Optimize your workflow with the pipeline integrity management system in Canada

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hello everyone and welcome to another edition of our nace calgary zoom webinar series i'm your host brett johnson program chair for nace calgary so with heavy lockdowns and restrictions again occurring in our province imagine most of everybody is watching this from the comfort of their own home which makes me really glad we started up this series in the first place so a big thanks to everybody who's been involved to make this web series a success so far today so today's webinar features sankara papa winsam president of four magnet consulting bankera has provided consulting and expertise to companies all over the world with a focus on internal and external corrosion management sankara's long line of industry contributions include over 100 published industry papers and his own book on corrosion control he is all to act as a subject matter expert to government committees in canada and the u.s sanctuary we're extremely pleased to have you join us today thank you great it's good to be here i'm excited to listen to what questions i'm going to get that's awesome well so can you tell us about uh your presentation today yes uh thanks brad um before somebody asked questions i've lost the first question how many of us are familiar with nays fp0113 pipeline integrity methods and selection if you are familiar with it show you a thumbs up or sent a kind of smiley face today's presentation i am going to discuss a bit of zero one one three for which i am the dpm or this document project manager a fancy title in the new standards committee which means you are a chair with no voice chat the document focuses on selection of pipeline integrity methods but if you read the title it focuses only on selection but not on the implementation also it focuses on corrosion assessment not the whole aspect of integrated management the third question is how does this document fit in in a regulatory environment i am going to cover some of them in the webinar today in addition there is going to be a series of webinars hosted by nays headquarters on this document if you are interested give me a shout we will join together to prevent the document that's awesome well thanks for that sankara well none of this would be possible without our annual sponsors their contributions allow us to provide this webinar series to all of our membership here at no cost so today i'd like to highlight one of our gold sponsors risco corrosion services so risco corrosion has been a long time supporter of nays calgary and ace international all our technical staff either have knee certifications or diligently working towards the necessary achievements in order to satisfy those certifications they believe that nays education along with applicable experience is a cornerstone of their organization rights code success has built off the five pillars of service integrity innovation knowledge and excellence isco occurred and offers a complete set of services and equipment for all corrosion monitoring needs and of course all of our other annual sponsors are a huge reason why you can do what we do our sponsors help fund several initiatives that nace calgary takes on to promote the knowledge of corrosion sustainability and asset integrity to the next generation of engineers each one of our sponsors we thank you very much for your continued support so to see this webinar and some of our past webinars be sure to check out our website at nicecalgary.ca to get the youtube channel link and other details on upcoming webinars so sankara has pre-recorded his presentation be sure to stick around after the presentation as we'll move into a live q a session so please submit your questions to senkara using your zoom client by clicking on the q a buttons on the screen if you're joining us from youtube live please enter your questions in the comments field and i'll be sure to ask them so without further ado here's sankara's presentation first of all i would like to thank neis calgary section in organizing this workshop and thank you all for joining in this webinar i will discuss pipeline integrity methods specifically on their selection and implementation pipelines are the safest most economical and most convenient mode of transporting oil and gas they exist because they convert the lower value hydrocarbons to higher value hydrocarbons that is the dollar value of hydrocarbons at the end of the pipeline is higher than that at the beginning of the pipeline however during transportation some dollar value is lost due to various reasons primary reasons include financial issues regulatory issues environmental issues and risk in operating the pipeline the risk may arise due to improper material selection improper design improper operating conditions physical damage either due to natural causes or due to human activities and of course corrosion the best source for understanding a pipeline performance is the alberta energy regulators statistics if you reviewed the 2017 to 2017 reports you would find that of the thousand incidences that have happened 43 were due to improper material or improper design five percent were due to improper operation ten percent were due to physical damage and corrosion cost almost 50 percent of the incidences fortunately this risk occur simultaneously but at different time during the life of the pipelines if we plotted the number of failures versus pipeline lifetime it would have a boat-like appearance with three distinct phases at the beginning the risk is high but it will decrease with time as we optimize material design and operating conditions or operational conditions the constant operation phase the rest is relatively low and constant with time almost 90 percent of our pipelines operate in this space during this phase physical damage to the pipelines due to earth movement or two-party activities may occur as we continue to operate the pipelines the risk will again start to increase primarily due to corrosion tracking and fatigue almost 50 percent of the incidences happen in this case we implement integrity management program to reduce or to avoid risk during various phases the integrity management program consists of three activities first we assess their risk and quantify it for which we normally use risk matrix though 4x5 or 4x4 grids are available most prefer 5 by 5 grid as shown in this graph with 5 colors red indicating risk being at the dangerous level orange indicating the risk being high yellow indicating risk being moderate greenish yellow indicating risk being minimum and green indicating risk being low before implementing mitigation strategies to bring the risk down from the red or orange zones we normally perform cost benefit analysis or cbe to reduce risk or to increase reliability we incur cost spending money should bring us benefit depending on the types of pipelines operating conditions and other factors the relationship between reliability and cost may take reforms if we implemented the integrity management earlier smaller amount of dollars spent will reduce the risk tremendously as represented in graph e in this scenario penny spent today will earn a dollar in the future this is the most favorable situation if we delete implementation of the integrity management program then the dollar spent will proportionately will increase further the risk reduction is equal to the dollar spent as represented in curve b that is dollar spent today will earn a dollar in the future this ideal scenario almost never happens finally if you do not adequately take care of your pipelines then their risk will reach higher level and huge expenditures are required to bring their risk to a lower level as represented in curve c in this scenario the dollar spent today may only earn a penny or die tomorrow not ideal time once we establish a budget we undertake risk mitigation activities which may be repair or replacement or implementation of other corrosion or risk control strategies again if we implemented the mitigation activities earlier the benefits are higher for instance if we implemented the mitigation strategies when the right the when the risk moves from low to the alert level that is as low as reasonably possible level then you can keep the pipeline operating at low risk level that is in the green or greenish yellow color if we implemented the mitigation strategies when the risk is the alert level then you can keep the pipeline operating either in the alert level or low risk level that is greenish yellow or yellow color on the other hand if we implemented the mitigation strategies later that is only after the risk has reached higher level then the pipeline may operate either in the orange level or in the red level even after implementing mitigation strategies nays standard 0113 pipeline integrative methods collection describes various types of integrity management the most common is pressure testing or hydro testing in which we hold the pressure of the pipeline at a higher pressure higher than the normal operating pressure and monitor if the pipeline leaks and if did not leak then we stop we start the operating the pipeline the second most common method is inspection line inspection is very popular for pickable pipelines for non-pickable pipelines nase has developed the dea program or the direct assessment program which has got four steps step one pre-assessment step two indirect inspection which may involve which will involve above ground service for the external corrosion or modeling for the internal corrosion step 3 is the direct inspection and step 4 is post assessment industry currently uses either inline inspection program or dea program at the 2007 banff pipeline workshop a group of professionals came up with them with the 5n methodology as an all-inclusive integrity management methodology in this methodology the model provides the starting point or it provides the road map if the model predicts higher risk then we implement mitigation strategies we monitor the pipeline once in a while to ensure that the pipeline is behaving in the manner in which the model has predicted or to ensure that the mitigation strategy is implemented are working properly fourth one we carry out maintenance activities as required just like we take the car to the auto shop once in a while for service all these four activities should be coordinated funded and supported that involves upper management as you can see that all other integrity management types whether it is inline inspection or de they are all a subset of the 5m methodology with this background let us now go over various activities we carry out in different phases before we start up operation we must and we will select appropriate material establish appropriate design and then carry out the operation ingly if things do not are not done well or not done properly the pipeline will fail during the pressure testing or the hydro testing asa z662 provides good guidelines on all these activities it should be further noted that material for server service must be selected as per nice mro 175 or iso 1556 also all water used for hydro testing must be removed and the pipeline must be dried before startup otherwise the wear out phase will appear than you plant due to internal corrosion is working on a document tg440 on guidelines to avoid side effects due to hydrotesting integrity management activities in the constant operation phase the constant operating fees is a misnomer in our industry as our operating conditions change hourly weekly monthly and yearly however it is important that we track these changes and understand the implication of these changes for this purpose integrity operating window concept published by american petroleum institute epa 584 is very valuable the premises of iow are that if we operate the pipeline within the optimal operating conditions the pipeline will be safe if the pipeline is operated at standard high or standard low levels far away from the optimal conditions then failure will occur quickly if we sustain the activities sustain the operation at those levels finally if the pipeline operates at a critical high or critical low levels that is far away from the optical conditions established the failure will occur quickly i am aware of a situation in which a particular pipeline was protected with an external coating it was rated to 40 degree centigrade and during operation the temperature exceeded 80 degrees degree just for four hours and that completely destroyed the coating the company had to recode the whole pipeline section so it is very very important to understand the variations in the operating conditions now during the constant operation phase what can we do to prevent physical damage externally happening note the external damage may be caused by events it may be natural or human made probe monitoring using incredometers is commonly used to track variation caused by natural causes such as threats earthquake to avoid disturbance caused by human we have alberta one call program we could also place warning signage between the pipeline and the earth's surface and hope that the construction crew will notice it and stop the construction or we could security monitoring system using for example fiber optic cable that would provide warning as soon as a disturbance or activity has started the most prominent risk in the varroa phase is internal corrosion note that alberta regulations require that you evaluate internal corrosion mitigation program annually nest standards and canadian association of petroleum producers cap provide lots of guidelines and standards that provide tips and guidelines they should be used to assess and control internal corrosion model models provide a good starting point to control internal corrosion however the success of internal combustion model depends on two factors first the ability of the operators to at least provide the mandatory input parameters as indicated in the blue color both construction as well as operation most of our pipelines are constructed using carbon steel so the model internal fitting corrosion model should address repeating corrosion of carbon steel the second thing the model should have the ability to predict the locations of internal corrosion corrosion damage mechanisms pdm and overall corrosion trick considering all cdf to begin with start using standard critical reports to understand and select models test report 21413 provides evaluation criteria using 13 different criterias it also compares 17 commercial models 21410 provides six steps to select an appropriate model first to establish the evaluation instruction criteria is understand what data you have and what you want to get out of the model second you understand your corrosion damage mechanisms pdf 13 cdn can occur during operation internally prominent among them is localized fitting corrosion whatever you do please do not use a model that converts little corrosion rate to localized fitting corrosion science and large amounts of field data collected over 75 years have clearly indicated as given in this diagram that there is absolutely no correlation between general and pitting corrosion rate note that this plot is a log log plot in my opinion using general corrosion tree to predict pitting corruption rate is analogous to being a lottery ticket and start spending the money assuming that you would win the lottery the odds are very very low we can take one message out of this webinar that is this one do not use general corrosion models in predicting corrosion rate the fourth one it performed sensitivity analysis of the model for example if the model is not sensitive to hydrogen sulfate concentration then not use the model for summer pipelines establish boundary conditions for example if your boundary condition if your operating condition is 80 degrees centigrade and the model is validated up to 80 degrees centigrade do not use the model about that temperature finally understand the interior parameters used in the model don't assume that the model is a black box understand the interior parameters signs behind the model if the models and experience indicate higher corrosion rate they need to implement mitigation strategies strategies to indicate internal corrosion include use of cleaning pigs addition of corrosion inhibitors application of internal coatings and among them application of corrosion inhibitors is predominant however just do not use inhibitors without proper evaluation understand the conditions to add corrosion inhibitors inhibitors are not effective under all conditions especially if your operating condition changes the inhibitor may not be efficient also evaluate inhibitory efficiency using android health methods it is very very important standard test methods provide precision and bias statements using the precision and bias statement we can and we must qualify the apparatus the laboratory and the technicians involve the inhibitor evaluation at this stage rotating kit is the only methodology for which there is a candidate test method though standard test methods for other methodologies such as rotating syndrome are being developed finally understand the influence of secondary corrosion inhibitors inhibitor properties secondary inhibitor properties include water oil partitioning solubility motion tendency forming tendency thermal stability toxic space toxicity and compatibility with other additives and materials this list is not exhausting but understand the influence of secondary inhibitor properties because they influence considerably the inhibitory behavior as well as efficiency commonly used internal motion monitoring techniques are controversy monitoring that is use of corrosion coupons non-intrusive monitoring example ultrasonic inspection ut inspection and of course li lane inspection an industry survey was presented at the nase at the pipeline workshop 2019 it indicated that 65 of the companies are using coupons but only five percent of them believe in the corrosion rate obtained from the coupons what is the use of spending money on coupons message here is that not use techniques and collect data if you do not believe on the technology final risk we are going to discuss is external corrosion again note that alberta regulations require quick carry of annual inspection of external corrosion mitigation strategies time tested and proven methods to control external corrosion or application of coatings backed up with application of catheteric protection nase cap hipaa that is canadian energy pipeline association have published several standards and best practices on selecting and evaluating coatings and cp as well as in understanding the risk either quoting or cp are both at present industry release only on ocean growth rate from online inspection now if you selected data as suggested by various standards and practices that were discussed in the previous slide you should be able to obtain at least five different growth rates corrosion growth rates in fact developing corrosion growth rate from laboratory data is eluded in the nas standard 662 class 10.2.6 deadlines for converting laboratory data to corrosion growth rate are also recently published so use data appropriately to obtain as much information as possible most important activity that is common to all phases is maintenance we normally associate maintenance the physical structure just like but in reality maintenance consists of five interdependent entities there is pipeline workforce there is us data communication associated activities this role of forget better expert me from a 26 years of experience with industry i can say that the weak link is the data we collect lots of data but we do not organize our decision based on it or we do not write to provide insight to the risks i strongly believe that if we streamline data collection and decision making process we can obtain early warning on risk finally let us not forget the role of management management is a process that ensures that the dependent operation does not affect people infrastructure and environment management could be systematic inclusive proactive continuous ongoing technically sound financially viable i would emphasize visibility and effectiveness of the management process management should enable us to see the structure of all pipelines in the vast network for instance looking at this figure you can easily see that these are not working well for flow lines 1 8 14 12 16 16 and 18. from this level we should be able to look at the status of these activities in a particular pipeline for example you want to look at four line one you should be able to see what has higher risk in this flow line as you can see here from the details higher risk in flow line originates due to adequacy in implementing a couple of strategies so we should be able to see the picture as well as detailed analysis and i use seven colors for this in addition to the five class fire risk i use blue for an activity that is considered relevant for the particular pipeline or gray or an activity that's not started for the particular pipeline number of incidences is indirectly related to the efficiency of the integrity management program the integrity management program is poor incidences will act as illustrated in type 4. the integrity management program is poor and if no incident has happened as illustrated in pipeline don't be complacent risk will increase in the various fees we want the integrity management program is good but still incidences occur illustrated in pipe one then review with feel personal on the implementation process there are some issues with implementation process finally the integrative management program is good and implemented properly we can safely economically and efficiently operate our pipelines for a long period of time as illustrated in year 2 and type 2. in summary select implement appropriate integrative element program is effective economical user-friendly feasible inclusive appealing in the integrity management program include all risks that will affect your pipeline finally collect data relevant to all risks and analyze them thank you and i would like to once again thank you for this opportunity and will be happy to take on your questions so with that um we're gonna then jump into our q a sessions so um so please enter your questions uh within the uh q a panel uh within your zoom client or if you're joining us on youtube live please enter your comments into the either the comment field or there's a chat panel on there and i'll try and watch that as well um so to get the ball rolling on here um so sankara you know what's the cost associated with running some of these uh different integrity management scenarios see we don't associate cost with integrity we want to keep the pipelines safe having said that almost all of us use inline inspection if you assume that inland inspection is the kind of standard if you do 100 to the indian inspection cost in my experience the direct assessment will be 70 to 80 percent of inlay inspection cost and the icda will be 40 to 60 of the inspection cost the benefit of dea programs is that they give free warning whereas inline inspection will be a post-mortem analysis that sounds that sounds pretty fair i know you kind of mentioned before that um uh yeah there you can't put a price on failure on that but you know in some cases like if it was that easy you know you would just run you would run an ili on every one of your pipelines and of course if you you know in the case world of upstream you can't always do that there's lots of other as you kind of showed your presentation mechanisms um other monitoring measures that you would employ before we would run to that uh ili case on there and then that's where you might run your va programs and such like that programs are very effective too and they are in my opinion in the experience they are far cheaper than ila program 40 to 80 percent cheaper depending upon which python you are running from which country you are running in absolutely so that so that moves into my next question here so um you know if you so you showed within your presentation there um uh when you're dealing with risk assessment and you're trying to prove a larp or as low as regional practical right um how can you do that with uh just using direct assessment programs the indirect assistance program the directors of one program rather was established for those pipelines which cannot be inline inspectorable so if you are going through the da program you must do all the four steps sometimes people start doing step one and two they don't do the dig they don't verify the model or above ground techniques so if you are going to do this dea program you have to do all the four steps only then the program can be effective it's very very important to do this step 3 that is digging and verifying what you have predicted otherwise you may be in the wrong direction yeah it's fair fair enough and sometimes um [Music] doing digs are more expensive than running your inline inspections so it's hard you know if you're trying to do a pure d.a program and showing that there isn't a threat yeah sometimes you might writing an inline inspection might just be cheaper yeah that's true see just to add to that one we established a fiver methodology because you can use dea and ili as complementary to one another if you do it either ila or da it doesn't give a big picture so in the final methodology what you do is what will work better what will work best for you that's what you used yeah fair enough thanks for that um so a clarification question here um so within one of your slides when you're doing starting up and talking about a pressure test are you talking about um you know after the pipeline's in operation or as part of the design and construction of the pipeline no pipeline in my knowledge can be operated at the beginning before pressure testing so pressure testing is a given at the startup and then during the operation if you make a different change or if you make further additional changes then you will do the design right pressure testing so at the beginning it's a must and during operation depending upon your stage you may or may not carry it out you're right and i think in most cases that's a pretty good assumption because i know one of the challenges uh especially when dealing with older pipelines is you don't have pressure test structure records so certainly you know like you said you can't actually start operating a pipeline without those uh without ever being a pressure pass so often in your risk assessment sometimes you know even if you don't have those specific records you'll make an assumption that it's at least to the code standards of uh that day um so another question here so the your presentation it touched on some of the uh initial risk assessments for pipelines and wondering what kind of um you know what's the source of the probability of failure that you should uh use based on this you know do you should you be using like api 579 or do you have something else you would recommend all of the above so i always give this example if you are going to drive a car in a freeway you can predict your car speed 100 kilometers you can put in the cruise and drive but if you are going to drive a car in downtown calgary when you are busy it's a stop and go there is always an uncertainty so any risk program you take you implement always associate itself with some uncertainty and other than it is i do two things at least look for the standards like the api and take their probability and two that's what if you are doing for example locally corrosion models most of the localized commercial models they give a uncertainty 10 plus or minus similarly i like 10 plus one minus 10 80 of the time so all these all these associate even integrity program with an uncertainty and that depends upon your operating conditions importance of the pipeline and its consequence awesome i think that answered that pretty good thanks for that um another question here so um in your mind if you're looking at say um subsea offshore pipelines you know what method might you follow on that you have any thoughts around that subsea pipelines are subsea flow lines subsea pipelines we can do in lane inspection program subsea flow lines it's difficult uh i mentioned about the maze document tg440 many of the pipelines have failed because they forgot or did not properly remove all the water after the hydro testing so if you are going to do hydra testing which is relatively easy for subsea when compared to other things please make sure that you remove the water afterwards and some companies um they also send divers to do the inspection non-destructive testing inspection fair enough i personally have never worked on offshore pipelines so yeah it's kind of an interesting world there's definitely you can't use every kind of method that you would normally use all right um another question here so um maybe a bit of clarification so when you're using an ili program you know what are your thoughts there on um whether or not you always need to do uh verification dicks related to it or some strategic dances specifically what was mentioned here um that's a good question again i have a slightly different view we use inlet inspection program as a starting thing for integrity management in my opinion you should do the modeling first and you should anticipate what you are going to see out of the inline inspection so that is one verification just run the model first and predict what is going to happen in the inspection and then check the model comparison model data with the inlay inspection that is the most ideal and given that even ionized vendors are saying it is 10 10 plus or minus 80 of the time at least for the pipelines which are in the high consequence region he must do the digging for no consequence region we may or we may not do it for actually for high consequence you should do the dick verification makes sense and in your mind maybe a follow up on that so where like so you said our high consequence on that you know do you have any ideas like uh or suggestions of what you might classify as that would that depend on the specific company and what their own risk policy is uh what is that is should that be based off of specifically just class location of your pipelines mostly cost location class location and again if you are in the south of the border you are mandated your regulatory things mandated for example in u.s almost all non-speakable pipelines in the high consequence area as defined by crimson must undergo d a program so here in canada we have a kind of little more linear in terms of user liberty to the pipeline operators that depends upon the company policy there's no one or one or two answers it's a combination of all depends upon what works for you no you're absolutely right it's definitely a complicated question i appreciate kind of that clarification unknown uh what the thoughts are because you're right there is no easy answer and most the time as a pipeline operator you want to do the analysis you can to avoid doing digs especially if it's on you know say minor corrosion on there we don't believe there is a significant threat and that's kind of what the picture your inspection is showing you as well um so maybe moving to a good segue to that so within your presentation too you also talked you you mentioned that um most people don't really believe uh the value that comes from their coupons but yet everybody still uses them and i know in a lot of cases you know even a lot of risk models or internal corrosion assessments they always take uh coupon rates on there uh as kind of a more of a validation of the model if you will but i mean in your mind if they if these aren't any good anymore then how do we evolve our internal corrosion management programs to go beyond using coupons you know without blowing up our costs and going to um inline inspections or you know in some cases where we don't or we can't take a line um and we're relying on coupons uh because it's the sections are unpickable yeah that discussion may take a couple of days to complete so see there are two ways of taking it one if you are going to place the coupons first understand where the coupons are going to be top of the line middle at the bottom and then all you have to do is whatever data you collect you have to do a postpartum analysis to see whether this make any sense unless you correlate the data with some decision making the data may look very bad but sometimes the data is good because we didn't have time to do the analysis we just throw the data so it is not the data you have to correlate the data with the decision making even after decision making that is there is no correlation then the data is bad unless you do the decision making analysis it doesn't make any help for anybody maybe maybe you want to provide a clarification on that what do you mean if you don't make um if you don't make the decision uh on that i'm i'm not sure i understand like how you would um i guess why you would not want to use why you would not want to use coupons in that scenario why because i know there could be some other examples but how do we evolve uh just an example i can give the reference a little later if you compare the coupon corrosion rate at a point of the pipeline compare the coupon corrosion rate to the corrosion rate of the pipeline the coupon corrosion rate will be 10 to 15 times higher than the pipeline corrosion rate so first you have to correlate why there is a difference because the coupon is at the phase of the flow as a result if you see the flow effect higher so first you have to understand how the coupons are oriented whether it is intruded or it is flushed on the pipeline surface so we have to consider the defined geometric consideration and then correlate the coupon corrosion rate with the pipe corrosion rate and then you take a decision for example if the coupon sees 40 npyf corrosion rate or one meters per millimeter per year that doesn't translate into a pipeline corrosion rate that translation must happen only then coupon corrosion rate can give indication about the internal corrosion okay that makes sense um what about if you're trying to you mentioned in your slide two about pitting corrosion then encouraging being very different from general corrosion on there as well so and that same theory you apply with coupons when you're dealing with bidding corrosion as well yes again when i talked about picking corrosion i was specifically talking about the models yes many models almost 85 of the models that are out they measure the general corrosion rate and they use a factor to convert it into a pitting corrosion rate that is not a good way of doing it because there is absolutely no correlation between general corrosion rate and peaking corrosion rate whether it's on the pipeline or on the coupon right but um i guess uh my question was more related to um related to more focused on coupons itself so if you're trying to like for example um if we see like how do we guarantee we're getting pitting on there would it just be general corrosion can you make assumptions on there because you kind of talked before about being able to kind of assume whether or not the coupon's in the right position and how that might look on the rest of the pipeline um and maybe i'm mistaken maybe you were talking about both but i got the impression you were just talking about general collision and not necessarily uh no yeah that's a good clarification i was talking very generally but if you are doing going to do the coupon analysis you have to do both general corrosion rate as well as spitting corrosion rate in fact there is a astn standard g111 a group of us are re-erasing it if you choose clear direction as to what all the things you should do if you are pulling a coupon out first take a photograph of the coupon and do the cleanup and understand the general corrosion rate and then understand how many pips are formed nowadays we use laser profiler meters to get the profile of the coupon all these things you have to do before you take a decision based on the coupons it is not just inserting a coupon pulling it out hey this is a corrosion date let's go right more than that okay no that makes sense and thanks for that clarification um so we got time for just one last question in on here so um so is there any place in different direct assessment programs or um what might be considered advanced technology monitoring an example could be something like your guided way vt that that can be answered by you brett as a pipeline operator or producer but in the third step step three of the da program there is a direct assessment which might involve the guided ut gateway anything that can be placed externally to understand what is happening internally can be a good thing for the step 3 of the va program but again big three involves digging so to find a place where you can dig and go down so that is where the main issue is not in technology but the accessibility sciences you can just say oh look we ran a guided ut and it fit our d a model and therefore we're done i know as an operator can be challenging to make sure that you have what's uh you know all the right elements in place to do the whole uh proper da programs on your pipeline and i know it doesn't you know one method doesn't fit all and sometimes it's kind of um you apply by through your standards but there's not always confirmation if you've done everything you could or if there should be more and because it always seems like there should be more you can add one more thing after that yeah good carpenter make two measurements before cutting it so always use at least two different technologies before you take a decision that's very good advice very good right so um so thanks thanks for that uh sankara that was a great uh video a great conversation um really appreciate you joining us uh today on here so as i mentioned before we are going to post this on here the video will be in a nice clear format that hopefully everybody can be able to read and see um so i appreciate everybody joining us today um so within so we've got one more um webinar series that we're gonna run here before we break for the holidays we've got uh dr frank cheng from the ufc he's gonna join us in about two weeks time so um be sure to watch our linkedin to get the latest updates on when uh when our registration site will open next week and uh keep posted on that because um yeah we're gonna announce some new uh new speakers for next year as well so and if yourself are interested in sharing your research experience or potentially interesting case study um with the industry on this platform please email me at program knees calgary.ca and you know we'll work to try and make it happen so again thanks everybody for joining us today um please be safe out there and we'll see you in a couple of weeks