synthetic micro seismicity calibrated the result against the field observation during the preconditioning for each of those preconditioning stages and the calibration process led to a much better understanding of in-situ stresses and also fracture properties we then built a global model of the mine with a better understanding of in-situ stresses and fracture properties and used that to predict the induced seismic events the graph on the left button side shows two lines in the first case so actually let's go to the dark blue one the dark blue one is the induced seismicity in a formation that wasn't preconditioned and we had fewer number of events the y-axis is the log of number of events but the magnitude went up to almost two and then the numerical modeling which was calibrated predicted that once we do the preconditioning we will have more number of events but with much smaller magnitude and this is exactly similar to the pattern that it was observed during the mining operation there are more number of events but with less magnitude when we carry out the preconditioning so this example shows how numerical modeling can be used for gaining insight into side characteristics including the fracture information and properties and also stresses and then how to reliably use these type of calibrated models for predictive analysis another example that shows the workflow was in the Fallon Forge project that we were involved for numerical modeling aspects of it so this was conceptual design these are horizontal wells and it was envisioned that stimulation would be carried out in stages sequentially the animation here shows the result of numerical modeling with explicit representation of fracture in the model and the region is basically the fractured fractures which have experience pressurization and the graph here shows fractures that experience sleep as a result of injection so the red color shows a sleep of about 2 centimeter and then this information which was obtained from a geomechanical model with discrete fracture representation was then translated to a micro seismic model and the micro seismic model was able to predict the micro seismic events, individual events on these fractures and eventually obviously their magnitude, location and time and eventually a micro seismic cloud that could be used for aiding the design for example where to put the production well so this concludes what I wanted to say today there are a few other things that I want to mention right now we have the capability of modeling heterogeneity and fracture in these models at all scale for example this is a laboratory scale of rock we can put a discrete fracture network and create a rock mass at a scale of meters we can increase this and go to a scale of a regional scale which is kilometer by kilometer and then we can get a portion of this regional scale model and create a reservoir scale model again the catch here is going through multi-scale modeling but the models that conform to one another so the capability for numerical modeling is there but then as our capabilities increases our ambitions also increase and computational time therefore increases this requires investing more in more advanced computational procedures such as use of parallel processing and also coming up with more efficient solvers there are also two criticism often associated with numerical modeling in general and especially with numerical modeling of fracture network the first one is that we don't have enough information about fractures and the answer to that would be obviously this calls for better side characterization but again I want to emphasize on the role that numerical modeling itself can play on constraining the data so these type of multi-scale modeling and explicit representation of fracture network are a very efficient and reliable tool for gaining a better understanding of the side characteristics including the stresses fractures their properties orientation and size the other criticism is that the range of variation in DFN response is very wide and my answer to that would be so is the range of variation in reality this doesn't mean that discrete elements modeling should not be used in fact they should be used and they should be used in a way we would be able to create a stochastic models and also run multi-scenario simulation so discrete elements models are useful when we do calibrate with respect to field observation such as micro seismic data and also when we are relying heavily on a stochastic model generation and multi-scenario testing and simulation and finally we are able to put these heterogeneities in these models but we don't want to put them with the field observation at all different scales so the amount of information that we put in a model which is one meter by one meter is very different from the number of fractures and the amount of details that we put in a regional model so we need some sort of research and some sort of approaches to be able to put these fracture network in different models at different scales by selecting the most important mechanism and representing those mechanism and those features in these models so that concludes my talk Thank you Azadeh. Now we will move on to Ken for his second appearance. The US Army during World War II wrote a book using a divining rod to find water I guess they were keen to try any approach to support the boys overseas so there you go. Anyways this is a good story because starting off with Colin and Jim I think we are looking at narrowing things down to issues of we know what we can do with this data if we have it and what sort of data do we need we don't have to wait for a Manhattan project to produce the sort of technologies that would be useful to us, they are actually there now it's a question of I would call it the social and political will to use them in a way which addresses the issues that we are facing going forward so I will give you a little bit of I may promise me this is one of these we call them now iconic images how many have seen this before this is Olympic Dam we have one, alright two so here the little bit of red at the top is one of the largest copper, gold uranium deposits in the world called Olympic Dam it's situated in the state of South Australia it's found back in the 70's it's now being mined by BHP but the important part from the point of view of this discussion are the images in color above and then with line work that show the seismic and electromagnetic patterns associated believe to be the root system of this giant ore deposit and this is what we call a footprint they are calling now the fingers of God coming out of Australia the arrogant Australians but anyways I told them I don't think it's necessarily the fingers of God but anyways they got naming rights so this is something which obviously we can take advantage of we're acquiring data sets like that here but I don't think any of the major deposits like for porphyries or in Carlin have actually had the same type of data acquired so one of the things isn't the invention of new technologies but the application of them in areas that are of interest to us and how do we calibrate moving over to terra firma here certainly we haven't been slack in terms of acquisition of regional scale data but even though there seems like a lot of dots these are I think about 70 kilometers apart which is really a semi-regional assessment this is a continental scale assessment and Carlin referred to kind of a sweet spot scale which is something I think we have to look at we need to tighten these things up and we can in order to come up with allow us to actually break apart individual basins look at specific geological formations that might host deposits we're not talking about actual target detection we're talking about the mineral system that these would be hosted in how do we characterize these and then hopefully with the suitable input from government academia the private sector can actually go in and do the hard slog and spend the big bucks with the drilling but they need to have it de-risked and they need data to de-risk it and this is I think where we're at this is helping there's been some really great projects using this data but you can see there's a large part of the US is actually doesn't have much coverage and notice a good part of Nevada as well as Arizona which are major mineral provinces in this country don't have any dots there are some dots out there but they're probably in the private sector and not available and some universities have probably taken some as well so something to be filled in also increase the resolution would be good Australia's busy with their program looking for more fingers of God they called the Aus lamp they started up much later then we did here and so they're probably working with advances in technology which are good getting longer frequencies which allow us to see deeper and they have a very systematic approach churning through probably in the next five years they will cover the entire continent Australia is a place with 80% 80% of that continent is covered by foreign material so they have just like Jim's comment about looking for the geothermal in Nevada a lot of under covered stuff that people don't even know exists because it's covered and so you need this sort of remote sensing to see it here in the states this came out last spring an initiative by the USGS and they called it the filling in the gaps which unfortunately a lot of those gaps and a lot of the existing data is circled there and that piece is sadly out of date I was actually starting in this business in the mid 70s when the major airborne magnetics initiative happened in this country totally by chance it was actually a radiometric survey triggered by the first oil crisis and they were going to fly the entire country with radiometrics then some trouble maker at the USGS put up their hand and said there's a magnetics to the survey they said as long as it doesn't interfere with the radiometrics we'll get magnetics data and that today is about I think 80% of our coverage in this country is data that was generated in that period mid to late 70s we should be able to do better here's a vintage map this is a qualitative ranking but I think the important thing is red is good 4 and 5 are pretty grotty you can quickly tell that most of the data we're working with in the continental US is pretty grotty but what do we map well we actually map the planet really well other than our own other than our own country you show this at an international conference and it's like heads are bowed down this is not something to be really proud of and the very few places that have high resolution aren't really probably really focused on minerals which is fine I mean if you do this sort of national mapping program it isn't just for one constituency it needs to be for everybody and it's a legacy that will go forward for the next 20 to 30 years just as the first data set did this is an investment in our future there's another initiative to look more from the USGS looking more at specifics in certain areas which is good increase the resolution image here the idea of you got to get more layers add gravity to the mix as well as electromagnetic and magnetic data so we have largely the technology we need it's really getting out there and putting it into platforms that allow us to acquire the data cost effectively and quickly here's my little cartoon of just or sketch at the back of the envelope if we were to do the sort of surveys that I think Colin Jim and I are quite familiar with through the geothermal and the mineral side of things somebody else in the room if we were to cover the entire continental US which is about according to my wiki site about 3100 square kilometers and if we were to use a line spacing for a survey of about 500 meters we have about 20 million line kilometers and it would cost us about just a little over a billion dollars which when I went on again another wiki site is about the cost for the last two missions to Mars so for what we've done in small part to explore the rest of our solar system we could actually contribute an enormous wealth of information to our country that has not been done and I think Remi you can probably see if there's one more but I think that's it there thank you I'll now open it up to questions I'll start can drone get these data are you thinking that direction drones should certainly be part of the story the ones that are in commercial use as opposed to military still have issues of payload size and endurance size so if we were to commit to using the sorts of ones the military have access to they could replicate the platforms that we use commercially for doing geophysical surveys but those when they cost five to six million dollars each those particular ones whereas would be fairly cost prohibitive for at least in the commercial world because I was thinking surely they'd be cheaper than flying people to get this right? it's not so much people it's you want a multi-sensor platform and these have existed but if you want to put a magnetic sensor a gravitational sensor a lidar system a hyperspectral system I mean these have to be scoped out but the commercial world actually has built systems like that one was used by BHP and Chile they called it the Griffin and it was a four-engine aircraft but the commercial world just didn't have enough use for this and it was decommissioned if I may add to that it's a really good question and a very logical application there's a major regulatory hurdle right now because the FAA requires for domestic applications of these drones that the pilots on the ground have to remain in sight of the drone you need to address that issue yeah it's like Susan's thing about the regulatory issues there are things that would have to be looked at and of course large part two who's doing it if it's some paparazzi you worry about loosening the things up flying around Hollywood but if it's for a program that the government is supporting and you probably would get one-off permissions Colin? Thank you just a couple of quick comments there are similar anomalies in the Great Basin like the ones in Australia in a rough way and it's not clear in a lot of cases how they relate to mineralization or geothermal fluid upwelling and some of the work we're trying to do in places like the Gaps Valley basically we're figuring that we need spacings of these stations on the order of 10 kilometers or maybe even less to get the resolution and so while the U.S. array data just to underline your point the U.S. array data is really useful at this 70 kilometer spacing it just doesn't give us the spatial resolution we need for the crystal scale features the other thing just to add on the drone issue it could also be true in the context of traditional aircraft and geophysical surveys in working with drones we've had some great success in collaboration with NASA who of course everything they send to other worlds is essentially a drone of one sort or another these days is payload directed flight where you can actually have onboard computing the analysis of the data it comes in and alter the configuration the spatial configuration of the survey depending on whether it sees anomalies or not one of the challenges we have it's not a great challenge but we could do better is that when you buy a survey you basically have to tell the company in advance the spacing and the layout of the survey and whether we use human or robotic pilots being able to have that real time information come back and scale things would be a significant advance too Tom One more question this for Jim I'm wondering do you know if like hyperspectral remote sensing has been applied to trying to tease out perhaps very minute changes in mineralogy alteration chemistry to help delineate geothermal systems yeah it has there's a couple groups have worked on that including some folks from UNR and it has netted some positive results borate minerals for example and clays and so on indicative of recent geothermal or hydrothermal alteration so yeah but it's just a few kind of local studies but I was going to maybe can I add one thing to the previous discussion in drones and geophysical surveys and all that are absolutely essential but let's not also lose sight of fundamental geologic mapping and LiDAR of course can facilitate that but you still need feet on the ground and so on and in a place like Nevada or much of the Great Basin where it's primarily federal land it's very difficult to get funding for detailed LiDAR studies and then just in general geologic mapping if we take Nevada about 25% of the states well done in terms of geologic mapping about half of that has been accomplished by the USGS and about half of that by Nevada Bureau of Mines and Geology so there's so much more left to do there in addition to the geophysical surveys and you need both to really understand where these resources may lie Next question for Azada about the fracture modeling, natural fracture modeling and induced fractures so one of the things that we've noticed in the research that we do is when we have we look at the density of natural fractures that occur in a borehole image and then you compare that to the stochastic models that we build if we kept that same density of fractures it's huge, it's absolutely huge and even if we kind of do some cleverness to coarsen that a bit it's even far too big or far too the density of fractures and the distribution of their length types is far too much to really be managed by a typical dynamic simulator so what we have found and this is kind of leveraging some of our experiences in the past is that just like when we build the high resolution earth models that geologists are so fond of and we find that going to the dynamic simulator we need to upscale them it's not the same if you build those earth models at a coarser scale to begin with and then just feed it to the engineers, there was a thought in the past that if we just use the scale of the geophysics the seismic, well that's just fine because it's coarser than it is based on the well board data which is much more highly resolved in the vertical domain so what we have found is that coarser it's important to build an engineering-scaled natural fracture model that is upscaled from a more dense model because otherwise you're just going to be waiting a very long time for those simulators to actually process the information and there's some cleverness with respect to building those upscaled models and this is an excellent area where machine learning could come into play where you could do some testing against the dynamic simulator with a highly resolved set of fractures on a small area and then upscaling it to an efficient set which gives you similar results I'm wondering if you've done anything in that area or you've experienced the same thing. We're dealing with the exact same issue even for a very sparse fracture density putting that density into a reservoir scale model would result in a lot of fractures. In one case I actually took this slide out a 10 by 10 meter fracture. If I exactly represent the density that we got from the field it would result in 13,000 fractures that in a reservoir scale model would mean million. We are even incapable of creating that model with the current CPU of a desktop. So we didn't take a machine learning approach but we do we exactly follow this line that goes back to my last point on this slide. Coming up with the research methodology that we get these fractured densities and then we create fracture network at different scale is an area of research and what we do right now is that we try to come up with depending on the scale we try to come up with the most dominant fracture characteristics so for example we tend to simplify the smallest fracture in the system disregard them knowing that it's an exponential law and replace that amount of try to keep to match the permeability but then replace the porosity of those fractures with a matrix permeability so we create models of different size and put pressure boundary condition and match for example hydraulic properties and mechanical properties but then again if we go to thermal that can completely change the story because then one fracture so that goes back to the point of understanding this simplification methodology depends on the problem that you're solving for a mining project it might be different compared to EGS project. Our approach is a scientific approach we don't do machine learning we try to build samples and take part of the smaller fractures out and replace them with the equivalent properties. Yeah so it's interesting I think it's relevant to point out that there's some good research to be done on finding the effective scale of the fractures for these different domains whether it's thermal or whether it's petroleum or whatever hydrology find the effective scale that makes sense and that in part addresses what Linda was talking about earlier with respect to finding the right scales of these particular features. Yes I want to pick up on what you're saying it's very very accurate first of all let me say to Elizabeth I have found this the most stimulating meeting I've been in many years it's very great that I'm delighted but the underlying philosophy of Itasca has always been to try to use the mine or dam foundation or whatever as a laboratory and we went there with the idea of actually they have offices in Australia and Chile where the action was but one of the most fascinating areas that we've been working in has been block caving and if you know anything about block caving it's an attempt of huge gravitational forces with the rock to fracture and the process of extraction of the mine causes major redistribution of stresses etc but recently and this goes to the question we were doing it largely by seat of the pants picking some boronite oscillations and saying what size of fracture should we use in trying to see if we violated the principle of minimal potential energy and so on but a recent study on a block caving showed some behaviors that were quite unanticipated for example that a tunnel converges when you unload it now why was that? because in the earlier stage of the loading of the block caving process put high normal stresses on fractures and later those were released and so they could slide when they couldn't slide before and so this notion of using a mine as a laboratory to me is a very powerful one where there's a great deal of you know I don't know where we'll lead to with getting ideas for practicing engineers underground how they do it but and then I look at the amount of funding that we get for looking at these things on the earth compared to what is for other planets and somehow we have to make the case that we have a major set of problems here that are very important thank you for the fracture modeling I just saw last week something that really caught my eye I think I can share with you who it was but I have to check to be sure I remember right but the thing about fractured systems is that they very arbitrarily connect things at odd distant scales and the model I'm thinking of that's what it focuses on and so swarms connected to swarms and different length scales and it gets away from the need to specifically grid around the fracture system which is impossible as you see there's too many but rather interconnect them and I've also seen another effort that I think is related the author is a cunha that one I do remember I mean stuff is out there that's going a little bit different direction very interesting going back to the pure point about fractures randomly connecting so this is the nature of fractures the fracture size distribution is often exponential having very large fractures at a scale of kilometers and going all the way down to meters and again this goes back to the concept of understanding these fracture systems and being able to put them in the model by respecting their characteristics the dominant one and one of them is this fracture size distribution which naturally gives rise to the type of mechanisms that you are mentioning so part of it is understanding what their characteristic is in nature and being able to reflect that in the numerical modeling and we are able to and again this also goes back to Jeff's comment that then we can look at these models through numerical modeling look at what fracture connect which region to what region so basically come up with the connectivity map of the fracture system that we have put in the model so regarding the role of natural fractures there are actually good news now so some data emerging from some of the field experiment especially the hydraulic fracture test site in Permian basin so the data released last year and this year shows although we have this kind of foot spacing natural fractures only about a couple percent actually participate in the flow so that give us a spacing of like a 10 centimeters so we are seeing the same thing in our colab experiment we have 400 or 600 natural fractures locked in the system but only the active ones are in the spacing of 10 centimeters so that is kind of a sweet spot for the current model so it is we don't necessarily need to model all the natural fractures most of them are sealed and they are not permeable in the kind of scale we care we still have time to talk about this so to some extent to overcome some of the issues of modeling natural fractures the approach the research that we have taken is to go to a particle based system so we are not using grids at all and that is the work originally that was done a number of years ago by Crenshaw at Stanford and then eventually after that from Shavasthava Crenshaw used a finite element based model and then Shavasthava turned it into a geostatistical based model that has growth at the point etc so if you read that stuff you can understand it and then the gridding comes later so you can use unstructured grids to get very very fine cells within the fracture domains and then the matrix goes to coarser cells and you can capture that information we found that works pretty well but it doesn't negate the need to develop the engineering scale that is critical for the natural fractures so I am still a believer that you build the natural fracture model with high density I don't like the idea of building fractures based on grids I think a particle based system is better and then you coarsen it to an engineering scale using unstructured grids that would be kind of the approach that we have been taking and it works pretty well I am not familiar with the way that you are mentioning to creating the grid I completely understand the structured versus unstructured mesh I just don't know how that would conform to a discrete fracture modeling the way that we do that we use the log data and create fracture network initially so independent of our finite element or finite difference underlying mesh we create a statistical model this is a Poissonian distribution of fractures in a space with fractures in 3D in a 3D model and then we create an unstructured mesh that would conform to the geometry of the fracture now during that fracture generation once we create that 3D fracture model then we take those upscale modeling approaches so we first create a very dense fracture network and then we say that which one of them we can represent with a background continuum model out of the model and which features we want to keep and then reduce the number of fractures that we have in the system by respecting mechanical properties, hydraulic properties and then once we reduce the number of fractures brought it to a manageable size we create a mesh which is unstructured and conformed to the exact geometry of the fracture I have a final comment perhaps the last one before we break for lunch but just in response to your ideal data acquisition for the US the Australian acquisition survey that was done in late 2000s and about 2008 and it was called the Australian Airborne Geophysical Survey AWACS and it cost them 2.6 million to fly the whole continent at 75 km spacing for the airborne radiometrics and MAG and now they estimate that would be about 200 million so I guess my comment was maybe it's not as bad as in the billions for the US you know I mean that's similar size countries so we could get away with cheaper and we don't have to worry about not going to Mars so ok well please join me in thanking Joe ok we have looks like lunch is ready so we will adjourn and reconvene at 120 so we purposely schedule a full almost full hour for lunch so folks have a chance to interact informally so please take advantage of that time to network she might have we're buying on time she kind of has to keep going all the way through so oh no we have a break at the end of the panel before we do the discussion I I ok Bridget if you want to folks please grab a seat and we'll we'll let Bridget get started with our third panel hi everyone I'm Bridget Ailing and it's my pleasure to welcome three panelists this afternoon for our third panel we have some really interesting talks looking at aspects of dynamic permeability first up on my right here we have Ping Cheng Fu who's an earth scientist at Lawrence Livermore National Lab he received his PhD from University of California Davis and has been studying dynamic permeability for about 10 years so very happy to have him next we have Christine Eleg Economedes who's a professor and the Hugh Roy and Lily Kranz Cullen distinguished university chair at the University of Houston previously she was a professor at Texas A&M for 10 years and worked on slummajay before that for 20 years so a wealth of experience she has more than 120 technical papers and two patents at the end we have Kuchuk who retired from slummajay in 2017 he was the chief reservoir engineer for slummajay and was a consulting professor at Sanford University in the late 1980s he's worked on many projects including work for BP and has also many papers published one thing I noted that he was also the Nobel laureate physicist I can peep the gold medal awardee which sounds pretty darn impressive so it's a pleasure to have you here so we'll get started first with and we'll hold questions again until after the three panelists have presented good afternoon so on behalf of the EGS CoLab experiment team so I'm going to share some of the observations and insights we obtained from the ongoing field experiment so the system motivation we have it's a project sponsored by the geothermal technologies office so we often see this kind of lab experiment the scale is from millimeter to you know half a meter or foot scale and occasionally we have the fortune to carry out a real field experiment such as you'd have forged sites but there's a vast scale gap in terms of scale between these two and if we're talking about geothermal thermal processes hydro and mechanical process they have different scaling rules so it's not very straightforward to actually extrapolate what you get from the lab to the field so the first motivation for this field experiment is to bridge the vast scale gap we have several older magnitudes of scale gap between these two kinds of experiments and we also want to validate the EGS codes we developed in the past couple of decades in the environment that's relevant to the field operation so for this to satisfy these objectives we have made several strategic choices so the first one is we carry out the experiment in a mine that's 1,500 meters deep so the stress state is relevant and the temperature there is not very hot it's about 35C so that's not ideal but it's very friendly to operate and to make a measurement so we partially compensate by circulating chilled water about 10 degree C so we have a 25 degree C of temperature difference and we also made a very heavy investment in characterization and monitoring and we are carrying out this experiment using a community based management approach so we have a fairly large team the experiment involves 9 national labs and the 6 universities and a few private entities it's led by Tim Nipsey of Lawrence Berkeley lab and Dr. Blankenship who is in the audience so here we have a list of names involved we have more than 100 people involved and about 15 to 20 people are heavily involved so we have at least two experiments the first one is concluding that's what we have been doing the past two years it's about hydraulic fracturing the second one is starting it's mainly to investigate shear stimulation so both experiments are in the Sanford underground research facility in South Dakota that used to be a gold mine you can see the equipment along the drift here so here this is the kind of conceptual model we have about the experiment so the idea is this long line that's the drift we wanted to create a couple of hydraulic fractures and we drilled 8 wells we used to stimulate and circulate the fluid and there are 6 wells in different angles trying to provide a very geophysical coverage of the experiment so the blue one this is injection and the red one was the production well so before the experiment we spent a lot of time and effort trying to characterize the site, the testbed so we retrieved a continuous course from the 8 wells about 500 meters and we blocked all the fractures with all kinds of properties we built a discrete fracture network that's almost deterministic and this is the inversion results from PNNL about the electrical resistivity of the rock body it provides very useful information about the fabric of the rock in that testbed and we deployed a lot of sensors so we have literally 5 miles of cables and we have fiber we have acoustic sensors temperature sensors in the 6 monitoring wells so we have done a few simulations this is the fracture we're using now for circulation so we did this carefully did this in 4 or 5 little episodes we'll check a little bit see what happens so this figure shows this is the fiber measured temperature in one of the wells so every time a hydraulic fracture hit that well, hit the fiber you'll see a bright spot so corresponding to the injection history and we have continuous fiber in all the wells so this one happened to be hit by the hydraulic fracture and we also have cameras we'll put cameras in the production well so we actually captured a precious footage showing the actual intersection of the hydraulic fracture with this well bore and we did some analysis to see the trajectory of the hydraulic fracture so on the right you see a lot of dots that's apparently micro seismic so you see we can see several planar features and we believe those are newly created hydraulic fractures because there was no we have a good map of that natural fracture there was no natural fracture in that orientation so if you take a closer look at the micro seismic you actually see two planar features one here and one there from the results of LBL and Oak Ridge National Lab and these two fractures correspond to these two temperature anomalies we received we saw so it's just very strong evidence to show where the fractures are we have multiple ones here and also showing the black circle here that's the natural fracture we know we saw that natural fracture big natural fracture permeable in all the wells intersected so they have very consistent orientation so we have very high confidence in the resisting of the natural fracture so when we inject fluid from this well we get fluid both from this natural fracture intersection with the production well and the hydraulic fracture intersection so starting in October last year we did some circulation test the first one we did about one month of circulation test so this is the data from the first four days so we kept constant injection rate 400 milliliters per minute basically just drink a soda in one minute that kind of rate so the pressure was stable the injection pressure so that's what we know as the fractures limiting behaviors once the fracture is open you don't need much more pressure to push the fluid in so everything was happy this is what we had expected and we were getting 90% of the fluid recovery from different wells just noisy data and from the DTS the temperature we solved one single or hydraulic fracture showing up in this map so it was a very happy moment and we achieved what we wanted then but you know real experiment never rarely does what you hope then the pump broke so this is the dynamic permeability evolution part that broke we put on new pump and that pump worked with a higher rate then we start to see these micro seismic events these red dots and turns out we were actually slowly propagating this fracture in 24 hours we solved consistent micro seismic and at some point we start to see temperature signal in another well so this signal is where the fracture so later we learned that the fracture was propagating then when we went back to the lower flow rate then the pressure start to increase continuously at a very high rate that's not acceptable because it becomes unsafe then we did a little bit stimulation try to already open the fracture then we come back the fracture was still increasing and we put a chiller on the fracture water at like a 10 to 15 degrees C the pressure drops a little bit thermal mechanical effect but it starts to increase again so during this time we did seven tracer test and I'm picking three recovering curves you can see from three channel each different color represents a different channel you can see we have very different breakthrough curves at these three moments so it's a very dynamic system it's very stressful and confusing time because why the pressure was increasing and we cannot control that it turned out it might be it was likely something to do with geochemistry and when we finished this we pulled out the tool we saw the mineral deposition on the tool so it just hypothesis now is the mineral precipitation was blocking the fracture so we later resolved that problem since April this year the circulation test has been largely continuously carried out for now six months as we speak now the circulation test is going on so the system behaved reasonably well and we resolved the water source problem so the pressure was still going up and we see this just that it goes this kind of continuous very slow increase continuous increase we thought through some modeling work we believe that's poor elasticity so the simple way to look at this is to open the fracture we need the pressure to be higher than the total in situ stress in this kind of elevated pressure the pressure is going to diffuse into the rock matrix and cause the pressure to increase like this and through the poor elasticity the poor pressure increase will cause the total stress to increase and you got this feedback to cause the pressure to continue to go up so that's the part we can explain there are still other parts we couldn't couldn't explain so every once in a while the pressure will suddenly just drop a couple hundred MPa sometimes they increase a little bit we don't fully understand those we're still trying to do modeling interpretation of the data the recovery rate from different wells, different channels they evolve all the time although the total recovery ratio we have is somewhere between 80 and 90 percent so I'm going to show you a specific window we saw something very interesting so this window is from April to May and in this time window from this well there's a very significant signal in one of the DTS along one well and in May we didn't do anything we're still pumping and this signal kind of disappeared we know at this location because we have such a good mapping of the fracture we know there's a natural fracture naturally open fracture there at that depth this is from the televiewer log this is from the core we know there's a fracture but after about a month of injection that fracture used to be conducting fluid then you lost it at the same time the recovery rate from that well went down and the flow rate in other channels went up so we know that fracture was for some reason closing it's actually very nice to have this kind of well characterized testbed to definitive tell what's going on in the experiment so we have learned a lot in this uh experiment and I'm a modeler most of my time spent at the lab do geomechanics and flow modeling so we were involved in the design of the testbed we thought we have cubic law, we have cup holder model HPC enabled modeling this is going to be a slam dunk but in this two years experience I'm very very humbled so one thing we'll learn is this kind of deep intermediate scale experiment is a very effective way to learn about subsurface and also to test and verify tools it's so nice that when you see something you actually know what's going on for certain so in some other kind of experiment you might have 10 different explanations for the phenomenon and you don't have a sufficient constraint of the physics so the investment we made in site characterization and monitoring paid off handsomely so but there are still behavior and processes about fractured permeability that we don't fully understand so after we learn this many people look at the data it might become predictable and exploitable as we learn more so we're working very hard to get data available to the public so we're releasing the raw data process of data so here all these little things these are the notes people took during real time experiment this is this is one week of data so we're making that available so more people can look at the data to help understand more so that's what I have for sharing today thank you good afternoon so I'm going to be showing you other people's data and we'll focus here on the source rock plays the unconventional so just a couple of quotes to start with first of all impermeable rocks impermeable rocks do not exist in nature according to irison et al. 1994 fascinating observation and very well defended and secondly Roberto Aguilera told me just last week all rocks are naturally fractured so there you go we'll start with eagle ford source rock and looking at some fractures that are circling yellow in case you have trouble seeing them and they've both with bedding planes at zero degrees to the drilling and at 90 degrees to the drilling and then these same cores were put under 500 psi confining pressure and there's no trouble to see the fractures once that's happened so I think why this is relevant is because when we hydraulically fracture we are changing the stress and potentially doing this kind of thing to the rock now we're switching over to eagle ford and looking at the micro seismic surveys micro seismic was acquired during the hydraulic fracturing of wells P2 and P3 so let's see if I can figure out how to make that work over here, nope I don't see how to make your arrow work anyway you can see the P2 and P3 well trajectories there and you can see that these wells have been drilled more or less on minimum stress so that the hydraulic fractures are perpendicular to the wells and these micro seismic events are primarily sheer from what I understand and also in the lower picture we can see that they're pretty limited in height growth to see where exactly this is in the map on the right you can see the eagle ford trend you can see the wells that are green as oil the wells that are red as gas and then the star if you look towards the right side of that trend you can see where these wells actually are and this particular study was one of the field sites and it's absolutely fascinating the observations that they were able to make they drilled some wells especially for data gathering and so you can see those P2 and P3 wells again on the map view of kind of an idealized well trajectory map on the left and you can also see these observation wells S3 and then sidetracks from S3 labeled 1, 2 and 3 and you can see that S3 paralleled P3 and I guess it's on the order 70 feet distance seems like that's what I've been told and then some of the wells were drilled above P3 so trying to get an idea of how the fractures are by drilling through them after the hydraulic fracture treatment work they also cored through S3 and so the upper core that you see we're seeing fractures that resulted from the hydraulic fracturing we also see the core spread out so you see the images of that as flattened and then you can see the borehole seismic image and it's very interesting because you're seeing swarms of fractures 100 feet away from the well that was generating those hydraulic fractures so it's really interesting to try to imagine what's making that happen on the right we see that in some of the fractured areas they did see propellant the upper image shows propellant on the face of a fracture in the core and the lower one showing embedment and then the core image at the bottom is showing the distinction between unpropped and propped fractures so the propped ones of course are the main hydraulic fractures the thing is if we are getting swarms like this that are more or less parallel to the main fracture this is actually not doing that much for the enhancement it's kind of widening the hydraulic fracture but it's not taking you far into the shale necessarily so it's very interesting to see this kind of data and imagine what it might be telling us this is a different example it's up in the DuVernay shale shale acquired these data on the left once again micro seismic on the right an interpretation that helps you appreciate the fracture envelopes and it's very interesting what they did here the well that follows minimum stress so you can see it coming sort of northwest southeast is perpendicular to the created fractures as you can see in the micro seismic and the one that went north south you can see the fractures are at an angle so the minimum stress direction is not varying aerially here and we can see that the fractures in the north south well appear to extend a lot farther than the ones in the well drilled on minimum stress well they did something else they used a polymerized thick fracturing fluid for the minimum stress direction well and the off azimuth or north south well they used slick water so their observation is really counterintuitive because the on minimum stress well has much better productivity than the north south well despite what you would expect from what you see there and I want to point out a couple more things to you the first well was the one in the minimum stress direction and the second well was fractured right after the first one so there was elevated stress when they fractured the north south well maybe it's my imagination but I would say that the fractures in the north part of that well are avoiding the fracture area of the elevated stress due to the first well and I have seen that on other micro seismic images so the fractures will they're lazy just like people are they're going to go where the stress is lower and so they've gone to the left and there is an actual there's another development to the southwest where you see that marking maximum stress and there the fractures actually may be avoiding elevated stress to the right so I think this is really interesting case and I wonder whether the well on minimum stress might be producing some of the fractures in the north south well and that's why it looks like that well produces more because it is really counterintuitive to see that and on the right you can see these trends how the micro seismic company interprets the fracture intensities just an outcrop here illustrating brittle and ductile this is in the Woodford shale as we go to drill these horizontal wells the operators will look for brittle and ductile even while drilling you can get this without even logging the horizontal well and the fractures the hydraulic fracturing is much easier in the brittle and ductile rock I don't think they really do it but they could be altering their stage by stage hydraulic fracturing according to whether the stage is dominated by brittle or ductile but I don't think it's what they do another thing that's interesting I like this picture I think the red cylinder is representing the idea of a horizontal well we're looking at an outcrop and the possibility that the fracture starts up is the blue arrow and then makes a T and T's and T's and shifts and does all kinds of stuff according to those layer interfaces and this would be very counterproductive to the height growth of your fracture because it's going to be hard to prop it around those sharp bends and even if you do manage to do that in the subsurface your maximum stress most likely is working like crazy to crush that propane so it really enlightens for me how we should understand production data in light of the possibility of this sort of behavior salt as well it's a tracer and in the shale gas wells it's been observed that a small fraction of the water injected for the hydraulic fracturing actually comes back as flowback most of it stays in the formation and it may go in fresh but it comes out essentially saturated with salt so 10 times saltier than the ocean even and so there's a lot of salt being contacted by the hydraulic fracturing fluid on the left we can see a Marcellus core with very clear fractures that are salt so natural fractures are nice to us in conventional formations but in these source rock plays they're healed if they were working for us we wouldn't need to be fracturing the way we do hydraulically but the hydraulic fracturing is altering stress and causing these shear events that the seismic sees and when they're connected those could be tensile as well so a lot of activity in this material that I think is very different from the tight rocks where traditional hard rock fracturing got its start also the graph on the right is the reduction data and looking at the salinity versus time with an interpretation that when the salinity increases a lot more before it levels out that might be related to more natural fracture or secondary fracture generation then when it levels out at a lower salinity value so I think this is pretty interesting possibility some work out of UT looking at modeling fractures and as we get into these DFN models it's very important not just to model where the fractures may have gone and even use the micro seismic to guide that but as well where did the proper go because there's a strong possibility that unpropped secondary fractures are not going to stay open as you produce because the lowered pressure due to production will actually aggravate the stresses against those fractures and tend to close them on the right a simulated comparison for the fractures modeled on the left and then for the left picture the left simulation picture assuming that the unpropped ones are closing and on the right assuming they all stay open more or less with the same width a big difference there in my world I'm a conceptual model we might consider these wells more or less what you see here map views of the wells and you can see here again kind of helping you appreciate what the Shell wells in the Duverne may have been doing so the north well north south well is like the one on the top and the on minimum stress well is like the one on the top and the north south well is like the one in the lower picture and let's see if Lynn this is for you he was interested in what people are thinking about how to improve the recovery because the oil recovery is very low just primary recovery 5 to 10 percent but operators are trying already cyclic injection and production Huff and Pop or I'm just going to call it HAP, H-A-P typically using produce gas that's stranded gas anyway but we've also been looking at completions that would enable simultaneous well alternating injection and production so the idea here is that every other fracture you complete the well in such a way that every other fracture is either on injection or on production and try to produce simultaneous injections and productions between these created hydraulic fractures and the third case there the single well alternating production you don't do it simultaneously but rather you inject the injection fractures then you switch the flow controllers and inject and produce the producing fractures and why do we go to this level of complication why don't we just do well to well well people have tried it and I wouldn't have done this so here's a bucket water flood experiment where they saw the wells already there and you see those horizontal wells but they're all also hydraulically fractured imagine the fractures that I drew in the simplified view on the previous slide so the minimum stress direction is north south the fractures are going to connect between the injector and the wells on the east and west of that injector and sure enough they did I think this should be expected and what we are doing with these wells is not amenable to well to well unless we start deliberately creating the fractures so they're not intersecting so this is a modeling case looking at the Huff and Puff and this is in the Eagle Ford Nexon Energy did this one the swap well as I mentioned the idea is this is a picture that helps you appreciate what I'm talking about zooming in on the fractures we see every other fracture red if it's on injection green if it's on production and the advantage actually of swap over the simultaneous the simultaneous could be subject to the risk of things like a cement connection and if you had let's say we have 50 of these displacements going on but one cement connect that could take over the well the risk is very strong in this kind of a configuration and you're putting a lot of jewelry in the well so you don't want a risk and we find the swap to be almost like self-healing that is far less vulnerable to a short circuit but anyway yeah this is my last slide this is just a comparison of the three so Lynn looking at possibilities of far better recovery and even the Huff and Puff already is improving what's being done and here just looking at NPV so I hope this I hope you find this interesting the way the fractures work in these source plays is quite a bit different I think from what we hope to do with things like geothermal wells thanks very much good afternoon I'm going to talk about permobility of fracture systems in respect to modeling rather of modeling but I'm going to not include everything what goes to model I'm going to refer to permeability with respect to fracture modeling so basically we have three types basic fracture system basement which we have a bunch of reservoirs in Vietnam Yemen, few other places sandstone few in Texas but most of the fracture reservoirs they are in carbonate systems especially in Middle East I put some of them I'm also lucky that I worked with most of them as Christine said in all carbonate fracture reservoirs they are faulted and fractured okay but in terms of permobility fracture permobility as you see Christine I didn't put zero approximately zero okay so basically you have matrix almost no permobility what permobility comes from the fracture aperture more aperture you have better permobility you have also that on the density of fracturing that is really one of the most important parameters in basement reservoir density and the aperture sandstone reservoirs this is really one of the best defined permobility especially core permobility most of the aeropermobility knowledge comes from sandstone because a lot of reservoirs in texas you know sandstone and these as I developed it very early 60s even much earlier so most of our knowledge about permobility comes from sandstone but sandstone permobility is homogenous very little anisotropy meaning the very little fractional permobility and because of lack of diagnosis fracture conductivity varies with aperture but not a lot actually so sandstone first of all there are few of them fractures fractured and it is actually most of things is well defined when you go to carbon reservoirs as I said almost all carbon melted and fractures great geologist Nelson said if you don't have one that means you have not discovered when you have a fault that implies you have fractures in fact with seismics we don't see only 60% of the faults because rest they don't have no throw you will not see seismic although it is improving then fracture reservoirs as you know there are two types one continues the fracture reservoirs meaning part of the reservoirs fracture communicating each other I don't think there are very few reservoirs very few of them they are completely continuous but most the reservoirs are discreet the fracture reservoirs and three examples left you see you have a fault clearly you see the fault bunch of fractures again that's another fault maybe you know you can see the throw and then many fractures because of the faulting on the right you see this some these are outcrops of course these are two is they are the example for continuous fracture reservoirs as I said there are very few of them in the nature so most of the fracture parameters normally exhibit power load distribution actually this is a little bit good news although highly heterogeneous but at least we know that they have power load distributions basically whether these hundreds of fractures may have high conductivity while thousands of millions of them have low in fact you see that curve is fracture spacing very few fractures has you know above the 10 feet or 100 feet but thousands of them has very small spacing so that is what I consider fractures are basically macro fractures they are primary fractures they are open they provide the most of the conductivity second one is secondary fractures they are short their aperture is much smaller and they enhance the permeability third one is really the tertiary fractures they are much smaller some of them they are even not open but still they they increase the permeability affect the permeability when we look at these pictures we have okay we have three kinds of fractures but that is not enough if we don't know the orientation of these fractures if we don't know the density of those fractures length of them and the height of them knowing only the permeability is small part of the you know the game basically these three or four parameters are essential to do the correct you know the fracture natural fractures rather were modeling of course permeability is very important you have to have it other ways anything doesn't mean it doesn't mean that you cannot produce but what I'm saying that these are other parameters orientation density spacing length in both vertical and horizontal are very important parameters to characterize the you know whether geothermal reservoirs whether you know the carbon reservoirs in fact I'm not familiar with geothermal fields in Turkey most of them they are carbonates are fractured heavily so basically carbonate reservoirs you have core permeability of course you can get a core okay but the one again complexity most of the carbonate cores have walks you know in these figures you see the you know the walks you know you can take any part of this you know the core if you measure permeability is going to be different is going to be different in horizontal direction is going to different with vertical directions now it's very important especially from image logging getting the the walks and then do some statistic or just statistic well to well correlations get some idea of distribution of these walks because they enhance permeability considerably okay the the hygienic is significantly effective fracture conductivity particularly mineralization and scaling and of course these two you know mineralization and scaling is reduced to permeability that makes actual fracture system much more heterogeneous because some of them mineralize some of them open many faults and thousands of primary fractures and millions of secondary tissue fractures with different apertures conductivity length orientation size spacing exhibit power load distribution and that is little bit helps in the modeling we have to expect that variability power load distribution as I said micro fractures and walks considerably enhance mass experimentability and it becomes scale dependent one thing that I might add micro fractures and walks in the unconventional especially the carbonate shale they have out of macro fractures and my personal belief that because of those fractures and micro fractures we are able to produce this none none of Darcy reservoirs so basically again when it comes to model I try to say you know first you have to model basic open fractures with the sizable length explicitly you cannot upscale that you cannot upscale this you know the one you know 10 Darcy with one macro or one you know mini Darcy you cannot upscale that you have to respect these features because they are going to dominate the behavior of the system so forget the upscaling fault and major fractures then then what we do with millions of small fractures not one or two or three so actually first we have to do upscaling in this case if their permeabilities are not very high second you know we have to use image works you know to and small scaling you know the pressure transient test and maybe well test calibrate them and then what happens you will end up with effective permeability in the what we see basically effective permeability of fracture reservoirs is the matrix permeability permeability of the wags permeability of macro fractures and secondary fracture fractures and this gives you after the upscaling effective permeability no not now our system is having major faults explicitly in the model finite difference as you said may not work very well in that case then upscale those smaller features and then you have a matrix so okay one thing that I put this scale for shape formation things are much more complicated so as you see you start with the matrix or macro fractures etc you have nano scale diffusion gas this is I'm talking about gas not the oil oil does not have that much absorbed gas but the gas formation shape formation have a lot of absorbed gas probably there's no gas in the absorption state state then the pores itself because pores is low so basically we start with diffusion from the nano pores then it goes to you know macro scale which is the normal where the the core itself and then there the flow is mixture flow not necessarily darsian flow then we go to macro scale which is you know you have many fractures macro fractures etc and these are like a dual porosity then where you have to do upscaling then you have a macroscopic scale explices the other fractures and finally you have hydraulic fractures so as I said you know compared to carbonate natural fracture reservoirs this is much more complex due to diffusion due to desorption these are non-linear things it's very difficult to solve with many many parameters finally I'll come to last slide in the oil industry many years I mean maybe 50 years we use the sugar cube model whether numerical, whether analytical it really doesn't make any sense and many many years we thought that this sugar cube model is a you know epoximate model for fracture system it is not basic and simple models for fracture reservoirs but there are few reservoirs they can be applied where you have very very small matrix you don't have very large explicit fractures you don't have faults and in this simple model we have two parameters lambda omega which is one is related to matrix parameter the other is porosity when I put those pictures you cannot really represent this complex system with these two parameters thank you very much let's open it up to a question for the three panelists first question well done I'm doing a real world field test my question to you is how well can you assimilate even that in-situ test you have a pretty good idea of the parameters how well can you assimilate and depending on that answer what is the prognosis of assimilating other real world field tests where we don't even have half the data that you have so there are many aspects of the observations some part of the data are easier to assimilate we're very proud that we predicted the fracture propagation direction based on the thermal gradient which it causes the stress gradient we predict how where the fracture is going to propagate so the shape was not exactly right but the direction was right the fracture initiation so some of the unexpected results come from the sudden pressure changes and also a challenge also it's a very important merit of the experiment because now you not only need to match the pressure data you have temperature data you have tracer data so it's actually very hard to come up with a model that can cover all these aspects but that's the value of this data set where we have many teams and modelers working very hard trying to do better model and understand more it's an ongoing process so how about the prognosis for assimilating when we don't even have that data it's hard to but now after seeing this much data in the real foresight at least now we know what to look for it's more inspirational so in the forge if we see interesting pressure behavior then we know there are many possibilities then we knew 2-3 years ago Sulfide on your equipment did anybody analyze that for gold? No Now the questions Lynn So I'm struggling to figure out how to ask this question so I like Fickery's picture of the complexity of the transport in shale because it has multiple length scales and it has multiple transport scales so he talked about adsorption and diffusion and there's some local permeability through the fractures and then transport through the bigger fractures to a well so I'm trying to think about how that would translate to a geothermal system and maybe one in which we're trying to induce a set of fractures that would cover thermal energy effectively allow transport through the system now it seems to me that not only do we want permeability you need to get fluids in and out but you also need to have some surface area because if you only have one big honking fracture then it doesn't take very long to get that one the heat unloaded from that and so there's a combined problem where how do we generate the kind of fracture system that you want for that kind of rock and then of course how do we work out what the transport properties are that seems to me it's fundamentally multi-scale in lots of ways and quite challenging to put together all the pieces that go with that and of course I'm not an expert in geothermal systems so I've probably left out two-thirds of the important stuff so I'd like the folks who are expert on oil and gas recovery fractures to say what I forgot there and then maybe one of the geothermal types could respond to the overall question okay so basically if you forget the absorption etcetera I think rest of my slide applies very well to geothermal system because geothermal system especially if you have a carbonate rocks they have all those complexities so you have a one poor scale as you mentioned second the rocks micro fractures small fractures etcetera big fractures and the faults and faults are big scales so basically we have many scales I think the problem in geothermal as well how we are going to reduce this scale at a manageable level probably we need more work some of similar experiments we can reduce this scale otherwise we cannot simulate and of course we can without simulating we can generate electricity for sure but to understand and also to enhance I'll tell you something interesting you know when you are producing who cares about fractures if you have good productivity nobody cares really nobody cares it took 40 years for Aramco and earlier Chevron etcetera to realize that cover field which is the largest field is fracture reservoir 40 years they produce 5 no 50 60 billion barrel of oil from that reservoir we didn't know that it was fractured what happened when they start putting horizontal wells faults and fractures coming constantly then of course the 80s 90s 3D seismic was not good 93 95 they did really very good 3D seismic all of a sudden it becomes fractures Gawar is today is a fracture reservoir so what I am saying that so when you are basically what happens when you are start injecting anything then fractures hits you so today like some of the big fracture reservoirs many others their water cut is 95% many reservoirs in fracture reservoirs in Oman is 95 to 100% they are still producing basically what happens because when you are happy you are good PI you don't invest but then you inject water water comes to well one week later then the problem starts but now your cash flow is not allowed to get out of data add a different twist on that because the way you ask the question implied perhaps an interest in also how do you make the fractures because he is talking a lot about fractures that are there and they are conductive but in your enhanced geothermal system you might be actually trying to create the fracture system and I think a couple of things I would point out just by way of analogy the the DuVernay case that I showed you they fractured one well with the usual viscousified fracturing fluid which over time was the obvious practice for creating massive fracture extent the other they did was slick water and historically in the Barnett the discovery that finally led to all the success first with natural gas and then with oil was slick water which was counterintuitive because that's not the way you carry propant but it turned out you don't need much thinking propant as Nathan Mann said because the rock permeability is so low at that point that the crack is mostly what you want and it turned out that the slick water was working and now the other point is the material because I think this source rock material is different from sandstone a lot of people make the mistake of saying hydraulic fracturing enhances permeability normally no but maybe in shale yes but it's not really the matrix permeability you're enhancing you're creating permeability with a secondary fracture network so I don't know the materials for the geothermal systems probably aren't shale like but to the extent that they might be or that you might want to reassess what kind of rock you're looking for these material properties really matter and how you go about creating fractures could really matter through a crack or a pour when you have you know the relative permeability is not right so it's easier to put oil through that it's common, it's just a basic physical principle now what I have observed is in a Brazilian field in the sandstone reservoir I've seen lots of wells build in the same reservoir and the interesting thing about it I had a chance to examine how the wells were performing in different spots in the sandstone and where you had high density fractures where your density fractures were high and your sandstone permeability was high you got a much better well so that was a turn on thing so all of these so your porosity enhances the rock and the fracture density enhances the rock for flow so all of these things you have to keep in mind and but the main thing I think your question is relative permeability is putting water in and getting it back sometimes it's a little bit difficult in smaller pore spaces can I make a comment from the geothermal side of things and talking about conventional resources see if I can articulate this in terms of understanding really those favorable settings I think we're still sort of in the infancy I mean we're decades behind the oil and gas industry I mean just think of structural and stratigraphic traps that basic science was done decades ago and we really just begun in the last decade to understand geothermal systems in that way and so you can think of for conventional systems of course and we need that source to be connected to our reservoir so source rock, reservoir rock it isn't too different but you need a deep connection of fluids so how do you do that with natural permeability and there's lots of combinations that you can do that and you add it up for like the box we did in Nevada it's 10-12% of the area but not every one of those favorable settings is going to be a system because we still don't understand the hydrology behind it and how recharge occurs in these systems so what I'm getting at is there's a huge potential I think in conventional resources not that I'm not minimizing EGS in any way because that's critical as well but we're at the infancy in really understanding the connections between what's to say deeper levels in the crust not the deep crust but deeper levels and upper levels and if we can get to the point that the oil and gas industry has gotten in understanding connections between source rocks and reservoir rocks and permeability and so on and porosity with geothermal I think the sky's the limit just for conventional resources so there's a lot of work to be done and once we establish the reservoir the detailed modeling and so on is absolutely critical as well but we still need that sort of broad scale modeling So this question to the geothermal folks here and what I want to bring up is an important point that Christine made and it has to do with the horizontal layering in the rock that you're fracturing so there's two points that I think she made and I think it's important to recognize this is that there's dissipation of the frack energy along these horizontal planes often and of course with prop and getting them around corners is just not the easiest thing to do unless you can make them walk or something like but the question is how much horizontal layering do you have is that an issue for you because there is if there's horizontal layering the thought of dissipating the energy of the frack along these horizontal beds is critical now we have mechanisms to avoid that we've got diverters and things like that but you'll run into the same problem we have today in the oil business which is don't want to spend the money to do that right so that's the question how much horizontal layering do you have in these reservoirs geothermal reservoirs that you're fracking into say one more thing one of the things that I observed in these basins is the fact that a lot of the things that are deep into basins that we use in the unconventional world are turbidites they're just turbidites so you've got this uniform turbidite these flows and these fans or whatever is coming in pretty fine grain material like in the Delaware Basin in the Texas there so the stuff is very uniform you can take a log over here in this side of the basin or another one over on this side and you can match the continuity across there correlation is just fine all the way through that turbidite system because the pulses that have come out there sequentially and covered a large area out of New Mexico now here's the trick though I think that you see is you want to use the fundamental geology of depositional environments now we hadn't talked a lot about that specifically I'd use that term but the first layer I put down is a depositional environment layer so I see if I can see these fans that point bars and things out there coming out and match the sinuosity of these things into the basin there's a lot of work but if you have that layer down pat and you look at the net and in turbidites we know what we have lots of bomber sequence and layers and so forth in this thing so what I find out is that you want to examine where your fundamental basic permeability and porosity is in the conventional sense in this network and then where you find the best conventional permeability and porosity and you can impose the best fracture density on that man mate that's a good shot for you so you've got to stack these things in your mind maybe that's something that the machine learning can help with in geothermal though we don't typically have these nice sedimentary sequences you know they're commonly in volcanic terrain and you have ignimbrates or other volcanic units or the host rock for the actual reservoir and not the source rock per se but so or you have actual fault zones that are probably the primary reservoir for geothermal fluids so I mean there's a couple of examples where geothermal fluids like in the Salton Trophy Imperial Valley Southern California and it looks like there you have such huge flow rates because the rate of extension is so high and a pull apart in the San Andreas four centimeters per year you get enough flow rate in the outflow in the sedimentary sequences to provide a consistent reservoir that you can put a number of straws down into and sustain a system for decades but that's relatively rare otherwise it's pretty extratigraphy in the Salton Trophy in some other places too but that's relatively unusual usually not but those rocks because the temperatures are so high I would tend to maybe call them as metamorphose rather than diagenesis very high temperatures, very high salinity things have changed a lot from the sedimentary body but even if you get metamorphic layers you can have horizontal layering metamorphic shifts and the like so you can still have this issue of dissipation of energy along those horizontal points perhaps I'll draw this panel session to a close so please join me in thanking the three panelists and we'll reconvene in 15 minutes so we have on the schedule to take a very brief break and then we're going to have our wrap up discussion Bridget has agreed to lead that so let's come back promptly at 2.45 if we could which is 11 minutes so we can have time to have a good conversation there's probably a continuation of this but with a few more key themes I think one thing I'd like to touch on which we didn't get a chance to argue about but I will mention that came before the component of fracture resolution so I think that the observations that Colab was looking at the potential closure of that fracture that's the problem so thinking about I think we put the phone about that some of the shear fractures were closing through time and I didn't know as I didn't get a backup that I would be able to talk about it but we need that fracture to be extended to the term it could easily be that there's a fracture so I think yeah so I think there's more to yeah so I think there's more to come there so what I plan for this is just to summarize a few of the things that I'd like to talk about for the next few days that probably opened up a number of observations opportunities that we had with the observations that were located around here so which were the questions that we had for the Colab sessions which used to be fine in the few days before it used to be fine so if you're there an hour and a half before yeah you'll be good if you just get an Uber from there mine is 5.30 oh you're playing it 5.30 but you'll be fine the Reagan is 20 minutes at 3.30 you'll be out the door yeah so what I'm from college what what what what what what what what what what what what what what what what what what what what what what what what


Can't even see me It's dark as f***ing this thing bruh Is it even on? Oh s*** this is recording And I'm swearing Madness Here we are Live and direct, shizumi Jamie Walker The Scottish women are me ball up Come on you Come on Looking good Jamie Fresh That's awesome That's what you do Right up Do a few walks more then He looks really really excited Oh I can put these on the outfits The light is perfect mate The light is perfect you know what I'm saying Can't even celebrate 50 cops Lengman Yes So basically This light is metro booming See I got my socks light And I'm sick Because obviously It's the low thing What? Who does the low socks?  Go on, shadow a box Nice We angle We angle That's the only pass we made today That's the only pass we made today Lengman for me That's what we did Television Good to do You're just taking socks down Yeah It's not like a cycle You're jamming me up please You don't want shorts You don't want shorts that No That's something on the ground I see him Hang on a second I need light Because I'm Darker Darker So Just finished up here The light is just beamin' in my, all right. When we go through that white, oh-ho! Yeah, see, this is nice. I need one of these. So we just finished up doing the new kit lunch. As you can see, black and white suits me perfectly, obviously, you know. Create your body. Yeah, so, that's a wrap. Goodbye. A little bit, a little bit. Ha-ha!