Recommendations
WARNING: No cement slurry should ever be pumped without a laboratory test using the actual materials that will get mixed on the job. (Cement, additives and field water).
Perform compatibility tests between the cementing fluids and wellbore. Drilling or control fluids, formation fluids and any other fluid potentially in contact with the cement slurry.
a) Thickening Time to 70 BC (Bearden units)
Thickening time (also called pumping time) testing should be performed at the estimated bottom hole or treatment depth temperature and pressure using a pressurized consistometer.
- Test temperature considerations
- For primary cement jobs, casing/liner cementing and cement plugs (except when using coiled tubing), the highest circulating hole temperature (not necessarily BHCT) should be used for the thickening time test. The preferred method to determine the BHCT is with computer simulation software (alternatively the API correlation/tables in the RP 10B-2 / ISO 10426-2 to be used when applicable).
- For remedial/squeeze cementing (except when using coiled tubing) the test temperature can generally (for near-vertical wells, with a known formation temperature gradient) be determined using the API correlation/tables in the API RP 10B-2 / ISO 10426-2. However, anytime the configuration of pipe size, depth and displacement rate/time does not correspond to API schedules, job-specific customized test temperatures and schedules based on actual job parameters and thermal computer models should be applied.
- When squeezing in production and injection wells, if accurate recent downhole (log) temperature data is available; this is used as the input parameter for modeling the squeeze test temperature.
- For coiled tubing operations, hole static temperature at the treatment depth (known geothermal gradient or recent logged temperature) should be used.
- Thickening (pumping) time requirement considerations
- For casing/liner cementing and plug cementing (except when using coiled tubing) the pumping time is estimated as the total operational time (including mixing and pumping cement, displacement, static periods like dropping wiper plugs or pulling out the cementing string, circulation of excess cement in liner cementing and cement plugs, etc.) Plus a safety factor of no less than two (2) hours.
- Thickening time tests for particular cases, such as liner cementing, cement plugs or two-stage cementing, should consider the need of a static time (no rotation in the consistometer for a small period) to identify any gelling tendency in the cement slurry in actual conditions, like before/during POOH drill pipe or before circulating excess cement.
- For casing/liner cementing and plug cementing (except when using coiled tubing) the pumping time is estimated as the total operational time (including mixing and pumping cement, displacement, static periods like dropping wiper plugs or pulling out the cementing string, circulation of excess cement in liner cementing and cement plugs, etc.) Plus a safety factor of no less than two (2) hours.
Thickening Time should be no more than is needed to place the slurry while allowing for contingencies safely. Shorter times increase risk. Avoid longer times because they are subject to increased measurement error and uncertainty.
- For remedial/squeeze cementing (except when using coiled tubing), pumping times should be long enough to allow the cement slurry to travel to the placement depth. Then the injection of the cement slurry (cement slurry volume at the anticipated injection rate) to the target zone. Time is also allowed for repeated squeeze-hesitation cycles. Then we allow time to reverse or direct circulate any excess cement out of the well (if this is planned). The following should be considered:
- A minimum safety margin of two (2) hours is recommended.
- When testing the slurry for a hesitation squeeze, it is recommended to simulate the shutdown times in the laboratory during testing of the cement slurry.
- An additional safety factor should be considered for circulation squeeze. In these operations, the actual thickening time is typically reduced and the gel strength development considerably accelerated due to the loss of filtrate while the cement slurry flows under pressure behind the casing between the perforations.
- For coiled tubing cementing we recommend a minimum thickening time of 8 hours.
- For laboratory testing, actual field mixing and pumping conditions should be reproduced by the cementing contractor considering the following:
- Additional mixing energy imparted to the cement slurry in actual conditions (batch-mixing of a relatively small cement volume and the high friction pressure inside the coil) makes the API mixing procedure described in API RP 10B-2 / ISO 10426-2 section 5 insufficient.
- The thickening time for a cement slurry mixed according to API mixing procedures may be reduced up to 75% in coiled tubing cementing.
- For laboratory testing, actual field mixing and pumping conditions should be reproduced by the cementing contractor considering the following:
b) Free Water
- Free water should be measured following the API RP 10B-2 / ISO 10426-2.
- For the following applications, free water should be zero (0%) percent:
- In primary cementing of casing/liner and in plug cementing, for cement slurries in front of permeable zones, reservoir zones and/or highly deviated sections, zero percent (0%) free water is mandatory. In highly deviated section (> 40o degrees deviation) the free water test should be conducted at the same angle.
- Squeeze cementing.
- Coiled tubing cementing.
- For other applications, such as surface casing, the cementing contractor should provide a recommendation. In general, this property becomes secondary to the other cement slurry properties.
c) Fluid Loss
- Fluid loss should be measured following the API RP 10B-2 / ISO 10426-2.
- For slurries in front permeable zones or reservoir section, < 30 – 100 ml/30 min is desirable.
- Cement slurries employed in narrow annular gaps, < 3/4” clearance, might require lower fluid loss values.
- For squeeze cementing we define the fluid loss according to the job objectives, the formation permeability, and the fluid injection rate. The following table provides a reference to select the required fluid loss value:
| Low Permeability Formation (~<10 md) | Use a moderate fluid loss value of 150 –200 ml/30min. Lower (100-150 ml/30min) if we anticipate a very high squeeze pressure. |
| Medium Permeability Formation | Use a moderate to low fluid loss value of 100-150 ml/30min. |
| High Permeability Formation (~ >200 md +) | Use a low fluid loss value of <75 ml/30min to prevent rapid slurry dehydration. |
- For coiled tubing cementing the fluid loss should be less than 100 ml/30min.
d) Rheology
- Cementing fluids (spacer and cement slurry) rheology should be measured following the API RP 10B-2 / ISO 10426-2.
- Rheology measurements are needed to build the model for the job into the computer simulation software for the cement placement, u-tubing effect, dynamic downhole pressures and thermal computer models.
- For coiled tubing cementing, the rheology of the cement slurry should be the lowest possible (for the lowest possible friction pressure inside the coil) without compromising its stability, i.e., no sedimentation of solids and no free water.
- The recommended rheological values for coiled tubing cementing:
- Minimum possible yield point of 5 to 10 lbf/100 ft2.
- A minimum possible plastic viscosity of less than 50 cP.
- The recommended rheological values for coiled tubing cementing:
e) Compressive strength test
- We measure the compressive strength values following methods and recommendations in API Recommended Practice 10B-2 / ISO 10426-2 section 7.
- Sonic Logs, like CBL/VDL, are set to identify the cement with certain Acoustic Impedance. This value is best estimated from the transit time in the Ultrasonic Compressive Strength Analyzer (UCA).
- Failure to use the correct temperature and heating schedule for the compressive strength test could cause impaired cement evaluation interpretation. Test temperatures references are presented below:
- Recommendation for compressive strength test temperature:
- Casing cementing
- Lead cement slurry (if present) > Use static temperature at the top of the lead cement length. For long cement columns in casing cementing or when the bottom-hole circulating temperature (BHCT) is higher than the static temperature at the top of the cement column refer to API Recommended Practice 10B-2 / ISO 10426-2 section 7.
- Tail cement slurry: > Bottom hole static temperature, BHST.
- Cement plugs, placed with drill pipe or coiled tubing > Static temperature at the top of the cement plug.
- Cement squeezes > Static temperature at the top perforation/injection point or top of cement inside the casing.
- For liner cementing > Hole static temperature at the liner hanger depth.
- Alternatively, we obtain a more precise test temperature from thermal computer models for any of the above cases.
- Casing cementing
- Recommendation for compressive strength test temperature:
f) Static Gel Strength Development
- Where cross-flow or fluids migration is a risk, the transition from 100 to 500 lbf/100 ft2 should be in less than 45 min.
g) Stability tests
- For all critical operations, including highly deviated liner cementing, jobs involving small annular gap, high temperature, and coiled tubing cementing, perform the tests as per API Recommended Practice 10B-2 / ISO 10426-2 section 15.
SGS Development
As per my experience, zero gell strength time (the transition from 100 to 500 lbf/100 ft2) should be kept minimum. less than 20 minutes will be ideal, it is difficult, but certainly doable. TT transition time(30 Bc to 70 BC) also gives a indication but sometimes it is misleading, so always rely on SGSA transition time. Use of latex also helps.
Mubashir, Gel Strength development is certainly an important feature to prevent fluid/gas migration and the recommendation could be different from one location to another depending on the experience and practices locally developed. Base on my experience, I would be inclined to agree on your recommendation, but It is good the audience of this site knows that developing such a slurry could be a bit difficult and it could require significant laboratory time/equipment use that at location level could be unmanageable. That kind of a project would be good task for a regional lab.
For the cement slurry development the one of the important things to know is the BHCT (Bottom Hole Circulation Temperature) and I’m not sure if anyone mentioned it. What do you use to calculate the BHCT?
Oleg, Thanks for your question.
BHCT is commonly estimated using API tables (not very precise) or calculated from Temperature Simulators
My preference is always temperature simulators, particularly for long casing section, liners, production casing and liner, tie-back and cement plugs.
For BHCT it is better to use simulations but i see in most cases clients as well as service companies using API’s Equation to calculate BHCT. Some time it is better to have some safety margins (+/-10F) when using API equation.
Mubashir, Thanks for your comment. I think it is better for me at this moment to just highlight some of the limitations when using API equation.
-Tend to over-predict
-Primarily developed from drill pipe measurements
-Do not work offshore or deviated well. In deviated wells with liner, the Highest circulating temperature is not necessarily at the bottom
-For high geothermal gradients and deep wells, the BHCT is calculated by extrapolation ignoring important physical parameters
-Works only for BHCT, there is no method for estimating the top of cement circulating temperature which is very important to the design of a long cement column.
In summary, it is better to use a suitable temperature simulator adequate to the well geometry and conditions
Best Regards
L. Diaz
it’s better to know the BHCT based on simulation because its parameters used closer to the real situation; that why it must be the first choice.
I agree with you Boulacel, just make sure the BHST is provided to you by your customer
Hi Leni
I have always designed Coiled Tubing jobs with Fluid loss additive as the slurry may dehydrate in the tubing. The maximum calculated FL will be under 50 cc.
I have been asked to design a slurry to pump through CT without FL. It just does not seem right to me.
How does the dehydration occur in the CT? I understand how dehydration occurs in the formation, but not in the CT.
Would it be possible to actually design and pump a slurry without FL through CT?
Thank you and looking forward to your answer.
Hello Carol,
First of all I would like to thank you for visiting my website and for your very interesting question.
Well, my intention here is to give you an answer that you can use, so let me try this ….
Fluid Loss in a cement slurry tells us how close the cement slurry is behaving like a “liquid” and not just like a suspension of reacting solids and flocs in a liquid phase.
In CT applications the fluids you pump travel through a pipe with a diameter of less than 2 inch that depending on depth gets narrower, probably to a range of 1 or 1 1/2 inches, and independently of the placement depth the cement slurry needs to travel anyway the whole length of the coiled tubing, if at any point a sufficient amount of particles get closer to each other, forming a cluster or clusters, so that they start to behave like a “porous media” for any cement slurry behind, a filtration (or self-filtration) process can immediately start plugging your CT with catastrophic results.
Also, in CT application there is typically a BHA, a diverter or other tool … any of these could have an effective flow path that can create an internal pressure drop leading to slurry filtration or self-filtration, again leading to your CT being plugged with cement.
You already know that in surface the pumping rates are limited by pumping pressure, typically to less than 3 bpm … inside the coiled tubing this is translated to a much higher liner fluid velocity and high friction pressure making and ideal scenario for what I described above to happen.
Anything you pump inside CT needs to be as close to a “liquid” as possible, for cement slurries this means homogeneous and stable and loss fluid loss is a very important element to achieve that.
Please let me know, if this answer helps
Best Regards
L. Diaz
Hi Lenin,
First of all, HAPPY NEW YEAR and all the best on 2017. Hoping that the Oil & Gas Industry picks up for all of us.
Thanks so much for your answer. I just realize I didn’t get back to you before.
I have not received training in Coiled Tubing, only in Cementing. So when I get a job in CT I always have many questions.
I would need to design some slurries to be pumped through CT. Current temperatures are between 170C to 230C Bottom Hole STATIC.
From my previous experience, I would design the slurry for CT using BHST and not BHCT, but I don’t know the theory behind it.
I know that when pumping through CT there is extra energy added to the slurry. Using BHST, is just a safety factor? Or is it because pumping rates are so slow that it is considered “static”?
My consistometer has an operating temperature of 200C. Can I design the slurry using BHCT to run TT?
Also, reading different company standards for cementing through CT, it is mentioned that TT should be minimum 5 hours. But why? For example, if I am setting a plug (50m) or filling up the casing for P&A and the actual job time is 40 minutes plus a safety factor of 1.5 hrs, total of 2hr10min, why do I need 5 hrs+? While pumping I am pulling out the CT.
I know my questions are really basic 🙁 and I just want to understand better. I was used to get a slurry request from the CT engineer but I don’t have that background.
In advance, thank you.
Hello Carol
Thanks for coming back and for your nice words. I also wish you an excellent New Year.
I like to apologise as well for this late reply.
Now let me answer you questions, that BTW are quite interesting and appropriate to the this post.
First of all I like to say that your BHST are quite high, 170 C and 230 C, please tell me about well depths? or Are we talking about thermal wells?
Anyway, BHCT is not used for CT cementing because of the following (assuming we are talking about old wells, i.e., rig-less):
1) Cement volume are typically small
2) Depending on placement technique, there is not actually a fluid volume circulating, if we are talking about cement plug for instance, the most common practice is to place the cement while pulling the CT out of the hole (POOH), basically the cement is just dropped. In this practice the height of cement slurry dropped equals the length of CT pulled up.
3) Pumping rates with CT are low. Inside the CT the linear velocity is high because its narrow diameter, but in the annulus the velocities is much slower
4) In CT, the most important aspect is operational safety, which is basically translated to “not getting the CT stuck” so precautions are much higher and operational times are much larger than in primary cementing new wells
5) API BHCT cannot be used, but some simulators can give you a BHCT value, but more than likely it would be very similar to BHST. If we are talking about injection, because of losses or low formation pressure, then temperature simulators can provide a temperature value at the point of injection, this value would be lower than the Static temperature.
In CT cementing the cement slurry undergoes extra mixing energy from: the mixing process at surface (small slurry volume batch-mixed) and inside the CT. All these has an effect on the slurry’s properties. The extra energy can be simulated in the lab by keeping mixing the slurry at 12000 rpm for a period of time. This time depends on the following (this is the theory):
t = (E / M)lab x (d x V) / (W x 2.35) in min
Where :
E/M = energy per mass unit
W = Power [hhp]
t = Time [min]
d = Slurry density [ppg]
V = Slurry volume [bbl]
However, this is not an exact replication of the mixing conditions in the field, mainly because the extra time at 12000 rpm will add a heating effect that does not necessarily occurs in the field with the batch mixer or in the CT.
So, coming back to your question, using the BHST is not a safety factor, instead it is closer to the actual conditions (you are right: “rates are so slow that it is considered static”). The additional mixing energy lowers TT, if you design the slurry as per API (lower mixing energy than CT).
Regarding TT, remember that this is a reference to being able to pump the slurry safely, in other words is a measure of pump-ability. In CT, because all of the above, TT needs to be long. Typical times of min 8 hrs are not uncommon. For practical purposes your main concern is compressive strength or when to tag the of the cement plug. As you now, longer TT does not necessarily means very long CS strength development, if the slurry is properly designed.
As an example (each CT company would have its own way, but they all are trying the same: justify a long TT) this is a reference to TT schedule for a CT-placed cement plug:
Two hours at atmospheric Temperature and pressure
It can be done using low RPM kitchen blender or by putting the slurry directly in the consistometer, leave the motor/ paddle running without heating up/ pressuring up the chamber for two hours.
Note: In case a consistometer is used, watch for a increase in temperature (tests can be repeated a few times until a good slurry is found, that means that for the second test, the oil in the consistometer might be quite high, does not represent surface temp.)
Two times Placement Time
Programme the consistometer, apply a constant gradient, increase from surface condition to bottom-hole pressure (BHP) and temperature (BHST).
Curing time
Five hours at BHST and BHP
Finally, in CT cementing there are not necessarily cementing engineers involved. CT companies have their own manuals and are not necessarily familiar with API or cementing practices more applicable to primary cementing or remedial cementing with Drill Pipe.
Hope this helps
Once again thanks for visiting my site and for your nice questions. Please let me know if you need any further clarification or have a question on any cementing topic
Cheers
LO. Diaz
Hi Leni,
Thanks a lot 🙂 It is all much more clear.
The depths that I have range between 3,800 m and 4,300m, and are not thermal wells. The area has high temperature gradients, 2.4-2.5 F/100ft.
Regards,
Carol.
Thanks to you Carol, I am gald to help
Cheers
L. Diaz
Thank you Leni and Carol for this conversation. The requirement for low fluid loss in CTU cementing mirrors what I thought was needed for cementing through coiled tubing due to small diameters, and sometimes changing in diameters or with the fluid travelling out through nozzles, all of which may promote dehydration.
Hi Dale, all that is very true, and the more important contribution is friction pressure inside the CT entire length (inside the coil).
Cheers
L. Diaz
Hi Leni. Hope you are well.
I am currently working on a light weight slurry minimum 9 ppg up to 10.5 ppg
I would like to know if you can start a discussion on light weight slurries or help me out through this slurry. I am having some trouble with the adequate water to cement ratio and also how much spheres I should add.
Apologies if this is not the correct place to post my question, but I have tried through “Contact and Questions” and it just doesn’t work.
Thank you.
Carol
Hi Carol
Thanks for your message.
First of all, I apologize for the late reply. I have been very complicated with both professional and personal life, at the same time !!.
No issues, first things first.
“Contact and questions” has been improved based on your feedback. Now there is the opportunity to call or use WhatsApp to contact me for urgent matters. The contact form is now simpler as well for easier input. Let me know what you think.
Contact and Questions?
Now coming back to your question and based on my experience, You would need an average of 70% BVOB +/- 10% Cenospheres (with an specific gravity averaging 0,75 sg +/- 0,1) . A combination API oil field cement and micro cement (1:2 to 1:1) (3,2 sg) and for the lowest density probably no H or G cement. You may also need to add medium or fine silica (2,7 sg) depending on depth to prevent strenght retrogression. I have also seen microsilica being used, but that does not count for strenght retrogression.
Hi to all,
I have a problem about static gel strength (sgs) value testing. If the gel value is below 3000, the system software could not reach the sgs value. Even changed slurry properties did not help. I need sgs value for gas well cementing to prevent gas leak while cement getting hard. Due to gel value below 3000, ı did not get sgs value. Is there anyone who experienced this problem before or any dea to solve it? Thank you to all.
Hi Ibrahim,
Can you please advise when you refer to 3000 what are the units of measure (lbf/100ft2 or Pa)?. If you refer to 3000 lbf/100ft2, that is a very high gel value, normally the standard SGSA equipment (similar to UCA) settings stops reading gel at 1500 lbf/100ft2.
Waiting for additional information
L. Diaz
Hi Leni
I have a question on the subject of thickening time pls: TT is measured with the consistometer motor “on”. I’m assuming the motor is kept “on” to simulate the dynamic situation during mixing/pumping etc. The TT will then steeply rise to 40, 80 and 100 Bc with the motor still “on”. My question is: will the same slurry also reach 40,80,100 Bc if the motor is kept “off” from the start of the test? I asked this because a test we did switching the motor off after 4 hrs for a period of 10 hrs actually managed to steeply reach the 100 Bc following a turbulent behaviour of the TT after 19 hrs. Why did the TT not rise during the 10 hrs motor off time when on another test wiht almost the same slurry wt and same additives but only 30 min of stopping the motor brought the TT to 40,70,100Bc in 14-16 hrs time
This a very interesting question Edwin, probably it is good to start, with the principle behind the Consistometer. As you mentioned, It is a dynamic test to simulate slurry behaviour under HPHT conditions while in motion, as a mean to assess the pumping time. The unit of measurement is referential (Bc).
When the motor is off, meaning the paddle is not moving, the slurry in static condition follows a related but different path, which is the development of static gel in other words the hydration process continues without shear.
In some occasions the motor if off for a certain period of time, usually less than 60 min, to have a qualitative image of the static gel strength only went the motor is back on and this gel is broken giving a higher value of Bc (instantaneous only, or sustained or a combination).
Some consistometers (most of them) are not very adequate to long static times, because when the motor is off the equipment cannot control the temperature (typically the BHCT) and it starts to rise. This is not a proper simulation of what is happening in the well, hence the resulting indication of static gel strength is more conservation due to the implied safety factor (rising BHCT).
Now, coming back to your question I don’t really understand the purpose of your tests and the very long static periods, however indeed in some occasions, due to incompatibility between additives, batch of cement and or quality of mix water the hydration process is poised and the cement is unable to develop compressive strength. It only viscosifies. I have seen this happening on the UCA test which is the equipment to measure CS development under static conditions. You can tell from the way the slurry looks like at the end of the TT test and you open the cup, how it looks, if the slurry would set nicely in the UCA. I have often seen this when Latex is in the slurry and when the cement is low quality (typically contaminated with construction type cement)
Hope this helps
L. Diaz
Hi Lenin here I’m again after being away for a year. Sorry not coming back earlier.
The stoppage time of 10 hrs during the TT test was to simulate the possible time required to open up the CFlex port (for a 2nd ary cmt job) with DP while having the Lead slurry well above the CFlex port. Opening the Cflex port was only required if during the primary cementing losses was observed.
As it turned out there were no losses but the 20 hrs TT had dire consequences on the cement quality (channeling) particularly in the casing to casing annulus. We know this as we had to cut the cemented together multi casing string (5 in total) just under the seabed. We can see the cement channeling physically.
The issue of FL in CT cementing was previously discussed. Can I expand my question w the following then; the Lead slurry FL was 40 mL but in a cng to csng annulus there again is nowhere for the Fluid to get lost. Could this be the reason why we see cement channeling ?, i.e the FL fluid unable to chemically bond with the cement particles due to saturation and when it dries up the channel is formed?
Hi Edwin, sorry for my late reply as well.
Very long TT means the slurry remains as a gelled structure dinamically for long time, if you have an UCA, is the 50 psi mark also this long (longer), or shorter? The problem is, if the slurry stays as a non-solid for too long in static condition, it might destabilise or separate, with a tendency to form zones of higher cement concentrantion with liquid phase migrating out thru the porosity of the gelled structure. In a casing-casing this liquid phase that is release out progressively can eventauly for a flow path at the opposite side (stand off would play a role as well) starting at the bottom (vertical well?) in an angle consistent with the zones of higher cement slurry presence. All this is only, if the UCA initial development, let’s say 50 psi, is very long as well.
Other possibility is dinamic placement, meaning the channel created during placement and have nothing to do with your long TT
Let me know more details
Thanks
When calculating Thickening time for cement job will you consider top and bottom plug to your thickening time calculation?
Yes, you should consider all the time from the moment the slurry is being pumped to the end of the job.