ENCANA SHALLOW GAS INFILL DEVELOPMENT PROJECT AND EUB APPLICATION NO JOINT REVIEW PANEL HEARING CONDUCTED PURSUANT TO:

Transcription

1 1133 ENCANA SHALLOW GAS INFILL DEVELOPMENT PROJECT AND EUB APPLICATION NO JOINT REVIEW PANEL HEARING CONDUCTED PURSUANT TO: SECTION 4.5 OF THE "AGREEMENT TO ESTABLISH A PANEL FOR THE ENCANA SHALLOW GAS INFILL DEVELOPMENT PROJECT" AND THE EUB'S RULES OF PRACTICE PROCEEDINGS AT HEARING OCTOBER 14, 2008 VOLUME 6 PAGES 1133 TO 1323 Held at: Energy Resources Conservation Board Govier Hall, 640-5th Avenue S.W. Calgary, Alberta

2 1134 APPEARANCES JOINT PANEL: Robert (Bob) Connelly, Panel Chair Bill Ross, Panel Member Gerry DeSorcy, Panel Member CANADIAN ENVIRONMENTAL ASSESSMENT AGENCY (CEAA): Marie-France Therrien Jeff Davis Lucille Jamault ENERGY RESOURCES CONSERVATION BOARD (ERCB): JP Mousseau, Esq., Board Counsel Meighan LaCasse, Board Counsel Jodie Smith Jennifer FitzGerald Mirtyll Albiou Peter Hunt Bruce Greenfield Carrie Dickinson Shaunna Cartwright Ken Banister Tom Byrnes Steve Thomas Karl Jors Lawrence Jonker Darin Barter Bob Curran PROPONENT Shawn Denstedt, Esq. ) For EnCana Corporation Ms. Terri-Lee Oleniuk ) Ms. Leanne Campbell )

3 1135 INTERVENERS: Kirk Lambrecht, Esq. Jim Shaw, Esq. Robert Drummond, Esq. Ms. Jennifer J. Klimek Mr. H. Binder John McDougall, Esq. Ms. Kelly Lemon (student) Keith Miller, Esq. ) For Government of Canada, ) Environment Canada, ) Natural Resources Canada, ) Department of National ) Defence, Parks Canada, ) Agriculture Canada, ) Department of Fisheries ) and Oceans ) For the Environmental ) Coalition ) ) For the Suffield ) Environmental Advisory ) Committee. ) For the Suffield Industry ) Range Control. REALTIME REPORTING: Mainland Reporting Services, Inc. Nancy Nielsen, RPR, RCR, CSR(A) Tambi Balchen, CRR, CSR No. 9166

4 1136 INDEX OF PROCEEDINGS DESCRIPTION PAGE NO. Housekeeping and scheduling matters spoken to: EnCana witness panel (on former oath/affirmation): Joel Heese (On former affirmation) Francis L'Henaff (On former oath) Gerard Protti (NOT PRESENT) Stephen Fudge (On former oath) Douglas Collister (On former oath) John Kansas (On former oath) Dr. David Walker (On former oath) Ron McNeil (On former oath) Ian Simpson Moss (On former oath) Cross-examination by Mr. Mousseau: 1141 Undertaking spoken to: 1259 Cross-examination by Mr. Mousseau (continued): EnCana witness sworn: Spencer Cox (Duly Affirmed) Cross-examination by Mr. Mousseau (continued):

5 1137 INDEX OF EXHIBITS DESCRIPTION PAGE NO. EXHIBIT : Bundle of documents prepared by EnCana in fulfillment of undertaking given regarding D and R approvals and well licence approvals for the Middle Sand Hills area EXHIBIT : Spencer Cox CV 1269

6 1138 (PROCEEDINGS COMMENCED AT 2:00 P.M.) THE CHAIRMAN: Good afternoon, Ladies and Gentlemen. I'd like to begin. I'd like to welcome you here this afternoon and hope you all had a good Thanksgiving Weekend. We are beginning our second week of hearings into the proposal by EnCana Corporation to install, over a three-year period, up to 1275 new shallow gas wells within the boundary of Canadian Forces Base Suffield in the National Wildlife Area. The Project, proposed Project is in addition to existing natural gas activities within the National Wildlife Area. In addition, the Panel also has before it for its consideration EUB Application No filed pursuant to Section 2.02 of the Oil and Gas Conservation Regulation for three licences -- for licences to drill three wells in the National Wildlife Area. We left off on Friday with the intent to begin cross-examination by Mr. Mousseau of the EnCana panel. We are aware, of course, that Mr. Protti is not part of your panel today and for that reason I believe Mr. Mousseau will focus his questions on resource and environmental issues, rather than some of

7 1139 the regulatory issues. Our intention this afternoon is to continue to about 5:30. We'll take a break in between. As I mentioned on Friday, there will be some food brought in at 5:30 for all of you to, to have some dinner and our plan would then be to reconvene and continue our proceedings to approximately 8 o'clock this evening. There's no change from the proposal as outlined on Friday. If there are no other matters then I will ask Mr. -- I'm sorry, Mr. Denstedt. HOUSEKEEPING AND SCHEDULING MATTERS SPOKEN TO: MR. DENSTEDT: Sir, I can report on the undertaking that was given by Mr. Heese on Friday. It will be ready probably by the break in this afternoon. It's just being photocopied. It was the undertaking to provide the regulatory approvals. So we'll provide that at the break, if that's okay. THE CHAIRMAN: Thank you, Mr. Denstedt. Yes, I'd forgotten that you had agreed to provide that and specifically the Development and Reclamation Certificates, as I understand it. Yes, Mr. McDougall, you have a comment? MR. McDOUGALL: A question, sir, forgive me. I'm wondering if the Panel wouldn't mind identifying

8 1140 who might be next in line with respect to witnesses. I apologize, I've been away for a couple of days but I know that there's -- certainly in my camp, there is some question as to whether we're going to be this week, later this week, next week. Does the Panel have -- is there a consensus on who might the next witness be? THE CHAIRMAN: Yes. The intent was -- and this was discussed at the end of the day Friday, the intent was after Mr. Mousseau has finished his cross-examination, that the Coalition would sit its, its panel and present their evidence. MR. McDOUGALL: And is there a determination who after the Coalition, or is that yet to be determined? THE CHAIRMAN: I'll check my notes. After that I believe, depending on, on, on how the time goes, we may then reconvene the EnCana panel, or more specifically Mr. Protti, to deal with some of the regulatory issues. Obviously, you are wondering when you may be providing your evidence. MR. McDOUGALL: THE CHAIRMAN: Right. And perhaps we could discuss that a little bit more at, at the break with Mr. Mousseau if you're going to be here at that point.

9 1141 MR. McDOUGALL: THE CHAIRMAN: Yes, I will be. It's obvious, obviously not going to be immediate. MR. McDOUGALL: That's fine, sir, I was just wondering -- you know, just -- I'm sure everyone's calendar is a bit chopped up, but for me it would be helpful just to identify within three or four days when, when it might, might be happening. THE CHAIRMAN: Right. I'm sure we can do that. MR. McDOUGALL: THE CHAIRMAN: Thank you, sir. Okay, Mr. Mousseau, please proceed. ENCANA WITNESS PANEL (ON FORMER OATH/AFFIRMATION): Joel Heese (On former affirmation) Francis L'Henaff (On former oath) Gerard Protti (NOT PRESENT) Stephen Fudge (On former oath) Douglas Collister (On former oath) John Kansas (On former oath) Dr. David Walker (On former oath) Ron McNeil (On former oath) Ian Simpson Moss (On former oath) CROSS-EXAMINATION BY MR. MOUSSEAU: MR. MOUSSEAU: Thank you, Mr. Chairman.

10 1142 Panel. Good afternoon. And happy election day. Q. I have a number of questions for you this afternoon and just, just to sort of give you a road map of where I'm going to be going, I'm going to start with -- probably with you, Mr. L'Henaff, with decline analysis, the, the modelling, some questions on directional drilling and then well spacing and the need for the wells. And that, that's going to take us a while to get through. And then following that, we're going to look at some environmental issues. So likely we'll be dealing with this, this half of the panel first and that half of the panel in the afternoon. I'm not saying you guys can take off, but it will be a while before I get to you. Now, Mr. L'Henaff, just, just so I understand, I'm going to give you a reference, which is Exhibit which was answers to Information Requests. I don't think you need to turn it up at this point but as I understand it, EnCana calculated incremental recovery of 3.8 bcf per section for the D6/D8 pilot area and that was determined using, in part, standard decline analysis and you used both hyperbolic and exponential analysis, is that accurate? A. MR. L'HENAFF: I'm not exactly sure which

11 1143 one you're referring to. Is it our submission of just after our Opening Statement? Q. Like, I can take you right to the -- maybe we do need to go to Exhibit , which was an answer to an Information Request. It was JRP7. But really, just, just super general question, your decline analysis, that was standard industry decline analysis and you used two different methods; is that fair? A. Yes, I guess it is fair. We typically will use a variety of techniques to take a look at the sensitivities between each of them. Exponential decline will be -- give you the most conservative. We feel that the most appropriate for this type of reservoir would be exponential going into a hyperbolic. Q. Okay. And can you comment on the applicability of the analysis to production in the NWA having regard for the, the characteristics of the, the multiple reservoirs being produced? A. I'm not exactly sure I understand your question. Could you elaborate a bit? Q. Sure. I can just -- I, I can say this: you used hyperbolic and exponential analysis. Is that the -- is that industry standard for the sort of reservoirs targeted in the NWA?

12 1144 A. Sure. It is. For this type of reservoir, it's a tight gas reservoir, multilayered, that is industry standard. What we've presented in our JRP7 basically there were several pilots that we presented the decline analysis for. All of those decline analysis results are highly, highly conservative. They are very -- we are very confident of those results. Those results would represent, as I, I believe I had indicated before, a probability of P-90, or better, so 90 percent chance that the number that you'll get out of that pilot will be at least that number or higher. It's in line with McDaniels' approach. McDaniels, when they do the reserve booking, has to take a very conservative analysis to put on the books. Mr. Protti kind of outlined the reasons for that. So what we chose to submit was an analysis of the same type. So a highly confident number. Through some of the reanalysis, we believe that the numbers that are presented in JRP7 are probably more confident than that, likely in the P-95 level. Q. Okay. And maybe just to follow up on something you said. You said you -- that the, I think it was the exponential analysis was more conservative. Did, did you do the hyperbolic analysis to, to test the accuracy of the exponential analysis? I'm just

13 1145 trying to understand why both were used. A. I believe it was only the, the one plot that we submitted for the D6/D8 that was predominantly exponential all the way. The, the hyperbolic basically tails out the reserves at the tail end, so it's really just making some accommodation for those multilayers kind of kicking in. And what you have then is a, a creep, a positive creep on your reserve estimate. So your reserve estimate will be higher using that combined curve. I'll call it a combined curve analysis technique. Q. Okay. If I -- if we can go to Exhibit , we're going to go JRP No. 7. And I want to look at Figure 7B, if we can. A. Yes, I have it. Q. Okay. And the first question I have is can you tell me what type of decline analysis was used to obtain the forecasts? Is this, is this an example of the hybrid approach? A. What is presented here is the exponential. Q. Okay. And could the same ultimate recovery for 8 wells per section and 16 wells per section be predicted if the decline parameters, and let's start with abandonment rate, were varied by 10 percent? What, what impact would that have?

14 1146 A. So the impact wouldn't be very large. It's basically just the abandonment pressure and it would relate to the, the abandonment rate per well. As I'd indicated, we're using a 5 mcf per well, so that wouldn't affect it that much. Q. Just, if I could just hold you up there, can you quantify the impact? Would it be... A. Well, maybe just as a matter of quantification, so, so we analyzed these pilot areas in several different ways, as does McDaniels and if you take a look at the last few years of the McDaniels analysis, their numbers, their estimates of reserve recovery at the P-90 level had been improving through time. So 2003 it was at the 70 million level, 2004 it was up to 86, 125 in 2005, 145, 150. So, really, what you're seeing is with the improved history and the incremental production that they're seeing from both curves, you are seeing that the estimate of the reserve number is approaching what would you expect is a P-mean. And so the McDaniels number, being a P-90, would continue to appreciate. Q. Okay. And, and that, that's useful, but what, what might be really helpful for me is that Figure 7B I think it shows an ultimate, or expected ultimate recovery for 16 wells per section of 6.18 bcf. And

15 1147 if you were to, say, vary the abandonment rate by 10 percent, would it move much off that 6.18? A. It would not. Q. Okay. A. I would have to guess at the number, but I would think it would be in the decimal of a bcf or in the double decimal of a bcf. Q. And, and what if you varied the B exponent to the same degree, would your answer be the same? A. It wouldn't -- again, the B exponent would not have that much of an effect, maybe -- Q. Okay, sorry. A. Maybe 10 percent. Q. Okay. And would it have a differential effect on the 16 wells per section or the 8 wells per section? Would the ultimate recovery for, for both be affected to a similar degree? A. It would. And in fact when we ran those numbers, we were getting the same numbers, even I guess higher numbers. 118 is, we believe, a P-95. Q. And I understand that EnCana used a B-value of 0.5. And is this industry standard or is this reasonable for a tight multilayer reservoir? A. Yes. We believe it is. Q. And is there a range of, of acceptable B-values for

16 1148 this type of reservoir? A. It's a consistent number that McDaniels uses, for sure. Bs in between zero and, and 5 is, is, you know, the difference between the exponential on the combined curve. Q. Right. And, and I'm going to put it to you that a B-value of, of 1 would also or could also be reasonable in these circumstances; is that fair? A. We don't believe that 1 would be reasonable. We believe the 0.5 is reasonable. Q. So is 0.5 the higher end of the range or? A. It's probably at the mid-range. Q. Okay. So accepting that it's in the mid-range, and 1 would be at the high end of the range, what impact would using a B-value of 1 have on the ultimate recovery? A. Again, we didn't take a look at that, but it likely wouldn't have an effect from the differential perspective. Both curves would be, would be drawn out. Q. So the effect would be the same on both? A. Yes. Q. And just to sort of follow up on that, would, would a B-value of 1 be considered reasonable given the group targeting formations or again, I think 0.5 is your

17 1149 number; is that fair? A. That's fair, 0.5 is our number. We believe that's representative of groupings of wells as well. Q. Okay. Sir, we're going to go now to Exhibit , which was an IR response from EnCana, and it's, I'm told it's on page 95 of 426 on the PDF, if that's helpful to someone. Are, are you guys set up for exhibit numbers? Or are you set up for the registry? A. I gambled and lost, sir, so... is that up, it up on the screen there? Q. Let me just check. UNIDENTIFIED SPEAKER: Registry number 217. MR. MOUSSEAU: There we have it. Q. My question on this one is really simple, sir. And I'm just interested in knowing what the units are for the X and Y axis. A. I suppose I'll have to get back to you on that. It -- it is the same plot, so it's on a per-section basis. So that would be bcf and mmcf per day. But I'll -- subject to check, I'll confirm that. Q. Subject to check? A. Yes. Q. Okay. So, having regard for this, having regard for this plot, you believe that the production period for

18 1150 each of the well densities in the, the D6/D8 pilot was long enough to accurately predict ultimate recovery at those densities? A. So this is -- so this analysis is the D6/D8 analysis interior, so it was an analysis that was done on an earlier version, and effectively what we submitted after our Opening Statement, which was the reanalysis of that, of that period, is the more updated version. If you take a look at both this one as well as the submission that we made just at the -- after our Opening Statement the, I guess the, the high flux area is the one that's being analyzed and -- Q. So maybe if I could just stop you there. Are you, are you referring to the exhibit you entered as part of your Opening Statement, so that's ? UNIDENTIFIED SPEAKER: That's correct. Q. And you -- A. Yes, sir, that's correct. Q. Okay. Go ahead, sir, I just wanted to know where you were at. A. Sure. So this was an older analysis of that, of that same period of high transition. Q. Right. A. So you can see, you know, not to the same degree of detail, but you can see the, the new infill wells

19 1151 coming on and as well as the refracs, so you can see that the decline curves that we've selected were to parallel those phases of activity. The submission that we made after our Opening Statement was a reanalysis of that and I believe more reflective of what you would see from that. But we do -- still do believe that there is so much going on that, that this would be a difficult period to forecast and to use. But this, this plot here, as well as the one after our Opening Statement, was an attempt at that. If you can note that the end result effectively was showing the same magnitude of incremental reserves, and so I guess they would just reflect a slightly different confidence level. Q. Okay. And how long was the D6/D8 run with a well density of 6.5 wells per section? A. You can see on the, the grey line on the one plot that you have up on the screen there, kind of indicates where the, the well count is, so. Just a couple of years you can see it's flat there. There's a longer period before that where it's at the 4 wells per section. And that's where you would get your most confident base decline. But the declines with the 6.5 percent are, the 6.5 percent wells or 6.5 wells per section, are kind of in the same range.

20 1152 Q. Sir, in a perfect world, would it have been preferable for the D6/D8 pilot to avoid operational changes in the existing wells in the pilot area prior to -- in order to establish a good baseline? A. Yes, I suppose that's true. If you wanted to just examine this one effect, that would absolutely be the way to go. When that pilot was, was first instituted, there were several things that EnCana wanted to investigate. And so it was because of that, a broad spectrum approach around objectives is why the approach was taken, to basically take a look at the, the offset ring as opposed to the interior. So it was the combination of the objectives that resulted in the approach. If you wanted to take a look at just the one objective, that would, would have been the way to go, absolutely. Q. Okay. And for the D6/D8 pilot, can you elaborate on whether the production from the Milk River Medicine Hat and Second White Speckled shale formations was commingled in the -- all wells at the same time? A. Yes, they were. Q. Sir, we're going to go back to Exhibit , which was the answer to the Information Request, and I think JRP7. The one we started off with earlier, sir. I'm not certain you have to turn this up, but

21 1153 just, this is where the question is coming from. And it was my understanding based on answers to Mr. Binder that EnCana used an abandonment rate of 500 cf, or cubic feet per day per well, regardless of well density for the pilots referred to, is that accurate? A. That's accurate. We typically will run a 5 mcf per day per well abandonment rate. Q. Okay. A. You know, when we're looking at our pilots. If you're -- if we're looking at projects on a larger scale, we will incorporate battery abandonment rates as well as field abandonment rates but when we're just looking at a pilot level, we will run a 5 mcf cut off. Q. Despite the difference in well densities? A. Yes. Q. And what was the gas forecast used to determine the expected recoveries under the various densities? Was it constant as well? A. I'm not sure I understand your question. Q. Did you use the same gas price forecast to determine expected recoveries? A. Oh. It was independent of, of price forecasts. So it was basically just depletion curve from the decline rate and the 5 mcf was a proxy for economic factors

22 1154 and physical limitations in the wellbore. Q. Okay, and so did that incorporate operating costs as well? A. It would, like I say -- that, that abandonment rate would accommodate all economic factors. You know, maybe if I can just elaborate on abandonment conditions for a particular well. What we found is when a well is, is getting very low in energy, typically it loses the ability to flow, so the reservoir energy drops off a lot faster, so almost independent of what the price is or what your operating costs are, it will lose the ability to flow against a line pressure or flow against the water that's in, in the wellbore, so very quickly it will, it will basically reach a zero production rate. So more, it's more of a physical limitation that, that turns out, at the field level, to be a more practical limitation than an economic criteria. Q. Okay. Sir, I'm not certain if this, this question figures into it, but in JRP No and, again, I don't know if you need to turn this up, but in there is referenced a figure called "Figure 7J". But there is no Figure 7J. And I'm wondering if Figure 7J is missing or perhaps that was a typo. A. I believe it was a typo. I can certainly get you the

23 1155 correct reference if, if it's important for... Q. We, we just don't want to be missing a figure, sir, so if you can check that for me at the break and get back to me, that would be great. A. I certainly will. Q. Okay. Sir, we're going to jump now to Volume 1 of the EIS and this is Exhibit And we're going to be looking at some reservoir pressures that are in there. And just so you know exactly where we're going, we're going to page 2-2, table 2-1. Are you with me? A. Yes, I am. Q. Okay. As I understand it, initial reservoir pressures of 3300, 4300 and 5700 are stated for the Milk River, the Medicine Hat and Second Speckled White Shale are included here. And I just want to know what the basis for these initial pressure values are. A. They would be from, I guess, our initial understanding of our reservoir pressures at, at discovery time. Q. So it's based on historical records? A. Yes. Q. Okay. And are these values representative of the virgin reservoir pressures in the NWA? A. We believe they are, yes. Q. Is there, is it homogenous throughout or does it

24 1156 differ slightly throughout the NWA? A. There will be some slight differences. There is a, a regional, a bit of a regional dip. If dipping down from the southwest corner down to the north, northeast corner, that can be referenced in -- there was a package of geological maps that was submitted, So structure top of Milk River is in there. And you can see very subtle regional dips. So because the play is so large, basically from Calgary to -- in, in almost Saskatchewan, Swift Current area, there is, based upon where you are, there will be some regional dip to that. But within the confines of the NWA, if you can take a look at, at the first structural figure for formation top for the Milk River, it's very shallow. Q. Okay. A. So because of that, we feel that the numbers presented are certainly representative. Q. Okay. We're, we're going to jump back to Exhibit and, and just for everyone's reference, we're going to spend the bulk of the time in that document, so if you want to keep it out, we're just going to be going back and forth to different information responses in there, just so you're not putting it away all the time and pulling

25 1157 it out all the time. A. Sure. Q. And we're going to be looking at -- this is number 13. And, again, and again, you can turn it up, sir, if you want, I'm not certain if anything hinges on this. It's more of a general question and then we'll get down to the more particular question. But all I want to understand is that EnCana used something called a "perforation inflow diagnostic method" for measuring reservoir pressure, and I want to know, (a), why was this method used -- so we can start with that? A. Sure. So I guess because of the nature of the reservoir that we have, it's a very tight reservoir. And it's, it's stacked. There's lots of flow units in it. Conventional pressure transient analysis doesn't work. You're getting a combined effect from all of the zones plus it's an extremely tight reservoir. So the time to reach stabilization is incredibly long. So we haven't found that conventional pressure transient analysis is useful for all of those effects. So what we've done, in order to get some sense around reservoir pressures at local conditions is to go into a, a perforation inflow performance. And it's really a limited, a limited pressure response, so it's based upon a limited perf. And it's

26 1158 just the pressure response after completion. So it's not a full-blown build-up. But you do get the sense around what the pressure is and how it's building up. Maybe if I can just take this opportunity to talk a little bit about our, our shallow gas model and I think that might inform the subsequent discussions; is that okay? Q. Please do, sir. A. So if you, if you, if you take a look at our model, shallow gas, there's lots of -- a lot of reserves are, are -- the nature of shallow gas is that there's a lot of reserves in the ground, it's a very thick reservoir. It's got a lot of gas in place. But it's very tight. The permeabilities are extremely tight. And so the key to getting that gas out is really contacting that gas. So if I can reference -- ask, ask you to reference that geological package, And if I could ask you to go to the core photographs at the end. Let's start off with the C-2 pilot. So it's, it's the, it's the page that has a log, an open hole log, core photographs, as well as permeability measurements. Q. I'm with you in spirit, sir. A. It's not the right number?

27 1159 THE CHAIRMAN: We can't seem to find that, Mr. L'Henaff. Perhaps you could check on your reference. MR. MOUSSEAU: I might have a better reference for you, sir, and I think it's JRP9. Could that be -- A. JRP9 is one of the, is one of the core plots. But we submitted all four. Q. You submitted all of them? A. Yes. Just one second and I'll -- Q. Can we go off 9 and -- UNIDENTIFIED SPEAKER: It's 107. A. 107? UNIDENTIFIED SPEAKER: Yes. A Q. Okay. A. I apologize for that. Yes, that's it. Yes, keep going. Those are the, the maps, the structure maps and the isopaches. Okay, there. So we can go to the C2-1, which is the 4 of 7, so that's, that's the one there. So at the bottom -- so what you have here is, on the left-hand side of the screen, an open hole log. In the middle of the page is core photographs with some rock parameters to them. And on the right-hand

28 1160 side of the page is permeability measurements using perineometer data. Q. Okay, sir, just hang on a second. I just want to make sure the Panel is, is with us. THE CHAIRMAN: We have it. MR. MOUSSEAU: Q. Okay. A. Oh, so if we could take a look at the C-2 pilot. Okay. So in the C-2 pilot, so it's, it's to the west of the NWA and it's to the southern part of the block. In this pilot, you can see -- so if we start down at the Second White Specks so, so you can see a core photograph of the Second White Specks. And this is a tight reservoir as well. But you can see in the core photograph that there is distinct layering and you can usually see the bedding plains in the, in the Second White Specks. So it is the better zone of the three zones. And you can tell that from the look of it. And if you take a look, there's permeability data that is identified on the various sections of the core photographs. So on the left-hand side one, it's millidarcies. So extremely tight rock. The one next to it is Then just up above, Just up above that, 2.08.

29 1161 So you can see the permeabilities are extremely low and yet on the Second White Specks you can see the interbedding. If you go up on the top of the photograph is the Milk River. So the Milk River is a thicker package, so up to 100 metres, but you can see that the bedding is pretty much destroyed. So it's really a tight reservoir, a lot of heterogeneity, very poor rock quality. So you can see the permeabilities ranging from at the bottom of that first slide, 0.8 millidarcies, then up to a 0.48, then up to a So within a very small area, you can see quite a variation in, in permeability. So large differences in permeability across very small layers. And, really, what we're seeing -- so if you take a look at the permeability plots, you can see that the silt stringers are the ones that are showing the better permeabilities. So the ones above 1 millidarcy, above 10. So there's silt stringers that are interspersed throughout this rock, and those are the, are the pieces of the reservoir that form the flow units. So they are very fine, very discontinuous, but they are spread out throughout the rock, and the

30 1162 rock itself contains the reserves. So these flow -- these silt stringers are the ones that basically allow the gas to flow in. So when you're taking a reservoir pressure across an interval that's opened quite large and often has a frac to it, you're getting a combined result. So, really, in order, in order to get a proper pressure of that piece of the rock, we basically go in and do a point by point as best we can. So it's because of the nature of this rock that you can see that the silt stringers are the major flow mechanisms, but it's their discontinuity that doesn't allow you to have a very large drainage radius, so it's really the, the infill wells that allow you to contact more of the rock that's really not being connected up by these silt stringers. Q. Okay, sir, and that, that's helpful. And what led to, what led into that discussion I think was the discussion of the PID method for measuring reservoir pressures. And I think I understand now why that method was used. If you could comment on the accuracy of pressure methods using that method. A. So the pressures that we gain from the PID approach aren't true reservoir pressures. They are -- the formation isn't allowed to build up sufficiently.

31 1163 It's really just a portion of a curve. So, really, all we're seeing -- and in one of the JRP IRs we've indicated some of our PID measurements. So all we're really seeing is kind of the pressure of that little piece of rock and how it's reacting to building up pressure. So we can get an indication around how many flow units we have in that portion of the rock and to what degree the flow unit is actually producing. So it's a conduit of production. So it's basically a level of production in the flow unit. If we happen to hit a storage unit, we get some indication around the amount of pressure, the amount of energy that's still in that storage unit. So it's a bit of a qualitative analysis, but we get a better, I'd say, detailed analysis of our rock and of our reservoir. So we get a better sense around our conceptual model. So it's an integral part of our conceptual model. Q. Sir, we're going to stick with the same exhibit, and so we're still on JRP 13, we're going to turn to page 2, which shows the D6/D8 pilot PID pressures. And all the reservoir pressure measurements gathered for the Milk River were below 3300 kpa and one was as low as 1,050 kpa. Were the pressure measurements

32 1164 taken on infill wells? A. In this particular example, the pressure measurements were, were taken on a series of wells, so, yes, infill wells. The D6/D8, so if you still had the previous example opened, the D6/D8 plot would show you that there's a better spread of permeability at the lower end of the Milk River. So we have more of the rock that's basically working in a silt stone, a silt stone flow unit, so it's a better connection of a flow unit at the lower part of the, of the reservoir. At the upper part of the reservoir, very small amount of silts in there, and so there is -- that part of the reservoir would be more indicative of the storage units. And so you'll see that the pressures higher up in the reservoir, in, in the log, is basically the higher pressures closer to virgin reservoir pressures. So it's a consistent, it's a consistent analysis from what we see at the core and at the log level. Q. Okay, just -- those little silent moments are us eliminating questions, sir, so don't think it's time being wasted. We're going to JRP 12 now, sir. I'm going to

33 1165 read you a quote from the first paragraph where EnCana states there is -- I'll let you get there, but I -- A. I'm there. Q. Okay. So EnCana states: "There's some interference between high permeability streaks and stringers between wells..." Now -- "... when referring to additional wells drilled within the pilot areas." Sorry. Now, with that in mind, can you comment on how much of the stated incremental recovery in all the pilot production forecasts is actually accelerated production related to these higher permeability streaks and stringers? A. So our, so our analysis that we've submitted in on the JRP7 was basically what we believe as the incremental, so the analysis that we're seeing there is incremental. The acceleration effects that we were talking about, although they should be present and you see them through the pressures, and, and so -- and I think you also see them from diminishing recovery levels.

34 1166 If you take a look at subsequent infill drilling, so going from 4s to 8s, the wells on average will recover more. And as you get further down, the recovery becomes less and less. So from a, from a real sense, you're seeing kind of a diminishing return on the recovery level. And so that's a real effect that you see. And you see the real effect by taking the PIDs. So when you're seeing -- your tapping into a flow mechanism, you're seeing that it is connected in some degree. Now that level of connectivity will be quite restricted because it's the -- it's basically the flow path that the rock, the storage rock is feeding it. And so it's the storage rock that's basically replenishing the flow path. But you do see some interference between subsequent phases. Our analysis, however, is -- just looks at the incremental difference, so we're really only looking at the difference in the infill wells, so what we believe to be the new production. So although we see interference at the pressure level, at the PID level, and although we see interference at the diminishing returns level, as we subsequently drill in more, we have not seen it through a decline curve yet. It, it doesn't make

35 1167 sense that you would see it, either, at this early juncture. A reservoir effect with this tight, tight of rock, would take quite a while to reach from one well to the other, or to basically change the flow regime. So although we haven't seen it, we do not see it in the decline curves, we think that those are surface effects, either back-out issues, or new wells coming on. You should ultimately see it. And where you will see that is the decline curve will be modified, so its decline rate will be modified later on in its life. So if it has an upward curvature, it will have a slightly less upward curvature. But because of the technique that we used, we basically have assigned any acceleration effects to the Base production. So we're assuming that the Base production will recover all of the incremental reserves that we forecast for it, which is the 120 bcf that we had estimated. Whether or not it -- all of that 120 comes out of all of the existing wells is kind of a neither here nor there. We have assigned it to the Base. That production may well, or a portion of that production may well come out of some of the new wells, but that is not the incremental production that we've analyzed and that is not the incremental production

36 1168 that we are assigning to the new wells. On top of that, I guess I'll also I guess restate that the, the reserve estimates that we've tabled are a highly conservative number. They are very confident. We believe they are at the P-90, possibly the P-95 level. So, in essence, as those -- as more production becomes real and you walk yourselves towards the P-mean, those, those production or those reserve estimates will, will actually appreciate. And what, what they will appreciate to, we don't really know. When we got into the discussion with Mr. Binder about the re-analysis of D14/D16, the one, I believe it was the 143 number, is basically our estimate of a P-mean number. We don't want to table that number. We're tabling a P-90 number. And that's why we're basically sitting at the 70 or 80, 81. But, ultimately, these reserve numbers will appreciate. As we've seen through McDaniels, I mentioned the D6/D8, the same effects are going on in D14/D16. McDaniels' numbers started out with 50 at it was 70, 75 to 80 to 2007, 88 to 94. So, really, as the production informs you about the reservoir, the ability to table a conservative P-90 estimate will appreciate and it will

37 1169 move towards the P-mean number. We're seeing this with all of our project areas as we develop Suffield. The same effect is happening. And McDaniels is basically substantiating that with their reserve estimates. Q. Sir, and just to confirm, is it fair to say that EnCana didn't perform a pilot within or offsetting the NWA with well densities between 8 and 16 wells per section to evaluate optimal well spacing? A. That is correct. Q. Okay. Sir, we're going to jump all the way to JRP 8. And, sir, in the first paragraph, EnCana states: "EnCana's experience has been that reliance on data and information gathered from actual field pilots is the most appropriate and accurate guide for development decision." Now, in JRP 14, at point (b), EnCana indicates that: "Pilot studies serve as a basis for estimating the reserves and production profile for the additional wells proposed for the NWA drilling projects."

38 1170 My question is, if a pilot was not attempted at 10, 12 or 14 wells per section, how was a well density of 16 wells per section determined to be better than 10, 12 or 14? A. So as I understand your question, it's really talking about optimal spacing? Q. Exactly. A. Yes. And I suppose, you know, the answer falls kind of -- comes at it from a couple of angles. One is the physical constraints of the system. We're already developed at 8. And so to get at a well at an interior spot, which is really what you're trying to do is, is target that trapped gas -- I'll call it "trapped gas" because it's not connected with a series of silt stringers that can effectively deplete that. So you're really looking at infill locations. Because of the geometry of the situation, you already have 8 wells in there. You have to fit in an even number of wells to basically fill in all the gaps. So that wouldn't occur with 10 or 12. You'd have -- you would be forced with choosing which infill spot. And, effectively, what you would be doing is getting the exact same results as a 16 well per section at a local area. So because the 8 wells per section is already

39 1171 a set template, you effectively, at a practical level, can't do it at the field. You can do it through a simulation and through some kind of esoteric calculation but you practically can't do it at the field level. You are basically stuck with a 16 well per section or 40 acre infill spots. I guess the second point is -- so our estimate of what 16 wells per section is going to gain is a significant amount. We believe it's 125 bcf and that's our conservative number again. So we feel that all of those infill spots going up to 16s is, is certainly justifiable and is a significant amount of reserves to be recovered. On average 100 mms per well. So we feel we're certainly not at the diminishing returns or at the point where it's, it's very minimal returns. It's still significant returns on a per-well basis. Q. And maybe I misheard you, sir, but I thought what I heard you to say was if you had the time and the inclination you could actually maybe reduce that spacing and achieve the same recovery. Is that what you said? A. No. No, that's not what I'm saying. I'm saying that you could do that in a simulator. So if you didn't have the original inprint of the development that you

40 1172 have, you could do it in a simulator, but you can't do it in the field. In the field you're left with infill spots that are effectively 40 acres. So even if you chose only to drill one of them to try and emulate a 12-well per section or a 10-well per section, what you'd be doing is just drilling a 40-acre spot and you'd be leaving another 40-acre spot untapped. So, in effect, you would not be getting the field analysis of a 10-well or a 12-well per section density. Q. And, sir, it's my understanding that there's some sections within the NWA that are, that are currently at 4 wells per section. I take it again the same approach applies? A. Yes. And, again, the same approach. We feel that there's significant incremental reserves trapped in those 40 well spots, that, that those are worth going after. Q. Okay, sir, we're going to move to the submission you filed as part of your Opening Statement, which is Exhibit And we're going to look at Figure 3. A. I have it. Q. I'm just waiting for it to come up so everyone's on the same page. This may be a bit of a lawyer

41 1173 question, sir, but what I want to know is, in the pink sort of magenta squiggly line, what I want to know is what is being shown by this line on the plot. What data is it showing? A. The -- so my understanding of the pink line is a representation of the production from a 6-and-a-half well per section well density. So it would be a particular grouping of wells that represented that particular vintage of well density. Q. So maybe this will clarify it, is that a straight pink line drawn through the pink squiggle or is that a straight line going into a squiggle turning back into a straight line? A. I'm not sure I understood your question. Q. Well, if I look elsewhere in the document, you have parallel to it a black line going through the blue curve and you have the red line going through the green curve. I just want to understand, is that supposed to be one line that's interrupted or is it one line overlaying another line? A. Oh, okay. So if I understand your question -- Q. Really simple. A. -- what it is is the -- so on the left-hand side of the curves where there is a lot of variability in the line, that is the production history. So that is the

42 1174 real production results from those well groupings. The straight lines -- or the curved lines that are very smooth are really the extrapolation. So it's the analysis of the production history line. Q. And what time period was that forecast based on? A. These lines were generated out 40 years, 40 more years. So, in that regard, this plot is slightly different as well because it was a 40-year timeframe as a cut-off, and it was merely as a result of the software package that we were using. It was -- we turned this plot around in fairly quick order. Q. And so the tame -- same time -- sorry. So the same time period was used for the entire plot? A. Yes. Q. Okay. Sir, in EnCana's Opening Statement, or, sorry, no, this is in 124 again, paragraph 2 refers to operational factors that EnCana has an understanding of. And, sir, what I guess I'm wondering is, is it possible for EnCana to use this understanding to alter some operational fact, factors, including fracturing technology and infrastructure modifications to get 16 well per section recovery with density less than 16 wells per section? A. Yes. Q. Can you use that understanding to, to help you recover

43 1175 more? A. No, we can't. The understanding that we have when it comes to operational factors is really an optimization of the existing wells, so we're trying to contact more rock at the existing well level. And we believe that we've achieved an optimal frac program to target all of these flow and storage units. The reason that working on the existing wells won't result in effects at the infill spot really boils down to the silt stringers and the ability to reach out through these silt stringers and get the untapped reserves. These untapped reserves are sitting -- you know, this is tight gas and so the question is, you know, with, with tight gas, can you reach out 80 acres and get that? This is extremely tight gas. It -- we cannot. There is no way that it can happen. And so you're really looking at you need to contact that infill spot. This is substantiated with our simulation results. If you take a look at our simulation results, the, the numbers, the recovery numbers are certainly in support. You know, the numbers were 188. But even at 188 per well incremental recovery, even with those simulation results, the recovery levels were only at the 42 percent recovery factor.

44 1176 So -- and it's amaze -- basically it talks about the nature of the shallow gas reservoir. Inherently it's tight. Inherently there's going to be a lot of pockets that are going to be trapped. So even at 16 wells per section, we're at the 43 percent recovery factor. So, ultimately, this, this reservoir will have a lot of gas that will just remain trapped. Q. Okay, sir, if we can go to Figure 4 now in Exhibit And this question also relates to Figure 5. I'll ask it first. Can EnCana explain how it derived the blue pre-pilot lines for Figure 4 and 5? A. By taking a look at the production performance of the pre-infill wells, the pre-drilling wells. So you look at those declines independently and then later on the declines of the, of the wells of newer vintage and of the wells with newer frac results. So you would basically look at it from a vintage perspective. It's a classical vintage analysis. Q. Okay. And did EnCana account for any impact that the additional pilot wells may have had on the performance of the pre-pilot wells once the pilot commenced with the additional wells? A. As, as I indicated, it's through the analysis of those curves and, you know, we aren't really seeing

45 1177 deviation from the existing decline plots, so, so we're not seeing any interference effects. And, as I said, that kind of fits with our model, is that we wouldn't -- you wouldn't expect to see interference effects through these small silt layers. You wouldn't expect to see them on an, on an early time basis. Intrinsically, this is a tight reservoir. It will take a lot of time to get a production result from one well to the other. You basically have to, would have to reverse the flow of the, of the drainage pattern of all those little silt stringers and you'd have to overpower the replenishing effects of the storage rock. That would be impossible to do in a tight reservoir on a short-time scale. Q. Sir, just looking at Figure 5, I'm interested in what the black lines represent on Figure 5. A. I'll have to flip to the figure. Q. The magic of technology, sir. There it is. A. Oh, there you go. So the black lines are just an approximation of where that decline curve would be. So it's basically an analysis of that well grouping. Q. Okay. And this is the exponential decline? A. Yes. Those are, those are straight lines, so that's exponential. Q. Okay. Okay. And I take it in Figure 4 it was

46 1178 hyperbolic? A. Figure 4 would be the combined. Q. Oh, it's the combined? A. Yes. So you would take that analysis and then expand the scale and then fit that analysis on the larger scale. Q. And you may have answered this already, sir, but why, why the two different types of analysis? A. The exponential to the, to the... Q. Yes, Figure 4 is done one way, Figure 5 is done another way. A. Because, with this type of rock, exponential is a more appropriate analysis technique for the early time periods because you basically have the silt stringers acting as higher permeability streaks. They will deplete initially, but then the storage units will kick in and it will follow a more of a, a hyperbolic decline. So the appropriate technique on the early time period is to model that with exponential moving into our, basically our combined curve into hyperbolic. Q. Okay, sir, now, sticking with Figure 4, what I want to understand is what led to the increase in expected recovery in the pre-pilot plus three-well case, was it the additional wells or the refracturing?

47 1179 A. I'm not sure I understand your question. Could you repeat it. Q. Sure. So it looks like if you look at Figure 4, there's an increase recovery in the pre-pilot plot, and it seems to sort of happen almost at the same time. And I'm just wondering whether it can be attributed to the additional three wells or the, the refracturing, or both? A. So are you talking about the curvature of the line or are you talking about some of the higher production spikes? Q. I'm told the curvature, sir. A. So the curvature would be indicative of basically that, that depletion going out into the reservoir, so you, so you would be in the transition period between an exponential and a, and a hyperbolic. So you would expect to see that creeping up. You know, coupled, coupled with the fact that, you know, every time we present these curves to senior management or to, to this Panel, we are always presenting a 90 percent probability. So inherent in the 90 percent probability is, every time you do an update, likely as not, your estimates will creep up, they will be moving up towards the P-mean. Q. And just sort of a follow-up on that, is there a way

48 1180 to quantify the relative contribution of the addition of the wells in the refracturing to the increased recovery? A. Yes. The way that you would quantify it would be, based upon the extrapolation of those two different trends, and then looking at the difference of those extrapolations. Q. Sir, if we can turn to page 1 of this same exhibit, so We're going to the fifth paragraph. And I don't want to plough over ground that you went over with Mr. Binder, but we're still wondering if you could again explain the difference between the 88 mcf incremental recovery versus the 81 mcf incremental recovery, the difference between these two numbers. A. Sure. Q. It's still not entirely clear for us. A. So the 88 was taking a look at the ring. The 81 is a P-90 estimate for the interior. What's presented on the plot is a P-mean, which works out to the 143. You know, I guess from an impact perspective, the 88 is close to the 81. Whether you believe the ring is as representative, and whether or not you believe the ring or the 88 is at the P-90 is really, you know, the judgment call. We're talking about basically 7 mms per well.