The following table is regularly updated. It contains a quick reference for documents about ISO and API cementing equipment and materials standards. This handy reference should save you loads of time compared to sifting through all of the documentation on API cementing equipment and ISO standards.
| API Doc # | Name | Overview |
|---|---|---|
| API STANDARD 65—PART 2 | Isolating Potential Flow Zones During Well Construction | Contains best practices for zone isolation in wells to prevent annular pressure and/or flow through or past pressure-containment barriers that are installed and verified during well construction. Well construction practices that may affect barrier sealing performance are mentioned along with methods to help ensure positive effects or to minimize any negative ones. The objectives of this guideline are two-fold. The first is to help prevent or control flows just prior to, during, and after primary cementing operations to install or 'set' casing and liner pipe strings in wells. The second objective is to help prevent sustained casing pressure. The guidance from this document covers recommendations for pressure-containment barrier design and installation and well construction practices that affect the zone isolation process to prevent or mitigate annular fluid flow or pressure |
| RP 10B-2/ISO 10426-2:2003 | Recommended Practice for Testing Well Cements | Specifies requirements and gives recommendations for the testing of cement slurries and related materials under simulated well conditions. |
| RP 10B-4/ISO 10426-4:2004 | Recommended Practice on Preparation and Testing of Foamed Cement Slurries at Atmospheric Pressure | Defines the methods for the generation and testing of foamed cement slurries and their corresponding unfoamed base cement slurries at atmospheric pressure. |
| RP 10B-5/ISO 10426-5:2004 | Recommended Practice on Determination of Shrinkage and Expansion | This standard provides the methods for the testing of well cement formulations to determine the dimension changes during the curing process (cement hydration) at atmospheric pressure only. This is a base document, because under real well cementing conditions shrinkage and expansion take place under pressure and different boundary conditions. |
| RP 10B-6/ISO 10426-6:2008 | Recommended Practice on Determining the Static Gel Strength of Cement Formulations | Specifies requirements and provides test methods for the determination of static gel strength of the cement slurries and related materials under simulated well conditions |
| RP 10D-2/ISO 10427-2:2004 | Recommended Practice for Centralizer Placement and Stop Collar Testing | Provides calculations for determining centralizer spacing, based on centralizer performance and desired standoff, in deviated and dogleg holes in wells for the petroleum and natural gas industries. It also provides a procedure for testing stop collars and reporting test results. |
| Spec 10A/ISO 10426-1:2009 | Specification for Cements and Materials for well Cementing. | Specifies requirements and gives recommendations for eight classes of well cement including their chemical and physical requirements and procedures for physical testing. |
| TR 10TR1 | Cement Sheath Evaluation | Provides the current principles and practices regarding the evaluation and repair of primary cementations. Cement bond logs, compensated logging tools, borehole compensated logging tools and ultrasonic logs. |
| TR 10TR2 | Shrinkage and Expansion in Oilwell Cements | Presents the results of research into shrinkage and expansion of oilwell cements in the wellbore as well as a series of test methods and procedures developed to measure these phenomena. |
| TR 10TR3 | Temperatures for API Cement Operating Thickening Time Tests | Work performed by the 1984-91 API Task Group on Cementing Temperature Schedules to update the temperatures in API well-simulation test schedules found in RP 10B are summarized in this report. The Task Group reviewed the largest set of temperature data available to the industry to date, resulting in significant improvements to the temperatures in the well-simulation test schedules. |
| TR 10TR4 | Technical Report on Considerations Regarding Selection of Centralizers for Primary Cementing Operations | Provides the petroleum industry with information for three types of centralizers, their selection and application, and their advantages and limitations. |
| ISO = International Organization for Standardization RP = Recommended Practice TR = Technical Report |
Hope that this post has been helpful to you. I run this site for free and your comments and feedback keep me going, so please let me know what you think!
It would also be great if you could help me keep this information up to date so that we can all help each other do the best engineering work possible in this specialist field. Let me know any of anything wrong in the comments, including version numbers, details, obsolete documents, info you think I should add, etc.
Good luck in your engineering and cementing adventures!
Cheers
L. Diaz
Hello Lenin,
This may seem a stupid question but as I don’t have experience on this subject matter request for your answer here.
Why do the tapered casings (sometimes called combination casings) are run? What is the use of it? How will the hole be drilled in this case and cemented ?
Thanks
Keshav
Thanks Keshav, this is not a stupid question and most definetely not stupid here.
Tappered casing includes, I believe, different weights (same OD different IDs) but not sure about casings with different OD.
If ran, it can be to save cost, lower string weight or use excess inventory for example.
Anyway, it can add a complication for cementing (casing hardware – plugs, x-overs, centralization). Simulation wise, it poses a nice case for some simulators.
I will get a friend to help me out here .. wait for more input
Cheers
L. Diaz
Lenin/Keshav,
Many simple well construction problems can be solved by tapered strings, including inventory availability, wellhead connection restrictions and the available well completion items.
There are also instances when tapered strings provide the correct engineering solution to wells with a high degree of complexity.
A practical example would be a 66.9 ppf, 9-7/8 x 53.5 ppf, 9-5/8 inch combination string. Both have an 8.50″ drift, which is a very important consideration when engineering for a tapered string. Internal diameter changes are not particularly desirable for a number of life-cycle reasons.
Assuming you need high burst and load ratings, then the benefit of using the 9-7/8″ joints higher up the well can add almost 50% to your burst and collapse rating across the section in which they are run.
As a general rule, avoid inside diameter tapers and ensure that the OD change is not in an open hole section – especially within the zone that will be cemented.
Hope this helps a little, would be happy to expand on the well engineering applications is asked.
Regards,
Steve Hauxwell
Excellent Contribution Mr. Steve. Very Professional. Thanks a lot
I’ve also seen tapered strings with a bigger casing higher up to accommodate sub surface safety valves and control lines with smaller casing below this depth. The hole size is the same but as the SSSV is fairly high up in the well, the top of cement will likely be a couple of hundred metres inside the previous casing shoe. From a cementing viewpoint, there isn’t much difference. The different ID’s are accommodated by the cement plugs.
Thanks Steve Devereux, Steve Hauxwell and Faouzi BEL for the expert feedback
Kesav & Lenin ,
To my knowledge Running a tapered casing ( 2 different ODs ) is not common practice in onshore wells , however , they run it in offshore wells to save money , by drilling a surface and intermediate sections in one go and run both casings in one run , they drill a pilot hole with a smaller OD bit say 12-1/4” to certain depth say 2000m , and on top they will have an hole enlargement tool ( hole opener ), it enlarge the hole say to 17-1/2” , to predetermined depth sat 1000m ….. you may ask why they don’t drill 12-1/4” section & run 9-5/8” casing to surface , well I think the reason of having a bigger casing OD is to have a specific casing OD size at sea bed level to accommodate the WH, and also the bigger size you start with , the better it is for your completion later on ( you won’t be restricted ) ,and running 2000 m of 13-3/8 casing to 2000 m is not practical cost wise , with regarding , cementing, I think they use a stinger, sting in into the shoe and cement it to sea-bed level.
having said all that , I will need to confirm with some of colleagues who got offshore experience …
Thanks Faouzi, for the clarification. Regarding inner cementing, it seems to be a bit to deep (2000m). However, possible the risk of failure with stab-in tool (mostly leaks) increases with depth. In any case.
I guess, as you said, It will be better to have further input on this one
Thanks Faouzi and Lenin, I now understand the method and the importance or running combination casings. Thank you so much !
Hi L. Diaz!
Excellent material, congratulations. Could you say if there is any normative practical recommendation that covers the design of cement sheaths and the necessary checks for failure criteria, as well as suggesting safety factors?
Thanks,
Gabriela
Hi Gabriela,
Currently, cement stress analysis softwares can predict failure and provide design elements to avoid it, under well life conditions.