CHARLES STERNBACH: Well, it sure has been a day of discovery. So we're down to the last talk. And it's a great pleasure. I know we, Paul and I, for a long time, wanted to get something in North West Australia. We're delighted that Chevron has agreed to give this talk. Mike McLerie and David Sibley are going to do it together.
And North West Australia is back to the concept we talked about earlier about superbasins. It's another superbasin. So let's hear about the Greater Gorgon area. Mike, are you ready for us?
MIKE MCLERIE: Very good. Thank you.
CHARLES STERNBACH: Let's give him a welcome, please.
MIKE MCLERIE: Thank you, Charles, for the introduction. And thank you all this afternoon. And David and I, it's just a privilege, it's a privilege for us on behalf of Chevron to give an overview, a bit of a history of the Gorgon project, where we are today, but also some of the lessons learned and some of the insights we've gained over many years of exploration, appraisal, and, happy to say now, development and production.
The Greater Gorgon area is located off North West Australia. So basically, here. This is a picture of the Osprey, the Atwood Osprey. This is a drilling rig that drilled all the Gorgon development wells. It was specifically built for that purpose.
This is the obligatory cautionary statement.
And a bit about the overview today. I'm going to give a bit of a status on where we are now with the project, look at the history. Chevron has been part of the history of exploration in Western Australia for, really, several decades.
Then I'm going to look at Gorgon itself, the story from the early days to production. Then I'm going to hand over to David Sibley, and he's going to give us an overview of the applying new technologies and knowledge, what we've learned, how we've applied technology and new innovations to really understand and improve our exploration and appraisal performance. And then at the end, we will just discuss some of the insights, the learnings that we've made, and the observations over many years.
And I would like I say before we start that I really acknowledge a lot of people. David and I really feel privileged to give this presentation. There's literally hundreds and hundreds of people that have been involved in this story. And certainly, we want to recognize them.
First of all, gas is important. Gas is good. Gas is increasingly important to Chevron. You can see over the last five years that it's increasingly becoming a more part of our production stream. As of this year, it's just over 40%.
Chevron has globally over 160 TCF of [INAUDIBLE] gas resources, of which nearly half of that is located in the Asia Pacific Region. And of that, over 50 TCF is in Australia, so it's a very important part of our portfolio.
Also Australia with these projects, it's not only Gorgon and Wheatstone, but we have other projects that's coming on. And really Australia's moving out into a major LNG producer. I think it's going to be in the top of one or two LNG producers over the next couple of years.
Looking at the Gorgon area in a bit more detail, here's an inset of the map. We're about 1,200 kilometers north of Perth. Perth's population around two million people. And it is a major focus for any domestic gas from the Northwest Shelf and Gorgon Area.
Looking to the east first, this is a North West Shelf Project. It's a major LNG oil-producing facility that's been going since the mid-80s producing gas to markets in Asia, LNG. And Chevron was a foundation participant and still is in the joint venture. Woodside-operated, we joined Shell and Woodside in the early 1960s, and it's been a very successful joint venture.
Moving east is Barrow Island. This is the home of the Gorgon LNG Project where the plant is located. Chevron's been operating this oil field, Barrow Island, for several decades. And I'll be talking a bit of that history this morning as well.
Gorgon has two major foundation fields, the Gorgon field, which is located about 65 kilometers to the northwest of Barrow Island in about 200 meters of water. The other foundation field is the Jansz, the very large Jansz field out in the deep water. That's probably 135 kilometers from Barrow Island.
This area shown in blue represents the Gorgon Joint Venture Area. And a lot of this gas that's in here is really part of that project. The green is the Wheatstone field, the Wheatstone Discovery. This is tied to a platform along with a couple of other fields. And then there's a plot that basically brings it down to the Wheatstone LNG plant located on the mainland next to the town of Onslow.
Further out of the west, the yellow area represents our Exmouth Exploration Area where we partner with Shell. And here we've operated since the mid-2000-- about 2005. And again, we've had several successful gas discoveries in these areas. Very, very large areas as you can see, about just over 16,000 square kilometers.
Overall, Chevron's leading the investment and is operator of the two projects, Gorgon and Wheatstone LNG, which total is in excess of $80 billion on behalf of that joint venture partners. And certainly today we're going to be talking about some of the exploration success that we've had and some other insights and lessons that we've learned over these years.
Looking at Gorgon in a schematic cross-sectional view, out to the northwest, we see the Io-Jansz field, about 1,300 meters of water. Subsea ties back to a manifold and up into the Continental Shelf. Gorgon is Triassic fluvial sandstones, again, all subsea through these manifolds and up through the Barrow Island. Barrow Island, where we have the three LNG trains, we have a domestic gas plant.
And also what's innovative about the Gorgon Project, is we've got the CO2 Injection Project, which is a major capital project in it's own right where we string out-- we separate out the CO2, we liquefy it and then reinject it below Barrow Island into saline Jurassic reservoirs. Also we export the LNG. And we have it through LNG tankers that come into the east in part of the island, which is protected. And then we have a domestic gas line that goes and joins the main North West Shelf trunk line.
The participation in Gorgon, Chevron, we're operator with just under 50% equity. ExxonMobil and Shell with 25% equity. And then we have Osaka Gas, Tokyo Gas, and Chubu Electric who are our customers in Japan. So they've joined the upstream project.
One of the features about Gorgon is the great reservoirs we've got and the performance of the development wells. Here's a map showing Gorgon. We've got eight development wells here, ten development wells at the Io-Jansz field. And then Wheatstone just in comparison, we have nine development wells between the Wheatstone and Iago fields.
You can see the rates that we're expecting from each of these wells, now over 240 million standard cubic feet per day. So overall these are expected to deliver this capacity of 4 and 1/2 bcf a day. And we're looking at decades-long production at these high rates. These are fantastic wells here, large bore, seven-inch completions. Really expect to deliver high rates over a long period of time.
This is a photograph of Barrow Island looking east from the center of the island. We can see in the foreground the three LNG trains, domestic gas module, large gas turbine generators, the LNG tanks, and then the condensate tanks. And then in the distance, we see the Gorgon, the wharf, where all the supplies and all the modules have come in by, and also the LNG jetty that extends beyond two kilometers, so a very long jetty. And these LNG tankers will come in and takeout the LNG. Just for comparison, some of the statistics on this, all the subsea infrastructure is a significant amount of steel, over 230,000 tonnes of steel involved in the subsurface infrastructure, which is probably one of the largest subsea developments in the world. And I guess for equivalence, that's equivalent to, I believe it just over two Nimitz class of aircraft carriers in terms of the displacement weight, so a significant amount of steel.
All these modules were-- this is a modular design. All the modules were fabricated in fabrication yards in Asia, and then shipped to the island, and then basically hooked up. And using construction techniques, we're up to 7,000 construction workers. So the logistics involved with Barrow Island was certainly significant.
So where are we today? We're very happy to say that we've shifted 50 LNG cargoes. Trains 1 & 2 came online in 2016. The domestic gas facility was up and running, providing gas in December last year. And very happy to say last week, train 3 came online. So very, very pleased and delighted that now Gorgon is going.
So we've had an industry-leading success and with remaining portfolio to drill. We have a very good resource position. And we're looking forward to potential expansion opportunities. This is a photograph of one of the "L" of the ship on LNG ships. And we estimate that every year that 200 shipments will go to markets in Asia, China, and India.
So let's just step back, look at the history, where it all began. Besides our interest in North West Shelf with Woodside and Shell, Chevron and Texaco formed West Australian Petroleum in 1952, along with a company called Ampolex, which later ExxonMobil bought its interest, and were granted significant areas of exploration licenses in 1953. Fortunately, the very first well, one of the first wells, Rough Range, was drawn in 1953 in areas just to the south of Barrow Island onshore and actually found oil. So that was a very good start. However, it proved to be a very small oil discovery. And after that, all the exploration programs-- I believe WAPET, as it's affectionately known-- drew about 100 dry holes, so certainly a lot of investment very early on, but not a lot of success.
Access to Barrow Island was delayed until the early '60s due to some atomic testing in the islands just to the north of Barrow Island. However in 1962-- you see a small inset photograph here-- the very first seismic recording truck landed on Barrow Island by barge and acquired its first seismic liner, a refraction survey in 1963, which led to the exploration well Barrow Island drew in 1964, which encountered a significant oil find in Cretaceous sandstones.
The first oil development went ahead very quickly. And the first oil was in 1967. And you can see here in the production profile in years back from the '70s, it reached its peak just in the early '70s, around 45,000 barrels a day. And it's been on a steady decline ever since.
At the moment, we're producing just under 5,000 barrels a day. It is a significant resources. And it's still the largest oil field in onshore Australia, just over a billion barrels in place. And we've produced over 300 million barrels to date.
You can see on the satellite view here, you can see the extent of the Windalia field. And then right next to it, you can see the site of the LNG plant located here on the eastern part of the island and the LNG jetty extending out into the waters to the east of Barrow. In 1972, this map shows a acreage position for WAPET in 1972, a huge area of Western Australia. And you can see the scale here, 300 kilometers, just under a million square kilometers, so a huge area.
This is the Rough Range well, as I mentioned before, just to the south of Barrow Island. Barrow Island was discovered in 1964. And you can see the acreage position shows Gorgon within the bounds of the exploration permits. Dongara was discovered in 1966 by WAPET. And this ended up being the first commercial gas project in Western Australia, providing gas to residential and industrial customers in the greater Perth area.
So this map compares to our acreage position today, just over 16,000 square kilometers in the North West Carnarvon Basin. And certainly, we have a really good acreage position. And we're very pleased that the discoveries that we've had and the follow-up appraisal that we've undertaken over these years. 1970s, after that long period of, I guess, sparse, a lot of exploration wells that were drilled which were dry, and went into the '70s when we looked offshore.
A lot of disappointments, a number of wells have been drilled through our Island Drilling Program and through semisub, and a lot of disappointments. However, there were two very significant discoveries. The first one was North Rankin-1 in 1971, which drilled gas-bearing sands into fluvial sandstones. And this really was the discovery well for the North West Shelf project.
Second well was West Tryal Rocks number 1 drilled in 1973, again, fluvial gas found in the fluvial reservoirs or the West Tryal Rocks field. This is the very first greater Gorgon field that was discovered. A smaller discovery, Spar, in 1976 found gas in Cretaceous sandstones.
This is a seismic line through Gorgon 1 acquired in 1974. You're looking at three-kilometer offsets. So by today's standards, it's actually a very limited offset range. And on the map over here, we see the Spar field as I mention the seismic line. And this is the pre-drilled map for the Gorgon prospect.
The seismic, you can see the horse block shown here. The base [INAUDIBLE] shell, typically in those days we map the base of the regional seal. And the well actually penetrated this and penetrated over 500 meter of gross gas column in the Triassic Mungaroo sandstone. It's a great discovery, a lot larger then what was originally thought pre-drill. This is the same map as I just showed you. But this map here shows you the current-day Gorgon structure extent, the Gorgon field compared to the original prospect. So certainly, it's not a much larger field then was originally thought pre-drill.
Looking at the activities following the Gorgon 1 discovery commenced with an appraisal program. And over 17 years, seven appraisal wells were drilled. We acquired Seismic in-- 3D Seismic in 1971.
And one of the funny anecdotes, I remember going to the Gorgon project engineer and saying that we needed to get a 3D over Gorgon. And his response is dry as a bone. He looked at me, he says, why do we need 3D? We already know where it is. So we had a lot to do in terms of our value of information and promoting the use of technology to better characterize and define the extent of these fields. And you'll see through this presentation the value of 3D particularly with fluvial reservoirs is absolutely important to really get a correct characterization of the field.
We followed up with additional exploration blocks to the west of Gorgon. And that resulted in another significant well, Jansz-1 drilled by ExxonMobil. And then we followed up with a well called Io-1. And that sort of define was a discovery well, sort of the large Jansz, Io-Jansz sandstone Jurassic field that was now part of the Foundation project.
Followed up with a 3D seismic over Jansz, at just about under 3,000 square kilometers. And then we had another 3D survey in 2006. And then just last year, we completed the third 3D survey over Gorgon using ocean bottom node technology. And we're looking forward to seeing the results of that.
Following on from there this is a cross section view showing the Gorgon field. So there's Gorgon here. This is right up the horse block. You can see the subcropping large fluvial sands and amalgamated channel complexes sealed up by Jurassic and Cretaceous shales.
And you can see the large size of these columns and varying thicknesses of these fluvial sands. We got large thicknesses of basically amalgamated sand sequences here and certainly the M sand, the I sand, and then T sand at the base. But the Mungaroo is a large section, about two kilometers of fluvial sandstones interspersed with floodplain deposits.
But what happened after we acquired the 3D and we bid [INAUDIBLE] the appraisals at Gorgon. It was recognized that there's further structures to the north and west of Gorgon in the deeper water. And that followed up with the discoveries at the a Chrysoar oil field, which is located just to the north of Gorgon in 1994. And then right after that, the Dionysus field, another significant gas discovery. And that led to the acquisition and the permit award in 1997 of some large permit areas out to the West, which led a more aggressive, a very focused exploration program of 2D seismic followed up by an extensive drilling program.
Just reflecting on the history, we can see here on the left we have all the key discoveries in the history of Chevron in Western Australia. Here shows the oil price with time and basically the significant discoveries that occurred during that time. Looking forward into the future, so we've been through a 60-year history where Chevron's showing-- the joint venture partners have shown a commitment to the long term. Even through the ups and downs of the oil industry, we've continued on with exploration. We've been successful. The number of oil discoveries just really helps support for the long-term aim of bringing fields like Gorgon to reality.
Looking forward, we can see going forward that this is not the end. And the Gorgon area, it's really the beginning of a new era of production and hopefully further development and further sales or further expansion of the opportunity into the future. So with that, I'm going to hand over to David. Thank you.
DAVID SIBLEY: Thank you, Mike. And so, I wanted to read the first sentence to get that part right, and then I'll be on the road. And so the emphasis for this part of the talk was that the way the technology worked, not on the last two years, but over that 60-year history to drive Chevron and our legacy associations with WAPET to where we are today.
And so the key technologies were used to unlock the greater Gorgon area, laying a foundation for an error of unprecedented exploration and appraisal success, building momentum for Gorgon and other LNG projects. And these technologies are not new to any of you. Most of the work that I'll show today was actually done Mike and I together and others in the mid-90s. Now, there are some new additions, but it was the way to change the paradigm and laid a foundation for what will become so much success for Chevron then and in the future.
And so those technologies hydrocarbon indicators and a focus on amplitude versus offset, offset seismic stacks, obviously 3D seismic interpretation, and the 3D seismic acquisition and processing, integrated time-to-depth studies, and regional studies, particularly basin modeling and integrative regional stratigraphy. So back in the '90s with the Chrysoar discovery, which marks a paradigm shift within WAPET and Chevron in the effort in this area, the integration of all of these things came together in such a way that we were rarely ever missed again. And we'll talk a little bit about that.
And so, we can focus-- and by the way, a lot of these slides are actually in the paper that Mike and I wrote together in 1999 in the AAPG Journals if you are interested in additional detail. But here, the Chrysoar was a step out from Gorgon. And so their people were recognizing the Chrysoar opportunity, which was on the edge of the Gorgon 3D survey. And there were HCIs there, but nobody would admit that they were HCIs because the teams had already assumed that they could not be that. There were some reasons for that.
Now, the other thing that was difficult were the complexities in the time-to-depth conversion. And so if you look on the panel to the left, this is the time structure from the new 3D survey following the Chrysoar discovery and preceding the Dionysus discovery. And the panel in the middle is a depth structure. So those warm colors are shallow in time or depth. And the cool colors are deep.
And you can see that the structures are very different. And so the overburden was complex. Also, little water layer was complex. And so near these fields, you went from the shelf 100 to 200 meters of water depth to over a kilometer. So all of these things obscured basic relationships that the interpreters could have seen if we had done better.
But we did do better at this time. And so as you saw that movie play-- I'm not going to play it again, there were a bunch of lines, there were lots of amplitudes, and some were gas sands and some were not. But when you got depth structuring right, it became very easy. And there were some other things that we did as well.
And so here again, first because we come out of Gorgon and make the learning is there to lead this success, we began to be very integrated in the way we thought about stratigraphy and petrophysics and/or geophysics particularly in modeling how the rocks should respond geophysically and looking for that in the data. And so the Gorgon composite log there on the left, you've got more than 20 reservoirs there with new 3D seismic at that time. And then you can take one of those little sands and you can look at the I sand. That little saying is this blown up in the North Gorgon 2 well.
The red there is for gas sands. And that gas sand, looking at that amplitude extraction, you see these channel-like geometries. And so the reservoir and the gas-bearing part of the reservoir is very well resolved.
So this is 20 years ago, but people were surprised with that new data when that happened. And here, the lithologies and the fluid, everything was just right. And so we began to work on the problem. And so here with the Chrysoar discovery, what was thought not to be two HCIs of course was shown to be.
So here, the red, these are the gas sands. We call it the double-A and the A sand. And then here's things like acoustic impedances and Poisson's Ratio showing how there's good contrast between the gas sands, the blue here, and the wet sands, and the shales in these two reservoir sections.
And we also took that into our models, predicted responses, and looked for those responses in the data and found them. And we're able to distinguish with confidence gas sands, wet sand shales, and carbonaceous shales. So in that movie, you saw many high amplitudes that looked just like gas sands, but they were carbonaceous shales. In here, that cross plot emphasizes that the y-axis, which was the gradient of amplitude over the different offset ranges, actually was opposite for the carbonaceous shales and the gas sands. So this is all done back in the '90s, but we had great confidence because the relationships held in the 3D, particularly over the Dionysus prospect that will be drilled later.
And it led to a different style of interpretation. So once we began to focus on AVO, we began building where we had 3D data, 3D volumes-- the one on the left here, this is a projected zero offset seismic volume. And the one in the middle is what we would call the nears, or the 0 to 30-degree incident angle volume, and 30 to 50 degrees, which would be the fars. Everybody does this today but this is kind of novel back then
And then the thing to see is these two reservoirs, you can see how they light up on the fars. And so there, we didn't have to do models everywhere where we were prospecting. We actually understood how to process the data to quickly identify those, and we did.
And of course, we had some fun getting the 3D data because it helped us recognize some things that were kind of embarrassing to look back on today. So Mike, I don't-- did you drill this well in 1979? That wasn't mine. I thought maybe it was. I'm just joking.
But this well was drilled in 1979. This is the Salton well. This is one of those dry holes that Mike made mention of before and then later all around it, there's gas. It's like it's drilled in the only place where you couldn't find something. So this is the Pluto field that is on production today. These are some discoveries that Apache made, the Zenith field and the Wheatstone field.
But this is a little spot, if you had drilled anywhere else, you would have discovered one of those fields. That's just-- you know, this seems old to you today, but this transitional period between 2D and 3D data had a dramatic impact in this area. And we built on this, so it became very seismically focus. So I was a structural geologist, but I loved seismic data because I couldn't find gas as easily understanding the structures as I could in understanding the amplitude. And so if you look here, this is the Wheatstone project. I was in this right after the discovery, and the appraisal phase, and into the early development.
And one of the things that we learned was we were making such strides in our ability to process seismic data, that we were almost constantly reprocessing. And so the discovery well in 2004 at Wheatstone we shot 3D after. I wish we had shot it before, but we shot it after. We reprocessed it.
And this is actually the 2009 data. This would be the roof of the reservoir here, a single gas-water contact. And you could see that there's some amplitudes in there that are interesting, that are probably telling you something about fluid [INAUDIBLE].
But we had this incredibly complex overburden. And so it affected the gatherers. They oftentimes-- they weren't flat. It affected the amplitudes on the gatherers, so our AVO techniques, it had worked so well in other places, it didn't work so well here. And the structure is distorted by all of that. And so we had all of these issues.
And just three years later, look what we get. That's the same line. It runs down the long axis of the field. There's the gas-water contact. There's the roof.
This is multi-ASMA seismic, so we weren't afraid to go out there and try new technologies in the acquisition. But we're also learning from our reprocessing every time we do it. And our capabilities are expanding.
And so that's three-year difference. We had to appraise the field on this, but we drew up our development wells on that. And it was a very successful program.
And so one of the things that we've been proud of is that we've always looked at the basin scale. And so this is meant to capture that basin look. And also it gives me an opportunity to tell the story about the basin modeling that we did so that we understood the way that the generation and migrations occurring in the basin very early, and to use that to our benefit.
And so here, this line is a 250 kilometers long. And this Mungaroo section that many of you are familiar with, that is very, very thick. That's about two miles. And most of our exploration effort has been in this red zone. And the things that I told you about Chrysoar, and Dionysus, and Wheatstone, they all mostly apply there, but it's a much greater challenge as you go deeper.
But we are looking deeper. So we've got about 150 leads and prospects in our portfolio. And then in addition to that, we think there's more gas to be found there, but so do others. So Geoscience Australia has said that we've already found about 130-- I'm sorry, about 120 TCF. And the USGS has predicted that there would be about 130 additional TCF of resources found. And we think we're well positioned to be part of that.
So basin modeling at this scale back in the '90s is what we used to understand whether these prospects that were low risk that we had found in many places that might reference around Gorgon back then, whether those accumulations were going to be dirty gas, high in CO2 like some of our reservoirs that we had at that time, or it was going to be lower CO2 and the kind of gas we wanted to find. And we were correct in most predictions, so it was important.
The other thing that we feel like we've done very well on-- and I can't-- there's a reason I can't show you the best stuff, so we consider that an advantage. You don't get to see that. I can show you the kind of good stuff that's a little out of date. But what we've been doing is we've been, of course, merging all of the 3D data sets and in a way where they're compatible.
And now you're seeing a movie slice, kind of a long stratigraphic layers. And you can see that the sand fairways are easily mapped. So this is a big area. And this is just a portion of what's been done.
So that's-- there's a 50-kilometer scale, so that's 200 kilometers there, more than 50 kilometers wide. And you saw how thick the Mungaroo section is. So we really understand this.
So this long-term commitment that Mike talked about has paid off. Year after year, we learn more, and more, and more. And our success rates, if-- I don't know that they can get much higher. But it wasn't always that way.
So before Mike and I, back when that Rough Range well was drilled and then the following, we had some exploration success. So in the '60s, these little histograms, the blues, these are the dry holes. The reds, these are the discoveries.
And the success rate to the right, it wasn't that good. It was about 13%. And this includes the Barrow Island discovery, which gives us some production, which allows us to take the long-term view. And then in the '70s, we are still drilling a lot of dry holes, but the success rate is coming up.
And this goes on to the '80s. And now you could see that we're at about 45%. And that's the discovery of Gorgon, and the discovery of Saladin, and the discovery of Rover and Skate. So it's in this big box in red, which is the traditional area where WAPET and Chevron were leading.
And then as we move into the '90s, the success rate went up again. Now it's over 50%. And then into the 2000s to 2010, you could see that we're up at 90%, and about 90% up until today and the next decade. And so there's just been this dramatic increase in exploration and appraisal success because we've integrated all of these technologies in some ways that I can't show today, but you get the general idea.
And so this is what it looks like on the map. And I don't promise that there's a star for every discovery because they'd just end up with stars on top of stars on top of stars. But you get the idea.
So Chevron has a very strong position here, many discoveries. From '52 to 2017, I count about 80. Actually, it was 85.
And then the others thing, since focusing on the deep water gas, which is that Chrysoar well going forward, that's actually 93%. So I apologize. I forgot to point out this one. So this is if you just look at the gas that's going to be part of our LNG projects. And that was a 93% exploration success from '93 until present. And this is about 50 TCF of discovered resources.
So we think this is world-class. And we're very proud of it. Mike, if you'd join me. We thought we would reflect a little bit on the keys to success. And we'll take turns sharing this.
MIKE MCLERIE: Sure. I think vision is-- and I guess commitment goes along with that as well. I think that having that long-term vision for commitment for exploration-- certainly we've appreciate the support long-term from our corporation. I know Bobby Ryan and the exploration leadership team, providing that funding, providing that support over a long time, our joint venture partners, I think that vision is important to know that the LNG business is a long-term business, large amount of investment. You're talking decades in terms of production and investments. So it's important to have that vision at the highest possible level.
DAVID SIBLEY: Yeah, and I'd like to add to that. This thing about regional understanding and integration, and so you saw how we worked the geophysics together with the geology, we understood the big picture down to the individual prospects. And when you get that kind of in-depth understanding, you're going to have a lot of success.
MIKE MCLERIE: And I think the technical excellence and creativity I think is referred to in the previous speaker, having that creativity, having that diversity of ideas, working amongst the geophysical community, the geology community, even the engineering, working together as a larger team, you really can generate some significant value and ideas.
I think also some of the technology, embracing the technologies, the things that are at our disposal to ensure that we can have the best practices and have quality technical references, really challenge ourselves and challenge the existing paradigms, and really try to think creative, think new ideas, think new [INAUDIBLE].
DAVID SIBLEY: Also this one was key was rigorous screening. And so we have corporate team for exploration or a major capital project is coming in. They're independent, and they review these things. And that's very important.
And it was really important for Mike and us. So Mike, you may remember when we started to drill those deep water wells in WA-267-P. What was the tolerance for risk? Was it-- were they very tolerant of risk?
MIKE MCLERIE: It was real focused risk. Obviously, we were looking to reduce the risk, drill the prospects that are going to offer the largest resource at the lowest geological risk.
DAVID SIBLEY: So Mike's very politically correct. I'll tell you that we were told don't drill a dry hole.
MIKE MCLERIE: That's right.
DAVID SIBLEY: And if we had drilled a dry hole, neither one of us would be here today.
MIKE MCLERIE: In fact, I think one of the people mentioned that one of the companies had a policy of not drilling dry holes. And that's a pretty good policy to have with you.
DAVID SIBLEY: And I think you've got--
MIKE MCLERIE: And the last one's really focused technology investments and time application, really embracing technology, having focused technology. We work closely with our subject matter experts, our research groups, in Chevron, but also with the joint venture partners. You have ExxonMobil and Shell. They have an excellence in terms of their technology. So embracing that to really focus on specific problems and bring it to bear, apply it. I think the 3D you saw from our talk today, really early embracing 3D, really trying to solve and address our technical challenges is vitally important.
So with that, we would like to do our acknowledgements. And I think we'd like to thank-- I see Chevron, I guess from a Chevron Australia business unit, also Chevron Corporation, ExxonMobil and Shell, and then our customers, Osaka Gas, Tokyo Gas, And Chubu Electric. Also we'd like to acknowledge the contributions of a vast number of people.
In fact, what we'd like to do for those who've had any part of the Gorgon story, we like you to stand today. There should be people out in the crowd that at some point in there careers have actually touched Gorgon in some way. So look at the hands. And there's many hundreds of people that have been part of this, so thank you.
David? OK, well thank you everybody for your time. And we'll open up for some questions.
INTERVIEWER 1: Question. What percentage of the gas is committed to the domestic market? And how is that priced relative to the export gas?
MIKE MCLERIE: Oh my goodness. It had to be a gas marketing question. OK. We have about 300 terrajoules a day for providing the gas market. But given the size of the research and the LNG program, the percentage is actually small-- Western Australia is a very small domestic gas market.
There is a requirement at the moment that all LNG projects have a certain commitment to the local market. But in reality, Western Australia, even though it's a very large state, the actual domestic gas use is actually very small. So most of the gas is going to export through LNG.
MAN: OK, I've got one.
INTERVIEWER 2: Main of Australia thus such big country. Why Chevron is not exploring the Western part of Australia at that time?
MIKE MCLERIE: I guess the-- that's a good question. I guess the question was, why did the Chevron start exploring Western Australia? I believe at the time that the Cannon Basin, the large are to the north, I think there was original studies that were some-- that showed that Western Australia was a focus area.
However, there were studies that were done out of the East Coast. I think our other company, Unocal, which is part of the Chevron fold, actually had the very first commercial oil discovery in Queensland in the, I believe, the early '60s. So I think our focus through Western Australia petroleum has been pretty much exclusively on Western Australia, but there has been other incursions.
But that's our focus here. It gets back to our focus here. I think we see the Carnarvon Basin, that area was a large potential. And it has proven to be very prolific.
INTERVIEWER 3: What is the source of the gas?
MIKE MCLERIE: The source of the gas, it actually is part of the Mungaroo. The Mungaroo, as we said, is very thick. You're looking at probably eight to 10 kilometers thick, a large sequence of fluvial deltax in the shale section. We had the luck of shale which is a deeper shale unit. So the Mungaroo itself is actually self-sourcing, very thick. David.
DAVID SIBLEY: No, that's right. So the basin modeling that we did in the '90s-- now we may have done it sooner. That was some that I was involved in. That's the way that we modeled it. And we predicted gas accumulations consistent with what we expected to find. So there'll be some bit where the gas is accumulating, and there's also some bit because the Mungaroo is thick where things are over-maturing. So there's a window of prospectivity that you have to pay attention to.
INTERVIEWER 4: What was the single most important factor to the success of this project?
DAVID SIBLEY: We can take turns.
MIKE MCLERIE: We can take turns.
DAVID SIBLEY: You go first.
MIKE MCLERIE: I think part of [INAUDIBLE] would be people. I think it's recognizing the skills, the people, and, I guess, the team, the way that's bought to bear. I guess the technology-- you kind of ignore the technology.
But I think it's the people that were there. Without people, you really don't get-- you really don't get any results. So I think it's how we use that technology, the skills, the dynamics, they're working, together, the diversity and the creativity of the people that really brings the prospects together utilizing the technology.
DAVID SIBLEY: Yeah, I think-- obviously, there was a focus on seismic gear. So this particular area was just right. But it was always recognized.
And so the seismic opportunity was there to do these types of studies so that you got into that place where you could get the almost 100% successful. But at the same time, there was an integrated thinking that was required to see that when others had missed it in the past. So 3D seismic makes it easier to see.
But it wasn't just that. I think at Chevron, my history with that company, which was 35 years, is that we were trying to be in the earlier part of my career as integrated thinkers. So some companies go towards experts. We weren't experts. We were trained to do everything.
So when I first started with Chevron, I interpreted the seismic, I correlated to Wells, I recognized the prospects, I estimated the risk. And that's the way we worked. That was in the Gulf of Mexico. And when you learn to think like that, then you put things together. And sometimes you get there just a little bit quicker.
INTERVIEWER 5: Hi there. You guys explained how you were wanting to look deeper than the top of the Triassic. And there seems like there's likely to be igneous rocks intruded in there. And I'm wondering you guys are looking to de-risk that or deal with that kind of risk.
DAVID SIBLEY: Look, I don't remember saying that we were looking deeper then the Mungaroo formation in this particular area. I do know there are some igneous rocks there. Some of those actually you can see on the seismic is sills, and dykes, and others that have worked that area are familiar with that.
But we're certainly looking to lead with seismic. And so the effort is, and how can we get more out of the deeper seismic, which is more of a challenge than that-- you might remember that I red patch which things looked a lot like what I showed, that was easier once you figured it out.
CHARLES STERNBACH: OK.
DAVID SIBLEY: [INAUDIBLE].
CHARLES STERNBACH: Yep, [INAUDIBLE].
MAN 2: OK. Thank you, gentlemen. Hang on just a second. So, I think we should show our appreciation. It was a great talk. Thanks very much.
CHARLES STERNBACH: --London and Salt Lake City.
MAN 2: OK. So Charles reminds me that the next time we're going to convene, this is going to be in London in mid-October. We have a half-day, really another outstanding half-day planned there. And then we'll also do at least half a day in Salt Lake of May of 2018.
So the [INAUDIBLE] lecture's going to be here in about 15 minutes. So if you want to hang around, great. If not, eventually we're going to have to kind of move out of the way here. So thank you very much for attending. It was an outstanding day. We appreciate it.