Thanks, everybody. My name is Salem. You may not have heard that name
before, so you've heard it now and you can remember it. I was going to give a
shout out actually, when I was sitting over here earlier today, to Joe
Brevetti, because he said, for new technology, get ahead of the thundering
herd, but the Joe Brevetti, I think, I went out with some of the thundering
herd. So he missed out on the shout out to him, so I apologize to that. But I
did want to do that.
We are a company that alters wettability. We alter wettability in primary,
secondary, and tertiary recovery. We do that in primary, we do that in
unconventionals. In secondary and tertiary, we do that in conventionals--
sandstones, carbonates. We're able to alter wettability by the use of salinity,
so no chemicals. So when Susan talks a little bit about what we're trying to do
here at AAPG, and introduce new technologies that can enhance old fields, do
old wells, maybe give you marginal better returns on new existing drilling off
of the lower-tier type prospects, that's what we do. Today's a quick little
presentation about how we used analytics to get to where we are today.
So we're going to go over how we started-- failures and field cases We were
born from failure. Wettability-- really what it is and how we see it. Some
screening criteria-- so now, we understand why it works and why it doesn't
work, and where it can work and where it can't work. That's pretty good.
Screening results and how they look-- where the best candidates are all over
the world-- we know where those are now-- and then some questions as we'll do
in the panel.
So how do we start with this? We started this with failure. Our CTO was
hired from the Enhanced Oil Recovery Institute in Laramie to prove that
wettability alteration using, at that time, low-sal could work in the Minol
USA. They spent a few years, lots of money-- complete failure. Well, that's
sometimes where ingenuity and inventions are born is in failure. It bothered
him so much, eventually, he left there, and he started his own business to
figure out why it didn't work. Because it worked in the North Slope with BP for
15% OIP recovery. It worked in ConocoPhillips. IT worked in Shell Syria. Saudi
Aramco's done it before. Then it failed at Statoil. And then if you start looking
at all the lab cases, more and more failures.
So we started thinking, maybe we're missing the boat here. Maybe we're
looking at the wrong things. We're using assumptions of the past. So I'm going
to erase all the assumptions of wettability is, wettability isn't, and how we
can alter it. And I'm just going to look at all the case studies in this, map
them out. I'm going to take empirical data and see if something leaps out. So
he went and took about 150-- took a whole year of his life off with no pay-- I
get reminded of that a lot-- and mapped every case example there was, and said,
wow, here's water wet to oil wet on the left diagram here. Here's all these
And then you have residual oil saturation. As the saturation goes lower, we
say, well, you're going to get more oil out, because at the end of your
waterflood, if your residual oil saturation's low, then it came out, right?
It's no longer in the rock. And what you see is you start seeing it's not water
wet or oil well that's going to give you more oil out. It's actually neutral
wettability, right in the middle. So that was kind of like an aha moment. And
so we started going, OK, maybe neutral wettability. Maybe there's something
there. Maybe water wet isn't the best to be in your formation. Maybe it's
And we flipped that curve around and we said, there's an optimal
wettability. Because if you're oil wet, what happens? Strong adhesion to the
rock. You're not going anywhere. If you're water wet, you have blocking your
pore throats. The oil's is never getting out, if you're highly water wet. So
you want to be somewhere in the middle. You want oil and water to move equally
together, and that's you're going to get the most drainage out of your field
and then most production out seems pretty simple actually.
So we take that and we say, well, is there a way to engineer salinity?
Because it used to be called low-sal. That's a sledgehammer. That was to go all
the way water wet is possible. Yes, there is a way. And what we were doing is
we were missing this sweet spot, the sweet spot in the middle of optimal
salinity. If you were water wet, you actually just maybe want to shift a little
bit-- not too much. If you're oil wet, you might want to raise your salinity a
little bit, we realized. And now, we started to say, OK, does this work? Let's
go back to empirical data again. Can this work what lends to these things?
So I made a feature about four things. There's 15 different parameters, we
realized, that actually affect wettability, and I'm going to go over four.
Water chemistry's able to change. Your water chemistry has to be able to
change. That's pretty simple. We're talking about water and we're talking about
salinity you have to be able to change that. Rock with surface adhesion sites--
what does that mean? I'll talk about that shortly. Oil with sufficient polar
components because the oil's sticking to the rock, has a relationship between
the oil, the water, and the rock-- not just one or the other. And then
favorable reservoir conditions for conventional fields-- you want to have some
sort of ability to waterflood it, because you have to be able to contact all
So on rock surfaces-- this is a sandstone. Started mapping up the
relationship. This is empirical data again. The more clay you had, the more
recovery you got. So those are those adhesion sites. So we started to say, OK,
this is a factor. Let's add it to our algorithm. The next one, oil-- we
realized oil needs to have acids, bases, and sulfurs-- quite a bit of them. We
had to have polar components, because that's the sticky parts. So we added that
in. And then fields good for waterflood-- you see this. It's a little
confusing. But really, what we were looking at was fields with lots of oil in
place and had good recovery factors, because that means you could actually get
to even more the oil that was still there.
So we started tying all those up, and what does that mean to us? We took
that, and we started putting together an analytical screening tool. Because
it's great to say to somebody, you can shift wettability in your field. The
standard model said it took you four to six years of a project and a couple
million dollars. And then you worked or you didn't work. That's what happened
in the Minol USA. We want to be able to predict it before you go and do your
project, so we put together all these different parameters, the 15 different
parameters-- we have rock, water, oil field inside there, quite a few more--
and that comes out to a score-- 0 to 100, 100 being really great. Never seen
that, of course.
In the figure over on the right-hand side, there's is actual data from the
Wolfcamp. So if anybody's in the Wolfcamp, this is one of our customers'
sanitized data of some areas and acreage that they had. So it does work. Below
that, we said, hey, we're going to be great if you want to buy fields, or if
you want to divest from fields, or if you want to see if your acreage is good,
because wettability alteration will be the next big thing? So we started
applying this to large swaths of acreage. We can apply the same algorithm over
and over to all the acreage, x, y, and z, straight down for your formation and
your acreage. And it can give you a score and a map associated with that. And
we're currently doing that with all the major formations in the US.
A screening tool's only as good as validation. So what we do is we've take
in all the public data we get. We keep putting it back in the screening tool.
We have laboratory testing, which we use a modified flotation test, old mining
test. We've been basically back and forth all year to the core barns and
getting oil samples from our customers and rock samples, and we go through our
laboratory experiments and we shift wettability in the lab, and then we go back
in to our screening tool. And it works.
And now, we have field tests, and we take the data from the field test, and
see if we got what we predicted to get in the fields. Update the model, and
then that model continues on. So the benefits-- this is the last little part of
it-- make it nice and quick-- the benefits of analytics and what happened with
what ability alteration. Your project time used to be four to six years. We can
do a project with a customer-- we're doing that now with quite a few
customers-- Gulf, unconventional, conventional, 9 to 15 months from the time we
signed the contract to the time you're putting in the field.
And you may see results between three and six months after that. So it's not
a four-year project anymore. We can screen all the candidates in all your
fields before you even start, and we can do that in a couple of weeks. So you
know all your acreage, what works and doesn't work in your project in a couple
weeks, pretty simply, and for a low investment. And that's a very low
expenditure early on to reduce risk in your project.
We also have drafts we've been able to lower your overall total costs of
that $4 million maybe or even more-- at least 10 times over. I say 10 times.
That's actually not quite right. It's even less. We do this very, very inexpensively
because of the analytical tool that we have. And lastly, we can multiply we can
evaluate multiple fields all at the same time. So it's not just one after
another in a linear progression. We can do all your properties. And we believe
that it significantly improves that opportunity for success of altering
wettability using salinity in your fields. And that's what we've done. So thank
you for your time. Appreciate it.
Thanks. On the E-Sal, I guess you all do more lab works in some of those. I
know you have an analytics approach. Where do you get your data?
So that's a great question. Thank you. First off, on the first part of the
data, we just scour through public records, or work with our customers to get
their actual data-- XRD data, water samples, everything along those lines.
After that, we actually do have a laboratory process, and analytical process,
in the laboratory where we take actual oil water and cuttings is all we need.
We can use core, as well, but sometimes core's not available for a lot of older
formations or a lot of older wells. And we put that through our laboratory
process with a modified flotation test.
What that does is that give us actually real-world-- we take that and we put
it through a myriad of salinities, and we actually adjust and watch wettability
shift in the lab. We can do that in just a few weeks with our lab processes. If
you're ever curious about that, there's an entire dissertation written on that
lab process that we've helped with. And we have all of those information on our
web page. So we do have papers. And if you're curious about wettability in
general, visit our web page, because we are transferring quite a bit of public
knowledge and publications onto our web page for anybody that's curious about
wettability in the future, how to alter it, and the testing associated with it.
Question for Salem-- so how much does it cost per well?
We have a couple of different cost models, depending on the size of the
operator. So if you're a mom and pop shop or maybe a equity-backed-- private
equity-backed operator that needed low cash values, we can do something like--
I'm not going to give an exact figure, but I'll say it's in the thousands of
dollars per well, as long as we can share in some back end information, and
potentially some back end production. We'll incur quite a bit of risk, along
with the operators. We don't believe there's much risk, so we're able to do
The larger operators that we're working with, we tend to up the price-- one,
because they can't afford it, but also, they don't like to deal with any back
end sharing. So they just like to pay upfront, and that's fine, but it's still
very low. One of our operators that we're working with in unconventionals, they
were using surfactants per well at $250,000 dollars per well, which is actually
cheap, we found out. That's because they're quite large, and they had a good
volume discount. Our process with them is 1/5 of that.
It's 50,000 rather than 30.
And we're looking at triple or a double-digit recovery with each one of
those wells now. So the profit margin for them is just huge.
Thank you, guys, for taking time to be able to do this for us. They're all
good presentations. I have a question for Salem on-- you do these on existing
waterfloods? Does salinity change, or I guess it's better to it out on the
front end of a waterflood?
Great question. It's better on the front end. We do do it on existing
waterfloods. If you've already had a waterflood done, we can look at the
performance your waterflood, find out what you did before, and see if there's
any leverage. We do that really simply. So if you've already waterflooded a
candidate and you didn't get the performance you wanted, I would really suggest
that you talk to us.
Most likely, it's because you used the wrong water. I believe that in
conventional and unconventional drilling-- or at least unconventional drilling
and all conventionals, as far as waterflooding, we've done these wrong for
years and years and years. Just used the wrong water by maybe 10,000 TDS. And
that's all it takes sometimes. It's a small shift in TDS, and you can get a
huge shift in wettability and a lot of recovery.