 2 H is • y� X S a wr47 WeII V111. } y^` r s: r as , ADL 390'20 a f( 1 n: _ Well r .: 11wFil ! # vt� y IUmiat _ f a • Proposed Well Locations Proposed Snow Road oUnc l+Is, N "i t ® Legacy Wells — •— Ice Road across ASRC N I : A I . _1♦ Sh A O Existing Gravel Pads — Infield Ice Road v1 fi Water Soiree Lakes — Gravel Road Vicinity Map Federal BLfd Lease ----- Lake Access Road 2012-2013 Winter Season State of Alaska Lease — Airstrip Northeast NPR -A, North Slope. Alaska l=J ADOUPF Airport Boundary ® Native Allotment c DOMAc Page 1i# NA683 UTU Zone 5 Figure 4 — Proposed Umiat Wells for 2012-13 Season Pape 16 Umiat Dispfal Injection Order Application November 1, 2012 3.0 SURFACE OWNERS AND OPERATORS The Bureau of Land Management (BLM) is the only surface owner within a % mile radius of the proposed disposal well. Similarly, Linc Energy is the only operator within this same % mile radius of the proposed disposal well. Figure 5 shows a % mile radius drawn around the planned Umiat DSP-01 well. Figure 5 — Surface Owners and Operators near Umiat 3.1 Offset Surface Owners and Operators The nearest surface owner other than the BLM is the Alaska Department of Transportation and Public Facilities (AKDOT&PF) lands that surround the Umiat Camp and Runway (yellow outline in Figure 4 and gray box in Figure 5). The boundary is located approximately 2,475' from the surface location of Umiat DSP-01. At total depth, the wellbore will be located approximately 1,416' from the boundary of AKDOT&PF lands. There is also ASRC land located about 2.3 miles from the proposed disposal well to the southeast on land that is located along the Colville River in Section 16, T1S, R1W Umiat Meridian. Page 17 Umiat Dispa"sal Injection Order Application November 1, 2012 The nearest operator other than Linc Energy is Anadarko/Petro Canada, located about 1.75 miles from the proposed disposal well to the west on lease AKAA-090724. 3.2 Affidavit for Offset Operators and Surface Owners Regulation 20 AAC 25.252 (c)(3) Affidavit showing that the operators and surface owners within a one - quarter mile radius have been provided a copy of the application for disposal or storage: Per regulation 20 AAC 25.252 (c)(3), this affidavit confirms that all surface owners and operators within mile of the proposed Umiat DSP-01 disposal well (as listed in section 3.1 above), have been provided a copy of this application for a Disposal Injection Order. This includes the Bureau of Land Management and the Alaska Department of Transportation & Public Facilities. PaV,e 18 0 Umiat Dispoaal Injection Order Application November 1, 2012 Affidavit of Corri Feige STATE OF ALASKA THIRD JUDICIAL DISTRICT I, Corri Feige, declare and affirm as follows: I am over 19 years of age. I am employed by Linc Energy Operations, Inc. as General Manager — Alaska. 2. 1 have personal knowledge of the matters set forth in this affidavit. 3. On November 1, 2012, the surface owners and operators listed in section 3.1, of this Disposal Injection Order application, were provided a copy of this permit application. DATED at Anchorage, Alaska this 1st day of November. 2012. Corri Feige, General Mana r —Alaska Linc Energy Operations, Inc. Subscribed and affirmed before me at Anchorage, Alaska on November 1, 2012. Notary Public COLEEN LEONARD State of Alaska My Commission Expires May 29, 2014 41 Notary Public in and for the State of Alaska My commission expires: Page 19 Umiat Dispersal Injection Order Application November 1, 2012 4.0 GEOLOGIC DETAILS 4.1 Umiat Geologic Overview and Description of Disposal Zone The proposed disposal interval is within the early Cretaceous (Aptian-Cenomanian) Torok Formation, which is a deep water marine formation within the greater Brookian sequence of the North Slope. Locally, the Torok Formation has been subdivided into an upper siltstone and sandstone member and a lower siltstone and shale member. In the Seabee #1 well, the upper siltstone/sandstone member is approximately 1,975 feet thick and the lower siltstone/shale member approximately 900 feet thick. The gross interval of the proposed disposal zone is approximately 650 feet thick and is situated within the upper siltstone/sandstone member of the Torok Formation. This disposal zone is projected to lie between the depths of 4,245' - 4,895' TVD (-3,932' --4,582' SSTVD), in the proposed Umiat DSP-01 well. Note that this disposal zone has the equivalent depths of 4,150' - 4,800' TVD (-3,828' --4,478' SSTVD) in the Seabee #1 well. Table 1 lists the Umiat DSP-01 projected depths and equivalent Seabee #1 depths, for the proposed disposal zone, as well as for the upper and lower confining intervals. Figure 6 is the Seabee #1 log section, showing the proposed disposal zone and confining intervals. Umiat DSP-01 Disposal & Confining Zones - PROJECTED Depths Seabee Test Well No.1 Umiat DSP-01(Projected) ft MD ft TVD ft SSTVD ft MD ft TVD ft SSTVD Upper Confining Zone Top 3,550 3,550 -3,228 3,743 3,645 -3,332 Base 4,150 4,150 -3,828 4,386 4,245 -3,932 Disposal Zone Top 4,150 4,150 -3,828 4,386 4,245 -3,932 Upper Porous Top 4,410 4,410 -4,088 4,664 4,505 -4,192 Interval Base 4,500 4,500 -4,178 4,760 4,595 -4,282 Lower Porous Top 4,620 4,620 -4,298 4,889 4,715 -4,402 Interval Base 4,675 4,675 -4,353 4,948 4,770 -4,457 Disposal Zone Base 4,800 4,800 -4,478 5,082 4,895 -4,582 Lower Confining Zone Top 4,800 4,800 -4,478 5,082 4,895 -4,582 Base 5,150 5,150 -4,828 5,457 5,245 -4,932 Ground Level Elevation 292 ft 292 ft Rotary Kelly Bushing Elevation (RKB) 322 ft 313 ft Table 1- Umiat DSP-01 PROJECTED Disposal and Confining Zone Depths F'a�e 110 Umiat Disposal Injection Order Application November 1, 2012 ']►t E= "ITTIVIIIIII L U.III ' INCH ■null i13' �" rnlill ■null _=t�lll ■/IIIN ■oft-7:miiz�_■_�i,�� '�Illllf ■/11111 �_ ..!fl ■/IIIII ■tea -�_C`--�i Cam—'— �—�--�i •�/11111 ■/11111 r'_illll ■Illlll ■��.�!' ��■Il��■� � ��/Ulil ■/11111►�llllll ■/tllll ■��■ii- i■��■�� E E,� 1 1 �/11111 ■111111'sllllll ■/Illll ■� ■�F ��C■i--- r E Ei�/11f11 ■IIIIII 0111111 ■Illlll ■�' ��■�i=�� F,d M ■/lull ,�iIllifl ■/III{I ■ _�o�;l EC■�.F � � E i�Illlll ■/IIIII r�llllll ■Illlll ■ r.."'!I• IFS �i I�1111{I ■111111.1111111 ■Illlll ■ !� E �� 1 • null ■11111! i111111 ■IIIIII ■ ��I�I�! ttttlttt�� !'`,i E :�Illl(I ■IIIIII : ;/11111 ■IUlil ■�r"t! ■■F"'1� E! Is !�1111lI ■IIIIII �Illfll ■nullam-s ly Wil rE'�/IIIN ■Mill III11111 ■null ■■E ■1� . ., ■� ; 1 • 111Uf1 ■IIIIII tlllllli ■11t1{I ■� ai�i i1� F� �:�Illfll ■/lull ■Illlll ■/lull ■�[-�� ._. �,� �� s Ei�llllll ��IIIlI #IIIIII L�1,11�`��R � �4� sr��i-�_ 1 ..�nlll ■�tnll . �t�ln ■�ttllt ■�r��. ., ... - '�_ ■� . 1 . I;Illlll 01111112111111 t■Ililil ■�■ 1wer Confining Layer1� t� �Mi Illlll ■Illlll MUM■lllill ■�MC_�=' �,� ��S ��.•�II ! i111 .■�� Illfil ■/illl. ■IIIIII ■/IINI ■� "M �-.rl•"��J Illlll ■Illlll ��Ifll ■1111A ■�i=�� .�� Wl IL JIlgiligiiiii.Trr,111111 Milli ■111111 ■111111 ■fit J§lL6_ ij� .M®®�Illill ■/llli ■/HI{I ■Illlll ■�F �� i �� ■M� C -'!�� /II(II ■nlll ■lllill ■Illlll ■�E Ant � a� E'! A11 milli, mill lfl ■Illlll E ■ �� M AE ■m III ■Illli'. ■Illlll ■Illlll E'er -'UM � ■ EW-Mi �� • • • fl ■1t111' ■Illlll ■Illlll � Mom: �� ■� � : ?ram r��■illlittr�� ■iiiii�.�� Figure 6 — Seabee Test Well No.1 electric log display of proposed disposal zone and confining layers In general, the upper Torok member is dominated by micaceous, slightly carbonaceous siltstone interbedded with relatively thin, very fine to fine grained, micaceous, carbonaceous sandstone. Herein sandstone beds on the order of 6 feet or less are locally interbedded with thin interbeds of siltstone and silty shale. The disposal zone is bracketed or encased by an upper —600 foot confining layer, projected at 3,645' — 4,245' TVD, in the Umiat DSP-01 well (3,550' — 4,150' TVD, in Seabee #1) and a lower —350 foot confining layer, projected at 4,895' — 5,245' TVD, in the Umiat DSP-01 well (4,800' — 5,150' TVD, in Seabee #1). Both the upper and lower confining layers identified in the Seabee #1 well, and projected in the Umiat DSP-01 well, are expected to have continuity across the Umiat structure. Interpretation of the 3D Seismic data gathered across the Umiat structure, shows the continuity of these strata. The seismic data shows that the relative thickness of the disposal zone (and confining intervals) is similar in the proposed Umiat DSP-01 bottom -hole location, as compared to the Seabee #1 well. The seismic interpretation Page 111 Umiat Dispersal Injection Order Application November 1, 2012 indicates that the confining and disposal intervals will be encountered approximately 95' TVD down -dip of the Seabee #1 well. There are two distinctive porous intervals within the proposed disposal zone, as seen in the Seabee #1 wellbore. The upper porous interval is roughly 90 feet thick and lies between 4,410' and 4,500' TVD, in the Seabee wellbore. This upper porous interval has a projected depth of 4,505' — 4,595' TVD (-4,192' — -4,282' SSTVD) in the planned Umiat DSP-01 disposal well. The lower porous interval is roughly 55 feet thick and lies between 4,620' and 4,675' TVD, in the Seabee #1 wellbore. This lower porous interval has a projected depth of 4,715' — 4,770' TVD (-4,402' —-4,457' SSTVD) in the planned Umiat DSP-01 well. Sandstone within the upper porous zone is very fine to fine grained, moderately sorted, argillaceous, carbonaceous and displays a dull gold cut fluorescence. The character of the lower porous zone is similar but less sandy as defined by gamma ray and resistivity response. Density, neutron and sonic data indicate an improvement in porosity and apparent permeability within these zones. Based upon cuttings and electric log data, sandstone porosity ranges from 6% to 12%, with the better porosities residing in the upper porosity zone. Core data is not available to accurately define permeability parameters but it is suspected to range from less than 1 and to 5 md. The confining layers, both above and below the disposal zone, are characterized by thin interbeds of largely impervious siltstone, silty shale and minor, thin very fine grained sandstone stringers. It should be noted that there are indications of faulting within the Seabee #1 wellbore, as evidenced by repeated sections seen in the well logs. These repeat sections do not occur in either the proposed disposal zone or in the upper or lower confining intervals, within the Seabee #1 well. 4.2 Geologic Data on Disposal and Confining Zones Overall the confining layer sequences are tight and appear largely impervious to any significant fluid flow. It should be noted that both the disposal zone and the upper and lower confining layers have been subjected to the same stress/strain regime that led to the formation of the Umiat Anticline. Fractures appear associated with these episodes of folding and faulting, and based on cuttings data are apparent in the confining layers. Mudlog cuttings data indicates fracture fill to be quite common, siting typical descriptions such as; "trace calcareous filled fractures", "trace anhydrite filled fractures", "calcareous vein", and "fracture fill". Hard rock data, however, from Torok sidewall and conventional core indicates that most of the fractures produced during tectonic events are healed and closed largely by calcite fill and other mineralization. It is also probable that fault surfaces themselves are healed largely by fault gouge and mineralization. These conditions also conform to surface outcrop observations. Note that no cores were cut across the proposed confining and disposal zones, either in the Seabee #1 wellbore, or in the equivalent depths in any of the legacy Umiat wells. Geologic data is limited to mud cuttings, historic outcrop observations, and literature from other Torok penetrations on the North Slope. Although the proposed disposal zone interval and confining layers were not cored in the Seabee #1 well, elsewhere in the cored Torok the presence of fractures is very common, especially in the shaly intervals. Mineralization, as stated before in the proposed disposal zone and confining layer descriptions, appears Pa -, 1 i 112 • Umiat DispPal Injection Order Application November 1, 2012 common in the cuttings. Elsewhere in the Torok, core data indicates that mineralization by quartz, calcite, and solid (bitumen) hydrocarbon fill is common. In outcrop the Torok behaves very incompetently and is readily deformed into complex folds. The Torok actually serves as a decollement surface for faulting effecting deformation of the overlying, more competent Nanushuk group. It is expected that in a formation with a high shale to sand ratio that fault gouge or shale smear would be encountered along fault surfaces. Although faults were not cored in the Seabee #1 well, gouge or smear along fault surfaces is expected and, indeed, has been observed in surface exposures. For a more complete description of surface lithologies, refer to: USGS Professional Paper 303 "Geology of the Chandler River Region, Alaska" 1963. In summary, the confining layers above and below the proposed disposal zone are typified by largely tight silt and shale prone lithologies which, although affected by a complex of mostly healed fractures and minor faults, remain as sound vertical barriers to fluid flow from the disposal zone. 4.3 Seismic Interpretation of Disposal and Confining Zones As previously mentioned, 3D seismic data (shot in 2007/2008 by Renaissance Alaska, LLC) was interpreted across the Umiat area. This interpretation showed that the disposal zone and confining intervals are continuous across the Umiat Structure. The seismic data also showed that the disposal zone and confining intervals remain relatively constant in thickness and that the Umiat DSP-01 projected penetration depth is approximately 95 feet (TVD) down -dip of the penetration point in the Seabee #1 wellbore. In regards to faulting, the seismic data indicates: 1. The main Umiat fault (north of the Seabee #1 wellbore) should be at a depth of 9,100' to 10,000' TVD, in the Seabee #1 area. There is also a minor fault south of the wellbore. 2. The main East-West Umiat fault has a displacement of roughly 1,000 feet. The minor fault south of the Seabee #1 wellbore has a displacement of approximately 170 feet. 3. With respect to the proposed Umiat DSP-01 disposal well, the main Umiat fault is approximately 3,275' to the north of the planned bottom -hole location. The minor fault to the south of the proposed wellbore is approximately 3,100 feet from the planned bottom -hole location. 4. With respect to the projected disposal zone in the planned Umiat DSP-01 well, the main Umiat fault is approximately 3,600' from the base of the disposal horizon. The throw of the minor fault to the south of the planned disposal well is below the resolution of the seismic, so it's difficult to detect the fault. One possible projection to where the fault may occur would place it at a distance of about 3,250' away from the planned Umiat DSP-01 wellbore, at the base of disposal zone. 5. No faults were detected on the seismic, within the planned disposal well. 6. The resolution of the seismic data at the level of the confining and disposal zone depths is between 80 and 100 feet. P a cc 113 • Umiat Dispersal Injection Order Application November 1, 2012 5.0 WELL LOGS Well and mud logs from the offset Seabee #1 well were used to determine the proposed disposal zone and confining intervals. Figure 6 shows the disposal and confining zones within the Seabee #1 wellbore. Information gathered from these logs includes Gamma Ray, Resistivity, Density, Neutron, and Sonic measurements. These open -hole logs came from logging runs made on 4/29/79, 5/01/79, 6/22/79, 1/20/80 and 2/23/80. In addition to the open -hole logs, cased -hole cement bond logs, run on 11/27/79 and 1/26/80, were also evaluated. The Seabee #1 logs are already on file with the Alaska Oil and Gas Conservation Commission, so they were not included with this DIO application. 5.1 Selection of the Disposal Zone The proposed disposal zone was chosen based upon the formation characteristics seen in the Seabee #1 wellbore. Specifically, drilling records (including the drilling mudlog) and electric logs indicate that the interval between 4,150' — 4,800' TVD (-3,828' —-4,478' SSTVD) in the Seabee #1 wellbore, does not contain commercial quantities of hydrocarbons, and has adequate porosity, permeability, and gross rock volume to serve as a disposal zone. In general, the entire proposed disposal zone can be characterized by: • Low porosity (6 — 12%) • Relatively constant separation between the Neutron and Density curves • No Neutron / Density porosity cross -over • Relatively low permeability (based upon low porosity, and lack of flow into wellbore) • Low resistivity 14 — 20 ohms • Fairly consistent background gas, recorded on the mudlog (slightly higher recorded gas over 4,455' — 4,500' TVD) • No significant gas flow during drilling operations (no gas kicks recorded, did not have to weight up the mud to control the well, etc.) The only interval within the gross proposed disposal zone, which may appear questionable regarding potential gas, is the interval from approximately 4,455' — 4,500' TVD (in the Seabee #1 wellbore). The mudlog over these depths shows elevated gas and the resistivity curve increases from approximately 14 ohms to about 20 ohms. Linc Energy does not believe this interval holds commercial quantities of gas, for the following reasons: 1. The resistivity across the interval 4,455' — 4,500' TVD, does climb to about 20 ohms (from —14 ohms), but is still very low as compared to the deeper Torok interval (5,380' — 5,390' TVD) that successfully tested gas. This deeper Torok interval has a resistivity of roughly 35 ohms. 2. The interval 4,455'— 4,500' TVD is very tight in the Seabee #1 wellbore. Even though the entire disposal zone has porosities ranging from 6-12%, this 45' (slightly higher resistivity) section only has porosities from 6-7%. It appears very shaly and is some of the tightest rock within the disposal zone. Compare this to the 15-18% porosity that was measured across the 5,388' interval that flow tested gas. 3. The Neutron and Density curves show relatively constant separation across this interval. The presence of gas should cause the Density response to increase and the Neutron response to decrease. Both the Neutron and Density curves decrease across this interval. Compare this to Page 114 Umiat Disp�"sal Injection Order Application November 1, 2012 the porosity log responses across the 5,388' interval that flow tested gas. This deeper Torok interval shows the classic Neutron and Density response due to the presence of gas in the pore space. 4. The drilling reports do not indicate any gas kicks or flow problems across this 4,455' — 4,500' TVD interval. This hole section was drilled with 10.1 ppg mud and Husky Oil did not have to weight up the mud to control the well. Compare this to the 5,388' interval that flow tested gas. Husky reported that they had significant gas entering the wellbore and they weighted up to 14.3 ppg mud to control the well. 5. Although the mudlog shows elevated gas across this 4,455' — 4,500' TVD interval, there weren't any pentanes (CS s) recorded, as compared to the 5,388' interval that flow tested gas. The 5,388' interval showed a significant amount of the heavier pentane molecules. Based upon the logging and drilling response of the 4,455' — 4,500' TVD interval (as well as across the entire proposed disposal interval), as compared to the response seen/measured in the 5,388' flow tested interval, Linc does not believe that the proposed disposal interval contains commercial gas. In addition, this gross interval 4,150' — 4,800' TVD (-3,828' —-4,478' SSTVD) in the Seabee #1 wellbore has adequate confining intervals above and below. As discussed earlier (Section 4), the proposed disposal zone is capped above by roughly 600 feet of confining strata and isolated from below by approximately 350 feet of confining strata. Note that the confining intervals, both above and below the disposal zone, show consistently low resistivity between 10 and 12 ohms and low porosities ranging from 6-12%. Further supporting the choice of this disposal zone, seismic data shows lateral continuity of these intervals across the Umiat structure, making them good disposal candidates. Finally, analysis shows that the formation water across the proposed confining and disposal intervals has salinity greater than 10,000 ppm (see Section 10.0). The disposal zone was picked such that it would be below any fresh water formations (freshwater interpreted above approximately 4,004' TVD, in the Seabee #1 wellbore) and well above the 5,388' Torok interval that successfully tested gas. 5.2 Proposed Umiat DSP-01 Open -Hole Logs Open -Hole logs will be run during the drilling of the proposed disposal well. The planned open -hole logs will include Gamma Ray, Resistivity, Density, Neutron, and Sonic logs. All logs will be provided to the AOGCC. Note that Linc Energy does not intend to cut any cores in the proposed Umiat DSP-01 disposal well. 5.3 Proposed Umiat DSP-01 Cased -Hole Logs Cased -Hole logs will be run during the drilling of the proposed disposal well. These logs will include a cement bond log run in the 7" casing from PBTD to above the previous casing shoe at 1,700' MD/TVD. Pr� 115 Umiat Disp sal Injection Order Application November 1, 2012 6.0 WELL CONSTRUCTION 6.1 Proposed Casing Program The Umiat DSP-01 well will be drilled from the existing Seabee gravel pad. The well construction consists of conductor casing set at 100' TVD and cemented to surface prior to bringing in the drilling rig. Surface casing will be set at 1,700' MD/TVD and production casing set at 5,100' MD (4,912' TVD). The surface casing will be 9-5/8" 40# L-80 BTC, run in a 12-1/4" hole and cemented to surface. The production casing will be 7" 26# L-80 BTC-MOD, run in an 8-1/2" hole. The production casing will be cemented in a single stage with the tail cement of 15.8 ppg to 4,000' MD (3,885' TVD), placing this cement 150' above the top of the disposal zone. The 12.5 ppg lead cement will be at 2,000' MD/TVD, placing this cement 1,550' above the top of the confining zone. These tops of cement should provide adequate isolation to prevent movement of fluid behind pipe. To evaluate the cement bond, a cement bond log will be run from TD up to the previous casing string at 1,700' MD/TVD. The well will be completed with 3-1/2" tubing to +/- 4,600' MD (4,445' TVD), with a packer at +/- 4,500' MD (4,352' TVD). After setting the completion, the tubing will be tested to 4,000 psi and the packer (tubing x casing annulus) will be tested to 4,000 psi. Once batch injections are commenced and injection rates and pressures are tracked, the future packer pressure tests may be reduced to reflect the lower pressures needed for injection, but will not go below the required injection pressure or 1,500 psi, whichever is lower. In subsequent years, Oxygen Activation logs or Temperature Surveys will be used as the well remains in service to confirm injection of waste into the disposal zone. A baseline temperature survey and initial injectivity test will be conducted upon completion of the proposed Umiat DSP-01 well. Page 116 0 0 Umiat Disposal Injection Order Application November 1, 2012 �� tease: Seabee Graved POO , t , Tubind I9anEer: 3d/2' IBT, 3"H' BP4 e: AA-081726 [81M) Tree Cadlmeat .: 3.S' 0TI5 FRERGY Wtll Type: service jodess II Disposal) *PROPOSED* Base of Permatrolt: 1,017' MD / i,D17' TVD m�Rkb 917AN3Si asL 1Nd. ti' saa—F.- Zm -ib4s Tw Uwparl Zane - 4215 Nx D'ap—1 Zane - 4AH Nat.L-&F Zant 5,14 TD-S.LW M01991:' w0 19A' low' rw Hdslptaan saa I Tap NtM1 9e,.1W01 Tw ITM 07mfTv[.YI Mud vn a hpt tpa retYador 21- p Ma O lee V'A Y�J C ttelaa 1L1Je' O Llaa' a 3,7w WMM aJ-9A 9" 9rpaatllwr L1/2' 1,rM' 5.11,101, 1.7W 401Z MOt a.1-10.1 22" CASUA M" DATA coteteb. lsth- r iss w liar a lar a :.nr dJU �i ltall-Illdpp9 Suhp 9-S7t' a1 4tC we Lor a LSM 0 treduetew i- M L-te aTGatlD ASra' a t.tap 1,aCp ffL• tWty 3-3�=- 93 L-K tt? 2!C' d d.G.d VIA ll+wl_ LM PERFORATION DATA Olt 4trrMMn ur to 1•eA . 2VU' 9giale T9e9 N%A 7a' {,a7t ♦ata 1 2-l/1' a dptrFtrwaRRla dLIKT� tas.0-2— 41IS fW 1taY{-va, aw lot letl - 3a.r Pon M-A,ZW' Tw a,au• r1A1 Lr7r latcl • ls.a pw DATE REVISED BY: WELL 114STORY DESCRIPTION Well Nodbe Umiat OSP-01 10/21/2D12 S. P0lttola Proposed Torok Disposal zone Compwtion Spud Daft N/A APB. No. N/A P'D N/A Mav Nose Arre N/A Ma. Dc�eg N/A Figure 7 — Proposed Umiat DSP-01 Wellbore Schematic Page 117 • Umiat DispSsal Injection Order Application November 1, 2012 6.2 Proposed Directional Plan The Umiat DSP-01 disposal well will be directionally drilled. The surface location is approximately 300' from the Seabee #1 well. After vertically drilling the surface hole to 1,700' MD/TVD, the well will be directionally drilled to the south, placing the top of the disposal zone approximately 1,150' from the Seabee #1 wellbore. The proposed Umiat DSP-01 directional plan is listed in Attachment 1. 7.0 WASTE TYPES, SOURCES, AND COMPATIBILITY Umiat DSP-01 will be used for disposing of fluids only during its first year of service, and is planned to be used for disposal of slurrified cuttings in subsequent years. Disposal injection is anticipated to be made in batch injections, averaging about 1,000 bbl per batch, at rates from 2 to 6 bpm. During its first year of service, it is estimated that up to 10,000 bbl of Crude Oil from well tests, 2,000 bbl of used Mineral Oil Base Mud (MOBM) drilling mud, 1,000 bbl of used WBM drilling mud, and 2,000 bbl of water/brine from pre -and post -flushes and completion fluids will be injected. This includes small volumes of other Class II wastes such as rig wash, cement returns, cement rinsate, snowmelt, and other wastes. The source of these fluids will be the exploratory oil and gas wells drilled in Umiat during the 2012/2013 winter drilling season. During a second year of exploration, it is estimated that up to 20,000 bbl of Crude Oil from well tests, 5,000 bbl of used MOBM drilling mud, 10,000 bbl of slurrified cuttings and 4,000 bbl of water/brine from pre -and post -flushes and completion fluids will be injected. The source of these fluids will be the exploratory oil and gas wells drilled in Umiat during the 2013/2014 winter drilling season. If the Umiat oilfield is fully developed, it is estimated that the total waste volume (to be disposed of) will be no more than 1,000,000 bbl of aggregate waste over the life of this well. That waste will include those listed in Publication 530-K-01-004 (October 2002), Exemption of Oil and Gas Exploration and Production Wastes from Federal Hazardous Waste Regulations: • Drill Cuttings • Drilling Mud Returns • Rig Wash • Completion Fluid Returns • Workover or Stimulation Fluid Returns • Packer Fluid/Freeze Protection Fluid Returns • Produced Sand • Frac sand Returns • Cement Returns • Cement Rinsate • Wellhead/Tree test Fluid Returns • SCSSV or Control Line Fluid Returns Pa18 0Umiat sal Injection Order Application November 1, 2012 • Produced Crude Oil and Gases from the Production Stream • Waste Crude Oil from Primary Field Operations • Produced Water and Removed Constituents • BS&W, Tank Bottoms from Storage Facilities of Exempt Waste • Hydrocarbons, solids, sands, and emulsion from production separators and impoundments • Gas plant dehydration waste (Glycol removed from heat exchangers and dehydrators) • Cooling Tower Blowdown • Pipe Scale, hydrocarbon solids, hydrates and NORM • Sludges and Solids collecting in production lines and tanks • Pigging Waste • Hydrocarbon -bearing Soil • Water and non -hazardous cleaners used to clean pipeline or production vessel cleanouts containing downhole materials (sand, hydrates, sludge, etc.) • Water and non -hazardous cleaners used to rinse off returned fluids or solids from tools and equipment • Freeze protection fluid used to protect flow lines • Snowmelt or rainwater in contact with downhole materials, duck ponds, bermed areas, well cellars, and production impound areas associated with exploration and development activities As a part of this DIO application, Linc Energy has applied for authorization for disposal of crude oil produced during the well testing operations from the Umiat 2012/2013 and 2013/2014 winter exploration seasons. Note that it is Linc Energy's preference to re -inject the produced crude oil back down the exploration wellbore(s), into the formation (most likely the Grandstand formation) where the oil was produced from. There may however be circumstances, unique to the Umiat oilfield, which dictate the disposal of the produced crude oil into the disposal zone (via the proposed Umiat DSP-01 disposal well). These circumstances include, but are not limited to: 1. The Upper Grandstand formation and portions of the Lower Grandstand formation are contained within the permafrost zone. As such, the reservoir temperature in the Upper Grandstand and portions of the Lower Grandstand is below freezing (<32° F). Injecting crude oil at a temperature greater than 320 F, will result in thawing of the reservoir (near wellbore), which could seriously damage the reservoir permeability or conductivity. This could result in permanent loss of productivity, which may be interpreted as "waste of resource". 2. Since re -injection of crude will be done in batches, the thawing and re -freezing of the reservoir between batches may create an "ice sheath" across the injection interval which could physically prevent the injection of oil back into the reservoir. 3. Crude oil storage during testing operations will be limited. Linc plans to test the proposed vertical and horizontal Lower Grandstand wells (Umiat #16 and Umiat #16H, respectively) back to back. Linc would like to achieve stabilized rates from each flow test, but will be limited on how long these wells can be tested by available storage volume. The remoteness of the Umiat field, as well as limited storage tank resources (in Alaska), may make it necessary for Linc to Page 119 soUmiat ,sal Injection Order Application November 1, 2012 empty some storage tanks (and dispose of test fluids into the disposal well) during the tests in order to obtain valid, comparative test data. 4. Re -injecting the oil back into the Lower Grandstand formation will have to be done after the conclusion of both the Umiat #16 and #16H well tests. It can't be done concurrently or in between tests due to: a. Possible interference between wells (Umiat #16H heal is projected roughly 1,000' away from the Umiat #16 wellbore). b. Potential reservoir damage could adversely affect the subsequent (or concurrent) well test. 5. The remoteness of the Umiat field and the expense to transport the oil to a sales point prohibits the sale of the produced oil. Transporting the oil off lease will also incur a sizeable amount of risk/liability. Linc has had discussions with potential purchasers of the produced oil, but due to the relatively small volumes (-10,000 bbls in 2012/2013 season) and the remoteness of the field, Linc has been unable to find an interested buyer. Linc has also considered donating the oil to a native regional or village corporation, but the small volumes, the remoteness, and the transportation cost & liability preclude this from being a viable option. 6. The winter exploration season at Umiat is dependent upon ambient temperatures and snow/ice conditions. Any unexpected increase in area temperatures, may dictate an earlier than anticipated end to the exploration season. If this occurs and Linc is not able to re -inject the produced oil (back into the Grandstand formation), disposal of the oil may be the only option a. Note that the Umiat #16 and #16H wells (as well as Umiat #23) will be drilled from ice pads and that the Umiat DSP-01 disposal well will be located on an existing gravel pad. Given an early end to the exploration season, operations (injection) at the disposal well will extend to a later date than on either of the ice pads. 7. Injection rates down the disposal well may also be significantly higher than rates down the exploration wells. There is no data available to predict how injection of the produced crude oil, back into a frozen (or nearly frozen) reservoir, will behave. 8. Extreme care will need to be taken when re -injecting crude oil back into the frozen (or nearly frozen) Grandstand reservoir(s), in order to avoid any chance of fracturing the formation(s). Since any future development of the Grandstand formations will require some sort of pressure maintenance, it is essential that the integrity of the reservoir seal be maintained. Note that there are no formation fluid samples or core analyses available from the proposed Torok disposal interval in the Seabee #1 well (or from any other well in the Umiat area). There is however extensive operational experience involving similar waste streams, similar geologic formations, and similar disposal depths at much higher disposal volumes currently on the North Slope. Therefore, these provide an analogy for the proposed Umiat disposal injection. t: 20 MUmiatOPsal Injection Order Application November 1, 2012 8.0 INJECTION PRESSURES AND RATES The estimated average and maximum injection pressure and rate are based on known rock properties used in fracture modeling, and potential equipment limitations. At an average injection rate of 4.0 bpm, with a 10.0 ppg cuttings slurry, it is anticipated that the surface injection pressure will average 2,000 psi. Injecting a 9.0 ppg fluid slurry, it is anticipated that the surface injection pressure will average about 2,500 psi. Maximum injection pressure and rate based on equipment limitations are 5,000 psi and 6.0 bpm, respectively. The proposed 7" 26# L-80 casing has a burst rating of 7,240 psi, with a maximum hoop stress of 70%, giving a maximum burst pressure of 5,068 psi. Therefore, the maximum injection pressure incorporating a 20% safety factor will be limited to 4,000 psi. The estimated injection rate will be between 2.0 to 6.0 bpm. Extensive fracture modeling was performed, using various fluid (with and without cuttings), injection rates, and for various perforation intervals. Of all the fluids investigated, injection of 10.0 ppg MOBM, at 6.0 bpm, produced the largest fractures; both fracture half-length and fracture height. These extreme cases predicted maximum injection pressures of less than 2,000 psi (the maximum injection pressure modeled was 1,919 psi). A more detailed discussion of the fracture modeling is located in Section 9.1 below. 9.0 WASTE CONFINEMENT Using the open -hole logs from the Seabee #1 well, rock properties (Young's modulus, Poisson's ratio, etc.) were calculated for the proposed disposal zone, as well as for the strata within, above, and below the disposal confining zones. A fracture model was then built using the program FracproPT, and potential fracture heights, widths, and lengths were investigated for the expected fluids, volumes, and rates that Linc expects to inject into the disposal zone. Note that these fluids, volumes, and rates were detailed in section 7.0 above, and will be mentioned again in section 9.1. All of the cases run (outlined below in section 9.1) show containment of the injection fluids. There is no evidence that the proposed disposal operation will initiate or propagate fractures through the confining zones, which might then enable certain oil field wastes or hydrocarbons to enter any freshwater strata. 9.1 Disposal Zone Fracture Analysis Utilizing rock properties calculated from the Seabee #1 open -hole logs, a fracture model was built using the program FracproPT. Numerous cases (varying injection rates, injection volumes, slurry type and density, perforated intervals, etc.) were run to investigate the heights, widths, and lengths of the generated fractures. Injection of the following fluids were simulated assuming injection rates of 2.0 — 6.0 BPM and injection batch volumes of 1,000 bbls: • Crude Oil (7 ppg) • Brine (8.5 ppg) Pa,-,e 121 Umiat Di'�p�isal Injection Order Application November 1, 2012 • MOBM (9.5 ppg) • WBM (10 ppg) • MOBM (10 ppg) • MOBM w/ Drill Cuttings (10 ppg) • WBM w/ Drill Cuttings (10 ppg) Table 2 (below) shows the fluid properties generated for the various fluids investigated in the fracture modeling. Fluid Name IR"9d 8.5 Brine WBM 10.0 PPG MOBM 10 Vendor Other Other Other Other System Crude Oil Brine WBM MOBM Description 7.0 ppg Crude Brine 8.5ppg WBM 10.0 P.P-g 10 ppg MOBM Initial Viscosity (gp,) 5.17 1.19 16.48 40.13 Initial n' 1.000 1.000 0.380 0.125 Initial k' ("nlftl) 1.000 1.000 0.380 0.125 Viscosity @ 4.0 hours (S4t1 5.17 1.19 16.48 1.72 n' @ 4.0 hours 1.000 1.000 0.380 0.136 k' @ 4.0 hours ft-t-.�"Djfts) 1.000 1.000 0.380 0.136 Base Fluid Specific Gravity 0.839 1.13 1.20 1.20 Spurt Loss (gal/ft=) 0.039 0.039 0.0 0.009 Wall Building (ft/min%) 0.065 0.065 0.129 0.003 FJQwrAJe #1 (bpm) 10.00 10.00 7.20 10.00 F#c Press #1 (psi/1000 Ft) 178.2 182.7 80.32 54.41 FJowMe #2 (kph) 20.00 20.00 14.39 20.00 Ffic Press #2 (psi/1000 lint) 633.0 690.E 290.8 104.2 Flow) e #3 (bum) 40.00 40.00 28.79 40.00 Flit Press #3 (psi/1000 ft) 2301.7 2664.2 1107.5 275.1 Wellbore Friction Multiplier 1.000 1.000 1.000 1.000 Table 2 - FracproPT Fluid Properties Cases were run assuming 20 feet of perforations (6 spf) in each of the porous zones within the disposal interval (discussed in section 4.1), and also sensitivities were run assuming 20 feet of perforations at the very top of the disposal interval and at the very bottom of the disposal interval. The four different perforation scenarios were: 1. Top of the Disposal Zone (Umiat DSP-01 Projected Perfs @ 4,245'-4,265' TVD) (equivalent Seabee #1 depths: 4,150' - 4,170' TVD) 2. Top of the Upper Porous Sand (Umiat DSP-01 Projected Perfs @ 4,505' - 4,525' TVD) (equivalent Seabee #1 depths: 4,410' - 4,430' TVD) 3. Base of the Lower Porous Sand (Umiat DSP-01 Projected Perfs @ 4,750'-4,770' TVD) (equivalent Seabee #1 depths: 4,655'-4,675' TVD) 4. Base of the Disposal Zone (Umiat DSP-01 Projected Perfs @ 4,875' - 4,895' TVD) (equivalent Seabee #1 depths: 4,780'-4,800' TVD) Page 122 Umiat Ui�p ssal Injection Order Application November 1, 2012 Note that the Umiat DSP-01 projected disposal interval is from 4,245' to 4,895' TVD (-3,932' to-4,582' SSTVD), which is the equivalent depth of 4,150' to 4,800' TVD, in the Seabee #1 well. The two porous intervals within the disposal zone are projected at 4,505' to 4,595' TVD (-4,192 to-4,282' SSTVD) and 4,715 to 4,770' TVD (-4,402 to-4,457' SSTVD), in the proposed Umiat DSP-01 well. These two porous sands have the equivalent depths of 4,410' to 4,500' TVD and 4,620' to 4,675' TVD, respectively in the Seabee #1 wellbore. These intervals have been previously discussed in section 4.1. The following four tables show the fracture modeling results for the FracproPT simulation runs. Note that all four of these tables represent runs made at injection rates of 6.0 bpm and for injection batch volumes of 1,000 bbls. Top of Umiat DSP-01 Projected Perfs: 4,245' - 4,265' TVD (equivalent Seabee #1 Perfs: 4,150' - 4,170' TVD) Disposal Zone Fracture Half Rate Fracture Top Bottom Net height Length Fluid type (bpm) (TVD ft) (TVD ft) (ft) (ft) Crude 7ppg 6 4106 4211 105 132 Crude 7ppg 4 4110 4205 95 124 Crude 7ppg 2 4118 4198 79 111 Brine 8.5ppg 6 4105 4209 104 132 Brine 8.5ppg 4 4110 4204 94 124 Brine 8.5ppg 2 4118 4198 79 111 MOBM 9.5ppg 6 4036 4278 242 124 MOBM 9.5ppg 4 4039 4274 235 122 MOBM 9.5ppg 2 4049 4230 148 173 WBM 10 ppg 6 4081 4236 156 81 WBM 10 ppg 4 4086 4230 144 76 WBM 10 ppg 2 4095 4221 126 65 MOBM 10 ppg 6 4035 4279 244 126 MOBM 10 ppg 4 4037 4275 238 123 MOBM 10 ppg 2 4047 4262 215 114 Drill Cuttings MOBM 10ppg 6 4066 4252 186 94 Drill Cuttings MOBM 10ppg 4 4072 4246 174 85 Drill Cuttings MOBM 10ppg 2 4082 4236 154 75 Drill Cuttings WBM 10ppg 6 4108 4213 105 52 Drill Cuttings WBM 10ppg 4 4122 4208 96 48 Drill Cuttings WBM 10ppg 2 4120 4200 80 40 Table 3 — Fracture Modeling for Perforations at the Top of the Disposal Interval Page 123 MUmiat9p'8"sal Injection Order Application November 1, 2012 Top of Umiat DSP-01 Projected Perfs: 4,505- - 4,525- TVD (equivalent Seabee #1 Perfs: 4,410' - 4,430' TVD) Upper Porous Sand Fracture Half Rate Fracture Top Bottom Net height Length Fluid type (bpm) (TVD ft) (TVD ft) (ft) (ft) Crude 7ppg 6 4341 4493 152 75 Crude 7ppg 4 4349 4489 139 70 Crude 7ppg 2 4359 4479 120 60 Brine 8.5ppg 6 4339 4491 152 76 Brine 8.5ppg 4 4348 4487 139 70 Brine 8.5ppg 2 4359 4479 120 60 MOBM 9.5ppg 6 4295 4538 242 118 MOBM 9.5ppg 4 4298 4534 236 114 MOBM 9.5ppg 2 4309 4521 211 101 WBM 10 ppg 6 4343 4493 150 74 WBM 10 ppg 4 4350 4488 137 69 WBM 10 ppg 2 4360 4479 119 59 MOBM 10 ppg 6 4294 4539 244 119 MOBM 10 ppg 4 4279 4535 238 115 MOBM 10 ppg 2 4307 4522 215 102 Drill Cuttings MOBM 10ppg 6 4329 4510 181 90 Drill Cuttings MOBM 10ppg 4 4334 4504 170 84 Drill Cuttings MOBM 10ppg 2 4345 4495 150 72 Drill Cuttings WBM 10ppg 6 4369 4468 99 50 Drill Cuttings WBM 10ppg 4 4372 4462 90 45 Drill Cuttings WBM 10ppg 2 4377 4453 76 37 'Table 4 — Fracture Modeling for Perforations at the Top of the Upper Porous Sand Page 124 MUmiat ,pc sal Injection Order Application November 1, 2012 Base of Umiat DSP-01 Projected Perfs: 4,750' - 4,770' TVD (equivalent Seabee #1 Perfs: 4,655' - 4,675' TVD) Lower Porous Sand Fracture Half Rate Fracture Top Bottom Net height Length Fluid type (bpm) (TVD ft) (TVD ft) (ft) (ft) Crude 7ppg 6 4578 4737 159 75 Crude 7ppg 4 4585 4732 148 68 Crude 7ppg 2 4598 4724 126 58 Brine 8.5ppg 6 4576 4735 158 75 Brine 8.5ppg 4 4583 4730 147 69 Brine 8.5ppg 2 4597 4723 125 58 MOBM 9.5ppg 6 4539 4778 239 114 MOBM 9.5ppg 4 4541 4774 233 109 MOBM 9.5ppg 2 4550 4761 211 96 WBM 10 ppg 6 4582 4740 158 74 WBM 10 ppg 4 4588 4733 146 67 WBM 10 ppg 2 4599 4724 124 58 MOBM 10 ppg 6 4538 4779 242 115 MOBM 10 ppg 4 4540 4775 235 110 MOBM 10 ppg 2 4549 4762 213 97 Drill Cuttings MOBM 10ppg 6 4571 4755 184 89 Drill Cuttings MOBM 10ppg 4 4577 4749 171 81 Drill Cuttings MOBM 10ppg 2 4588 4739 151 70 Drill Cuttings WBM 10ppg 6 4613 4718 106 51 Drill Cuttings WBM 10ppg 4 4617 4714 96 48 Drill Cuttings WBM 10ppg 2 4625 4706 81 40 Table 5 - Fracture Modeling for Perforations at the Base of the Lower Porous Sand Pape 125 40 Umiat0pisal Injection Order Application November 1, 2012 Base of Umiat DSP-01 Projected Perfs: 4,875' - 4,895' TVD Disposal Zone (equivalent Seabee #1 Perfs: 4,780' - 4,800' TVD) Fracture Half Rate Fracture Top Bottom Net height Length Fluid type (bpm) (TVD ft) (TVD ft) (ft) (ft) Crude 7ppg 6 4702 4869 167 84 Crude 7ppg 4 4708 4863 154 78 Crude 7ppg 2 4720 4855 135 66 Brine 8.5ppg 6 4701 4866 165 84 Brine 8.5ppg 4 4707 4860 153 78 Brine 8.5ppg 2 4720 4854 134 67 MOBM 9.5ppg 6 4708 4920 211 145 MOBM 9.5ppg 4 4715 4920 205 137 MOBM 9.5ppg 2 4732 4919 188 112 WBM 10 ppg 6 4710 4910 200 85 WBM 10 ppg 4 4711 4865 154 76 WBM 10 ppg 2 4721 4855 134 66 MOBM 10 ppg 6 4708 4920 212 147 MOBM 10 ppg 4 4717 4920 206 139 MOBM 10 ppg 2 4732 4919 188 114 Drill Cuttings MOBM 10ppg 6 4713 4918 206 89 Drill Cuttings MOBM 10ppg 4 4714 4912 198 83 Drill Cuttings MOBM 10ppg 2 4717 4865 148 71 Drill Cuttings WBM 10ppg 6 4733 4850 117 57 Drill Cuttings WBM 10ppg 4 4739 4847 108 53 Drill Cuttings WBM 10ppg 2 4747 4840 93 46 Table 6 — Fracture Modeling for Perforations at the Base of the Disposal Interval The modeled fracture heights, tops, and bottoms (shown in Tables 3-6, above), for all injected fluids and cuttings, were all contained within the proposed disposal zone and confining intervals. None of the cases run show fracture growth outside of the containment intervals. Note that Linc Energy plans to perforate the proposed Umiat DSP-01 disposal well within the two porous sand intervals, most likely starting at the base of the lower porous interval and then moving up to the upper porous interval as needed. To investigate any possible fracture growth outside of the confining intervals, sensitivities were run simulating 20' perforations at the very top of the disposal interval (Table 3, above) and at the very base of the disposal interval (Table 6, above). These extreme perforation cases show fracture containment within the confining intervals. No cases run, show fracture growth outside (above or below) the confining intervals. The maximum fracture growth (height and length) occurred when modeling injection of 10.0 ppg MOBM, at 6.0 bpm, for all four of the different perforation scenarios. Modeling showed fracture heights of nearly 250 ft. and fracture half -lengths of nearly 150 ft. Even with the nearly 250 ft. of fracture height, the modeling showed containment of the fractures within the confining intervals. The maximum surface injection pressure modeled in these 10.0 ppg MOBM cases, was less than 2,000 psi (1,919 psi Page 126 40 Umiatal Injection Order Application November 1, 2012 was the maximum modeled pressure). The full FracproPT run outputs for the four different perforation cases (assuming 10.0 ppg MOBM, at 6.0 bpm) can be seen in Attachment 2. Based upon fracture modeling, there is no evidence that the proposed disposal operation will initiate or propagate fractures outside the confining zones. Thus the proposed disposal operation will not enable any of the proposed oil field waste or hydrocarbons to enter any freshwater strata. 10.0 WATER SALINITY The proposed Umiat DSP-01 well has a projected disposal interval from 4,245' — 4,895' TVD (-3,932' — - 4,582' SSTVD). This is equivalent to the interval from 4,150' — 4,800' TVD, in the Seabee #1 wellbore. There are two main porous intervals within this gross disposal zone, the upper projected at 4,505' — 4,595' TVD (-4,192' —-4,282' SSTVD), and the lower projected at 4,715' — 4,770' TVD (-4,402' —-4,457' SSTVD) in the planned Umiat DSP-01 well. Table 1 (in section 4.1) shows the projected Umiat DSP-01 depths as well as the actual depths seen in the Seabee #1 wellbore, for these porous intervals, as well as for the gross disposal zone and confining layers. Water salinity analysis shows water salinities of 25,000 — 30,000 ppm, or greater, across the entire disposal interval. The apparent Formation Water Resistivity (Rwa) was calculated using the Archie Equation (with the coefficients; a=1, m=2, n=2, & a sandstone matrix), assuming a 100% water wet zone. Rwa was then converted to apparent Formation Water Salinity using the salinity equation below. Archie Equation: Sw = [(a/OAM) x (Rwa/Rt)]^1/n Rwa = (Rt)(Sw^n)(OAm/a) Rwa = (Rt)(Sw^2)(0^2) w/ a=1, m=2, & n=2 Salinity (PPM) = 5472 x [(Rwa x (Temp + 6.77)) / (83.4 — 0.0125)]^(-1.0397) An attached water salinity log (Attachment 5) for the Seabee #1 well, has been included with this DIO application. It might be noted on the attached salinity log, the calculated water salinity spikes down to—10,000 ppm at 4,205' MD. This low salinity is not thought to be real nor representative of any actual formation water at this depth. The density curve shows a spike in porosity from an average of 10 — 12% surrounding this depth, to roughly 20% right at 4,205' MD. Viewing the caliper log track, it appears that the caliper log was not working over this interval, which may indicate a washout. The spike in porosity is very questionable. If you take an average porosity of 10 —12% over this general interval and an average resistivity of 15 ohms, the calculated water salinity would be 30,000 — 40,000 ppm. Also note that this 1-2 foot interval is the only place across the entire proposed disposal interval that the calculated water salinity even approaches 10,000 ppm. The salinity curve shows that you have to move up -hole to about 4,004' MD, in the Seabee #1 well, to find water salinities less than 10,000 ppm. Given F'a �27 soUmiat sal Injection Order Application November 1, 2012 the depositional environment of the Torok formation, it is highly unlikely that an anomalous 1-2 foot sand stringer exists (at this depth) with a significantly lower water salinity than the surrounding strata (100's of feet above and below). In calculating of apparent formation water salinity, the assumption was made that the zones were 100% water wet. Viewing the Seabee #1 mudlog, it is apparent that some amount of gas is present in the disposal and confining intervals. Correcting for this gas would cause the calculated apparent formation water salinity to increase, over what has been presented. 1. The presence of gas within the pore space of a formation rock will cause the measured resistivity to increase. Thus if you make the assumption that there is some gas in the porosity (not 100% water), the measured resistivity would be higher than that if there were no gas present. Thus the true water resistivity would be lower, causing the calculated Apparent Formation Water Resistivity (Rwa) to decrease. This in turn would yield a higher apparent formation water salinity. 2. If on the other hand, you calculate a Water Saturation (Sw) < 100% (to account for any gas in the pore space) and use that Sw to calculate the Rwa (using the measured Rt), the Archie equation would once again yield a lower Rwa and thus a higher formation water salinity. 3. Finally, the presence of gas in the pore space causes the density measured porosity to be higher than the actual porosity. Thus the actual porosity across the disposal and confining zones would be lower than the measured/recorded density porosity, given the presence of gas. If you correct the density porosity for any potential gas (i.e. use a lower actual porosity), this will lower the calculated Rwa and thus raise the calculated apparent formation water salinity. Based upon the above arguments, the calculated water salinity curve (assuming 100% Sw) should be the lowest or worst case scenario, in regards to formation water salinity. Correcting for gas will only increase the calculated salinity. No water samples have been discovered from the original eleven Umiat wells nor from the Seabee #1 well, which were collected from the same correlative strata as the proposed disposal zone and confining intervals. There is however a water sample that was gathered during DST #3 (in the Seabee #1 well), which tested the deeper Torok interval from 5,366' — 5,394' TVD. The water analysis report (included as Attachment 3) lists a Total Dissolved Solids (TDS) of 10,989 ppm. It should be pointed out that the Seabee #1 well was drilled with freshwater mud and that Husky Oil had to weight up from 10.1 ppg to 14.3 ppg (5,000 ppm Chlorides) over this interval, to contain the well. Thus this measured salinity of 10,989 ppm could be on the low side of true formation water salinity, due to mud filtrate invasion. Also note that the calculated salinity log (Attachment 5) shows the apparent formation water salinity dropping down below 10,000 ppm between 5,380' — 5,390' TVD (the best pay within the tested interval). Having a measured salinity of 10,989 ppm, lends credibility to the above argument that the provided salinity log is a conservative or low estimate of the actual formation water salinity. Page 128 40 Umiat Opsal Injection Order Application November 1, 2012 It has thus been concluded that the water salinity is greater than 10,000 ppm over the entire proposed disposal interval. As such, no aquifer exemption is necessary. 11.0 AQUIFER EXEMPTION From the water salinity analysis (discussed in the previous section), it has been concluded that the water salinity is greater than 10,000 ppm over the entire proposed disposal interval. As such, no aquifer exemption is necessary. 12.0 AREA OF REVIEW The mechanical condition for all wells within a % mile radius of the proposed Umiat DSP-01 disposal well was reviewed. The only well that penetrated either the disposal or confining zones, within this % mile radius, was the Seabee #1 well. 12.1 Seabee Test Well No.1 The 17-1/2" hole in the Seabee #1 well was drilled from 1,623' MD/TVD to 4,009' MD/TVD. 13-3/8" casing was run down to 3,983' MD/TVD and cemented to surface. The 12-1/4" hole section was drilled from 4,009' MD/TVD to 10,004' MD/TVD and 9-5/8" casing was run to 9,980' MD/TVD. A second stage cement job was pumped through a DV collar at 5,591' MD/TVD. Based upon a cement volume of 327 bbl pumped through the DV collar at 5,591' MD/TVD, and assuming an open -hole excess of 150%, the cement top behind the 9-5/8" casing would be at 2,200' MD/TVD. This cement top is well above the top of the proposed disposal zone (4,150' MD/TVD), as well as the top of the upper confining zone (3,550' MD/TVD). The 9-5/8" casing was tested to 3,000 psi on 11/28/79. Attachment 4 contains the latest wellbore schematic for the Seabee Test Well No.1 (Seabee #1), as well as a due diligence summary of the Seabee #1 well. 12.2 Wells within a 1/2 Mile Radius If you extend the area of review to a % mile radius from the proposed disposal well, this review would also include the Umiat #9 well. The Umiat #9 well was drilled to 1,257' MD/TVD and does not penetrate the disposal or confining zones. Umiat #9 was plugged and abandoned in 2011. Pa F,,e 129 UmiatCi�rp�al Injection Order Application Attachment 1- Umiat DSP-01 Directional Plan Measured Indin Azimuth 7RJc Rea Depth agrees Degrees Jere, N'S MDy Ind 82 Amm spa TVD WS Measured Indin Azimuth TRUE Rec Denth Degrees Decrees Depth NIS Coord Dogieg Vert Gnd E.1M Deg110Dft Sect Ear.m.? EAN a (*1100 ft) Vsec Grid E 11 148 ^.o c Dogleg Vert Gnd De,W1ODft Beet Fasting Coord gorthir.@ Grid N Coorc Northing 0 0.3C 148DO C C Co 0.00 0.0C C 00 1875517 5825608 100 0.DC 148.D0 100 C 03 0.00 0.00 C.00 1875517 5625WO 2DO 0.00 148.DO 200 C 03 0.00 0.00 O.DO 1875517 5625eD6 3DO 0.30 148.DO 300 C 03 3.D0 0.00 D.DO 1875517 5625806 400 0.3C 14B.00 400 C.03 3.00 0.0C C.OD 187 5517 5825606 5DC 0.3C 146.00 500 C.00 0.D0 C.3C C 00 1875517 5625806 800 0.30 148.00 600 0.00 0.00 0.3C C DO 18756171 5625806 700 0.00 148.D0 700 0.00 0.00 0.3C C OD 18755171 5625606 800 0.DC 148.D0 800 C 03 0.00 C 3C C DO 1875517 5825606 900 0.00 148.00 900 0.03 0.00 0.3C O.00 1875517 5825806 1000 0.00 148 00 1000 0.00 3.00 O.3C O.DO 1875517 5625606 1100 0.00 148.D0 1100 0.00 0.00 0.07 D.00 787 5517 58BW 1200 0.00 148.D0 1200 0.00 0.001 0.aC D.DD 1875517 56256M 130C 0.00 148.00 1300 0.00 0.00 0.3C 030- 1875517 5025600 1400 0.00 148.00 1400 0.00 D.DO 0.0C 0-DO 1875517 5025606 1500 0.00 148.00 1500 0.D0 D.00 0.0C 0.00 1875517 5625806 1800 0.00 148.00 1600 0.00 0.00 0.0C 0.00 1875517 56258M 1700 0.00 148.1% 1700 0.00 0.00 D: O.OD 1875517 58250M 180C 0.00 148.00 1800 0.00 0.00 0. 0.00 1875517 5625606 190C 3.00 148.D0 1900 -2 22 1.39 3.0 2.82 1875518 5025604 2000 6.00 148.00 2000 -8.87 5.54 3.0 1DAe 1875523 5625597 2100 9.00 148.00 2099 -19.94 12.48 3.0 23.52 1875829 58255M 2200 12.00 148.00 2197 -35.40 22.12 3.0 41.74 1875539 5025571 23D0 15.00 148.00 2294 -55.19 34.49 3.0 65.08 1875551 5625551 2400 18.00 148.00 2390 -79 28 49.54 3.0 93.49 1875567 5825527 21.00 148_DO 2485 -107.59 67.23 3.0 128.87 1875584 5625498 21.00 148.00 2578 -137.9E 86.22 0.0 162.70 1875603 582546E 2'.30 148.00 2671 -168.37 105.21 0.0 198.54 1875622 925438 2'.DC 148700 2785 -198.76 124.20 0.0 234.38 1875641 5625407 2'.DC 148.00 2858 -229.15 143.19 0.0 270.21 1875MO M2 2'.DC 148.00 201 -259.55 162.18 0.D 306.05 1875679 5625.30 I 148.00 3045 -289.94 181.17 0.0 341.89 1875698 5825316 .30 146.00 3138 -320.33 200.1E 0.0 377.72 1875717 5625286 ".DD 148.D0 3231350.72 219.15 0.0 413.56 187573E 5825255 _'.3C 148.00 3325 -381.11 238.14 0.D 449.40 1875755 5625225 2'..00 148.00 3418 -411.60 257.14 0.0 485.23 1875774 5625194 21.00 14B.00 3511 - 41.89 276.13 0.001 521.07 18757931 5825164 3700 21.O0 148.00 3605 -472.28 295.12 0.0 556.91 1875812 5825134 3c3C 2'.00 146.D0 3898 -502.68 314.11 0.001 592.74 1875831 5625103 21.00 148.00 3792 -533.07 333.10 0.00 628.58 18758M 5025073 148.00 3885 -583.46 352.09 0.0 684.42 1875889 5625043 4' 3C 21.00 146.00 3978 -693.85 371.08 0.00 700.28 1875888 5625D12 4-- C 21.00 14B 00 4072 -824.24 390.07 O.00 738.09 1875907 5624982 4 _C 21.00 14B.00 4165 -854.e3 409.06 O.00 i71.93 187592E 5624951 443C 2'.00 146 00 4258 -8B5.02 428.05 0.00 807.77 187%45 5624921 450C 21.OD 148.00 4352 -715.42 447.04W0.0016D 1875964 5624891 463C 21.00 146-00 4445 -745.81 436.0344 1875983 5824860 470C 21.OD 148.00 4538 -776.20 485.D228 1876002 5624830 480C 21.OD 148.00 4632 4M. UA-0111 1876021 5624799 490C 21.OD 148A0 4725 -83 996 523.0095 187604C 5624769 2*.00 148.00 481E 86?._7 541.99T91878059 56247395'3C 2'.00 14E.00 4912 `�_-' S80.98.82 187607E 562470E November 1, 2012 Page 130 40 Umiat l p sal Injection Order Application November 1, 2012 Attachment 2 — FracproPT Fracture Modeling Outputs �31 • • FracproPT 2011 Hydraulic Fracture Analysis Date: Wednesday, October 31, 2012 Well Name: Umiat DSP-01 Location: Formation: Torok Job Date: 10/31 /2012 2:48:39 PM Filename: 10.0 ppg MOBM 6 bpm Top Disposal Table 1 • Fracture Geomet Summar * Fracture Half -Length ft 126 Propped Half -Length ft 0 Total Fracture Height ft 244 Total Propped Height ft 0 Depth to Fracture To ft 4035 Depth to Propped Fracture To ft 4160 Depth to Fracture Bottom ft 4279 Depth to Propped Fracture Bottom ft 4160 Equivalent Number of Multiple Fracs 1.0*Avg. x. Fracture Width in 0.74 Fracture Slur Efficienc ** 0.34 . Fracture Width in 0.47 Prop ant Concentration Ib/ft2 0.00 * All values reported are for the entire fracture system at a model time of 166.70 min (end of Stage 1 Main frac pad) ** Value is reported for the end of the last pumping stage (Stage 1, Main frac pad) TnhlP T Frnr.turP Conductivity Summarv* Avg. Conductivity" mD-ft 0.0 Avg. Frac Width Closed onprop) in 0.000 Dimensionless Conductivit ** 0.00 Ref. Formation Permeability mD 0.939 Pro ant Damage Factor 0.50 Undamaged Prop Perm at Stress mD 0 Apparent Damage Factor*** 0.00 Prop Perm with Prop Damage mD 0 Total Damage Factor 0.50 Prop Perm with Total Damage mD 0 Effective Propped Length ft 0 Pro ant Embedment in 0.000 * All values reported are for the entire fracture system. Actual conductivity could be lower if equivalent multiple fractures have been modeled ** Total Damage Factor and Proppant Embedment have been applied *** Apparent Damage due to non -Darcy and multi -phase flow TnhlP R• Fracture PrP.SSurP. Summarv* Model Net Pressure**(psi) 437 BH Fracture Closure Stress(psi) 2941 Observed Net Pressure**(psi) 0 Closure Stress Gradient si/ft 0.707 Hydrostatic Head***(psi) 2162 Avg. Surface Pressure(psi) 1498 Reservoir Pressure(psi) 2375 Max. Surface Pressure(psi) 1806 * Averages and maxima reported for Main Frac stages ** Values reported for the end of the last pumping stage (Stage 1, Main frac pad) *** Value reported for clean fluid Tnhla A- C)narntinnc Siimmarv* Total Clean Fluid Pumped bbls 1000.9 Total Pro ant Pumped klbs 0.0 Total Slurry Pumped bbls 1000.9 Total Pro ant in Fracture klbs 0.0 Pad Volume bbls 1000.0 Avg. H draulic Horsepower h 220 Pad Fraction % of Slur Vol)** 100.0 Max. Hydraulic Horsepower h 265 Pad Fraction % of Clean Vol)** 100.0A�Secontdary Bm Slur Rate b m 6.0 Prima Fluid Type ma Pro ant Type SecondaryFluid Type Pro pant Type * Averages and maxima reported for Main Frac stages Totals reported for all injections combined. ** Based on following volume ratio of stage types: Main frac pad / (Main frac pad + Main frac slurry), and excluding flush. FracproPT 2011 Table 5: Model Calibration Summary Crack Opening Coefficient 8.50e-01 Width Decoupling Coefficient 1.00e+00 Tip Effects Coefficient 1.O0e-04 Tip Radius Fraction 1.00e-02 Tip Effects Scale Volume bbis 100.0 Prop ant Drag Effect Exponent 8.0 CLE Outside Pa zone 25.00 Multiple fractures settings start V/L/O 1.0 / 1.0 / 1.0 Multiple fractures settings end V/L/O 1.0 / 1.0 / 1.0 FracproPT 2011 • • G wth H; t * I aole n: End of Hydraulic Fracture Stage Type ro Time Is or Fracture Fracture Fracture Avg. Model Net Slurry Equivalent Stage # (mm:ss) Half-Leng Height Width at Fracture Pressure Efficiency Number of th (ft) Well Width (psi) Multifracs ft in in 1 Main frac ad 166:40 126 244 0.739 0.474 437 0.34 1.0 * All values reported are for the entire fracture system and at the ehu U1 caU I �LOVV P d F turn Pro erties hy Distance from the Well at Fracture Center at Depth of 4160ft Table 7. ro Distance from Well (ft) a rac Fracture System Width* in Conductivity per Frac** (mD•ft) Frac System Conductivity*** (mD-ft) Prop Conc per Frac (lb/ft-) Frac System Prop Conc**** (lb/ft-) 0.0 0.719 0.0 0.0 0.00 0.00 0.0 0.719 0.0 0.0 0.00 0.00 0.0 0.719 0.0 0.0 0.00 0.00 0.0 0.719 0.0 0.0 0.00 0.00 0.0 0.719 0.0 0.0 0.00 0.00 0.0 0.719 0.0 0.0 0.00 0.00 0.0 0.719 0.0 0.0 0.00 0.00 0.0 0.719 0.0 0.0 0.00 0.00 0.0 0.719 0.0 0.0 0.00 0.00 0.0 0.719 1 0.0 1 0.0 0.00 0.00 * Width values reported are for the entire fracture system. ** Fracture conductivity reported for total proppant damage of 0.50 and 0.000 in of proppant embedment. *** Frac system conductivity reported for 1.0 equivalent multiple fractures with 100% considered conductive. **** Frac system proppant concentration reported for 1.0 equivalent multiple fractures. FraeproPT 2011 0 Tahle R. f)esinn Treatment Schedule Stage Stage Type Elapsed Fluid Clean Prop Stage Slurry Proppant # Time Type Volume Conc Prop. Rate Type min:sec al pp kibs bpm Wellbore Fluid MOBM 10 1516 1 Main frac pad 1 166:40 MOBM 10 42000 0.00 0.0 6.00 Design clean volume (bbls) 1000.0 Design proppant pumped (klbs) 0.0 Design slurry volume (bbls) 1000.0 FracproPT 2011 0 Table 9: Pr000ant and Fluid Material Quantity Units Unit Cost $ Discnt % Cost $ MOBM 10 1000.0 bbls 0.00 0.0 0.00 Treatment Totals calculated from design schedule Proppant and Fluid Subtotal: 0.00 ($) Total: 0.00 ($) FracproPT 2011 0 0 - 1- A ll. CI. .;A f]......m..i�. rr I CIVIC IV. I IUlu r QI QI IIGL-J Fluid Name MOBM 10 Vendor Other System MOBM Description 10 peg MOBM Initial Viscosity cp 40.13 Initial n' 0.125 Initial k' Ibf-s^n/ftZ 0.125 Viscosity 4.0 hours cp 1.72 n' 4.0 hours 0.136 k' 4.0 hours Ibf-sAn/Ift 21 0.136 Base Fluid Specific Gravit 1.20 Spurt Loss al/ft2 L0.009 Wall Building ft/min'/2 0.003 Flowrate #1 b m 10.00 Fric Press #1(psi/1 000 ft 54.41 Flowrate #2 b m 20.00 Fric Press #2 si/1000 ft 104.2 Flowrate #3 b m 40.00 Fric Press #3 si/1000 ft 275.1 Wellbore Friction Multiplier 1.000 All Fluid info is at a reservoir temperature of 93.0 ("F) All Viscosities at Shear Rate of 511 (1/sec) Wellbore Friction pressures shown are the interpolated values multiplied by the Wellbore Friction Multiplier. Friction is displayed for longest wellbore segment FracproPT 2011 • • Table 11: Leakoff Parameters Reservoir type User Spec Reservoir fluid compressibility 1/psi 2.58e-0 Filtrate to pore fluid perm. ratio, Kp/KI 10.00 Reservoir Viscosity c 0.02 Reservoir pore pressure psi 2375 Porosity 0.10 Initial fracturing pressure(psi) 4039 Gas Leakoff Percentage % 100.00 Reservoir Parameters Reservoir Temperature (oF) Depth to center of Perfs (ft) Perforated interval (ft) Initial frac depth (ft) 4160 Table 12: Laver Parameters 93.00 4160 20 Layer # Top of zone ft Stress (psi) Stress Gradient psi/ft Young's modulus psi Poisson's ratio Total Ct (ft/min%) Pore Fluid Perm. mD 1 0.0 1115 0.697 2.6e+06 0.29 3.498e-03 1.38e+00 2 1600.0 1777 0.718 1.5e+06 0.34 3.840e-03 3.72e+00 3 3350.0 2468 0.726 1.2e+06 0.36 3.784e-03 2.99e+00 4 3450.0 2553 0.731 1.1 e+06 0.37 3.733e-03 2.52e+00 5 3534.0 2562 0.725 1.2e+06 0.36 3.623e-03 1.85e+00 6 3538.5 2562 0.723 1.2e+06 0.35 3.764e-03 2.79e+00 7 3549.5 2580 0.717 1.1 e+06 0.36 3.750e-03 2.67e+00 8 3650.0 2649 0.716 1.5e+06 0.34 3.823e-03 3.48e+00 9 3750.0 2711 0.713 1.3e+06 0.35 3.784e-03 2.99e+00 10 3850.0 2787 0.720 1.2e+06 0.35 3.785e-03 3.01 a+00 11 3897.0 2824 0.724 1.2e+06 0.35 3.658e-03 2.03e+00 12 3904.0 2840 0.724 1.2e+06 0.36 3.773e-03 2.88e+00 13 3942.0 2873 0.725 1.2e+06 0.36 3.205e-03 8.02e-01 14 3984.5 2949 0.734 1.1 e+06 0.38 3.828e-03 3.55e+00 15 4050.0 2952 0.720 1.6e+06 0.34 3.817e-03 3.39e+00 16 4150.0 2936 0.707 2.0e+06 0.32 3.711 e-03 2.36e+00 17 4156.5 2941 0.707 2.0e+06 0.32 3.612e-03 1.79e+00 18 4162.5 2954 0.709 1.9e+06 0.32 3.767e-03 2.82e+00 19 4170.0 2967 0.711 1.8e+06 0.33 3.647e-03 1.96e+00 20 4176.0 2998 0.714 1.8e+06 0.33 3.731 e-03 2.50e+00 21 4221.0 3048 0.721 1.5e+06 0.35 3.673e-03 2.11 e+00 22 4229.5 3016 0.712 1.8e+06 0.33 3.740e-03 2.58e+00 23 4238.0 3064 0.722 1.5e+06 0.35 3.571 a-03 1.62e+00 24 4248.5 2991 0.701 2.1 a+06 0.31 3.758e-03 2.73e+00 25 4279.0 3044 0.710 1.9e+06 0.32 3.635e-03 1.90e+00 26 4297.0 3048 0.709 1.9e+06 0.32 3.729e-03 2.49e+00 27 4301.5 3050 0.708 2.0e+06 0.32 3.606e-03 1.77e+00 28 4314.5 3046 0.703 2.1 a+06 0.31 3.747e-03 2.64e+00 29 4350.0 3155 0.717 1.7e+06 0.34 3.774e-03 2.89e+00 30 4450.0 3159 0.702 2.3e+06 0.30 3.828e-03 3.53e+00 31 4550.0 3219 0.706 2.1 a+06 0.31 3.752e-03 2.68e+00 32 4569.5 3291 0.718 1.6e+06 0.34 3.585e-03 1.68e+00 33 4597.0 3330 0.724 1.5e+06 0.35 3.724e-03 2.45e+00 34 4601.5 3321 0.721 1.5e+06 0.35 3.622e-03 1.84e+00 35 4611.5 3385 0.731 1.2e+06 0.37 3.750e-03 2.66e+00 36 4650.0 3427 0.734 1.1 e+06 0.38 3.745e-03 2.62e+00 37 4684.0 3402 0.726 1.3e+06 0.36 3.532e-03 1.48e+00 38 4689.0 1 3431 0.727 1.3e+06 0.36 3.624e-03 1.85e+00 FracproPT 2011 Layer # Top of zone ft Stress (psi) Stress Gradient psilft(psi) Young's modulus Poisson's ratio Total Ct (ftlmin'/z) Pore Fluid Perm. mD 39 4750.0 3470 0.723 1.4e+06 0.35 3.495e-03 1.37e+00 40 4850.0 3512 0.723 1.4e+06 0.35 3.525e-03 1.46e+00 41 4864.0 3524 0.724 1.4e+06 0.35 3.185e-03 7.77e-01 42 4871.0 3530 0.724 1.4e+06 0.35 3.544e-03 1.53e+00 43 4880.0 3539 0.723 1.4e+06 0.35 3.100e-03 6.80e-01 44 4908.5 3553 0.723 1.4e+06 0.35 3.399e-03 1.13e+00 45 4919.5 3543 0.720 1.5e+06 0.35 3.030e-03 6.12e-01 46 j 4922.6 3561 0.723 1.5e+06 0.35 3.479e-03 1.33e+00 47 4927.0 3550 0.720 1.5e+06 0.35 3.082e-03 6.61 e-01 48 4934.0 3558 0.720 1.6e+06 0.34 3.544e-03 1.53e+00 49 4950.0 3573 0.720 1.5e+06 0.35 3.618e-03 1.82e+00 50 4975.5 3574 0.718 1.6e+06 0.34 3.128e-03 7.10e-01 51 4979.0 3591 0.721 1.5e+06 0.35 3.466e-03 1.29e+00 52 4983.5 3593 0.721 1.5e+06 0.35 3.201 e-03 7.97e-01 53 4989.5 3587 0.719 1.5e+06 0.34 3.467e-03 1.29e+00 54 4992.5 3630 0.723 1.3e+06 0.36 3.181 a-03 7.72e-01 55 5050.0 3697 0.731 1.2e+06 0.37 3.503e-03 1.39e+00 56 5064.0 3732 0.737 1.1 e+06 0.39 3.109e-03 6.89e-01 57 5069.0 3675 0.724 1.4e+06 0.36 3.534e-03 1.49e+00 58 5089.5 3731 0.730 1.2e+06 0.38 3.229e-03 8.35e-01 59 5129.0 3677 0.717 1.6e+06 0.34 3.486e-03 1.35e+00 60 5135.5 3687 0.717 1.6e+06 0.34 3.255e-03 8.72e-01 61 5149.0 3702 0.719 1.6e+06 0.34 3.477e-03 1.32e+00 62 5155.0 3715 0.720 1.5e+06 0.35 3.187e-03 7.79e-01 63 5165.0 3729 0.722 1.5e+06 0.35 3.494e-03 1.37e+00 64 5170.5 3759 0.726 1.4e+06 0.36 3.004e-03 5.89e-01 65 5182.0 3772 0.727 1.3e+06 0.37 3.393e-03 1.12e+00 66 5198.0 3774 0.725 1.4e+06 0.36 2.838e-03 4.66e-01 67 5213.5 3811 0.730 1.2e+06 0.37 3.494e-03 1.37e+00 68 5228.5 3817 0.729 1.3e+06 0.37 3.076e-03 6.55e-01 69 5240.0 3830 0.731 1.2e+06 0.37 3.447e-03 1.24e+00 70 5247.0 3867 0.736 1.1 a+06 0.39 2.072e-03 1.72e-01 71 5261.0 3788 0.714 1.6e+06 0.34 3.682e-03 2.16e+00 72 5350.0 3889 0.720 1.3e+06 0.36 3.819e-03 3.41 e+00 73 5450.0 3935 0.687 1.5e+06 0.35 3.696e-03 2.25e+00 74 6000.0 1 4368 0.728 1.3e+06 0.36 3.779e-03 2.94e+00 Tnhla 1 R• 1 ithnlnm Parameters Layer # Top of zone ft Lithology Fracture Toughness psi-in'/2 Composite Layering Effect 1 0.0 Sandstone 1000 25.00 2 1600.0 Sandstone 1000 25.00 3 3350.0 Sandstone 1000 25.00 4 3450.0 Sandstone 1000 25.00 5 3534.0 Shale 1000 25.00 6 3538.5 Sandstone 1000 25.00 Sandstone 1000 25.00 ff3549.5 3650.0 Sandstone 1000 25.00 3750.0 Sandstone 1000 25.00 FracproPT 2011 • • Layer # Top of zone ft Lithology Fracture Toughness psi in'/z Composite Layering Effect 10 3850.0 Sandstone 1000 25.00 11 3897.0 Sandstone 1000 25.00 12 3904.0 Sandstone 1000 25.00 13 3942.0 Shale 1000 25.00 14 3984.5 Sandstone 1000 25.00 15 4050.0 Sandstone 1000 25.00 16 4150.0 Sandstone 1000 25.00 17 4156.5 Sandstone 1000 25.00 18 4162.5 Sandstone 1000 25.00 19 4170.0 Sandstone 1000 25.00 20 4176.0 Sandstone 1000 25.00 21 4221.0 Sandstone 1000 25.00 22 4229.5 Sandstone 1000 25.00 23 4238.0 Sandstone 1000 25.00 24 4248.5 Sandstone 1000 25.00 25 4279.0 Sandstone 1000 25.00 26 4297.0 Sandstone 1000 25.00 27 4301.5 Sandstone 1000 25.00 28 4314.5 Sandstone 1000 25.00 29 4350.0 Sandstone 1000 25.00 30 4450.0 Sandstone 1000 25.00 31 4550.0 Sandstone 1000 25.00 32 4569.5 Sandstone 1000 25.00 33 4597.0 Sandstone 1000 25.00 34 4601.5 Sandstone 1000 25.00 35 4611.5 Sandstone 1000 25.00 36 4650.0 Sandstone 1000 25.00 37 4684.0 Sandstone 1000 25.00 38 4689.0 Sandstone 1000 25.00 39 4750.0 Sandstone 1000 25.00 40 4850.0 Sandstone 1000 25.00 41 4864.0 Shale 1000 25.00 42 4871.0 Sandstone 1000 1.00 43 4880.0 Shale 1000 1.00 44 4908.5 Sandstone 1000 1.00 45 4919.5 Shale 1000 25.00 46 4922.6 Sandstone 1000 25.00 47 4927.0 Shale 1000 25.00 48 4934.0 Sandstone 1000 25.00 49 4950.0 Sandstone 1000 25.00 50 4975.5 Shale 1000 25.00 51 4979.0 Sandstone 1000 25.00 52 4983.5 Shale 1000 25.00 53 4989.5 Sandstone 1000 25.00 54 4992.5 Shale 1000 25.00 55 5050.0 Sandstone 1000 25.00 56 5064.0 Shale 1000 25.00 57 5069.0 Sandstone 1000 25.00 58--F 5089.5 Shale 1000 25.00 59 1 5129.0 Sandstone 1000 25.00 FracproPT 2011 LI 0 Layer # Top of zone ft Lithology Fracture Toughness psi-in'/2 composite Layering Effect 60 5135.5 Shale 1000 25.00 61 5149.0 Sandstone 1000 25.00 5155.0 Shale 1000 25.00 51650 Sandstone 1000 25.00 r65 5170.5 Shale 1000 25.00 5182.0 Sandstone 1000 25.00 5198.0 Shale 1000 25.00 5213.5 Sandstone 1000 25.00 .5 Shale 1000 25.00 t .0 Sandstone 1000 25.00 .0 t5261.0 Shale 1000 25.00 71 Sandstone 1000 25.00 72 5350.0 Sandstone 1000 25.00 73 5450.0 Sandstone 1000 25.00 74 6000.0 Sandstone 1000 25.00 10 FracproPT 2011 E • Table 14: Casing Configuration Length ft Segment Type Casing ID in Casing OD in Weight Ib/ft Grade 5100 Cemented Casing 6.276 7.000 26.000 L-80 Table 15: Surface Line and Tubing Configuration Length ft Segment Type Tubing ID in Tubing OD in Weight Ib/ft Grade 4575 Tubing 2.992 3.500 9.200 L-80 Total frac string volume (bbls) 36.1 Pumping down Tubing Table 16: Perforated Intervals Interval #1 Top of Perfs - TVD ft 4150 Bot of Perfs - TVD ft 4170 Top of Perfs - MD ft 4150 Bot of Perfs - MD ft 4170 Perforation Diameter in 0.300 # of Perforations 120 Table 17: Path Summary Segment Type Length ft MD ft TVD ft Dev de Ann OD in(in)___in Ann ID Pipe ID Tubing 4150 4150 4150 0.0 0.000 0.000 2.992 11 FracproPT 2011 Tnhln 1 A• Klan r-VValIhnra Frirtinn R Parfnratinn Frirtinn Time Flowrate Flowrate Near-Wellbo Perforation Total Entry Perforation Perfs (mm:ss) #1 #2 re Friction Friction Friction Friction Effectively b m) (bpm) (psi(psi) psi Multiplier Open 0:00 0.00 0.00 0 0 0 1.00 120.00 TahlP 19• RPSPrvnir Pressure and Permeabilitv Summary Table Plot Est. Reservoir Est. Reservoir Est. Reservoir Pressure Pressure Permeability (psi) Gradient (mD) psi/ft Injection/Shut-in #1 Perm Analysis Plot 1.00e-01 12 FracproPT 2011 Table 20: Model Input Parameters Fracture Model 3D Shear-Decou led Reservoir Data Entry General Single Scale Run From Job-Desi n Data Fracture Orientation Vertical Proppant Transport Model Proppant Convection Run Fracture and Wellbore Models Growth after Shut-in Allow General Iteration Backstress I nore Heat Transfer Effects Model Acid Fracturing Model FracproPTDefault Leakoff Model Lumped -Parameter Default Table 21: Fracture Growth Parameters (3D Shear-Dernunled) Parameter Value Default Crack Opening Coefficient 8.50e-01 8.50e-01 Tip Effects Coefficient 1.00e-04 1.00e-04 Channel Flow Coefficient 1.00e+00 1.00e+00 Tip Radius Fraction 1.00e-02 1.00e-02 Ti Effects Scale Volume bbis 100.0 100.0 Fluid Radial Weighting Exponent 0.00e+00 0.00e+00 Width Decoupling Coefficient 1.00e+00 1.00e+00 Table 22: Proppant Model Parameters Parameter Value Default Minimum Proppant Concentration Ib/ft2 0.20 0.20 Minimum Proppant Diameter in 0.0080 0.0080 Minimum Detectable Proppant Concentration p 0.20 0.20 Proppant Drag Effect Exponent 8.0 8.0 Proppant Radial Weighting Exponent 0.2500 0.2500 Proppant Convection Coefficient 10.00 10.00 Proppant Settling Coefficient 1.00 1.00 Quadratic Backfill Model ON ON Tip Screen -Out Backfill Coefficient 0.50 0.50 Stop Model on Screenout ON ON Reset Proppant in Fracture after Closure ON ON Table 23: Low Level Parameters Parameter Value Default Perm. Contrast: Distance Effect 1.0 1.0 Perm. Contrast: Containment Effect 1.0 1.0 Perm. Contrast: Permeability Level 1.00 1.00 Perm. Contrast Model: FracproPT Default YES Fluid < el> Bulk Modulus(psi) 3.000e+10 3.00Oe+10 Proppant Bulk Modulus(psi) 3.00Oe+06 3.00Oe+06 Fluid el Bulk Coefficient of Thermal Expansion 3.00Oe-04 3.00Oe-04 Effect of Proppant on Length Growth 1.00 1.00 Fraction of BRACKET FRAC Proppant that is INVERTA-FRAC by Volume 0.5 0.5 Remember Position of Proppant Banks after closure on Proppant NO NO Allow Slippage NO NO Reset Fluid Leakoff after Frac Closure NO NO Minimum Volume Limit Value 0.20 0.20 Center Shifting Option: Fracture Always Stays Connected to Perfs X X 13 FracproPT 2011 Parameter Value Default Stages can Move from Perfs after Shut-in Fracture can Move from Perfs after Shut-in Fracture can Move from Perfs at an Time Stage Splitting Volume Threshold bbls 200.0 200.0 Sta e Splitting Leakoff Compensation bbls 5.0 5.0 -r L. nA. 1r4:1 1 ..., L.,Ff A (`Incllrn 1 QLJIG Lam. 11 IIIIGI L Parameter Value Default Initial Leakoff Area Multiplier Coefficient 1.000 1.000 Initial Leakoff Area from Last Simulation ft2 999.271 n/a Closure Leakoff Area Multiplier Coefficient 0.025 0.025 Default Shut-in Model YES YES Shut-in Tip Weighting Coefficient for Leakoff 1.00 1.00 Shut-in Tip Weighting Exponent for Leakoff 1.00 1.00 Minimum Shut-in Volume bbls 100.0 100.0 Model Proppant in Flow -back Model Wall -building Viscosity Effect YES NO YES NO nc. 11A:(2..,-Ak Dmnfnrc 1 QLJIG L�J. IVIIJGGIIGI IV VGV v Parameter Value Default Set Minimum Fracture Height NO NO Model Ve Small Fractures NO NO Model Head Effects in Fracture NO NO Model Fracture Center Shifting NO NO Near-Wellbore Friction Exponent 0.50 0.50 14 FracproPT 2011 IE IE Figure 1 Fracture Profile for Upper Sand MOBM 10ppg, Subtitle, Date 15 FracproPT 2011 • FracproPT 2011 Hydraulic Fracture Analysis Date: Wednesday, October 31, 2012 Well Name: Umiat DSP-01 Location: Formation: Torok Job Date: 10/31 /2012 2:48:39 PM Filename: 10.0 ppg MOBM 6 bpm Upper Sand Tnhla 1 • Frarti ira C-�anmptry Si immarv* Fracture Half -Length ft 119 Propped Half -Length ft 0 Total Fracture Height ft 244 Total Propped Height ft 0 Depth to Fracture To ft 4294 Depth to Propped Fracture To ft 4420 Depth to Fracture Bottom ft 4539 Depth to Propped Fracture Bottom ft 4420 Equivalent Number of Multiple Fracs 1.0 Max. Fracture Width in 0.71 Fracture Slurry Efficienc ** 0.31 Avg. Fracture Width in 0.45 Avg. Proppant Concentration Ib/ftZ 0.00 * All values reported are for the entire fracture system at a model time of 166.70 min (end of Stage 1 Main frac pad) ** Value is reported for the end of the last pumping stage (Stage 1, Main frac pad) Tahla 9• FrarturP Cnnrtuctivity Summarv* Avg. Conductivity" mD-ft 0.0 Avg. Frac Width Closed onprop) in 0.000 Dimensionless Conductivit ** 0.00 Ref. Formation Permeability mD 0.939 Proppant Damage Factor 0.50 Undamaged Prop Perm at Stress mD 0 Apparent Damage Factor*** 0.00 Prop Perm with Prop Damage mD 0 Total Damage Factor 0.50 Prop Perm with Total Damage (mD)0 Effective Propped Length ft 0 Proppant Embedment in 0.000 *All values reported are for the entire fracture system. Actual conductivity could be lower if equivalent multiple fractures have been modeled ** Total Damage Factor and Proppant Embedment have been applied *** Apparent Damage due to non -Darcy and multi -phase flow Table 3: Fracture Pressure Summar * Model Net Pressure**(psi) 445 BH Fracture Closure Stress(psi) 3155 Observed Net Pressure**(psi) 0 Closure Stress Gradient si/ft 0.714 Hydrostatic Head'(psi) 2297 Avg. Surface Pressure(psi) 1598 Reservoir Pressure(psi) 2375 Max. Surface Pressure psi 1863 * Averages and maxima reported for Main Frac stages ** Values reported for the end of the last pumping stage (Stage 1, Main frac pad) *** Value reported for clean fluid Table 4: O erations Summar * Total Clean Fluid Pumped bbls 1000.9 Total Proppant Pumped klbs 0.0 Total Slurry Pumped bbls 1000.9 Total Proppant in Fracture kibs 0.0 Pad Volume bbls 1000.0 Avg. Hydraulic Horsepower h 235 Pad Fraction % of Slur Vol)** 100.0 Max. Hydraulic Horsepower h 274 Pad Fraction % of Clean Vol)** 100.0 Avg Btm Slurry Rate b m 6.0 Primary Fluid Type Primary Proppant Type Secondary Fluid Type Secondary Proppant Type * Averages and maxima reported for Main Frac stages Totals reported for all injections combined. ** Based on following volume ratio of stage types: Main frac pad / (Main frac pad + Main frac slurry), and excluding flush. FracproPT 2011 • • 'r ki G• KAnA 1 r'n!ihrn+inn G immnry Crack Opening Coefficient 8.50e-01 Width Decoupling Coefficient 1.00e+00 Tip Effects Coefficient 1.00e-04 Tip Radius Fraction 1.00e-02 Tip Effects Scale Volume bbls 100.0 Pro ant Drag Effect Exponent 8.0 CLE Outside Pa zone 25.00 Multiple fractures settings start V/L/O 1.0 / 1.0 / 1.0 Multiple fractures settings end V/L/O 1.0 / 1.0 / 1.0 FracproPT 2011 • Table 6: Hvdraulic Fracture Growth Historv* End of Stage Type Time Fracture Fracture Fracture Avg. Model Net Slurry Equivalent Stage # (mm:ss) Half-Leng Height Width at Fracture Pressure Efficiency Number of th (ft) Well Width (psi) Multifracs ft in in 1 Main frac pad 166:40 119 244 0.712 0.455 445 0.31 1.0 * All values reported are for the entire fracture system and at the end of each stage Table 7: Pr000ed Fracture Prooerties by Distance from the Well at Fracture Center at Depth of 4420ft Distance from Well (ft) Fracture System Width* in Conductivity per Frac** (mD•ft) Frac System Conductivity*** (mD•ft) Prop Conc per Frac (lb/W) Frac System Prop Conc**** (Ib/W) 0.0 0.680 0.0 0.0 0.00 0.00 0.0 0.680 0.0 0.0 0.00 0.00 0.0 0.680 0.0 0.0 0.00 0.00 0.0 0.680 0.0 0.0 0.00 0.00 0.0 0.680 0.0 0.0 0.00 0.00 0.0 0.680 0.0 0.0 0.00 0.00 0.0 0.680 0.0 0.0 0.00 0.00 0.0 0.680 0.0 0.0 0.00 0.00 0.0 0.680 0.0 0.0 0.00 0.00 0.0 0.680 0.0 0.0 0.00 0.00 * Width values reported are for the entire fracture system. ** Fracture conductivity reported for total proppant damage of 0.50 and 0.000 in of proppant embedment. *** Frac system conductivity reported for 1.0 equivalent multiple fractures with 100% considered conductive. **** Frac system proppant concentration reported for 1.0 equivalent multiple fractures. FracproPT 2011 0 0 r-L.l., o. n,. ., T..,.,4. .,+ Cnhnr4i In 1 QUIG V. Stage V�01 Stage Type Elapsed Fluid Clean Prop Stage Slurry Proppant # Time Type Volume Conc Prop. Rate Type min:sec al klbs bpm Wellbore Fluid MOBM 10 1611 1 1 Main frac pad 1 166:40 MOBM 10 42000 0.00 0.0 6.00 Design clean volume (bbls) Design slurry volume (bbls) 1000.0 Design proppant pumped (klbs) 1000.0 0.0 FracproPT 2011 IE KI Table 9: PrODDant and Fluid Material Quantity Units Unit Cost $ Discnt % Cost $ MOBM 10 1000.0 bbls 0.00 0.0 1 0.00 Treatment Totals calculated from design schedule Proppant and Fluid Subtotal: 0.00 ($) Total: 0.00 ($) FracproPT 2011 • • I dUIC I U. FIUIU rai ai ucici a Fluid Name MOBM 10 Vendor Other System MOBM Description 10 ppg MOBM Initial Viscosity cp 40.13 Initial n' 0.125 Initial k' lbf•s^n/ft2 0.125 Viscosity 4.0 hours c 1.72 n' 4.0 hours 0.136 k' @ 4.0 hours lbf•s"n/ftZ 0.136 Base Fluid Specific Gravity 1.20 Spurt Loss al/ftz 0.009 Wall Building ft/min% 0.003 Flowrate #1 b m 10.00 Fric Press #1 si/1000 ft 54.41 Flowrate #2 b m 20.00 Fric Press #2 si/1000 ft 104.2 Flowrate #3 b m 40.00 Fric Press #3 si/1000 ft 275.1 Wellbore Friction Multiplier 1.000 All Fluid into is at a reservoir temperature or as.v l r) All Viscosities at Shear Rate of 511 (1/sec) Wellbore Friction pressures shown are the interpolated values multiplied by the Wellbore Friction Multiplier. Friction is displayed for longest wellbore segment FracproPT 2011 • 0 Tnhlc 11 • 1 anknff PnramPtPrC Reservoir type User Spec Reservoir fluid compressibility 1/psi 2.58e-0 Filtrate to pore fluid perm. ratio, Kp/KI 10.00 Reservoir Viscosity cp 0.02 Reservoir pore pressure psi 2375 Porosity 0.10 Initial fracturing pressure psi 4039 Gas Leakoff Percentage % 100.00 Reservoir Parameters Reservoir Temperature ff) 93.00 Depth to center of Perfs (ft) 4420 Perforated interval (ft) 20 Initial frac depth (ft) 4420 Tnhlc 17. 1 aver PnramatarS Layer # Top of zone ft Stress (psi) Stress Gradient psi/ft(psi) Young's modulus Poisson's ratio Total Ct (ft/min'/) Pore Fluid Perm. ml) 1 0.0 1115 0.697 2.6e+06 0.29 3.498e-03 1.38e+00 2 1600.0 1777 0.718 1.5e+06 0.34 3.840e-03 3.72e+00 3 3350.0 2468 0.726 1.2e+06 0.36 3.784e-03 2.99e+00 4 3450.0 2553 0.731 1.1 e+06 0.37 3.733e-03 2.52e+00 5 3534.0 2562 0.725 1.2e+06 0.36 3.623e-03 1.85e+00 6 3538.5 2562 0.723 1.2e+06 0.35 3.764e-03 2.79e+00 7 3549.5 2580 0.717 1.1 a+06 0.36 3.750e-03 2.67e+00 8 3650.0 2649 0.716 1.5e+06 0.34 3.823e-03 3.48e+00 9 3750.0 2711 0.713 1.3e+06 0.35 3.784e-03 2.99e+00 10 3850.0 2787 0.720 1.2e+06 0.35 3.785e-03 3.01 e+00 11 3897.0 2824 0.724 1.2e+06 0.35 3.658e-03 2.03e+00 12 3904.0 2840 0.724 1.2e+06 0.36 3.773e-03 2.88e+00 13 3942.0 2873 0.725 1.2e+06 0.36 3.205e-03 8.02e-01 14 3984.5 2949 0.734 1.1 e+06 0.38 3.828e-03 3.55e+00 15 4050.0 2952 0.720 1.6e+06 0.34 3.817e-03 3.39e+00 16 4150.0 2936 0.707 2.0e+06 0.32 3.711 e-03 2.36e+00 17 4156.5 2941 0.707 2.0e+06 0.32 3.612e-03 1.79e+00 18 4162.5 2954 0.709 1.9e+06 0.32 3.767e-03 2.82e+00 19 4170.0 2967 0.711 1.8e+06 0.33 3.647e-03 1.96e+00 20 4176.0 2998 0.714 1.8e+06 0.33 3.731 e-03 2.50e+00 21 4221.0 3048 0.721 1.5e+06 0.35 3.673e-03 2.11 e+00 22 4229.5 3016 0.712 1.8e+06 0.33 3.740e-03 2.58e+00 23 4238.0 3064 0.722 1.5e+06 0.35 3.571 e-03 1.62e+00 24 4248.5 2991 0.701 2.1 e+06 0.31 3.758e-03 2.73e+00 25 4279.0 3044 0.710 1.9e+06 0.32 3.635e-03 1.90e+00 26 4297.0 3048 0.709 1.9e+06 0.32 3.729e-03 2.49e+00 27 4301.5 3050 0.708 2.0e+06 0.32 3.606e-03 1.77e+00 28 4314.5 3046 0.703 2.1 a+06 0.31 3.747e-03 2.64e+00 29 4350.0 3155 0.717 1.7e+06 0.34 3.774e-03 2.89e+00 30 4450.0 3159 0.702 2.3e+06 0.30 3.828e-03 3.53e+00 31 j 4550.0 3219 0.706 2.1 a+06 0.31 3.752e-03 2.68e+00 32 4569.5 3291 0.718 1.6e+06 0.34 3.585e-03 1.68e+00 33 4597.0 3330 0.724 1.5e+06 0.35 3.724e-03 2.45e+00 34 4601.5 3321 0.721 1.5e+06 0.35 3.622e-03 1.84e+00 35 4611.5 3385 0.731 1.2e+06 0.37 3.750e-03 2.66e+00 36 4650.0 3427 0.734 1.1 e+06 0.38 3.745e-03 2.62e+00 37 4684.0 3402 0.726 1.3e+06 0.36 3.532e-03 1.48e+00 38 4689.0 3431 0.727 1.3e+06 0.36 3.624e-03 1.85e+00 FracproPT 2011 Layer # Top of zone ft Stress (psi) Stress Gradient psi/ft Young's modulus psi Poisson's ratio Total Ct (ft/min'/z) Pore Fluid Perm. mD 39 4750.0 3470 0.723 1.4e+06 0.35 3.495e-03 1.37e+00 40 4850.0 3512 0.723 1.4e+06 0.35 3.525e-03 1.46e+00 41 4864.0 3524 0.724 1.4e+06 0.35 3.185e-03 7.77e-01 42 4871.0 3530 0.724 1.4e+06 0.35 3.544e-03 1.53e+00 43 4880.0 3539 0.723 1.4e+06 0.35 3.100e-03 6.80e-01 44 4908.5 3553 0.723 1.4e+06 0.35 3.399e-03 1.13e+00 45 4919.5 3543 0.720 1.5e+06 0.35 3.030e-03 6.12e-01 46 4922.6 3561 0.723 1.5e+06 0.35 3.479e-03 1.33e+00 47 4927.0 3550 0.720 1.5e+06 0.35 3.082e-03 6.61 a-01 48 4934.0 3558 0.720 1.6e+06 0.34 3.544e-03 1.53e+00 49 4950.0 3573 0.720 1.5e+06 0.35 3.618e-03 1.82e+00 50 4975.5 3574 0.718 1.6e+06 0.34 3.128e-03 7.10e-01 51 4979.0 3591 0.721 1.5e+06 0.35 3.466e-03 1.29e+00 52 4983.5 3593 0.721 1.5e+06 0.35 3.201 e-03 7.97e-01 53 4989.5 3587 0.719 1.5e+06 0.34 3.467e-03 1.29e+00 54 4992.5 3630 0.723 1.3e+06 0.36 3.181 e-03 7.72e-01 55 5050.0 3697 0.731 1.2e+06 0.37 3.503e-03 1.39e+00 56 5064.0 3732 0.737 1.1 e+06 0.39 3.109e-03 6.89e-01 57 5069.0 3675 0.724 1.4e+06 0.36 3.534e-03 1.49e+00 58 5089.5 3731 0.730 1.2e+06 0.38 3.229e-03 8.35e-01 59 5129.0 3677 0.717 1.6e+06 0.34 3.486e-03 1.35e+00 60 5135.5 3687 0.717 1.6e+06 0.34 3.255e-03 8.72e-01 61 5149.0 3702 0.719 1.6e+06 0.34 3.477e-03 1.32e+00 62 5155.0 3715 0.720 1.5e+06 0.35 3.187e-03 7.79e-01 63 5165.0 3729 0.722 1.5e+06 0.35 3.494e-03 1.37e+00 64 5170.5 3759 0.726 1.4e+06 0.36 3.004e-03 5.89e-01 65 5182.0 3772 0.727 1.3e+06 0.37 3.393e-03 1.12e+00 66 5198.0 3774 0.725 1.4e+06 0.36 2.838e-03 4.66e-01 67 5213.5 3811 0.730 1.2e+06 0.37 3.494e-03 1.37e+00 68 5228.5 3817 0.729 1.3e+06 0.37 3.076e-03 6.55e-01 69 5240.0 3830 0.731 1.2e+06 0.37 3.447e-03 1.24e+00 70 5247.0 3867 0.736 1.1 a+06 0.39 2.072e-03 1.72e-01 71 5261.0 3788 0.714 1.6e+06 0.34 3.682e-03 2.16e+00 72 5350.0 3889 0.720 1.3e+06 0.36 3.819e-03 3.41 a+00 73 5450.0 3935 0.687 1.5e+06 0.35 3.696e-03 2.25e+00 74 6000.0 4368 0.728 1.3e+06 0.36 3.779e-03 2.94e+00 Tahle 13- Litholoov Parameters Layer # Top of zone ft Lithology Fracture Toughness psi•in% Composite Layering Effect 1 0.0 Sandstone 1000 25.00 2 1600.0 Sandstone 1000 25.00 3 3350.0 Sandstone 1000 25.00 4 3450.0 Sandstone 1000 25.00 5 3534.0 Shale 1000 25.00 6 3538.5 Sandstone 1000 25.00 7 3549.5 Sandstone 1000 25.00 8 3650.0 Sandstone 1000 25.00 9 3750.0 Sandstone 1000 25.00 FracproPT 2011 0 C Layer # Top of zone ft Lithology Fracture Toughness psi• in% Composite Layering Effect 10 3850.0 Sandstone 1000 25.00 11 3897.0 Sandstone 1000 25.00 12 3904.0 Sandstone 1000 25.00 13 3942.0 Shale 1000 25.00 14 3984.5 Sandstone 1000 25.00 15 4050.0 Sandstone 1000 25.00 16 4150.0 Sandstone 1000 25.00 17 4156.5 Sandstone 1000 25.00 18 4162.5 Sandstone 1000 25.00 19 4170.0 Sandstone 1000 25.00 20 4176.0 Sandstone 1000 25.00 21 4221.0 Sandstone 1000 25.00 22 4229.5 Sandstone 1000 25.00 23 4238.0 Sandstone 1000 25.00 24 4248.5 Sandstone 1000 25.00 25 4279.0 Sandstone 1000 25.00 26 4297.0 Sandstone 1000 25.00 27 4301.5 Sandstone 1000 25.00 28 4314.5 Sandstone 1000 25.00 29 4350.0 Sandstone 1000 25.00 30 4450.0 Sandstone 1000 25.00 31 4550.0 Sandstone 1000 25.00 32 4569.5 Sandstone 1000 25.00 33 4597.0 Sandstone 1000 25.00 34 4601.5 Sandstone 1000 25.00 35 4611.5 Sandstone 1000 25.00 36 4650.0 Sandstone 1000 25.00 37 4684.0 Sandstone 1000 25.00 38 4689.0 Sandstone 1000 25.00 39 4750.0 Sandstone 1000 25.00 40 4850.0 Sandstone 1000 25.00 41 4864.0 Shale 1000 25.00 42 4871.0 Sandstone 1000 1.00 43 4880.0 Shale 1000 1.00. 44 4908.5 Sandstone 1000 1.00 45 4919.5 Shale 1000 25.00 46 4922.6 Sandstone 1000 25.00 47 4927.0 Shale 1000 25.00 48 4934.0 Sandstone 1000 25.00 49 4950.0 Sandstone 1000 25.00 50 4975.5 Shale 1000 25.00 51 4979.0 Sandstone 1000 25.00 52 4983.5 Shale 1000 25.00 53 4989.5 Sandstone 1000 25.00 54 4992.5 Shale 1000 25.00 55 5050.0 Sandstone 1000 25.00 56 5064.0 Shale 1000 25.00 57 5069.0 Sandstone 1000 25.00 58 5089.5 Shale 1000 25.00 59 5129.0 Sandstone 1000 25.00 FracproPT 2011 • • Layer # Top of zone ft Lithology Fracture Toughness psi•in'/2 Composite Layering Effect 60 5135.5 Shale 1000 25.00 61 5149.0 Sandstone 1000 25.00 62 5155.0 Shale 1000 25.00 63 5165.0 Sandstone 1000 25.00 64 5170.5 Shale 1000 25.00 65 5182.0 Sandstone 1000 25.00 66 5198.0 Shale 1000 25.00 67 5213.5 Sandstone 1000 25.00 68 5228.5 Shale 1000 25.00 69 5240.0 Sandstone 1000 25.00 70 5247.0 Shale 1000 25.00 71 5261.0 Sandstone 1000 25.00 72 5350.0 Sandstone 1000 25.00 73 5450.0 Sandstone 1000 25.00 74 6000.0 Sandstone 1000 25.00 10 FracproPT 2011 • • Tahle 14- Casing Configuration Length ft Segment Type Casing ID in Casing OD in Weight Ib/ft Grade 5100 Cemented Ca sin 6.276 1 7.000 26.000 L-80 Table 15• Surface Line and Tubina Configuration Length ft Segment Type Tubing ID in Tubing OD in Weight Ib/ft Grade 4575 Tubing 2.992 3.500 9.200 L-80 Total frac string volume (bbls) 38.4 Pumping down Tubing Table 16: Perforated Intervals Interval #1 Top of Perfs - TVD ft 4410 Bot of Perfs - TVD ft 4430 Top of Perfs - MD ft 4410 Bot of Perfs - MD ft 4430 Perforation Diameter in 0.300 # of Perforations 120 Tnhle 17• Path Summary Segment Type Length (ft) MD (ft TVD ft Dev de Ann OD in Ann ID in Pipe ID in Tubing 4410 4410 4410 0.0 0.000 1 0.000 2.992 I 1 FracproPT 2011 0 • "r„W 10 AlXAloilk nrn Grintinn k Pnrfnrnfinn Frirrfinn ~ vTime vM v Flowrate Flowrate Near-Wellbo Perforation Total Entry Perforation Perfs (mm:ss) #1 #2 re Friction Friction Friction Friction Effectively (bp m bpm) (psi(psi) psi Multiplier Open 0:00 0.00 0.00 0 0 0 1.00 120.00 Tnhla 10• Pp-_prvnlr PrARR11rA anri Permeability Summary Table Plot Est. Reservoir Est. Reservoir Est. Reservoir Pressure Pressure Permeability (psi) Gradient (mD) psi/ft Injection/Shut-in #1 Perm Analysis Plot I I 1.00e-01 12 FracproPT 2011 0 • Table 20: Model Input Parameters Fracture Model 3D Shear-Decou led Reservoir Data Entry General Single Scale Run From Job -Design Data Fracture Orientation Vertical Proppant Transport Model Proppant Convection Run Fracture and Wellbore Models Growth after Shut-in Allow General Iteration Backstress ignore Heat Transfer Effects Model Acid Fracturing Model FracproPT Default Leakoff Model Lumped -Parameter Default Table 21: Fracture Growth Parameters 3D Shear-Decou led Parameter Value Default Crack Opening Coefficient 8.50e-01 8.50e-01 Tip Effects Coefficient 1.00e-04 1.00e-04 Channel Flow Coefficient 1.00e+00 1.00e+00 Tip Radius Fraction 1.00e-02 1.00e-02 Tip Effects Scale Volume bbls 100.0 100.0 Fluid Radial Weighting Exponent 0.00e+00 0.00e+00 Width Decoupling Coefficient 1.00e+00 1.00e+00 Table 22: Proppant Model Parameters Parameter Value Default Minimum Proppant Concentration Ib/ft2 0.20 0.20 Minimum Proppant Diameter in 0.0080 0.0080 Minimum Detectable Proppant Concentration pp 0.20 0.20 Proppant Drag Effect Exponent 8.0 8.0 Proppant Radial Weighting Exponent 0.2500 0.2500 Proppant Convection Coefficient 10.00 10.00 Proppant Settling Coefficient 1.00 1.00 Quadratic Backfill Model ON ON Tip Screen -Out Backfill Coefficient 0.50 0.50 Stop Model on Screenout ON ON Reset Proppant in Fracture after Closure ON ON Table 23: Low Level Parameters Parameter Value Default Perm. Contrast: Distance Effect 1.0 1.0 Perm. Contrast: Containment Effect 1.0 1.0 Perm. Contrast: Permeability Level 1.00 1.00 Perm. Contrast Model: FracproPT Default YES Fluid < el> Bulk Modulus(psi) 3.000e+10 3.00Oe+10 Proppant Bulk Modulus psi 3.00Oe+06 3.00Oe+06 Fluid el Bulk Coefficient of Thermal Expansion 3.00Oe-04 3.00Oe-04 Effect of Proppant on Length Growth 1.00 1.00 Fraction of BRACKET FRAC Proppant that is INVERTA-FRAC by Volume 0.5 0.5 Remember Position of Proppant Banks after closure on Proppant NO NO Allow Slippage NO NO Reset Fluid Leakoff after Frac Closure NO NO Minimum Volume Limit Value 0.20 0.20 Center Shifting Option: Fracture Always Stays Connected to Perfs X X 13 FracproPT 2011 • • Parameter Value Default Stages can Move from Perfs after Shut-in Fracture can Move from Perfs after Shut-in Fracture can Move from Perfs at any Time Stage Splitting Volume Threshold bbls 200.0 200.0 Stage Splitting Leakoff Compensation bbis 5.0 t 5.0 -r k! •. 7A• Ir,i+i-I 1 o L--ff nnrl (-Inciim Parameter Value Default Initial Leakoff Area Multiplier Coefficient 1.000 1.000 Initial Leakoff Area from Last Simulation ft2 813.009 n/a Closure Leakoff Area Multiplier Coefficient 0.025 0.025 Default Shut-in Model YES YES Shut-in Tip Weighting Coefficient for Leakoff 1.00 1.00 Shut-in Tip Weighting Exponent for Leakoff 1.00 1.00 Minimum Shut-in Volume bbls 100.0 100.0 Model Prop ant in Flow -back YES YES Model Wall -building Viscosity Effect NO NO T.. L.i.. 7c• t\Ai.. ni! ('-r.hh Dnrnmatore Parameter Value Default Set Minimum Fracture Height NO NO Model Very Small Fractures NO NO Model Head Effects in Fracture NO NO Model Fracture Center Shiftin NO NO Near-Wellbore Friction Exponent t 0.50 0.50 14 FracproPT 2011 (• Width Profile (in) Concentration of Proppant in Fracture (lb/ft') Layer Properties TVD(ft) 0 50 100 150 200 250 300 350 400 R°... ND(ft FFractureLength (ft) 118.9Length (ft) 0.0 4300 ---_ cture Height Propped Hei (ft) 244.5 ht ft 0.0 4300 4350 -- -- -- - - - 4350 - ---- -- aaoo - -�-- _ . 4400 - — - - — T_ 4450 --, t - - - - — � - - - -- - 4450 - 4500 - � - --t- - ---- -- - 4500 4550 - - ---- i I --- —, ------ Proppant Concentration (Ib/ft') 4 50 5 - - 4600_0 _0.10-020 � 0_. 4600 0 4Q �Il SQr-010:__ -0 90 -�.�- Figure 1 Fracture Profile for Upper Sand MUbM IUppg, 5umme, uaie 15 FracproPT 2011 • • FracproPT 2011 Hydraulic Fracture Analysis Date: Wednesday, October 31, 2012 Well Name: Umiat DSP-01 Location: Formation: Torok Job Date: 10/31 /2012 2:48:39 PM Filename: 10.0 ppg MOBM 6 bpm Lower Sand _17 L.h 4 C.....+!'_+C, Im mnni* Fracture Half -Length ft 115 Propped Half -Length ft 0 Total Fracture Height ft 242 Total Propped Height ft 0 Depth to Fracture To ft 4538 Depth to Propped Fracture To ft 4665 Depth to Fracture Bottom ft 4779 Depth to Propped Fracture Bottom ft 4665 Equivalent Number of Multiple Fracs 1.0 Max. Fracture Width in 0.78 Fracture Slurry Efficienc ** 0.32 Avg. Fracture Width in 0.50 Av . Proppant Concentration Ib/ft2 0.00 All values reported are Tor the entire Tracture system at a modei ume of I OK). iv nun test lu vl otaya I Mall l Il— Nau1 ** Value is reported for the end of the last pumping stage (Stage 1, Main frac pad) T.. t.l.. 7. C.....+. .... t'—A..'.+i..i+.. Cllm* d. Avg. Conductivit ** mD-ft 0.0 Avg. Frac Width Closed onprop) in 0.000 Dimensionless Conductivit ** 0.00 Ref. Formation Permeability mD 0.939 Proppant Damage Factor 0.50 Undamaged Prop Perm at Stress mD 0 Apparent Damage Factor*** 0.00 Prop Perm with Prop Damage mD 0 Total Damage Factor 0.50 Prop Perm with Total Damage mD 0 Effective Propped Length ft 0 Proppant Embedment in 0.000 . All values reported are Tor the entire Tracture system. HctUdl cUMUGUVIty uvula VG IVWGI 11 V%J UIVaIGIIt nlulurlc nc.a.wi..� ..ay. v..v. modeled " Total Damage Factor and Proppant Embedment have been applied *** Apparent Damage due to non -Darcy and multi -phase flow _ Model Net Pressure**(psi) 342 BH Fracture Closure Stress(psi) 3427 Observed Net Pressure**(psi) 0 Closure Stress Gradient si/ft 0.735 Hydrostatic Head***(psi) 2424 Avg. Surface Pressure(psi) 1618 Reservoir Pressure(psi) 2375 Max. Surface Pressure(psi) 1824 Averages and maxima reported Tor main rrac stages ** Values reported for the end of the last pumping stage (Stage 1, Main frac pad) *** Value reported for clean fluid T_LI_ A. t-%- 0.. ..* M Total Clean Fluid Pumped bbls 1001.3 Total Proppant Pum ed klbs 0.0 Total Slur Pumped bbls 1001.3 Total Proppant in Fracture klbs 0.0 Pad Volume bbls 1000.0 Avg. Hydraulic Horse ower h 238 Pad Fraction % of Slur Vol)** 100.0 Max. Hydraulic Horsepower h 268 Pad Fraction % of Clean Vol)** 100.0A�Se�contdary SlurryRate b m 6.0 Prima Fluid Type Proppant Type SecondaryFluid Type Proppant Type Averages and maxima reported Tor iviam rrac stdyea I vtdla IaNvl MU IVI all II Ij L .. ** Based on following volume ratio of stage types: Main frac pad / (Main frac pad + Main frac slurry), and excluding flush. FracproPT 2011 Ll • -r ki r• KAnA 1 (`nlihrn+inn C, immnry Crack Opening Coefficient 8.50e-01 Width Decoupling Coefficient 1.00e+00 Tip Effects Coefficient 1.00e-04 Tip Radius Fraction 1.O0e-02 Tip Effects Scale Volume bbis 100.0 Proppant Drag Effect Exponent 8.0 CLE Outside Pa zone 25.00 Multiple fractures settings start V/L/O 1.0 / 1.0 / 1.0 Multiple fractures settings end V/L/O 1.0 / 1.0 / 1.0 FracproPT 2011 • 1 0 Table 6: Hydraulic Fracture Growth History* End of Stage Type Time Fracture Fracture Fracture Avg. Model Net Slurry Equivalent Stage # (mm:ss) Half-Leng Height Width at Fracture Pressure Efficiency Number of th (ft) Well Width (psi) Multifracs ft in in 1 Main frac pad 166:40 115 242 0.784 0.496 342 0.32 1.0 * All values reported are for the entire fracture system and at the end of each stage Table 7: Pro ped Fracture Pro erties by Distance from the Well at Fracture Center at Depth of 4665ft Distance from Well (ft) Fracture System Width* in Conductivity per Frac** (mD•ft) Frac System Conductivity*** (mD-ft) Prop Conc per Frac (lb/ft2) Frac System Prop Conc**** (lb/ft2) 0.0 0.740 0.0 0.0 0.00 0.00 0.0 0.740 0.0 0.0 0.00 0.00 0.0 0.740 0.0 0.0 0.00 0.00 0.0 0.740 0.0 0.0 0.00 0.00 0.0 0.740 0.0 0.0 0.00 0.00 0.0 0.740 0.0 0.0 0.00 0.00 0.0 0.740 0.0 0.0 0.00 0.00 0.0 0.740 0.0 0.0 0.00 0.00 0.0 0.740 0.0 0.0 0.00 0.00 0.0 0.740 0.0 0.0 0.00 0.00 * Width values reported are for the entire fracture system. ** Fracture conductivity reported for total proppant damage of 0.50 and 0.000 in of proppant embedment. *** Frac system conductivity reported for 1.0 equivalent multiple fractures with 100% considered conductive. **** Frac system proppant concentration reported for 1.0 equivalent multiple fractures. FracproPT 2011 I aDle o: Stage uesl n I redu l l Stage Type lit ol.i icuwc Elapsed Fluid Clean Prop Stage Slurry Proppant # Time imin:sec Type Volume Conic Prop. Rate Type al p klbs bpm Wellbore Fluid MOBM 10 1800 1 n frac pad 1 166:40 Mai MOBM 10 42000 0.00 0.01 6.00 Design clean volume (bbls) Design slurry volume (bbls) 1000.0 Design proppant pumped (kibs) 1000.0 0.0 FracproPT 2011 Table 9: Proppant and Fluid Material Quantity Units Unit Cost $ Discnt % Cost $ MOBM 10 1000.0 bbls 0.00 0.0 0.00 Treatment Totals calculated from design schedule Proppant and Fluid Subtotal: 0.00 ($) Total: 0.00 ($) FracproPT 2011 Table 1U: t-lula varameters Fluid Name MOBM 10 Vendor Other System MOBM Description 10 PPg MOBM Initial Viscosity cp 40.13 Initial n' 0.125 Initial k' Ibf•s^n/ftZ 0.125 Viscosity 4.0 hours cp 1.72 n' 4.0 hours 0.136 k' 4.0 hours Ibf-s"n/ft2 0.136 Base Fluid Specific Gravity 1.20 Spurt Loss al/ft2 0.009 Wall Building ftlmin% 0.003 Flowrate #1 b m 10.00 Fric Press #1(psi/1 000 ft 54.41 Flowrate #2 b m 20.00 Fric Press #2 si/1000 ft 104.2 Flowrate #3 b m 40.00 Fric Press #3 si/1000 275.1 Wellbore Friction Multi Lfier:��1.000 All Fluid info is at a reservoir temperature of aa.v t r) All Viscosities at Shear Rate of 511 (1/sec) Wellbore Friction pressures shown are the interpolated values multiplied by the Wellbore Friction Multiplier. Friction is displayed for longest wellbore segment FracproPT 2011 0 u Table 11: Leakoff Parameters Reservoir type User Spec Reservoir fluid compressibility 1/psi 2.58e-0 Filtrate to pore fluid perm. ratio, Kp/KI 10.00 Reservoir Viscosity cp 0.02 Reservoir pore pressure psi 2375 Porosity 0.10 Initial fracturing pressure psi 4039 Gas Leakoff Percentage % 100.00 Reservoir Parameters Reservoir Temperature ff ) Depth to center of Perfs (ft) Perforated interval (ft) Initial frac depth (ft) 4665 Table 12: Laver Parameters 93.00 4665 20 Layer # Top of zone ft Stress (psi) Stress Gradient psi/ft(psi) Young's modulus Poisson's ratio Total Ct (ft/min%) Pore Fluid Perm. mD 1 0.0 1115 0.697 2.6e+06 0.29 3.498e-03 1.38e+00 2 1600.0 1777 0.718 1.5e+06 0.34 3.840e-03 3.72e+00 3 3350.0 2468 0.726 1.2e+06 0.36 3.784e-03 2.99e+00 4 3450.0 2553 0.731 1.1 e+06 0.37 3.733e-03 2.52e+00 5 3534.0 2562 0.725 1.2e+06 0.36 3.623e-03 1.85e+00 6 3538.5 2562 0.723 1.2e+06 0.35 3.764e-03 2.79e+00 7 3549.5 2580 0.717 1.1 e+06 0.36 3.750e-03 2.67e+00 8 3650.0 2649 0.716 1.5e+06 0.34 3.823e-03 3.48e+00 9 3750.0 2711 0.713 1.3e+06 0.35 3.784e-03 2.99e+00 10 3850.0 2787 0.720 1.2e+06 0.35 3.785e-03 3.01 e+00 11 3897.0 2824 0.724 1.2e+06 0.35 3.658e-03 2.03e+00 12 3904.0 2840 0.724 1.2e+06 0.36 3.773e-03 2.88e+00 13 3942.0 2873 0.725 1.2e+06 0.36 3.205e-03 8.02e-01 14 3984.5 2949 0.734 1.1 e+06 0.38 3.828e-03 3.55e+00 15 4050.0 2952 0.720 1.6e+06 0.34 3.817e-03 3.39e+00 16 4150.0 2936 0.707 2.0e+06 0.32 3.711 e-03 2.36e+00 17 4156.5 2941 0.707 2.0e+06 0.32 3.612e-03 1.79e+00 18 4162.5 2954 0.709 1.9e+06 0.32 3.767e-03 2.82e+00 19 4170.0 2967 0.711 1.8e+06 0.33 3.647e-03 1.96e+00 20 4176.0 2998 0.714 1.8e+06 0.33 3.731 e-03 2.50e+00 21 4221.0 3048 0.721 1.5e+06 0.35 3.673e-03 2.11 e+00 22 4229.5 3016 0.712 1.8e+06 0.33 3.740e-03 2.58e+00 23 4238.0 3064 0.722 1.5e+06 0.35 3.571 a-03 1.62e+00 24 4248.5 2991 0.701 2.1 e+06 0.31 3.758e-03 2.73e+00 25 4279.0 3044 0.710 1.9e+06 0.32 3.635e-03 1.90e+00 26 4297.0 3048 0.709 1.9e+06 0.32 3.729e-03 2.49e+00 27 4301.5 3050 0.708 2.0e+06 0.32 3.606e-03 1.77e+00 28 4314.5 3046 0.703 2.1 a+06 0.31 3.747e-03 2.64e+00 29 4350.0 3155 0.717 1.7e+06 0.34 3.774e-03 2.89e+00 30 4450.0 3159 0.702 2.3e+06 0.30 3.828e-03 3.53e+00 31 4550.0 3219 0.706 2.1 e+06 0.31 3.752e-03 2.68e+00 32 4569.5 3291 0.718 1.6e+06 0.34 3.585e-03 1.68e+00 33 4597.0 3330 0.724 1.5e+06 0.35 3.724e-03 2.45e+00 34 4601.5 3321 0.721 1.5e+06 0.35 3.622e-03 1.84e+00 35 4611.5 3385 0.731 1.2e+06 0.37 3.750e-03 2.66e+00 36 4650.0 3427 0.734 1.1 a+06 0.38 3.745e-03 2.62e+00 37 4684.0 3402 0.726 1.3e+06 0.36 3.532e-03 1.48e+00 38 4689.0 3431 0.727 1.3e+06 0.36 3.624e-03 1.85e+00 FracproPT 2011 0 • Layer # Top of Stress Stress Young's Poisson's Total Ct Pore Fluid zone (psi) Gradient modulus ratio (ftlmin'/2) PmD) ft psilft psi 39 4750.0 3470 0.723 1.4e+06 0.35 3.495e-03 1.37e+00 40 4850.0 3512 0.723 1.4e+06 0.35 3.525e-03 1.46e+00 41 4864.0 3524 0.724 1.4e+06 0.35 3.185e-03 7.77e-01 42 4871.0 3530 0.724 1.4e+00 0.35 3.544e-03 1.53e+00 43 4880.0 3539 0.723 1.4e+06 0.35 3.100e-03 I 6.80e-01 44 4908.5 3553 0.723 1.4e+06 0.35 3.399e-( 3e+00 45 4919.5 3543 0.720 1.5e+06 0.35 3.030e-03 6.12e-01 46 4922.E 3561 0.723 1.5e+06 0.35 3.479e-03 ..33e+00 47 4927.0 3550 0.720 1.5e+06 0.35 3.082e-03 6.61 e-01 48 4934.0 3558 0.720 1.6e+06 0.34 3.544e-03 1.53e+00 49 4950.0 3573 0.720 1.5e+06 0.35 3.618e-03 1.82e+00 50 497 5.5 3574 0.718 1.6e+06 0.34 3.128e-03 7.10e-01 51 497. 3574 0.721 1.5e+06 0.35 3.466e-03 1.29e+00 52 4983.5 3593 0.721 1.5e+06 0.35 3.201 e-03 7.97e-01 53 4989.5 3587 0.719 1.5e+06 0.34 3.467e-03 1.29e+00 54 4992.5 3630 0.723 1.3e+06 0.3E 3.181 e-03 7.72e-01 55 5050.0 3697 0.731 1.2e+06 0.37 3.503e-03 1.39e+00 56 5064.0 3732 0.737 1.1 a+06 0.39 3.109e-03 6.89e-01 57 5069.0 3675 0.724 1.4e+06 0.3E 3.534e-03 1.49e+00 58 5089.5 3731 0.730 1.2e+06 0.38 3.229e-03 8.35e-01 59 5129.0 3677 0.717 1.6e+06 0.34 3.486e-03 1.35e+00 60 5135.5 3687 0.717 1.6e+06 0.34 3.255e-03 8.72e-01 61 5149.0 3702 0.719 1.6e+06 0.34 3.477e-03 1.32e+00 62 5155.0 3715 0.720 1.5e+06 0.35 3.187e-03 7.79e-01 63 5165.0 3729 0.722 1.5e+06 0.35 3.494e-03 1.37e+00 64 5170.5 3759 0.726 1.4e+06 0.36 3.004e-03 5.89e-01 65 5182.0 3772 0.727 1.3e+06 0.37 3.393e-03 1.12e+00 66 5198.0 3774 0.725 1.4e+06 0.3E 2.838e-03 4.66e-01 67 5213.5 3811 0.730 1.2e+06 0.37 3.494e-03 1.37e+00 68 5228.5 3817 0.729 1.3e+06 0.37 3.076e-03 6.55e-01 69 5240.0 3830 0.731 1.2e+06 0.37 3.447e-03 1.24e+00 70 5247.0 3867 0.73E 1.1 a+06 0.39 2.072e-03 1.72e-01 71 5261.0 3788 0.714 1.6e+06 0.34 82e-03 2.16e+00 72 5350.0 3889 0.720 1.3e+06 0.36 19e-03 13!.696e-03 3.41 e+00 73 5450.0 3935 0.687 1.5e+06 0.35 2.25e+00 74 6000.0 4368 0.728 1.3e+06 0.3E 3.779e-03 2.94e+00 T,. w- -i 4- I i+hnlnnv PornmPtPrC avw Layer # Top of zone ft - Lithology Fracture Toughness psi-in'/2 Composite Layering Effect 1 0.0 Sandstone 1000 25.00 2 1600.0 Sandstone 1000 25.00 3 3350.0 Sandstone 1000 25.00 4 3450.0 Sandstone 1000 25.00 5 3534.0 Shale 1000 25.00 6 3538.5 Sandstone 1000 25.00 7 3549.5 Sandstone 1000 25.00 8 3650.0 Sandstone 1000 25.00 9 3750.0 1 Sandstone 1000 25.00 FracproPT 2011 • r: Layer # Top of zone ft Lithology Fracture Toughness psi•in% Composite Layering Effect 10 3850.0 Sandstone 1000 25.00 11 3897.0 Sandstone 1000 25.00 12 3904.0 Sandstone 1000 25.00 13 3942.0 Shale 1000 25.00 14 3984.5 Sandstone 1000 25.00 15 4050.0 Sandstone 1000 25.00 16 4150.0 Sandstone 1000 25.00 17 4156.5 Sandstone 1000 25.00 18 4162.5 Sandstone 1000 25.00 19 4170.0 Sandstone 1000 25.00 20 4176.0 Sandstone 1000 25.00 21 4221.0 Sandstone 1000 25.00 22 4229.5 Sandstone 1000 25.00 23 4238.0 Sandstone 1000 25.00 24 4248.5 Sandstone 1000 25.00 25 4279.0 Sandstone 1000 25.00 26 4297.0 Sandstone 1000 25.00 27 4301.5 Sandstone 1000 25.00 28 4314.5 Sandstone 1000 25.00 29 4350.0 Sandstone 1000 25.00 30 4450.0 Sandstone 1000 25.00 31 4550.0 Sandstone 1000 25.00 32 4569.5 Sandstone 1000 25.00 33 4597.0 Sandstone 1000 25.00 34 4601.5 Sandstone 1000 25.00 35 4611.5 Sandstone 1000 25.00 36 4650.0 Sandstone 1000 25.00 37 4684.0 Sandstone 1000 25.00 38 4689.0 Sandstone 1000 25.00 39 4750.0 Sandstone 1000 25.00 40 4850.0 Sandstone 1000 25.00 41 4864.0 Shale 1000 25.00 42 4871.0 Sandstone 1000 1.00 43 4880.0 Shale 1000 1.00 44 4908.5 Sandstone 1000 1.00 45 4919.5 Shale 1000 25.00 46 4922.6 Sandstone 1000 25.00 47 4927.0 Shale 1000 25.00 48 4934.0 Sandstone 1000 25.00 49 4950.0 Sandstone 1000 25.00 50 4975.5 Shale 1000 25.00 51 4979.0 Sandstone 1000 25.00 52 4983.5 Shale 1000 25.00 53 4989.5 Sandstone 1000 25.00 54 4992.5 Shale 1000 25.00 55 5050.0 Sandstone 1000 25.00 56 5064.0 Shale 1000 25.00 57 5069.0 Sandstone 1000 25.00 58 5089.5 Shale 1000 25.00 59 5129.0 Sandstone 1000 25.00 FracproPT 2011 • • Layer # Top of zone ft Lithology Fracture Toughness psi-in'/2 Composite Layering Effect 60 5135.5 Shale 1000 25.00 61 5149.0 Sandstone 1000 25.00 62 5155.0 Shale 1000 25.00 63 5165.0 Sandstone 1000 25.00 64 5170.5 Shale 1000 25.00 65 5182.0 Sandstone 1000 25.00 66 5198.0 Shale 1000 25.00 67 5213.5 Sandstone 1000 25.00 68 5228.5 Shale 1000 25.00 69 5240.0 Sandstone 1000 25.00 70 5247.0 Shale 1000 25.00 71 5261.0 Sandstone 1000 25.00 72 5350.0 Sandstone 1000 25.00 73 5450.0 Sandstone 1000 25.00 74 6000.0 Sandstone 1000 25.00 10 FracproPT 2011 • • Table 14: Casing Configuration Length ft Segment Type Casing ID in Casing OD in Weight Ib/ft Grade 5100 Cemented Casing 6.276 7.000 26.000 L-80 Table 15: Surface Line and Tubing Configuration Length ft Segment Type Tubing ID in Tubing OD in Weight Ib/ft Grade 4575 Tubing 2.992 3.500 9.200 1 L-80 Total frac string volume (bbls) 42.8 Pumping down Tubing Table 16: Perforated Intervals Interval #1 Top of Perfs - TVD ft 4655 Bot of Perfs - TVD ft 4675 Top of Perfs - MD ft 4655 Bot of Perfs - MD ft 4675 Perforation Diameter in 0.300 # of Perforations 120 Table 17: Path Summary Segment Type Length ft MD ft TVD ft Dev de Ann OD in Ann ID in Pipe ID in Tubing 4575 4575 4575 0.0 0.000 0.000 2.992 Casing 80 4655 4655 0.0 0.000 0.000 6.276 11 FracproPT 2011 • Table 18: Near-weuoore ruction Flowrate a rGI III, QUV,1 Flowrate 1 11-1-11 Near-Wellbo Perforation Total Entry Perforation erfs Pctiv Time (mm:ss) #1 #2 re Friction Friction Friction Friction Effectively b m bpm psi psi psi Multiplier Open 0:00 0.00 0.00 0 0 0 1.00 120.00 w— rf__.,-.... 0nr1 Darmanhility RummarvTable 1c7UIC 1�. UNUOVIvvu Plot -. ......_ - - ---- Est. Reservoir Est. Reservoir Est. Reservoir Pressure Pressure Permeability (psi) Gradient (mD) psi/ft In'ection/Shut-in #1 Perm Analysis Plot 1.00e-01 12 FracproPT 2011 • Table 20: Model Input Parameters Fracture Model 3D Shear-Decou led Reservoir Data Entry General Single Scale Run From Job-Desi n Data Fracture Orientation Vertical Proppant Transport Model Proppant Convection Run Fracture and Wellbore Models Growth after Shut-in Allow General Iteration Backstress Ignore Heat Transfer Effects Model Acid Fracturing Model FracproPT Default Leakoff Model Lumped -Parameter Default Table 21: Fracture Growth Parameters 3D Shear-Decou led Parameter Value Default Crack Opening Coefficient 8.50e-01 8.50e-01 Tip Effects Coefficient 1.00e-04 1.00e-04 Channel Flow Coefficient 1.00e+00 1.00e+00 Tip Radius Fraction 1.00e-02 1.00e-02 Tip Effects Scale Volume bbls 100.0 100.0 Fluid Radial Weighting Exponent 0.00e+00 0.00e+00 Width Decoupling Coefficient 1.O0e+00 1.00e+00 Table 22: Proppant Model Parameters Parameter Value Default Minimum Proppant Concentration Ib/ft2 0.20 0.20 Minimum Proppant Diameter in 0.0080 0.0080 Minimum Detectable Proppant Concentration p 0.20 0.20 Proppant Drag Effect Exponent 8.0 8.0 Proppant Radial Weighting Exponent 0.2500 0.2500 Proppant Convection Coefficient 10.00 10.00 Proppant Settling Coefficient 1.00 1.00 Quadratic Backfill Model ON ON Tip Screen -Out Backfill Coefficient 0.50 0.50 Stop Model on Screenout ON ON Reset Proppant in Fracture after Closure ON ON Table 23: Low Level Parameters Parameter Value Default Perm. Contrast: Distance Effect 1.0 1.0 Perm. Contrast: Containment Effect 1.0 1.0 Perm. Contrast: Permeability Level 1.00 1.00 Perm. Contrast Model: FracproPT Default YES Fluid < el> Bulk Modulus psi 3.00Oe+10 3.000e+10 Proppant Bulk Modulus psi 3.00Oe+06 3.000e+06 Fluid el Bulk Coefficient of Thermal Expansion 3.000e-04 3.00Oe-04 Effect of Proppant on Length Growth 1.00 1.00 Fraction of BRACKET FRAC Proppant that is INVERTA-FRAC by Volume 0.5 0.5 Remember Position of Proppant Banks after closure on Proppant NO NO Allow Slippage NO NO Reset Fluid Leakoff after Frac Closure NO NO Minimum Volume Limit Value 0.20 0.20 Center Shifting Option: Fracture Always Stays Connected to Perfs X X 13 FracproPT 2011 • r: Value s can Move from Perfs after Shut-in ure can Move from Perfs after Shut-in M20 VParameter ure can Move from Perfs at an Time en Volume Threshold bbls n Leakoff Compensation bbls 200.0 5.0 I able z4: Iflllldl LCdr Ull di w vtvaui c Parameter Value Default Initial Leakoff Area Multiplier Coefficient 1.000 1.000 Initial Leakoff Area from Last Simulation ft2 785.442 n/a Closure Leakoff Area Multiplier Coefficient 0.025 0.025 Default Shut-in Model YES YES Shut-in Tip Weighting Coefficient for Leakoff 1.00 1.00 Shut-in Tip Weighting Exponent for Leakoff 1.00 1.00 Minimum Shut-in Volume bbls 100.0 100.0 Model Pro ant in Flow -back YES YES EM-odel-Wall-building Viscosity Effect NO NO n a I aDie zo: iviisceiiaiieuua vivwu1 r a1a11 013 Parameter Value Default Set Minimum Fracture Height NO NO Model Very Small Fractures NO NO Model Head Effects in Fracture NO NO Model Fracture Center Shifting NO NO Near-Wellbore Friction Exponent 0.50 0.50 14 FracproPT 2011 KI • Width Profile (in) Concentration of Proppant in Fracture (Ib/ft2) Layer Properties 7yp(1t) 0 _ 50 100 150 t.. 200 ' f'T7 Zt 250 300 Fracture Propped Total Total 350 400 Ro... ND(ft Length (ft) Length (ft) Fracture Height Pro ed Hei (ft) ht ft 114.7 0.0 241.7 0.0 Sand .. , 4550 t - - —- -4550 i - 4600 - — - 4600 - 46507 —, - . 4850 -- 4700 4 00 4750 - -- - 4750 -- - - -- - 4800 1'rogpant Concentration (IbifN) -- , -� - 4800 0 0.10 0.50 0.60 0.70 0.80 0.90 1.0 0.20 0.30 0.40 Figure 1 Fracture Protile for Upper band Mutsm 9 uppg, OUDuue, udte 15 FracproPT 2011 • FracproPT 2011 Hydraulic Fracture Analysis Date: Wednesday, October 31, 2012 Well Name: Umiat DSP-01 Location: Formation: Torok Job Date: 10/31/2012 2:48:39 PM Filename: 10.0 ppg MOBM 6 bpm Base Disposal Fracture Half -Len th ft 147 Propped Half -Length ft 0 Total Fracture Height ft 212 Total Propped Height ft 0 Depth to Fracture To ft 4708 Depth to Propped Fracture To ft 4790 Depth to Fracture Bottom ft 4920 Depth to Propped Fracture Bottom ft 4790 Equivalent Number of Multiple Fracs 1.0 Max. Fracture Width in 0.53 Fracture Slur Efficienc ** 0.25 Av .Fracture Width in 0.35 Av . Proppant Concentration Ib/ftZ 0.00 -All Values reportea are Tor ine enure Tracture system at a nwuei unie ui Ivv. r v rinn tcnv vi . Vi 1 1— ., ,-Nam, ** Value is reported for the end of the last pumping stage (Stage 1, Main frac pad) T.. LJ r. 1) Cr....+. .ram rr`r A+ivi+v Cmmnr * Avg. Conductivit ** mD•ft 0.0 Avg. Frac Width Closed onprop) in 0.000 Dimensionless Conductivit ** 0.00 Ref. Formation Permeabilityrr 0.939 Proppant Damage Factor 0.50 Undamaged Prop Perm at Stress mD 0 Apparent Damage Factor*** 0.00 Prop Perm with Prop Damage mD 0 Total Damage Factor 0.50 Prop Perm with Total Damage mD 0 Effective Propped Length ft 0 Proppant Embedment in 0.000 . All values reportea are Tor ine enure rracture system. Mctuai cunuucuvity vvulu U� 1-- 1. modeled ** Total Damage Factor and Proppant Embedment have been applied *** Apparent Damage due to non -Darcy and multi -phase flow _17 L.L. 4• Cr.-...+..ram D Ci im m orv* Model Net Pressure**(psi) 263 BH Fracture Closure Stress(psi) 3470 Observed Net Pressure**(psi) 0 Closure Stress Gradient si/ft 0.725 Hydrostatic Head*** psi 2489 Avg. Surface Pressure psi 1555 Reservoir Pressure psi 2375 Max. Surface Pressure psi 1919 Averages ana maxima reportea Tor Twain riac stayer ** Values reported for the end of the last pumping stage (Stage 1, Main frac pad) *** Value reported for clean fluid Total Clean Fluid Pumped bbls 1001.8 Total Proppant Pumped klbs 0.0 Total Slurry Pumped bbls 1001.8 Total Proppant in Fracture kibs 0.0 Pad Volume bbls 1000.0 Avg. Hydraulic Horsepower h 228 Pad Fraction % of Slur Vol)** 100.0 Max. Hydraulic Horsepower hp 282 Pad Fraction % of Clean Vol)** 100.0 Avg Btm Slurry Rate (bpm) 6.0 Primary Fluid Type Primary Proppant Type Secondary Fluid Type Secondary Proppant Type Averages ana maxima reporteu for main rldu DtayeJ I VIQID icjlvi— wi mi ..jI, -- ** Based on following volume ratio of stage types: Main frac pad / (Main frac pad + Main frac slurry), and excluding flush. FracproPT 2011 E • -r L.I . G• RA..A 1 t' lik—fl— Q, immnry Crack Opening Coefficient 8.50e-01 Width Decoupling Coefficient 1.00e+00 Tip Effects Coefficient 1.00e-04 Tip Radius Fraction 1.00e-02 Tip Effects Scale Volume bbis 100.0 Pro ant Drag Effect Exponent 8.0 CLE Outside Pa zone 25.00 Multiple fractures settings start V/L/O 1.0 / 1.0 / 1.0 Multiple fractures settings end V/L/O 1.0 / 1.0 / 1.0 FracproPT 2011 • • Table 6: Hydraulic Fracture Growth History* End of Stage Type Time Fracture Fracture Fracture Avg. Model Net Slurry Equivalent Stage # (mm:ss) Half-Leng Height Width at Fracture Pressure Efficiency Number of th (ft) Well Width (psi) Multifracs ft in in 1 Main frac pad 166:40 147 212 0.533 0.348 263 0.25 1.0 * All values reported are for the entire fracture system and at the end of each stage Table 7: Pro ped Fracture Pro erties by Distance from the Well at Fracture Center at Depth of 4790ft Distance from Well (ft) Fracture System Width* in Conductivity per Frac** (mD-ft) Frac System Conductivity*** (mD-ft) Prop Conc per Frac (lb/ft-) Frac System Prop Conc**** (lb/ft-1) 0.0 0.533 0.0 0.0 0.00 0.00 0.0 0.533 0.0 0.0 0.00 0.00 0.0 0.533 0.0 0.0 0.00 0.00 0.0 0.533 0.0 0.0 0.00 0.00 0.0 0.533 0.0 0.0 0.00 0.00 0.0 0.533 0.0 0.0 0.00 0.00 0.0 0.533 0.0 0.0 0.00 0.00 0.0 0.533 0.0 0.0 0.00 0.00 0.0 0.533 0.0 0.0 0.00 0.00 0.0 0.533 0.0 0.0 0.00 0.00 * Width values reported are for the entire fracture system. ** Fracture conductivity reported for total proppant damage of 0.50 and 0.000 in of proppant embedment. *** Frac system conductivity reported for 1.0 equivalent multiple fractures with 100% considered conductive. **** Frac system proppant concentration reported for 1.0 equivalent multiple fractures. FracproPT 2011 _.nL,.4 Stage e0 e111 Stage Type 9 P'G Ela sed4� ` Fluid Clean Prop Stage Slurry Proppant # Time Type Volume Conc Prop. Rate Type min:sec . al p klbs bpm Wellbore Fluid MOBM 10 2000 LLLEL��-166:40 11 1 Main frac pad MOBM 10 42000 0.00 Design clean volume (bbls) Design slurry volume (bbls) 1000.0 Design proppant pumped (klbs) 1000.0 0.0 FracproPT 2011 • • Table 9: PrOonant and Fluid Material Quantity Units Unit Cost $ Discnt % Cost $ MOBM 10 1000.0 1 bbls 1 0.00 1 0.0 1 0.00 Treatment Totals calculated from design schedule Proppant and Fluid Subtotal: 0.00 ($) Total: 0.00 ($) FracproPT 2011 iaale iu: rlUla varameters Fluid Name MOBM 10 Vendor Other System MOBM Description 10 PPg MOBM Initial Viscosity cp 40.13 Initial n' 0.125 Initial k' Ibf•s"n/ftz 0.125 Viscosity 4.0 hours cp 1.72 n' 4.0 hours 0.136 k' 4.0 hours Ibf-s^n/ft2 0.136 Base Fluid Specific Gravity Spurt Loss al/ftZ Wall Building ft/min% 1.20 0.009 0.003 Flowrate #1 b m 10.00 Fric Press #1 si/1000 ft 54.41 Flowrate #2 b m 20.00 Fric Press #2 si11000 ft 104.2 Flowrate #3 b m 40.00 Fric Press #3 si/1000 ft 275.1 Wellbore Friction Multiplier 1.000 All Fluid info is at a reservoir temperature or 93.0 t r) All Viscosities at Shear Rate of 511 (1/sec) Wellbore Friction pressures shown are the interpolated values multiplied by the Wellbore Friction Multiplier. Friction is displayed for longest wellbore segment FracproPT 2011 0 0 Table 11: Leakoff Parameters Reservoir type User Spec Reservoir fluid compressibility 1/psi 2.58e-0 Filtrate to pore fluid perm. ratio, Kp/KI 10.00 Reservoir Viscosity cp 0.02 Reservoir pore pressure psi 2375 Porosity 0.10 Initial fracturing pressure psi 4039 Gas Leakoff Percentage % 100.00 Reservoir Parameters Reservoir Temperature (°F) Depth to center of Perfs (ft) Perforated interval (ft) Initial frac depth (ft) 4790 Table 12: Laver Parameters 93.00 4790 20 Layer # Top of zone ft(psi/ft) Stress (psi) Stress Gradient Young's modulus psi Poisson's ratio Total Ct (ft/min%) Pore Fluid Perm. mD 1 0.0 1115 0.697 2.6e+06 0.29 3.498e-03 1.38e+00 2 1600.0 1777 0.718 1.5e+06 0.34 3.840e-03 3.72e+00 3 3350.0 2468 0.726 1.2e+06 0.36 3.784e-03 2.99e+00 4 3450.0 2553 0.731 1.1 a+06 0.37 3.733e-03 2.52e+00 5 3534.0 2562 0.725 1.2e+06 0.36 3.623e-03 1.85e+00 6 3538.5 2562 0.723 1.2e+06 0.35 3.764e-03 2.79e+00 7 3549.5 2580 0.717 1.1 e+06 0.36 3.750e-03 2.67e+00 8 3650.0 2649 0.716 1.5e+06 0.34 3.823e-03 3.48e+00 9 3750.0 2711 0.713 1.3e+06 0.35 3.784e-03 2.99e+00 10 3850.0 2787 0.720 1.2e+06 0.35 3.785e-03 3.01 e+00 11 3897.0 2824 0.724 1.2e+06 0.35 3.658e-03 2.03e+00 12 3904.0 2840 0.724 1.2e+06 0.36 3.773e-03 2.88e+00 13 3942.0 2873 0.725 1.2e+06 0.36 3.205e-03 8.02e-01 14 3984.5 2949 0.734 1.1 e+06 0.38 3.828e-03 3.55e+00 15 4050.0 2952 0.720 1.6e+06 0.34 3.817e-03 3.39e+00 16 4150.0 2936 0.707 2.0e+06 0.32 3.711 e-03 2.36e+00 17 4156.5 2941 0.707 2.0e+06 0.32 3.612e-03 1.79e+00 18 4162.5 2954 0.709 1.9e+06 0.32 3.767e-03 2.82e+00 19 4170.0 2967 0.711 1.8e+06 0.33 3.647e-03 1.96e+00 20 4176.0 2998 0.714 1.8e+06 0.33 3.731 e-03 2.50e+00 21 4221.0 3048 0.721 1.5e+06 0.35 3.673e-03 2.11 e+00 22 4229.5 3016 0.712 1.8e+06 0.33 3.740e-03 2.58e+00 23 4238.0 3064 0.722 1.5e+06 0.35 3.571 e-03 1.62e+00 24 4248.5 2991 0.701 2.1 e+06 0.31 3.758e-03 2.73e+00 25 4279.0 3044 0.710 1.9e+06 0.32 3.635e-03 1.90e+00 26 4297.0 3048 0.709 1.9e+06 0.32 3.729e-03 2.49e+00 27 4301.5 3050 0.708 2.0e+06 0.32 3.606e-03 1.77e+00 28 4314.5 3046 0.703 2.1 a+06 0.31 3.747e-03 2.64e+00 29 4350.0 3155 0.717 1.7e+06 0.34 3.774e-03 2.89e+00 30 4450.0 3159 0.702 2.3e+06 0.30 3.828e-03 3.53e+00 31 4550.0 3219 0.706 2.1 a+06 0.31 3.752e-03 2.68e+00 32 4569.5 3291 0.718 1.6e+06 0.34 3.585e-03 1.68e+00 33 4597.0 3330 0.724 1.5e+06 0.35 3.724e-03 2.45e+00 34 4601.5 3321 0.721 1.5e+06 0.35 3.622e-03 1.84e+00 35 4611.5 3385 0.731 1.2e+06 0.37 3.750e-03 2.66e+00 36 4650.0 3427 0.734 1.1 e+06 0.38 3.745e-03 2.62e+00 37 4684.0 3402 0.726 1.3e+06 0.36 3.532e-03 1.48e+00 38 4689.0 3431 0.727 1.3e+06 0.36 3.624e-03 1.85e+00 FracproPT 2011 Layer # Top of zone ft Stress (psi) Stress Gradient si/ft Young's modulus (psi) Poisson's ratio Total Ct (ft/min%) Pore Fluid Perm. 39 4750.0 4850.0 4864.0 4871.0 4880.0 4908.5 4919.5 g4922.6 4975.5 4979.0 4983.5 4989.5 4992.5 5050.03630 5064.0 5069.0 5089.5 5129.0 5135.5 5149.0 5155.0 5.0 0.5 2.0 15198.0 5213.5 5228.5 5240.0 5247.0 5261.0 5350.0 5450.0 6000.0 3470 3512 3524 3530 3539 3553 3543 3561 3550 3558 3573 3574 3591 3593 3587 3630 3732 3675 3731 3677 3687 3702 3715 29 59 72 74 E37 3811 3817 3830 3867 3788 3889 3935 4368 0.723 0.723 0.724 0.724 0.723 0.723 0.720 0.723 0.720 0.720 0.720 0.718 0.721 0.721 0.719 0.723 0.731 0.737 0.724 0.730 0.717 0.717 0.719 0.720 0.722 0.726 0.727 0.725 0.730 0.729 0.731 0.736 0.714 0.720 0.687 0.728 1.4e+06 0.35 1.4e+06 0.35 1.4e+06 0.35 1.4e+06 ' 0.35 1.4e+06 0.35 1.4e+06 0.35 1.5e+06 0.35 1.5e+06 0.35 1.5e+060.35 1.6e+06 0.34 1.5e+06 0.35 1.6e+06 0.34 1.5e+06 0.35 1.5e+06 0.35 1.5e+06 0.34 1.3e+06 0.36 1.2e+06 0.37 1.1 a+06 0.39 1.4e+06 0.36 1.2e+06 0.38 1.6e+06 0.34 1.6e+06 0.34 1.6e+06 0.34 1.5e+06 0.35 1.5e+06 0.35 1.4e+06 0.36 1.3e+06 0.37 1.4e+06 0.36 1.2e+06 0.37 1.3e+06 0.37 1.2e+06 0.37 1.1 a+06 0.39 1.6e+06 0.34 1.3e+06 0.36 1.5e+06 0.35 1.3e+06 0.36 3.495e-03 1.37e+00 3.525e-03 1.46e+00 3.185e-03 7.77e-01 3.544e-03 1.53e+00 3.100e-03 6.80e-01 3.399e-03 1.13e+00 3.030e-03 6.12e-01 3.479e-03 1.33e+00 3.082e-036.61 e-01 3.544e-0349 3.618e-03 1.82e+00 3.128e-03 7.10e-01 3.466e-03 1.29e+00 3.201 e-03 7.97e-01 3.467e-03 1.29e+00 3.181 a-03 7.72e-01 3.503e-03 1.39e+00 3.109e-03 6.89e-01 3.534e-03 1.49e+00 3.229e-03 8.35e-01 3.486e-03 1.35e+00 3.255e-03 8.72e-01 3.477e-03 1.32e+00 3.187e-03 7.79e-01 3.494e-03 1.37e+00 3.004e-03 5.89e-01 3.393e-03 1.12e+00 2.838e-03 4.66e-01 3.494e-03 1.37e+00 3.076e-03 6.55e-01 3.447e-03 1.24e+00 2.072e-03 1.72e-01 3.682e-03 2.16e+00 3.819e-03 3.41 e+00 3.696e-03 2.25e+00 3.779e-03 2.94e+00 40 41 42 43 44 45 46 47 48 50 51 52 53 54 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 71 72 73 74 'r ki 1 Q• I i+hnlnnv PnrnmPtarG Layer # Top of zone ft Lithology Fracture Toughness psi•in% Composite Layering Effect 1 0.0 Sandstone 1000 25.00 2 1600.0 Sandstone 1000 25.00 3 3350.0 Sandstone 1000 25.00 4 3450.0 Sandstone 1000 25.00 5 3534.0 Shale 1000 25.00 6 3538.5 Sandstone 1000 25.00 7 3549.5 Sandstone 1000 25.00 8 3650.0 Sandstone 1000 25.00 9 3750.0 Sandstone 1000 25.00 FracproPT 2011 • 0 Layer # Top of zone ft Lithology Fracture Toughness psi-in'/2 Composite Layering Effect 10 3850.0 Sandstone 1000 25.00 11 3897.0 Sandstone 1000 25.00 12 3904.0 Sandstone 1000 25.00 13 3942.0 Shale 1000 25.00 14 3984.5 Sandstone 1000 25.00 15 4050.0 Sandstone 1000 25.00 16 4150.0 Sandstone 1000 25.00 17 4156.5 Sandstone 1000 25.00 18 4162.5 Sandstone 1000 25.00 19 4170.0 Sandstone 1000 25.00 20 4176.0 Sandstone 1000 25.00 21 4221.0 Sandstone 1000 25.00 22 4229.5 Sandstone 1000 25.00 23 4238.0 Sandstone 1000 25.00 24 4248.5 Sandstone 1000 25.00 25 4279.0 Sandstone 1000 25.00 26 4297.0 Sandstone 1000 25.00 27 4301.5 Sandstone 1000 25.00 28 4314.5 Sandstone 1000 25.00 29 4350.0 Sandstone 1000 25.00 30 4450.0 Sandstone 1000 25.00 31 4550.0 Sandstone 1000 25.00 32 4569.5 Sandstone 1000 25.00 33 4597.0 Sandstone 1000 25.00 34 4601.5 Sandstone 1000 25.00 35 4611.5 Sandstone 1000 25.00 36 4650.0 Sandstone 1000 25.00 37 4684.0 Sandstone 1000 25.00 38 4689.0 Sandstone 1000 25.00 39 4750.0 Sandstone 1000 25.00 40 4850.0 Sandstone 1000 25.00 41 4864.0 Shale 1000 25.00 42 4871.0 Sandstone 1000 1.00 43 4880.0 Shale 1000 1.00 44 4908.5 Sandstone 1000 1.00 45 4919.5 Shale 1000 25.00 46 4922.6 Sandstone 1000 25.00 47 4927.0 Shale 1000 25.00 48 4934.0 Sandstone 1000 25.00 49 4950.0 Sandstone 1000 25.00 50 4975.5 Shale 1000 25.00 51 4979.0 Sandstone 1000 25.00 52 4983.5 Shale 1000 25.00 53 4989.5 Sandstone 1000 25.00 54 4992.5 Shale 1000 25.00 55 5050.0 Sandstone 1000 25.00 56 5064.0 Shale 1000 25.00 57 5069.0 Sandstone 1000 25.00 58 5089.5 Shale 1000 25.00 59 5129.0 Sandstone 1000 25.00 FracproPT 2011 0 • Layer # Top of zone ft Lithology Fracture Toughness psi•in'/z Composite Layering Effect Shale 1000 25.00 Sandstone 1000 25.00 Shale 1000 25.00 "605135.5 Sandstone 1000 25.00 Shale 1000 25.00 . Sandstone 1000 25.00 0 Shale 1000 25.00 .5 Sandstone 1000 25.00 .5 Shale 1000 25.00 .0 Sandstone 1000 25.00 .0 ff Shale 1000 25.00 .0 Sandstone 1000 25.00 .0 Sandstone 1000 25.00 .0 Sandstone 1000 25.00 .0 Sandstone 1000 25.00 10 FracproPT 2011 Table 14: Casing Configuration Length ft Segment Type Casing ID in Casing OD in Weight Ib/ft Grade 5100 Cemented Casing 6.276 7.000 26.000 L-80 Table 15: Surface Line and Tubing Configuration Length ft Segment Type Tubing ID in Tubing OD in Weight Ib/ft Grade 4575 Tubing 2.992 3.500 9.200 1 L-80 Total frac string volume (bbls) 47.6 Pumping down Tubing Table 16: Perforated Intervals Interval #1 Top of Perfs - TVD ft 4780 Bot of Perfs - TVD ft 4800 Top of Perfs - MD ft 4780 Bot of Perfs - MD ft 4800 Perforation Diameter in 0.300 # of Perforations 120 Table 17: Path Summary Segment Type Length (ft) MD (ft TVD ft Dev de Ann OD in Ann ID in Pipe ID in Tubing 4575 4575 4575 0.0 0.000 0.000 2.992 Casing 205 4780 4780 0.0 0.000 0.000 6.276 FracproPT 2011 0 • 1-: _1:..... 9 1713-F.....+i.�r� Crin#inn _ i able 1 b: Near-Wenoore 1- T hi , n• D r—ir Drccci Irc anti ParmPahllity Summary Table Plot - Est. Reservoir Est. Reservoir Est. Reservoir Pressure Pressure Permeability (psi) Gradient (mD) psi/ft Injection/Shut-in #1 Perm Anal sis Plot I I I 1.00e-01 12 FracproPT 2011 • • Table 20: Model Input Parameters Fracture Model 3D Shear-Decou led Reservoir Data Entry General Single Scale Run From Job -Design Data Fracture Orientation Vertical Proppant Transport Model Proppant Convection Run Fracture and Wellbore Models Growth after Shut-in Allow General Iteration Backstress Ignore Heat Transfer Effects Model Acid Fracturing Model Frac roPT Default Leakoff Model Lumped -Parameter Default Table 21: Fracture Growth Parameters OD Shear-DeCOUDied) Parameter Value Default Crack Opening Coefficient 8.50e-01 8.50e-01 Tip Effects Coefficient 1.00e-04 1.00e-04 Channel Flow Coefficient 1.00e+00 1.00e+00 Tip Radius Fraction 1.00e-02 1.00e-02 Tip Effects Scale Volume bbls 100.0 100.0 Fluid Radial Weighting Exponent 0.00e+00 O.00e+00 Width Decoupling Coefficient 1.00e+00 1.00e+00 Table 22: Proppant Model Parameters Parameter Value Default Minimum Proppant Concentration ib/ft2 0.20 0.20 Minimum Proppant Diameter in 0.0080 0.0080 Minimum Detectable Proppant Concentration p 0.20 0.20 Proppant Drag Effect Exponent 8.0 8.0 Proppant Radial Weighting Exponent 0.2500 0.2500 Proppant Convection Coefficient 10.00 10.00 Proppant Settling Coefficient 1.00 1.00 Quadratic Backfill Model ON ON Tip Screen -Out Backfill Coefficient 0.50 0.50 Stop Model on Screenout ON ON Reset Proppant in Fracture after Closure ON ON Table 23: Low Level Parameters Parameter Value Default Perm. Contrast: Distance Effect 1.0 1.0 Perm. Contrast: Containment Effect 1.0 1.0 Perm. Contrast: Permeability Level 1.00 1.00 Perm. Contrast Model: FracproPT Default YES Fluid < el> Bulk Modulus psi 3.000e+10 3.000e+10 Proppant Bulk Modulus psi 3.000e+06 3.000e+06 Fluid el Bulk Coefficient of Thermal Expansion 3.000e-04 3.000e-04 Effect of Proppant on Length Growth 1.00 1.00 Fraction of BRACKET FRAC Proppant that is INVERTA-FRAC by Volume 0.5 0.5 Remember Position of Proppant Banks after closure on Proppant NO NO Allow Slippage NO NO Reset Fluid Leakoff after Frac Closure NO NO Minimum Volume Limit Value 0.20 0.20 Center Shifting Option: Fracture Always Stays Connected to Perfs X X 13 FracproPT 2011 Parameter Value Default Stages can Move from Perfs after Shut-in Fracture can Move from Perfs after Shut-in Fracture can Move from Perfs at any Time 0.0 Stage Splitting Volume Threshold bbls 25.0 .0 25 Stage Splitting Leakoff Compensation bbls 5.0 .0 able L4. 11 nudi L-Ganvn a, — v, - Parameter Value Default Initial Leakoff Area Multiplier Coefficient 1.000 1.000 Initial Leakoff Area from Last Simulation ft2 10 Closure Leakoff Area Multi tier Coefficient .025 0.025 .02 0.0 S YES Default Shut-in Model YES 1.00 1.00 Shut-in Tip Weighting Coefficient for Leakoff 1.00 Shut-in Tip weighting Exponent for Leakoff 1.00 1 100.0 Minimum Shut-in Volume bbis YEESS YES Model Proppant in Flow -back NO NO Model Wall-buildingViscosityEffect iaDleLD:wnscendiivivvvu,,a,u,,,�••, Parameter Value Default Set Minimum Fracture Height NO NO NO NO Model Very Small Fractures NO NO Model Head Effects in Fracture NO Model Fracture Center Shifting NO Near-Wellbore Friction Ex onent 0.50 0.50 14 FracproPT 2011 L-1 a Width Profile (in) Concentration of Proppant in Fracture (lb/ft') Layer Properties TVD(ft) 0 2,5 50 75 100 125 150 175 200 225 250 275 300 325 350 Ro"' TVD(ft j ! Fracture Length ft 146.9 (ft) Fr8 roPT+ 1 Propped Length 0.0 I 4700 - _ �` Total Fracture Height (ft) 211.8 — 70 4 0 Total Pro ad Hall ht ft 0.0 1 1 I � i 4750 4750 I •. -4800 I I 4800 - t} a I T fir � 4850 . , . 4850 wand . whale- - 4900 4900 land . Proppant Concentration (Ib/ft') sand... 4950 j � 4950 0 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.0 i Figure 1 Fracture Profile for Upper Sand MOBM 10ppg, Subtitle, Uate 15 FracproPT 2011 Umiat D c sal Injection Order Application November 1, 2012 Attachment 3 — Seabee Test Well No.1, DST #3 Water Analysis Report /I VA nx 4-MM "LV"Wd*W"*.M4 AMMM0ftMKMMM"CMWM CJEWCAL R GWLOGIW LAB©RATOR$S OF ALA" M NM/wap.Ainb O *14400 eT � P&i iftL A L AA$ Adn RIB Mir ... .. iiYir . . . i AM .. ..yM,�r...... �i. 4.sB��--� •- Ibis ----• - �� "awl come low ANIM ......�._ Teri am*" *ib MxM • - - - tpdb tw. ten. • "asu •i!l AXAL{ Mdall sub dw" 4=k%4 ■s4 PRU & 10 lb M ]LO Ca 10 us 10 h Iwvein rOR" wwftbornwxBps u mom MOM wndwPokki PIWANOMW Udd* i Y. MERPSW Ca 804 cab Page 132 Umiat D � I Injection Order Application November 1, 2012 Attachment 4 — Seabee Test Well No.1 Due Diligence Summary with Schematic Page 133 so ;�j EXISTING WELLBORE DIAGRAM Spud: 7/01/1979 Seabee Test Well No.1 Section 5-T1S-R1W, UM API #: 50-287-20007-00-00 Operator - Husky Oil NPR Operations Inc. PTD #: 100-223 FO Collar set @ 996' 26" hole to 1,623' 20" casing to 1,617' Cemented with 566 bbl 15.2 ppg AS -II (3,400 sx) Cemented to Surface 20" FO Collar set @ 1,990' Cemented with 243 bbl of 15.2 ppg AS -II cement 1,450 sx (40% OH Excess) Cemented to Surface FO Collar set @ 2,103' FO Collar set @ 3,519' 17-1/2" hole to 4,009' iYii 13-3/8" casing to 3,983' 13-3/8" Cemented with 328 bbl 15.8 ppg Class G cement 1,600 sx (25% OH Excess) TOC = 1,990' (est) DV Collar set @ 5,591' Cemented with 327 bbl Aw 15.8 ppg cement 1,600 sx (150% OH Excess) TOC = 2,200' (est) 12-1/4" hole to 10,004' 9-5/8" casing to 9,980' Cemented with 245 bbl 15.8 ppg cement 1,200 sx (150% OH Excess) a TOC = 8,300' (est) 8-1/2" hole to 12,814' 7-5/8" liner from 9,601'to 12,814' Cemented with 191 bbl 9-s/8° 18.1 ppg cement (896 sx) Liner top squeezed with 36 bbl 17.2 ppg 7-5/8° cement (200 sx) TOC = 9,601' (est) 6-1/4" open hole to 15,611' Plug #8-1,478' 20" Casing tested to 2,400 psi Casing Punch Squeezed 1,500' - 1,501' 20" Casing Shoe FIT Test to 11.5 ppg 13-3/8" Casing tested to 2,500 psi Perfs Perforations Squeezed 2,652' - 2,664' 13-3/8" Casing Shoe FIT Test to 15.3 ppg Perfs Perforations Squeezed NEB+«_ 5,366' - 5,394' Plug #4 - 9,416' Plug #3 - 12,637' Plug #2 - 13,180' Plug #1 - 14,250' 9-5/8" Casing tested to 3,000 psi 9-5/8" Casing Shoe FIT Test to 17.6 ppg 7-5/8" Liner tested to 3,000 psi 7-5/8" Liner Shoe FIT Test to 20.0 ppg Rev 3/14/12 �il N oUnc SEABEE #1 EOERGY Due Diligence 3-14-12 DRILLING SUMMARY: 7-01-79 to 4-15-80 API: 50-287-20007-00 PTD No.: 100-223 SPUD DATE: 7/01/1979 RIG: Nabors #25 (Rotary Rig) OPERATOR: Husky Oil NPR Op. Inc. LOCATION: Sec05-T01S-R01W-UM 1099' FSL, 1339' FEL 7/01/79 to 7/01/79 MIN N/A Conductor Hole • Cut 30" casing and set at 115'. • Cement casing w/ 214 bbl (1,285 sx) of Arctic Set II at 15.2 ppg. Cement to surface. • Nipple up 30" Hydril diverter. 7/01/79 to 7/19/79 MIN 8.9 — 9.7 ppg Surface Hole • Spud well (7/01/79). • Drill 17-1/2" hole from 115' to 1,115'. Tight hole. Ream with 3-point reamer. • Drill 17-1/2" hole from 1,115' to 1,623'. Tight hole. • Run in hole with logging tools. DIL/GR, FDC/CNL, BHCS, HDT 125'-1,615' 1 7/05/79 • Open hole to 26" from 115' to 1,623'. • Ran 20" casing. Casing parted 2 jts below rig floor. Fished parted casing. • RIH w/ 26" bit and drill on junk 2 hours. • Ran 20" casing. Welded casing joints, shoe and float collar. 20 jts 169#, 24 jts 133#. • Set casing at 1,617'. Float collar at 1,579'. Stab -in for cement job. • Cement casing w/ 566 bbl (3,400 sx) of Arctic Set II at 15.2 ppg. Full returns. • Cemented 30" x 20" annulus at 12'. • Welded on 20" starting head. Failed at 100 psi. Re -weld and test to 500 psi (test -OK) (7/18/79). • Cemented cellar w/ 32 bbl of Arctic Set II at 15.3 ppg. • Nipple up BOPE. Test valves/lines/manifold to 3,000 psi. Test annular to 1,500 psi. • RIH w/ 17-1/2" bit and tag cement at 1,552'. Drill cement to top of shoe. • Test casing to 2,400 psi (test -OK) (7/19/79). 7/19/79 to 8/01/79 MIN 9.3 —10.1 ppg Intermediate Hole FINAL v1.0 Pg 1 so SEABEE #1 Due Diligence 3-14-12 Drill 17-1/2" hole from 1,617' to 1,641'. Perform FIT to 11.5 ppg at 250 psi at 1,617' TVD of 20" shoe (7/19/79). Drill 17-1/2" hole from 1,641' to 2,465'. Bridge at 1,678'. Drill 17-1/2" hole from 2,465' to 2,661'. Drilling break. Drill 17-1/2 hole from 2,661 to 3,321 . Tight hole at 2,840 . Bridge at 3,068 . Drill 17-1/2" hole from 3,321' to 3,750'. Bridged at 3,250' and 3,685'. Drill 17-1/2" hole from 3,750' to 4,009'. Run in hole with logging tools. DIL/GR/SP, BHCS/GR/Cal, FDC/CNL/GR, HDT, Velocity 1 1,618'-4,004' 1 7/2 Ran 13-3/8" 72# casing, set at 3,983'. Stab -in for cement job. Cement casing w/ 328 bbl (1,600 sx) of Class G at 15.8 ppg. Open bottom FO collar at 1,990'. Circulate bottoms up. Close FO collar at 1,990'. Open top FO collar at 996'. Cycle FO collar. Cut 13-3/8" casing. Install pack -off. Test pack -off to 2,500 psi (test -OK) (7/30/79). Set RTTS packer and cement thru FO collar at 1,990' w/ 243 bbl (1,450 sx) Arctic Set II at 15.2 ppg. Returns at 211 bbl (1,260 sx) pumped. Open and close top FO collar. Test to 2,500 psi (test -OK) (7/31/79). Drill float collar, 84 feet of cement, and float shoe. Clean out to 4,009'. Perform FIT at 15.3 ppg at 3,983' TVD of 13-3/8" shoe (8/01/79). 8/01/79to 11/28/79 • MW 9.9 —14.9 ppg Production Hole Drill 12-1/4" hole from 4,009' to 5,388'. Well began to flow. SIDP = 800 psi. Well under control at 14.1 ppg. Built mud to 14.3 ppg. Circulate bottoms up with 3,150 units of gas to surface. Circulated to remove gas. Mud at 14.3 ppg. RIH and perform DST #1(failed-plugged). RIH. Mud cut to 11.8 ppg. Circulate bottoms up. Mud at 13.9 ppg with 314 gas units. Drill 12-1/4" hole from 5,388' to 5,390'. POOH to core. Core from 5,390' to 5,402'. Core barrel jammed. POOH. Recovered 12 feet. RIH and perform DST #2 (failed -packer failure). Clean to bottom to 5,402'. Circulated bottoms up. Mud cut to 11.7 ppg w/ 3,150 gas units. FINAL v1.0 Pg 2 M so SEABEE #1 Due Diligence 3-14-12 • Drill 12-1/4" hole from 5,402' to 6,541'. POOH to core. • Core from 6,541' to 6,551'. POOH. Recovered 7.3 feet. • RIH and clean out to bottom. Bottoms up gas at 380 gas units. Circulate for logs. • Run in hole with logging tools. DIL/GR/SP, FDC/CNL/GR/Cal 1 3,983'-6,521' 1 8/19/79 • RIH w/ open-ended drillpipe to 4,100'. Cement openhole w/ 400 sx of 15.2 ppg. Cement plug set from 3,883' to 4,100'. • Set retrievable bridge plug at 3,635'. • RIH w/ RTTS to 1,005'. Test below RTTS to 2,000 psi for 20 min (test -OK) (8/21/79). • Test 13-3/8" casing above RTTS to 1,950 psi for 20 min (test -OK) (8/21/79). • Open top FO collar at 996'. Test to 2,000 psi. Bled to 1,600 psi in 15 min. No injection. • Close top FO collar at 996'. • Suspend well at 2:15 p.m. (8/21/79). • Well suspended (8/21/79 to 10/15/79). • Rig up and mix mud. Test BOPE. Test 13-3/8" casing to 2,500 psi (test -OK) (10/17/79). • Drill cement from 3,883' to 4,110'. • Drill 12-1/4" hole from 6,551' to 6,557'. Bit balled. POOH. RIH w/ bridges at 4,073' and 4,100'. • Drill 12-1/4" hole from 6,557' to 10,004'. • Run in hole with logging tools. , FDC/CNL/GR/Cal, BHC/GR, HDT/Dip, Velocity 1 3,933' • Ran 9-5/8" 53.5# casing. • Cement casing w/ 245 bbl (1,200 sx) of Class G at 15.8 ppg. Bump plug w/ 3,000 psi. • Open DV collar at 5,591'. Circulate w/ no contaminated returns. • Cement thru DV collar w/ 327 bbl (1,600 sx) of Class G at 15.8 ppg. Bump plug w/ 2,200 psi. Recovered 30 bbl of contaminated mud during cement job. • Drill DV collar. RIH to 9,850'. Drill hard cement from 9,850' to 9,896'. • Tested 9-5/8" casing to 1,500 psi (test -OK) (11/27/79). • Run in hole with logging tools. -9,876' 1 11/27/79 FINAL v1.0 Pg 3 M SEABEE #1 Due Dilieence 3-14-12 CBL/VDL/CCL/GR 1 0'-3,988' 11/27/79 • Tested 9-5/8" casing to 3,000 psi (test -OK) (11/28/79). • Drill cement to 9,990'. Opened hole to 10,004'. 11/28/79 to 1/27/80 MW 14.5 —17.0 ppg Production Hole • Drill 8-1/2" hole from 10,004' to 10,021'. • Perform FIT to 17.6 ppg at 9,980' TVD of 9-5/8" shoe (11/28/79). • Drill 8-1/2" hole from 10,021' to 12,814'. • Run in hole with logging tools. DIL/GR/SP, BHCS/G 9,967'-12,772' 1 1/1 • Ran 7-5/8" 39# liner from 9,661' to 12,814'. • Cement liner w/ 191 bbl (896 sx) of Class G at 18.1 ppg. • RIH and tag cement at 12,686'. Drill cement to 12,734'. • Test liner, had 1,340 psi leak off. • Set retainer at 9,576', squeeze liner top w/ 36 bbl (200 sx) Class G at 17.2 ppg. • Drill retainer at 9,576'. Tag cement at 9,586'. Drill cement to 9,661'. • Test liner to 3,000 psi (test -OK) (1/25/80). • Run in hole with logging tools. Gyro Survey unknown CBL/VDL/CCL/GR unknown • Drill cement to shoe. 1/27/80 to 4/15/80 MW 17.0 —18.6 ppg Liner Hole • Drill 6-1/4" hole from 12,814' to 12,832'. • Perform FIT test to 20.0 ppg at 12,814' TVD of 7-5/8" shoe (1/27/80). • Drill 6-1/4" hole from 12,832' to 15,611'. • Run in hole with logging tools. Temperature GR/SP/DIL 100'-12,750' 12,938'-13,172' 1/26/80 3/30/80 3/31/80 FINAL v1.0 Pg 4 SEABEE #1 Due Diligence 3-14-12 • Attempt to gather additional logs (failed). • Run in hole with logging tools. GR/CAL/CNL/FDC • Attempt to gather additional logs (failed). • Run in hole with logging tools. GR (thru drillDi • Spot plug #1 14,250'-14,450' (4/05/80). • Spot plug #2 13,180'-13,787' (4/05/80). • Spot plug #3 12,637'-12,913' (4/06/80). • Spot plug #4 9,416'-9,910' (4/06/80). • Spot plug #5 8,243'-8,343' (4/07/80). • Run in hole with logging tools. Bond Log 785' 1 4/02/80 12,700'-15,490' unknown 1 4/07/80 • Perforate 5,366'-5,394' (4/08/80). • RIH and perform DST #3 (flowed up to 6.7 MMCF/d). • Set cement retainer at 5,295', squeeze plug #6 w/ 150 sx Class G cement (4/11/80). • Perforate 2,652'-2,664' (4/13/80). • RIH and perform DST #4 (small gas flow). • Set cement retainer, squeeze plug #7 from 2,506' w/ 150 sx Class G cement, left 10 bbl cement on top of retainer (4/14/80). • Casing punch 4 holes at 1,500'. • Set cement retainer at 1,478', squeeze plug #8 w/ 320 sx Arctic Set cement, left 10 bbl cement on top of retainer (4/14/80). • Displaced mud to water to diesel. • Release rig at 11:00 p.m. (4/15/80). Directional Survey Single Shot Survey • Maximum deviation of 26.50° at 15,070' MD. At 5,178' MD deviation is 3.75°. FINAL v1.0 Pg 5 so so SEABEE #1 Due Diligence 3-14-12 DEPTH (FT) INC (0) AZI (Dir) DEPTH (FT) INC (0) AZI (Dir) DEPTH (FT) INC (0) AZI (Dir) 175 0.00 - 5,926 3.75 S73W 10,808 10.75 N80E 378 0.50 - 6,347 4.25 S78W 10,870 12.00 N78E 467 0.75 - 6,541 4.75 N78W 10,920 12.00 N78E 719 0.75 - 6,853 5.25 - 11,070 12.25 N80E 931 1.00 - 6,869 5.12 S89W 11,265 13.25 N85E 1,053 1.00 - 7,166 5.00 N85W 11,457 15.00 N87E 1,200 1.25 - 7,292 5.00 N85W 11,603 15.00 N85E 1,580 1.50 N38W 7,660 5.00 N70W 11,760 15.00 N87E 1,808 1.75 - 7,925 4.50 N70W 11,946 15.25 S88E 2,029 1.75 N34W 8,155 4.50 N60W 12,201 14.75 S88E 2,217 1.50 - 8,392 4.25 N65W 12,320 14.00 - 2,420 2.00 - 8,575 3.50 N60W 12,550 13.25 - 2,661 2.25 - 8,711 2.75 - 12,750 13.50 - 3,069 1.50 N36W 8,850 2.50 N50W 13,320 13.75 S32E 3,382 1.00 N10W 9,038 2.50 N45W 13,504 12.50 S18E 3,601 1.00 N25E 9,260 2.50 N55W 14,060 5.00 S65E 4,009 3.00 S05W 9,508 1.75 N35W 14,280 4.50 N23E 4,256 3.25 S03W 9,681 1.75 N10W 14,510 10.50 S88W 4,423 3.50 S06E 10,004 2.25 N20W 14,747 16.00 N77W 5,178 3.75 - 10,292 5.25 N08W 14,900 20.00 N75W 5,709 3.25 S56W 10,450 8.00 N68E 15,070 26.50 N55W FINAL v1.0 Pg 6 soUmiat AMPI Injection Order Application November 1, 2012 Attachment 5 — Seabee Test Well No.1 Water Salinity Log Page 134