John McLennan (U. Utah): Utah FORGE: Hydraulic Fracturing for an Enhanced Geothermal System (EGS)

excellent i hope that's okay john if you record absolutely kind of taking on the role which is not mine here i think uh watching [Music] yeah this here and we're right on back i should shut up okay so hi everybody i hope you are all doing great welcome to the second wish of the semester today we are delighted to have with us john mclennan from the university of utah john will talk about the first eds project for which his co-pi with john moore that we've already had over the summer for fish if you missed it the talk is available on yale youtube channel john got his phd in civil engineering from the university of toronto in 1980 and has more than 35 years of experience with petroleum service and technology companies since 2009 he has been a faculty member in the department of chemical engineering at the university of utah so thanks again john for accepting our invitation and the floor is yours uh ching yoo thank you so much and thanks everyone for this invitation um and i'm going to talk to you a little bit about forge and i'll i'll specifically talk about hydraulic fracturing and forge is a department of energy venture it stands for frontier observatory for research in geothermal energy and as i indicated doe is sponsoring this but we've been lucky enough to have many stakeholders local statewide and uh certainly our congressional representation as well to whom we're very very grateful now what is all this about frontier observatory for research in geothermal energy well as as ching you mentioned my colleague joe moore gave you some basic introduction about the forge site so i've tried to put together a talk that's that's um going to follow on from what joe likely talked to you about and what he what he probably first did was introduce the difference between enhanced geothermal systems and conventional geothermal systems well it's it's pretty straightforward conventional geothermal systems have three attributes and those are temperature at a adequate temperature at a depth that you can drill to fractures within the reservoir and fluid in situ fluid that can be movable uh within that fracture system so that you have a convectively dominated fracture system where you can produce fluid to the surface convert that to electricity or potentially direct heat um and then re-inject that fluid well in most parts of the country as as we know particularly uh away from uh tectonic hot spots we don't have all of those elements we can drill deep enough to reach high enough temperatures but there's there's no for not necessarily adequate fracturing and there's not necessarily in situ fluid so what if we took the opportunity to uh introduce natural introduce fractures and add fluid so that we had all three components and in fact this is the concept of enhanced geothermal systems where you have two wells that are interconnected by hydraulic fracturing and you can circulate fluid through this hydraulic fracture network and it acts as a heat exchanger so it's it's a pretty simple idea and you can see however that we've been trying to do this for 50 years since the work at fenton hill in the ams caldera just outside of los alamos new mexico and you know frankly none of these have been tremendously successful commercially i think salts is maybe generating a megawatt of electricity a megawatt of electrical energy and cooper basin in australia was a scientific success but a commercial not successful commercially raft river there's been some success there it's a it's more like a hybrid egs situation and we won't we won't talk about these other things but do we recognize the opportunity for enhanced geothermal systems and they also recognize the difficulties that we've experienced over the last 50 years so they initiated the forged project which uh has been going on for the last you know five six years and a number of sites were considered but ultimately a site in central utah was selected because it had the attributes that are appropriate for an enhanced geothermal system and those include adequate temperature 350 fahrenheit we're we're actually closer to 430 440 degrees fahrenheit at the depths that we're at and those are depths that are within uh relatively easy drilling depths um it's a situation where you're dealing with impermeable rocks and and and the reason for that is that you're looking for a system that has conductive heat transfer rather than convective heat transfer as would occur through the natural fracture systems in a conventional hydrothermal geothermal system you're also looking for a situation that that people at your facility can uh dramatically appreciate and that's a situation where there is relatively low risk of induced size seismicity and and this area has been monitored by the university of utah seismograph station since the since the early 80s and it's relatively benign and the potential is low for significant uh seismicity associated with with the egs operations low environmental risks this this is is really in in in a desert area very little wildlife uh no no agricultural activity uh other than some pig farming but that that that happens in barns rather than on uh on the landscape and uh no potable water that's that's really relevant here and then as as we've mentioned that there's no interaction with a conventional hydrothermal system so the forge site was selected and the obligations and the conceptual agenda at forge are to create an in-situ geothermal laboratory and this has happened as shown in this schematic by creating a heat exchange system and uh so the first and first obligation is to drill this blue well and that well has been drilled that well has a total depth of just under 11 000 feet measured depth and it's about 80 just about 8 500 odd feet true vertical depth it's drilled at a 65 degree angle in the direction of the minimum principal stress and the second step in this operation is to create a network of hydraulic fractures right at the end of this well right at the toe of the swell and you can see it's it's right in in the in the toe of of the first well and grow those hydraulic fractures upwards and then subsequently drill a second well to intersect that fracture system so that now you've created a small heat exchange system but notice that you've left most of the lateral section of these wells open for further research and and that's that's part of the obligation of the forge project is to make the this section these sections of the wells available for research by uh through fos and issue issue awards to look at stimulation perforating logging numerical calculations uh back analysis development of of uh isolation systems etc etc and so so that's that's the concept of forge in a commercial situation you'd have more than those three fractures that i've shown that ideally you'd have fractures all along the length of that lateral section and you'd be circulating cold water down wet the blue well it would pass through the hydraulic fractures and be produced out through the red well and at the surface you would either flash the steam or run it through an organic rankine cycle binary plant both ways creating electricity well one of the questions that you may ask is is you know why did you not drill both of these wells at the same time and uh the the answer to that question is historical and it's things that we've learned from past experience and and and actually one of the best demonstrations of this is the stimulation that was done on a couple of wells at los alamos at fenton hill in the jemez called in the in the night early 1980s and and later on in the 1980s as well and there were two wells that were drilled there was well ee ii and there was well ee-3 and these walls were sub-vertical you can see that this is approximately the scale or maybe 30 degrees i can't exactly remember what but the stimulation was to go from was to stimulate one well grow that fracture to the second well and develop a connection and significant stimulation was carried out um on ee-2 but unfortunately this is this is what occurred and and and you have people on staff that are more expert than i am at this but you can see the production well this is a plan view and you can see that these wells had slight angles the injection well and the production well and you can see that most of the microseismic activity was distal from the production well so there wasn't an adequate communication so one of the lessons learned from los alamos is to drill the first well do some sort of a stimulation monitor the micro seismicity use whatever technologies are available to characterize the cloud of evolving hydraulic fractures and then drill a second weld to intersect that cloud and hopefully there will be an effective intersection between the fractures that are created and we'll talk quite a bit more about that as we proceed through this talk so where are we now we have drilled that first well okay that first well is known as 16a 7832 and often we'll just call it 16a and you can see that that well has been drilled here's a view an aerial view looking to the west this well started where my cursor is and it was drilled down at a 65 degree angle at an azimuth of 105 degrees which is pretty normal to what we think is the direction of the maximum horizontal principal stress and so by virtue of that you have the potential seeing as the minimum stress is along the length of the weld the potential to create a multiplicity of fractures ultimately communicating to a second well drilled immediately above that the other wells that are of interest are 5632 and a well that i had that has been drilled that i i need to update this slide drill right where my cursor is and this original well 5832 those three are all vertical wells varying in depth from 7 500 feet to 9500 feet as i recall and there will be seismic monitoring equipment installed in those wells prior to the stimulation along with the surface network of uh um of of geophones and and other instrumentation so that we can do our best to triangulate on the chronological development of microseismic events and and and pick where the fractures are growing so we've drilled that well and just i'm not going to talk much about that well but just some of the highlights and really the success stories and it's not just hydraulic fracturing it's drilling and reservoir characterization that have been very very effective on on this well you know prior to drilling this well the geothermal community largely used roller cone bits those are the bits that you see on television from oil well drilling in the 19 up through the you know the early 1990s even these days people are using polycrystalline diamond bits but the geothermal business had not frankly changed it was still using roller cone bits they were getting rates of about 8 to 10 feet per hour and bits were maybe lasting for 40 hours we said on this well we're not going to do that we're going to drill with poly crystal and diamond compact bits which are bits that have uh cutters with industrial diamonds brazed onto these tungsten carbide cutters and uh they've been used in the oil industry for the past 30 odd years plus i mean they keep they started in the 70s but almost exclusively these days the oil industry is using that type of bit and ultimately by the time we had finished this well um with with many many developments we were up to drilling 50 or 60 feet per hour and bits lasting for 700 or eight hundred feet subsequent wells that have been drilled we're now drilling up on the order of 100 feet per hour and and there was a bit run lasting 2000 feet and so this is this dramatically changes the game in terms of drilling because drilling has historically been a huge cost that is potentially involved in creating a geothermal commercial geothermal plant and so now drilling costs have been reduced um costs for casing and other ancillary equipment and and casing design are becoming more uh dominant in the cost structure as as this goes on but nevertheless drilling has been an important element also from the perspective an engineering perspective um not not only was the drilling improved by the bit design but it was improved by actually using the bit as a laboratory and careful monitoring of what goes on at the bit um in particular what i'm just showing here and just illustrating are calculations of mechanical specific energy mse and so mse has been uh enfranchised by the oil and gas industry since about 2005 and it really started to become involved in the geothermal industry with some of this recent drilling where you're looking at an expenditure of energy each one of these terms is energy normalized per unit volume drilled and that gives you units of psi if if or a megapascal or pascals if you go through the calculations and you can see there's a term here where this is the axial energy expended wob stands for weight on bit so that's the force that is applied to the face of the hole so it's it's an axial term and then you've also got tor oh that's torque and rpm revolutions per minute so this is a rotational energy expenditure normalized per unit volume drill and if you minimize this term and watch this term it it really helps you with um understanding optimizing your drilling parameters and and and really has led to improvements in drilling so you know a couple of messages from this talk is that even already i think forge has contributed substantially to improvements in drilling we've had some nice um reservoir characterization developments um we we have run uh surface reflection seismic uh uh the resolution of that seismic has has been difficult largely because there's about three thousand feet of granitic of alluvium derived from the mountains to the east um and uh below that are granotoid bodies that have relatively high impedance and so difficult what surface seismic has identified is this contact rather than than significant details within the granitoid however while we are drilling this well in other wells we've done significant amount of logging typically quad combo as well as image as well as imaging and one of the logging techniques that was particularly effective when we were drilling recent wells including the inclined hole has been what is called through bit technology and the reason that we had to use through bet technology was because the temperature exceeds the capability of many of the existing logging tools and service companies aren't anxious to upgrade their temperature capabilities because they have not yet appreciated that there will be or should be or hopefully will be a significant geothermal market so how these tools work is that you have you run in the hole on tubing and at the bottom of the tubing you have a bit but that bit has a hole in the middle of it okay and so you you you can run in the hole with this bit and the fact that you have the hole in it and ports in that bit and above the bit means that you can circulate chilled fluid so when you're drilling these wells you're chilling the fluid because uh the high temperature will devastate the bits um the the the the diamond structure will degrade more rapidly with temperature and so if if you can cool a hole it helps and similarly with logging techniques you can use conventional logging tools if you can bring the temperature down enough and so the basis of it this is to run in the hole and to circulate through that hole in the bit and then after you've circulated enough and you've cooled the hole down enough you take the logging tool and you actually pump that logging tool down it's got a little parachute or device on the end that allows you to pump it down inside the tubing it is pumped down inside the tubing and it latches in the bit here but it extends outwards in the bit and so you pumped your tool in you've got it connected to your wire line you make sure it's working then you disconnect your wire line pull the wire line out of the hole and then you come out of the hole with your tubing you the the drill crew pulls the tubing out of the hole progressively and as you're coming out of the hole you log the well and the the logging data are recorded on memory down hole fantastic uh least successful uh for running quad combo you know gamma porosity resistivity and digital digital uh sonic data recorded also through bit runs with formation micro imager and we have separate runs with ultrasonic borehole and imaging devices so really some very interesting opportunities that are brought to mind because techniques are available to overcome some of the conventional logging difficulties and you don't have to run tools and doers and things like that and we're going to look at some of those logs in a minute but let's sort of put this granted in in perspective okay people at mit are used to right from the days of bill brace uh you know people are used to granite at mit not everyone is and and and people you know like to compare see how it differs from a shale and what you can see in this plot is that typically it's a higher modulus material that's no surprise to any of us in poisson's ratio we can't tell too much from that typically the unconfined strength is high it's nothing like a quartzite necessarily but it's it's it's it's modest and high the interesting thing in terms of the measurements that have been done are that the angle of internal friction is particularly high and so the effective confining pressure is going to be substantially felt because of that you know you think of a more failure envelope this is the slope of the more failure envelope and it's it's much higher than what we would expect for you know many many sedimentary rocks that we deal with the other thing that is high is typically it's high but it's not enormous is the mode 1 fracture toughness now the the message that comes here because of the strength of this material and an elevated fracture toughness is that it is going to be relatively difficult to break this rock i haven't shown tense out strengths but let's presume they're an analog to the um the fractured toughness um that these are are tough materials and they're going to be difficult to break and indeed we found this from some of our experience in terms of trying to fracture fracture these reservoirs and and and what you see is probably the fracturing is going to be dominated by pre-existing in-situ fractures that exist in this formation and that's going to be sort of a theme for part of this discussion that we're going to talk about the roles of natural fractures and how they come to bear in terms of the overall hydraulic fracturing process to connect these two wells you can also see the matrix permeability is low now are there fractures in this formation well let's let's just look at some of the observations uh this these are outcrops they outcrop approximately two kilometers away and this actually is the formation of interest this is the granite the granatoid body uh there has been a rotation and and so uh and and uh uh there had there has been a rotation i'm not gonna necessarily show that i can't remember whether i show it or not to be honest but there has been a rotation um and uh the formation is exposed here but it's at a depth maybe about three to four thousand feet um uh with alluvium on top of that in the area of interest to to the west but what you can see at the surface and certainly they're exaggerated by erosion is and and by uh stress release is that there is a network of natural fractures that we would anticipate existing in situ and indeed from the fmi data these are data that were taken uh from the inclined well and you can see these data came from through bit logging in and it really gives a pretty good representation certainly larger diameter tools that that are run in open hole are always preferable but something that can be run through tubing seems to give good results and what you can see from these results is you can look at the panel on the right and you can see substantial indications of many many natural fractures that exist along the length the length of the wellbore now these fractures were determined from a formation micro image imager a resistivity device um and and you basically for those people that aren't familiar and i think everyone in in the seminar is familiar is that you're mapping resistivity and here we have the circumference of the wellbore unfolded and this stands u stands for upper up and d stands for down r stands for rock right and l stands for left well we've got those numbers in here because it is not a vertical hole if it was a vertical hole you would be seeing compass azimuths along the top going from zero to 360. but you basically unfolded the rock and you're characterizing the fractures that are present we've done a a similar study with dipole sonic and you say well how do i do that with dipole sonic well what's being done with the dipole sonic and and uh um i don't pretend to be the expert here is that they've evaluated the entire waveform of the dipole sonic and by virtue of looking at at some of the lower frequency events they be able to look for reflectors that are away from the wellbore and so it's you know deep sonic monitoring and and schlumberger is not the first person to have this i think baker had it a number of years ago um but schlumberger has mapped reflectors that are 30 to 60 feet away from the wellbore and we're attributing those reflectors to being natural fractures of some significance and you can see from the rose diagram to the upper right that the induced fractures are trending just east of north shown by the the the rose diagram uh the the dots or the poles um and so so the the maximum horizontal principle stress is inferred to be a little bit east of north and so this well was drilled a little bit south of east so that it would allow fractures to be created in a transverse fashion and so this was a very very nice addition to the fracture mapping program it provided to me at least some confidence that at least some of those fractures detected in fmi were fractures of significance many of them i personally believe are are are small short fractures that are associated with with thermal relaxation because we had to cool the drilling fluid as we were drilling in addition in these wells a significant amount of work was done for in-situ stress measurements trying to do extended off tests and diagnostic fracture injection tests almost exclusively when we were doing these tests there was a failure of packer elements rubber elements to use to seal the zones we did have some eventual success beca even after the packers failed because we had installed um stout casing in the well and we were able to pump down the casing and actually do diagnostic fracture injection tests at the tip of at the toe of the inclined well so that inclined well it was cased all the way down cased and cemented all the way down except for the bottom 200 feet and so in that bottom 200 feet we set a packer just inside the casing that pack and and pump down tubing through the packer and into the open hole zone below that packer did not hold but it didn't matter because in this particular case we were able to continue to pump down tubing and by closing the annular bops at the surface and pressurizing the casing as well as the open hole we were able to fracture the open hole section and fracturing that open whole section we we did a number of tests and and and the things that are of interest are um the the panel on the left shows low rate injection and some determination of in-situ stresses from evaluation of the closure uh the middle panel shows breaking this formation down by injecting it five barrels a minute for oh i don't know two and a half minutes short test and then shutting in for 18 hours or so monitoring the pressure decay inferring um the in-situ stresses and the final panel on the right is is interesting to um well at least people that that specialize in this area is that what this involved was a cyclic flow back and shut in so flow back for 30 seconds shut in for three minutes immediately after we stopped pumping so you can see here that the rate was about five barrels a minute it's shown in blue in the right hand panel and five barrels a minute here the pressure at the surface was just under 3000 psi we pumped five barrels a minute this was the third cycle this was and in this in the second cycle we shot in the third cycle we flowed back shut and flowed back shut and flowed back shut in and by processing that data um using um reciprocal uh rate normalized pressures and equivalent a mass balance time looking for inflections on that we were also able to infer the in-situ stresses now the thing that's important about that cyclic injection cyclic flow back is that look at this it was done in about 3000 seconds whereas at 80 000 seconds in the previous test we still had not finished finish the test so we see some real opportunities for flow back but that's uh i talk about that because um it's something that interests me in particular okay but something that interests the general audience in particular is the reservoir characterization and the success that we had the reason i'm showing this is is that it it shows the success of the fmi at the left so you can see at the far left the static fmi section um um in track two well i guess it's not quite track two but in in in this panel on on the left hand side you're seeing a dynamic fmi where there's a local over a ten foot interval or so the colors are enhanced and it it shows more of the of the fractures and and and and the structure of the material i have a rose diagram showing the stresses are fundamentally north east in this particular case and what what's interesting to me are the static and dynamic ultrasonic borehole imaging very very beautiful results from this showing the static image is unclear the enhanced image uh is is the image that's in the second panel uh from from the right and what you can see here is you can see some sort of drilling induced fractures that are acting just and this is from a vertical section in a vertical well just east of north consistent with something like this and just west of south 100 degrees off but the interesting thing is is that you start to ask yourself whether these are uh on echelon fractures or whether this is just a function of some sort of a structure if it's on echelon fractures it suggests that this vertical well is not 100 aligned with the um it's not necessarily vertical and horizontal that that the stress field is not 100 aligned with the wellbore uh we have many people that dispute this and and um i'm very interested in alternate opinions as to whether or not this just suggests material anisotropy or some sort of rotation of the stress field and the rotation of the stress field is not out of the question because in recent times the overall block of rock has been rotated as well nevertheless the message from this is that there are natural fractures present in in this in this reservoir there are drilling induced fractures and we want to consider the consequences of those fractures in terms of designing these three stimulations that i've talked about now how are we going to do those stimulations well pretty much all along we've been looking at doing fluid injection and particularly high rate fluid injection uh to create hydraulic fracturing and that's uh ultimately being the interest uh you know being the technology that has been adopted in many many many parts of the of the world where people have done these measurements and you can see that in these igneous rocks the bulk of the injections have been hydraulic and that is at either high rate or low rate high rate you're going to favor extensional development and hydraulic fracturing low rate there is the potential for hydraulic shearing and self propping and we will do a little bit of low rate injection to try and evaluate the potential for hydraulic shearing you can see that there also has been some acidizing that has been done we're hesitating to do acidizing because this is dominantly a salicious formation and that the most effective acid in that formation would would be a mud acid which is a blend of hydrofluoric acid or fluoroboric acid probably and uh and hydrochloric acid um and it it it's so hot that it just may spend so quickly we just don't know how acid is really going to perform here without a substantial amount of cool down acid has been successful elsewhere in particularly in hybrid type situations and then there has been some thermal injection done the raft river project that i mentioned really benefited from thermal injection where the cooldown was associated with a reduction in the total principal stresses and ultimately some sort of fracture evolution that was associated with it so if somebody's interested in thermal stimulation the publications on raft river are a good example the only caveat there is that we got raft river to be successful but that was after injecting several billion gallons of cold fluid into uh a an injection well we were originally given that injection well because it wouldn't take fluid and the fact that uh thermal stimulation was a success was reflected by the fact that the organization ultimately wanted the well back so how are we going to treat this well we're going to we're going to do hydraulic fracturing that is that is the ultimate decision in this particular well and uh we can ask well how is hydraulic fracturing or hydraulic injection at least worked in other scenarios well in in the fentanyl scenario we showed you the the diagram earlier that that there was an abundance of of microseismic activity for a large um injection that was done in december 1983 but uh there there was limited interconnection between the two wells and the the directionality of the growth of of the cloud whether it was biased by by measurements or whatever seemed to be away from the the production that the recipient will and so so there are challenges in terms of you know fractures going where you want them to go at rosemont always in in cornwell that was also reflected because there were some indications that the fractures grew downwards when injection was carried out there the geomechanical calculations done for for the forged situation suggest that there will be upward growth salts you can see the patterns there in some of these wells and they show you know you know well there is there is a cloud they're showing that there is some network of hydraulic communication that that is is is trending at least vertically in in ellipsoidal pattern uh basel very interesting okay basel was a situation where high rate hydraulic fracturing uh was was implemented it was ultimately terminated because of of seismic activity but the the microseismicity is is really quite quite interesting in terms of what you see in in in this particular situation and what you can see in this particular situation is it looks like there has been uh growth along some sort of pre-existing feature and the growth has been reflected in terms of some wing cracks and so there were shear initially because of a slightly uh a fracture that was slightly offset from the inferred maximum principal stress and beautiful wing cracks result i mean this is just a classic mechanics example of the growth of these wing cracks that grow and shear but ultimately align with the maximum principal stress um regrettably the seismicity uh precluded this becoming a commercial site so one has to ask well what about these natural fractures and how are they going to contribute if one is stimulating these wells well we've seen a lot of evidence geological evidence uh logging evidence uh um outcrops whatever that suggests there are not natural fractures and one wonders how those are going to impact the ultimate stimulation that is going on and so here are some some thoughts by various people even well before forge in terms of trying to understand what sort of mechanisms will occur well i'd be disingenuous if i said i knew exactly what was going on although my predisposition is that the rock is strong enough that the fractures are going to be finding natural fractures and reactivating and reopening those natural fractures and i'm thinking it's going to be something like these two scenarios here on on the right hand panel the two scenarios at the extreme right where you're going to have a combination between hydraulic fractures and and following natural fractures ultimately propagating um in a plane in the nominal plane perpendicular to the minimum principal stress now where we run into issues these days is is that there's a lot of there's a lot of evidence from some beautiful beautiful pilot studies in in the oil industry where natural fractures seem to be ignored in those particular cases and so you have to ask you know what are the scenarios um and and why would forge be different well the scenarios could be that that the stress contrast um in in these formations may be such that linearly or planar oriented features are are are appropriate i mean these these pilots are are very very strong information where there's been a lot of wells drilled a lot of micro seismic monitoring and and very very um um significant evidence of of planar features and including fiber optics in in offset what in offset wells and so there's a lot of feeling now um by people in the oil and gas industry that natural fractures don't matter and the question that we have in in the geothermal side is that is is that true here or do those natural fractures actually is is this an extreme is this an extrema or natural fractures in the geothermal business are going to be much more much more important because it's more difficult to create uh virgin fractures in in the rock now even within the the oil field there are some observations that secondary fracturing was was was observed um as shown in this publication by halliburton evaluating some of these things but um work by julia gail at the bureau of economic geology in texas is also shown well natural fractures were present some of them were activated but not all of them and the ones that were activated were in a favorably oriented direction so just sort of as we might anticipate so this ultimately brings us to the question is that you know we have this complex reservoir and what are the challenges that we're dealing with in this reservoir we're dealing with potentially natural fracturing we're dealing with a situation that is a high modulus high strength formation and we're dealing with a situation where there's a high temperature so how would one go about doing this well let's look back at history and see if we're going to propose to do anything substantially different this picture i took in december 1983 during the stimulation of that fenton hill reservoir and and what did we pump we pump slick water that's just what we're pumping these days we pumped it at 50 barrels a minute that's you know a high rate and we pumped almost 6 million gallons of fluid with uh 200 mesh calcium carbonate as a fluid or diversion atom this is almost identical to what we will conceive of these days so believe it or not hydraulic fracturing technology has not changed substantially uh the ability to treat horizontal wells and isolate those horizontal wells and has has changed significantly but the treatments have not changed substantially and so we have some questions to ask about the fluids that will pump um whether we'll try and do hydraulic shearing what the role is for natural fractures those are all major questions and still on top of this what we have to deal with are cementing uh technology and i'll show a slide on that that is relevant isolation technology how can we get these packers to actually work at high enough temperatures what sort of stimulation we're going to and what sort of stimulation we're going to use well you say well why is the cementing important well the cementing is kind of important because um we're worried first of all if there are vacancies in the cement that once we start to apply high pressure to the casing whether that casing is going to bulge or fail in those vacancies or if that casing is at risk because of microseismic growth along pre-existing fracture systems we're also worried about the movement of that case there's going to be a poor bond between the cement and the pipe and think about what happens when i pump 4000 barrels of cold fluid down this casing that casing is going to shrink and it's going to shrink a substantial amount so actually one of the things we're considering is whether or not we have to heat the fluid that we're pumping in the hole we'll never be able to get it up high enough but just some degree of heating may actually be relevant to prevent that casing from uh from moving as much as as as we might anticipate it would and if you do the calculations for how much that casing is going to move you'll be surprised it's it's not inches it's it's if nothing if if if there's very poor bond and you decrease the temperature by hundreds of degrees that contraction can be in on the order of 20 feet significant movement is possible also the isolation technology so so you you you have different stages in these fractures and you isolate a previous stage from the current stage by putting in elements called packers which have rubber elements that are expanded against the wall of the casing and seal off the downstream of where you're currently pumping we've had a history of failure obese because of temperature uh that the rubber hasn't tolerated the temperature and also probably because of changes in dimensions of the tubing because of thermal effects and and so um we are looking at situations now where we where we don't have the the tubing attached that those things aren't the temperature isn't as big of an issue uh in terms of uh the change stress field and also looking at different elastomers um on these polymers to tolerate 400 odd degrees fahrenheit and and the pressures won't exceed 8 000 because our wellhead is only rated for 10 000 but psi but but it's a it's a big it's a big deal and so for our stimulation we'll be looking at um at high temperature and uncertain fracture morphology so what are we going to do what what what are we going to do and i'll wrap this up pretty quickly we're going to pump three stages at the toe okay the first stage will be in this open hole section and that will be using slick water and slick water is a is just water and it's it's it's it's it's slick meaning it's got friction reducer added and that what that does is that reduces the frictional losses as you pump this fluid and we're going to pump it at a higher rate ideally up to 50 barrels a minute it will have a organic tracer in it i mean tagged with an organic tracer a separate organic tracer in a second stage but in the second stage it's not open hole it's in a cased and perforated section that as i mentioned is isolated from stage one by one of these uh frack plugs the rubber element that's expanded against the wall to isolate the previous zone so you install the frack plug you perforate the well and then you pump your treatment and and this would be friction reduced water with a different organic tracer the final zone would be about another couple hundred feet up hole and that would be using a crosslink much higher viscosity fluid and that would be tagged with a discrete tracer and also with with a man-made property but this problem is a very very fine mesh micro problem that probably isn't going to impact the viscosity of the fluid what whatsoever and so what we're aspiring to do is to grow a vertical fracture from the blue well up where the red well will ultimately intersect that and we want that distance to be at least 300 feet so that when we drill it um we'll be able to connect to it and and we're going to drill into the micro seismic cloud and hopefully inter can interconnect um if we don't interconnect we'll have to do some remedial treatments uh so we'll be as we're pumping these treatments we'll be monitoring the we'll be monitoring the treat the micro seismicity and hopefully using the microseismicity to guide us as to whether or not we need to pump more than we plan or potentially less than we plan and we want these fractures to grow up but not necessarily uh laterally either along the length of the fracture or perpendicular to the length of the fracture and as i said we'll we'll have guide the treatments with our micro seismicity so we're going to start this first stage and we're going to pump it about five barrels a minute we're going to pump slick water and and we're going to pump slick water because that's what the service pumping companies are used to pumping okay we're not going to pump profit because we don't want to have the risk of that pump of that profit screening out meaning that the problem jams into the fracture and prevents propagation of the fracture from occurring we're going to start at five barrels a minute we already know that we can treat this open whole zone at five barrels a minute because i showed you a diagnostic fracture injection test earlier in the pump at five barrels a minute so we'll pump at five barrels a minute and then we will increment our treating rate um in five barrel per minute increments and i i could say that we did this because of uh sophisticated design but we're doing this just out of caution because we really don't know what's going to happen how the how the reservoir is going to respond and so we're going in relatively small increments and we're we're seeing how the friction develops how how the treating pressure develops and leaving it long enough to get a significant stabilized microseismic cloud once we walk this up to 50 barrels a minute as you can see on this plot rate on the left uh total volume on the right we'll walk it up to here we'll leave it at 50 barrels a minute and then we'll re reduce the rate progressively and when we reduce this rate progressively it's it's what's called a step down test and this will tell us something about the friction in the near wellbore domain uh all along we'll be monitoring microseismicity we have a traffic light system in place and if seismic activity microseismic activity exceeds certain criteria uh then then we'll we'll take actions that range from reducing the pumping rate to actually going home and hopefully the latter does not does not occur uh we've done a lot of monitoring our modeling in in terms of this you know the the the complication with the month with the monitoring is is is the uns that was an alarm telling me to stop um uh is the uncertainty in these parameters and and you can see that we have uncertainty in the strength the fractured toughness the modulus some degree of uncertainty certainly an uncertainty in the fluid loss that's occurred because of of the natural fractures and the variation in the in-situ stresses and the variation in the in-situ stresses is reflected in these simple simulations that we've done here with some planar fracture models that you can see depth here and you can see the stress gradient during here where the stretch is a low stress zone predicted by the schlumberger stress predictions some variations in moduli and if you do some simulations with a simple planar mod model what you can see is that this fracture is captured by this particular reduction in the in-situ stresses nothing that's really surprising to anybody familiar with this whereas if you assume just a constant stress gradient as we have in other models you can see that the fracture height becomes 400 feet here whereas in this previous situation where i showed you here it's much lower it's just a couple hundred feet because it's captured here and so these simulations have shown us that reservoir characterization is really really important unfortunately we don't really know what's what's going to happen and and despite all of the simulations that we've done including a large body of simulations using discrete fracture network modeling used using itasca's excite code um we'll just have to wait and see in terms of what the fractures and the microseismicity show us itasca has done some sophisticated three-dimensional modeling building in the dfns and you can see from the the the plot on on the left this is a simulation of stage one that we see a significant upwards growth we pumped a lot of fluid and it's permeable and the reason i say permeable is because you have flow into the natural fractures that were specified in this model that there was a frictional df in if as in the second part model you say that those natural fractures were impermeable and add a high friction coefficient you get something that's much much more like what one anticipate for a conventional planar hydraulic fracture and indeed no dfm it's just a planar model like what i described before and so from this plot of those we can see that the height we're going to get depending on what we select it's a minimum of 100 meters and maybe substantially higher and based on that that meets our 300 foot criteria so i'm feeling good about what the simulations tell me um i also look at the um the height at which slip occurs and and we're seeing significant slippage upwards and um so even if i am not opening fractures extensionally i've got reactivated fractures that are communicating vertically now the only drawback with those reactivating fractures is the lateral extent that means how far up and down the length of the well where we're extending and we want to minimize that extent because we do not want these stages interacting with each other and you can see that depending on what happens it could be significant in terms of of these meters and so this is this is probably one of our biggest worries and it will be taken into account on the fly that means while we are there doing these treatments to decide where we perforate from one zone to another so my final slide is that from the hydraulic fracturing we're initially just looking at connectivity being able to connect between one well to the other you know ultimately in this project project we're looking connectivity conductivity conformance conversion but today i'm only talking about connectivity and we were able to compare different treatments look at the role of natural fractures we'll wait on conductivity and propane for the future and we may have to do some remedial injection we'll just have to wait and see remedial to be sure that we've connected between the two wells so a fantastic opportunity here and really something that can advance the state of geothermal science and so i apologize for going on long um i um but i'd be open to answer any questions for those people that can stay thanks john for the great talk it's very informative we are now open up for questions i see there are few questions from emmy in chat in zoom chat thank you john yeah maybe if you can i i can't see the chat so if you could read the questions or maybe it may might launch sure i can do that i was just taking notes and putting questions in um let me ask my last question first so basically um you said that people had found in the oil and gas industry primarily that natural fractures don't matter and so i'm trying to reconcile that with mechanical intuition because if if you ask me to choose between you know two specimens of rock to frack i would why wouldn't i always choose the one that already has cracks in it so what would be the reason i wouldn't want a one that's already cracked so i'm going to try to crack it more you know it's just like the fashion industry it changes every year you know if if we looked if we looked five to ten years ago there there was a a huge influx of publications where people were doing you know based on some of the work by pollard and his colleagues you know fantastic work where people were looking at the role of natural fractures in terms of impeding hydraulic fractures and and whatever now what has happened is that we've had specific reservoirs where the natural fractures are less important okay and and and so i think one has to take this with within a just exactly as you said it's a combination of our geo mechanics intuition and really looking at what the characteristics of those specific reservoirs are but the problem is is that these studies have been so widely publicized that sometimes sometimes it's taken as um uh as the norm so this is a situation where i believe that the contrast in in the principal stresses favors um uh fractured controlled fractured growth in a nominally planar situation and that the characteristics of the natural fractures may be such that they do not substantially impede uh deviations of these fractures also in those situations if you look carefully at them there there are publications that suggest that the secondary fractures are indeed sometimes activated so you have to be i mean this is just just like everything that we do these days we have to parse it carefully and sort out what we really is going to believe is specific for our specific reservoirs exactly as you say we believe in this particular reservoir that because of the relatively high value of the fractured toughness the inferred elevated elevation of the tensile tensile strength and the presence of certainly some natural fractures that the natural fractures are going to play a role we've done previous stimulations where we selected zones to perforate and complete where some of those zones had an abundance of natural fractures and some of them had opacity of natural fractures we were able to break down the zone that had the abundance and we could not break down the zone because of well had restrictions that had fewer fractures so this is one of the things we definitely want to establish and um our intellectual preference is that the natural fractures will play a role in this formation and we need to establish the magnitude of that role by the measurements that we're making in this reservoir so so our our opinions are aligned but i don't necessarily agree with everybody uh it sounds complicated but that was a great answer thank you what what does the stress field tell you about the whether the natural fractures should flip do you feel you know the minimum stress and the maximum stress amplitude well enough to infer whether fractures are favorable oriented well that's a loaded question and sorry and probably a rhetorical question but i'll do my best to answer it okay so uh we've got a pretty good idea of the vertical stress just based on assumptions measurements of density okay yeah um the minimum principle stress when we first started to measure the minimum principle stress we were pumping small volume uh microfracs and we were measuring uh relatively small values of of the minimum principal stress like 0.62 psi per foot and that's you know that's that's that's common but it's on on the lower end as we started to pump larger injection treatments defects and and techniques to infer the minimum principal stress we found that um we we modified our inference of the minimum principle stress up to about 0.75 psi per foot and so my attribution is that those lower principal stresses were reflecting near wellbore fractures that had developed because of of thermal cooldown as we were drilling the well so we've we've migrated towards a number that we feel more confident for the minimum principal stress the maximum um originally we didn't have any breakouts in these rooms that the rock was strong enough that we didn't have breakouts so we we had a difficult time making any sort of inference in in the maximum principal stress horizontal stress uh as we drilled these wells we we we did get breakouts but our conventional calculations of the maximum principal stress using these breakouts are giving us values of maximum horizontal principal stress that we that are quite large and and we're uncertain as to whether or not they're realistic so we're still presuming that we're in a normal stress environment that the maximum horizontal principle stress an extensional environment that the the maximum principal stress is somewhere between the um the vertical and and the minimum that we're not in a shearing regime and so we have good comfort with the minimum i i would have to say now we have pretty good comfort with the minimum with the uh um the vertical principal stress but as usual the maximum principal stress is something that um has been a variable in terms of the numerical calculations that we're carrying out and by virtue of of that it can vary anywhere between the minimum and and and the vertical and and that that comes into play in these calculations in terms of governing the extent of the shearing that that occurs we still see hydraulic fracturing but the amount of hydraulic shearing is governed by the magnitude we select for the maximum so um despite our best efforts we're still somewhat uncertain about the maximum prince maximum horizontal principle stress do you think the pre-existing fractures are vertical i mean i'm wondering are they tilted um to the vertical so i'm sorry no you're you're you're by and large those fractures are inclined um somewhat and and we see some shallow but most of them are maybe at um um um a dip of 65 degrees or something like that that they're 60 25 degrees from the vertical so there are inclined fractures that are present and so it's this is why uh where we see this the microseismic cloud growing is going to be really really constructive in terms of understanding what is going on in this formation there was some seismicity observed i think during the earlier the small stimulations do they provide any any help in an understanding or yeah so so you know the this was this was done in 2019 there were there were three zones that that were stimulated in an existing vertical well and we had geophones in a well that was uh um about 3000 feet deep and the geophones straddled the granitic contact there were 12 geophones spaced out 100 feet apart now this well was relatively close to the vertical well that was stimulated and these geophones were um at a much much shallower um shallower depth they were at 3000 feet we were treating at maybe 6 000 feet so we did in fact measure um micro seismicity in the minus two to minus one range uh however schlumberger did not feel comfortable in the location because of of the bias and the location of of the geophones that it was almost looking right down on on where the events were occurring so we're certain that we can create events um and and but we were not comfortable that we could um accurately locate those events at that time and so the upcoming stimulation where we have three wells ideally located straddling the toe of this well and geophones as deep as we can get them based on temperature restrictions and that's about 220 200 220 degrees c and so those those will be maybe at 7 000 feet depth or something like that we feel much more comfortable that we we should be able to see uh and triangulate on events reliably so the question was accurate that that there were uh events that were detected uh the events were in a magnitude range that we were anticipating but we could not in good conscience locate those events i'd like to to jump in because i have to step out and there's one thing i'd like to be able to achieve before doing so and i'll have to hold my questions what i want to do is mention that we have in the room a student in herbert einstein's group his name is perry smalls and he's also a founder of a startup on electrical stimulation cool and he was he was wondering if um it would make sense to be in touch with you guys on the topic of electrical stimulation in concert with with hydro fracking um they're they're they're moving in that area interested in collaborations with the goe and uh um so i guess the broad theme here is you know is is forge open to you know crazy ideas about stimulation uh well i can't say about forge but i'm always interested in crazy uh and it's not crazy well was it robert grace where is paris as paris parents uh yeah but we would i i i would be happy to interact uh and and and facilitate some sort of presentation um so that you can introduce various people to this to this concept yeah and i i can um i guess since i have the floor i'll do a quick i have to step out so thank you so much john i really appreciate this uh we we i think you'll get more questions from from the audience so you know thanks again well thanks laurent and and i'm sorry i went on so long fantastic thank you so much um so just real quick i can actually i can't do that my uh okay sorry but i also want to make sure that people get to ask their questions to john about his talk right so um let's make sure we get those improvements but essentially i just submitted a um a proposal to rpe um and the reviews are pretty good looking at maybe getting it funded if it gets funded but finally six weeks i've also been in contract with been in contact with the switzerland similar to forest but much lower um much shallower batterido isn't it's another like underground lab and they're interested in testing there as well um so essentially what we're looking to do is instead of doing high pressure hydraulic fracturing we use uh the joint heating process to create make the practice really hard follow it up with um with cold water injection temperature differentials create fractures and also do post electric fracking between the two i'm electros um it's pretty early stage but we've got some initial stuff in the lab that i've been working on and looking to do some field trials here and we wrote up a lot of stuff about what we want to do at 4h and the proposal we could talk about it later would be very very i'd be very interested in in uh exploring this further with you and professor einstein okay i'll set up a a call maybe sometime next few weeks yeah that'd be awesome uh well and i and i can set up from this end so that you can have you know the correct people participating okay thank you hey thanks uh i did see one question let's see um so it wasn't it it was a dipole sonic um i'm i i i don't believe that there was much uh differentiation between the uh uh fast and slow uh shear waves and and so i'm not sure how much anisotropy was actually detected i'm i'm a little embarrassed to say that i should know an answer to you i should know an answer to your question i i think that the um an isotropy was actually quite minimal but uh douglas i i can try and find out an answer to that question for you i asked the question uh just curious in general uh dipole sonic analyzation for anisotropy in a highly deviated well is tricky and if you have local induced fractures and you have stress fields that are rotated away from the plane normal to the borehole somebody at schlumberger knows how to think about all that stuff and um in indeed they they parse this data pretty pretty significantly um but i don't have a specific answer to your question and i'll try and find out now very interesting talk thank you so if there's no more question from zoom should we have any question from the classroom george could you have to unmute oh i can answer the first question that the the reason um why were fmi data not interpretable on 1227 and and that was nothing to do with analysis that was that was due to the fact that the the data set had been corrupted uh likely due to a component failure because of temperature thank you and um second question was when you talked about thermal stimulation how do you get the heat in is it using some kind of electricity or um the the thermal stimulation that that that has been conventionally done in these reservoirs is cold water injection or just and and so so it's it's not heating the formation up it's it's cooling the formulation and and so so what happens when you cool the formation as you can imagine is is that you cool you cool the reservoir and there's a thermoelastic uh coupling between the temperature and the poor in the fluid in the fractures and and the response of the cooling formation and there tends to be a reduction in the in the total stresses so with that reduction in the total stresses you you you have a reduction in the normal stress on that fracture and that has that accomplishes one of two things it it either causes uh well it causes increase in aperture for one thing so that you know hydraulic transport is improved but the reduction in the normal stress can also impact the uh the frictional resistance and you can also see shearing events happening and and actually as as we did in raft river you know we inject a lot of fluid there and and over days and weeks and months we could watch seismicity walk along um um a a a mapped uh fracture system so the the rock matrix is compressing because it's being chilled that right it's it well the the the matrix is yes that's correct it's it's shrinking because it's being chilled yes thank you does that does that um walking effect follow a diffusion front that you understand you know it it follows uh a mapped fault system and uh you know the good thing was is that that that the uh that the seismicity was sub-zero um you know whether we completely understand it or not i mean that's that's why i smiled uh but it it looked like it it followed a definitely a major mapped fault system that bounded the geothermal field and so intellectually it made sense and presumably convective change of temperature that is that is absolutely correct again very interesting talk well thank you so much do you have any other questions i guess there's no question from the classroom yeah okay so thanks again john wonderful talk and uh thanks all for attending today's wish and next wednesday we will have yeah fabian from action who will give a talk

2021-12-01 15:39

Other news