EOG
#Yes, <UNK>, this is <UNK> <UNK>.
Certainly to each one of our tests we've learned a lot.
I would say that without hesitation that all of our pilot tests were successful.
Certainly we continue to learn from each one.
We started the project really with some laboratory experiments on just trying to understand what the fluid behaviors would be.
And that certainly was very encouraging.
Then we rolled it out to a single well pilot and had positive results from that.
And then we started applying it to more multi-well pilots.
We had two full well pilots and a six well pilot.
And each one of those was successful.
So the next step, as we discussed, is to roll it out on more of a field scale model, which is a 32 well pilot.
And we will certainly continue to learn from that.
But yes, each one was very successful.
Yes, <UNK>.
As you know, we believe we have very sustainable cost reduction and technology gains.
We have done it every year we have been in the business.
And we have a lot of confidence and we see a lot of upside going forward to continue that process.
So as we increase productivity through being able to identify better rock and precision targeting and get even better with our high density frac techniques, we believe that the well productivity will continue to increase.
That would be one way to convert.
And then we also believe that we have sustainable cost reduction.
So two-thirds of our cost reductions during the downturn have been through technology and efficiency gains.
And we do not see any end in that.
And so we are quite confident that efficiency and technology will continue to drive those costs down.
So we believe a large percentage of the inventory that we have in the Eagle Ford will be converted to premium.
We also believe that in the Permian and we believe we will add continued premium in the Bakken and other plays too.
So we are very confident that our premium inventory but grow much faster than our drilling pace.
Yes, <UNK>, this is <UNK> <UNK>.
We've ---+ typically the governing part will mainly be ---+ and actual field applications will be on how we develop each pattern.
So as <UNK> mentioned earlier, the primary goal will be to go through and do a full-scale development on each and every lease with the latest high density completions.
That's the number one goal.
And the pace of development from that will dictate as to when we roll out the secondary or the EOR process.
But typically as we ---+ I think we have a slide in the deck on I think slide 4 that shows that timeframe will be somewhere in the first two to five years.
So I think that will probably be our initial guide.
There's no detriment that we see as to if you wait too long to implement it, it's going to be detrimental.
We think it is a great tool for just continuing to contact the remaining oil left in the reservoir.
Certainly economically there might be an advantage to doing it earlier than later.
But more importantly, the advanced completions are driving probably incrementally more success to start with.
So I don't know if that helps to answers your question but I would say that it will be somewhere in that first couple of years ---+ two to three years of developing.
The Eagle Ford is ---+ as we mentioned in the call, the primary ---+ one of the primary factors in the Eagle Ford success is the vertical containment.
The Eagle Ford is very well incased and has good strong barriers for both upward and downward growth, which is key for the process.
The Bakken and many other plays are going to be more challenged in that area.
That's probably the key primary difference that I would say lends the success more readily to the Eagle Ford than maybe other plays.
We have no desire or intention to consistently out spend.
So the number one goal this year is to balance our discretionary cash flow with CapEx and then, of course, we are working on property sales to help us ---+ prices continue to firm.
We have a lot of confidence that we are on the road to accomplishing that.
We do believe that because we are seeing significant cost savings in the current drilling, we think that is going to continue.
And any extra capital that we would have from cost savings, we will apply to completing new wells.
And that will be ---+ we're going to be disciplined.
We are certainly watching the market to make sure that we are not in a temporary uptick on prices, that the prices are more sustainable.
But when we feel good about that, we will apply those cost savings to completing additional DUCs later in the year ---+ most likely in the fourth quarter.
We want to enter 2017 on a growth mode in an uptick.
So we believe that we will be ---+ we will have the capital to do that.
Yes, we have a very robust exploration effort on new plays.
So we have various plays ---+ actually we will be testing this year.
We will see ---+ update you that when we have some meaningful results.
And then we're also picking up acreage.
It has been a great time to pick up low-cost acreage in places that we couldn't get acreage in the previous years.
So we have an active program going on.
Of course, we are very selective.
We only want premium plays to fit into our capital program.
So we are trying ---+ we're identifying rock that would meet that category and deliver those kinds of returns.
So we're not short changing that effort at all.
<UNK>, this is <UNK>.
On the chalk, we drilled these two wells.
We have taken a couple cores here and we've got quite a bit of log dated to go with that.
So we have really kind of mapped out the play and we are feeling pretty confident that we can move this play into the premium category and have a meaningful impact to EOG.
So we're going to go ahead and test, like a mentioned in my remarks, we will test another seven wells this year to kind of delineate the play.
And then, like I said, we will go ahead and move that into the premium [in-store] account.
And so it will be developed along with the Eagle Ford.
Yes, <UNK>, this is <UNK>.
The second part of your question to the extent of the acreage that might be applicable to this, honestly we just don't know at this point.
We do know that there are some areas that probably will be challenged to work economically.
We ---+ but we are still early on in that process and trying to determine how much of the acreage is applicable.
We just don't know yet.
Now the 32 well pattern is probably a good indication and maybe what we will look at in the future.
Will be subsets of ---+ or leases that will dictate the size of how we develop it going forward.
So maybe you guys think about it ---+ instead of a single well it will be groups of wells that will be implemented at one time and not single wells.
So we've kind of given you some guidelines of what we think the capital cost is.
And we tried to boil that down to a single well just so you can kind of think about it and knowing that each lease will have different counts of wells ---+ maybe 12 to 20 wells on any given lease.
And then the production profile we have kind of given a [cueme] curve out there that maybe give you some insights on what the cueme curves might look like.
The production response from this is pretty unique in the sense of secondary recovery projects in that it is probably the only process that gives you such a rapid production response.
You get a response in the first three months essentially, which is pretty fast.
And then it holds pretty steady for a number of years.
And so that maybe ---+ and so that is probably about as much detail on the ---+ on how we see the ---+ how it would be rolled out.
Again, the pace of development ---+ I know this is tough to model economically.
The pace of development is purely just going to be on the things we learned from this next pilot.
And then our development of existing units, we've used our high density completions.
So we de expect to increase the ---+ I would say we expect to increase the number of wells each year as we rollout the new budgets.
And it will become an ever-increasing part of San Antonio's capital allocation.
Yes, <UNK>.
This is <UNK> again.
You're exactly right.
I think that's a part of it.
First of all, we're early in the process.
So you have to remember that our forecast start out with trying to model ---+ trying to use simulation models to match our history from the pilot projects and then forecast what the future production might be from these.
So we haven't actually seen long-term production from a pilot.
Over the number of years it would take to demonstrate what the ultimate recovery is going to be, we're trying to model that with some simulation techniques.
I would say that our challenge technically ---+ so we're working on some enhance models to better understand what the long-term production will actually be.
So I think we just need further clarification and tests from existing pilots that were ---+ and future pilots to really nail that down.
And then you're right.
I think the vintage of the completions so ---+ will make a big difference.
The new high density completions, we expect, will respond better than some of the completions done several years ago.
Our pilot projects to date have been older style completion in large part.
So we expect improvements to continue to improve.
I think there is upside there.
Yes, <UNK>.
This is <UNK>.
I think you are on the right path there.
What we've learned is here where we're playing the chalk is the oil is stored a bit different than has been in kind of the previous history of the play.
And what that does is it allows it to be a bit more predictable.
And also allows us to employ our completion techniques.
And so I think going forward it is just going to give is a little more certainty on drilling repeatable high-quality wells.
<UNK>, I would like to add to that too to kind of expand on what <UNK> said.
I think that same kind of techniques that we're finding very successful in these other plays, by identifying their very sweet spots, the very best rock quality with our proprietary techniques and then being able to keep that bit at a very small zone in conjunction with the high density frac, that's really the key to all of these plays.
And it's no different from the chalk.
So we're just finding that we can identify a quality pay in the chalk and we are very encouraged about that.
You know, <UNK>, right now at this point we're not going to give you a lot of detail around the process itself or how we're implementing it.
But we will say that it is a missable process.
And so you can read into that what you might.
But we're not really giving a lot of specific details about how we're doing that or the interaction between wells or those kinds of things.
No, it's definitely not that process.
Again, were not going to give a lot of details on how much gas we are injecting.
But the important thing there is that ---+ two things I guess.
One, is that we have gas readily available in the field.
And then two, with our large footprint there in the facilities and infrastructure that we been able to put in place for our field really enhances our ability to move the gas around and get it to these leases to take advantage of this EOR process.
It really helps position EOG uniquely to be able to take advantage of something like this.
We'll it will be ---+ we're reporting production on a lease basis as we're required to do under the Railroad Commission rules.
And certainly over time there may be some things you can gleam from that data.
We'll see.
Honestly, I haven't checked a lot of that dated to see what it looks like versus what we see internally.
But I think over time you'll be able to discern what the actual results are.
And I would expect that data will become apparent in the future.
Yes, <UNK>.
We would ---+ we hold Austin Chalk with our Eagle Ford production.
So, yes.
It's right above the Eagle Ford.
And the second part of your question was.
As you know, there in the Eagle Ford, acreage is held pretty tight.
So at this point we're not leasing anything new on the Austin.
Yes, <UNK>.
I think that's right.
I think the overall benefit in the long-term is, yes, it will help flatten the decline ---+ the long life decline from the field.
We still haven't been able to quantify that yet.
But we're certainly very optimistic that it will certainly be very meaningful to not only the individual leases but the field in general.
<UNK>, this is <UNK> <UNK>.
As far as the potential on our acreage, we are encouraged because we see data, rock data and test data on various parts of our acreage that are encouraging.
And so we have seven wells, additional wells, additional to the two we've already drilled that we have planned this year that we will be testing some of these concepts.
And so once we get those done and we get some results that confirm the production like we have seen, then we will be able to, I think, give people an update that will be more meaningful on what the scope could be.
And then on the technical side of it ---+ let me let <UNK> kind of update you on that part of the question.
Like I mentioned before, we have collected a substantial amount of data.
Pretty much all the Eagle Ford wells that we've drilled have drilled down through the chalk.
So we have a very good set of log data, seismic data and, like I mentioned before, core data to delineate this.
So that's what gives us confidence.
And as well, there has been other industry wells drilled.
Some of the larger operators have not necessarily drilled very good wells.
But some of the smaller operators have drilled some really good wells along this trend.
Some of them have [cuemed] 300,000 to 400,000 barrels of oil in the first year.
So these are substantial wells.
And like I mentioned before, based on the data we have, we think they are very repeatable.
<UNK>, the technical advantages from a competitive standpoint are our ---+ I think our ability to recognize these pay zones.
And then target those pay zones.
That is ---+ it's what we've learned on the other plays is applying to the Austin Chalk.
So we're just taking this targeting ---+ precision targeting a step further to the chalk.
And we think that's very proprietary knowledge at this point.
Yes.
This is <UNK> <UNK>, <UNK>.
And what we've shared before is we're just going to be completing roughly 270 wells this year ---+ drilling about 200.
So we will be completing roughly 70 of our DUCs.
And we're just ---+ as <UNK> said, we've got these in inventory.
When we see prices improved, when we have additional capital, this will be just a source of assets that we can develop rapidly to bring on production when it is justified.
Yes, <UNK>, we've certainly taken a look at a lot of different pricing scenarios.
But we've looked at it in the sense of what we are currently modeling and also incrementally up to $5 gas prices.
And we still see incremental benefit and good economics even up to those levels.
So our economic sensitivity is not really a factor of what we think gas prices could be anywhere in the near future.
So I think it's going to be ---+ continue to be ---+ it will continue to be economic, even at what we see could be a foreseeable gas price in the future.
Good morning, <UNK>.
This is <UNK>.
We have 11 rigs under contract currently.
And that will declined to 9 at the end of the year.
So we will really average about 9 because we started with 15 rigs there in January.
And then next year I will start with 8 and that will declined to 4 so we will average about 5.5 rigs in 2017.
So, yes, we will have some DUCs but we will have quite a number of wells that we will be able to drill.
And we've got quite a few of these patterns we would like to further develop.
So we will maintain certainly more than 5.5 rigs in 2017.
The first ---+ that's a long question there.
As far as the premium DUCs, roughly 100 of the DUCs are in the Eagle Ford.
Most all of those are going to be premium.
We've got some there in the Permian Basin, they will also be premium.
The neat thing here is when you look at it on a finding cost basis, our new drilling is roughly $10 a barrel ---+ barrel oil equivalent.
And when you look at the DUCs and having already spent the dollars to drill, it's probably in the $7 range.
So those all look pretty darn good.
And as far as on our Eagle Ford and what wells have the modern completion to fit with EOR, by the time we get these patterns developed, a large portion ---+ the majority of our wells will have the more modern completion.
So that is what <UNK> and <UNK> are talking about now and just mentioning, yes, we want to go ahead and further develop these.
Because we're still working on our spacing and we need to get our spacing down there in the Eagle Ford.
So with that, the vast majority of the wells will have modern completion ---+ very fitting for EOR.
Yes, in closing, the first thing I would like to say is that we are extremely proud of all of the EOG employees.
They're doing an incredible job this year of resetting EOG to be successful in lower price environment.
The second thought I will leave you with is that EOG continues to focus on long-term value creation by making sure that every dollar we invested today is making a strong return.
And [growth] should be a product of making great returns.
So because of the tremendous technology and efficiency gains, the Company has the ability to make strong returns in the $40 oil environment.
And this uniquely positioned EOG to continue its leadership in high return US oil growth as prices improve.
Thanks for listening at thanks for your support.
