It was good to see so many comments and lively exchanges following Cementing Challenge No. 1. Now in challenge No. 2, we cover cement substitutes. There is a challenge, not to cementers, but to cement itself … and for its purpose of creating a BARRIER for zonal isolation.
Some time ago, a blue service company talked about the future of well integrity not being around cement anymore… Instead, they suggested that it will be influenced by some other new material… Cement substitutes might perhaps include a new ‘smart-material’ where we do not rely solely on flow and displacement for coverage, but also on some sort of ‘in situ’ effect maximising isolation even despite poor hole geometry and conditions… That would be cool.
After looking at a post by Matteo Loizzo about triaxial tests, I recalled some interesting work happening at the University of Stavanger about Geopolymers for Permanent Zonal Isolation and Well Plugging. So, this is the challenge question:
Why would we need to find alternatives to cement to provide zonal isolation
Below are some clues:
a. Operational safety and health.
b. Technically… Solving issues related to cement placement.
c. Commercially… Profitability of cementing service providers, lower cost to oil companies (Reduced NPT, increase success rate, etc.), etc.
d. Operationally… Easier deployment, QA/QC, etc.
Enjoy our lively conversation about cement substitutes, and you’re more than welcome to add to it.
Matteo Loizzo Lenin, as usual, I cannot keep away from your challenges: finally an opportunity to discuss fundamentals in these straitened times. Let me weave it from your blue quote: in fact, well integrity is a lot about rocks. Creeping formations are probably one of the secrets of why wells don’t leak as much as some environmentalists fear (they certainly leak more than some oil companies hope, though).
Even Portland cement has some excellent properties while flowing and setting that more expensive solid-laden (or gas-laden) soups don’t have: the more you look at the details, the more you figure out how good class G is and why. Service companies always want to look beyond cement to make a buck, since operators only pay for dust and additives, expecting engineering and science to be thrown in for free (forget about Rolls Royce, Sony and all the others that make money from services selling hardware for a bargain).
JUAN SOTO Hi Lenin, glad to get into your plot.
The perfect dream for a zonal isolation job would be pumping an inert or latent fluid (not setting under temp or time), position in place, hi-five and then, at the order “set,.. arr” send a signal to nanoparticles into the fluid to thick on and turn to solid, voila !!. Then I woke up.
Later I read that this really a valid thinking. How long have to wait?
Ronald (Ron) Sweatman Juan, a patent search can show you several different ideas proposed for your dream of ‘on-demand’ ultra-fast setting of types of cement. To help you get started, google the following ones: ‘Releasing activators during wellbore operations’ at ‘http://www.google.com/patents/WO2013077947A1?cl=en‘ or at ‘http://www.google.com/patents/US20130126164?cl=en‘ and another one titled “Encapsulation Breaking Tool Methods for Improved Lost Circulation Treatments and Well Cementing”
Matteo, you are correct for some wells conditions. However, when you have different conditions, we sometimes have to run many laboratory tests, including triaxial ones to find a suitable cement design to seal the annulus. These wells are typically the ones that fail to achieve zone isolation with low-cost Class G types of cement. The latest surveys show that this is the case with 31% of wells in the USA. Other areas have similar sealing issues and, sometimes, in higher percentages of wells.
Ronald (Ron) Sweatman Lenin, your wish to have ‘”smart” and/or sealants with “in-situ effect maximising isolation” has been on industry’s wish list for many years. There have been some chemical systems that are much better than conventional types of cement.
The problem is the cost of these systems is 10 to 100 times the cost of an expensive Class H or G cement design with additives to reduce gas migration. By the time you add all the special equipment to handle, mix, and pump the chemical systems, the cost for well cementing may double or triple the typical AFE cost. Except for a very few operators, no one will pay for this kind of cost increase.
Clayton.Adonis. Browne Lenin, Over three(3) decades ago the same question came up for an alternative to cement in oil-well construction. Not too sure where those plans and test went, but as a field specialist, any cement alternate will increase the well cost until proven.
It was considered then about using the drilling fluid as the medium but there was a concern of the barite ability to support the casing although it is a rock base. We should be able though to use the cement as the weighted replacement to barite, to drill the well in an (oil base) environment as we have with many wells now. and then activated when casing in on the bottom. This will include equipment design changes but which can be minimal utilizing the present systems. I believe this method will be far cheaper than a replacement and can increase the success rate.
JUAN SOTO Thanks Ron: I’ve already done some research on this systems, from microwaves to resin for oil muds, and the truth their limit always will be the cost, speaking of Rolls.
Vidar Rygg Juan, I often wonder people think a zonal isolation material needs to turn solid. The company I work for, Sandaband Well Plugging, use a quartz-based “paste” that will never turn solid and never degrades. Anything that turns solid can break up as downhole stress exceeds strength. If it bonds, it can also de-bond. We have as an industry focused our efforts in trying to develop an almighty cement that can both build strength and also seal pressure.
In my opinion, the better solution is to use setting materials where strength is needed (Surface casing/Conductor/Perforations), and non-setting materials where zonal isolation is needed (Liner above reservoir/Intermediate casings/P&A). I realize that this is a non-commercial group, so just search the web for more info, or check out SPE 133446-PA for a case history.
Matteo Loizzo Ronald (Ron) Sweatman, don’t get me wrong: diluting neat G is the worst you can do to a well (if you really want isolation), and if you’re losing circulation then you have to use something lighter but competent. However, my impression is that when we see a leak we point our finger to the reason-du-jour and then use an expensive, poorly validated solution without spending the time to understand the interplay of conditions and why the leak happened in the first place.
I remember a new system being introduced to great fanfare before somebody found out that logs tended to look bad with it, therefore reducing its appeal. Maybe logs were really worse (or maybe we just logged more and looked closer at the squiggly lines), but I can venture a couple of reasons why those systems perform “worse” than neat G. Vidar’s idea sounds great, and I’ll look it up, but his point about bonding is an example: cement doesn’t really “bond” to casing, and what de-bonds will in many cases re-bond. As shales do.
Luis Simba simba Gostei deste pormenor
Neda Ahmadpour Lenin, this discussion reminds me of a project in the north of Africa. across to the reservoir (around 6-7km below the surface), there is a slow tectonic movement (which parted continent Europe from Africa, many years ago). So under those super slow movement, the well life was shorter than the expected. we proposed FlexSTONE* technic as the solution which affects like ball-bearing in front of slight movements, also it expands under P&T changes to seal the wellbore…
In this case, we could see less SCP as well
István Onozó I agree with Vidar statement to use setting materials where strength is needed and non-setting materials where zonal isolation needed.
There are so many specialized products available other than cement that are either quartz-based or polymer based and have been used successfully. These systems are environmentally friendly and cover wider applications.
I believe the answer to the original question is that we need an alternative for those cases where the application of the traditional cementing fails.
james cottom It would be great to have a fluid system that could be used to drill the hole, clean and condition the hole, run casing and then trigger it somehow to set with adequate properties to provide zonal isolation. As Mr Sweatman mentioned, this has been experimented with for years.
The big obstacle to overcome is COST. These systems are very expensive. One old adage in the oil field remains as true today as when I first heard it… Cement is the cheapest thing on location! When properly designed and properly placed, it is hard to beat.
Clayton.Adonis. Browne I agree with James and the use of cement for the complete process is worth considering since it is cheap and if properly designed the well can be completed with both strength and isolation. It can help a lot with lost circulation control and minimize contamination.
David Esteban Pizarro Lopez Dear Lenin, in the market there are products right now with proven efficiency used for zonal isolation different than cement, as Istvan said before. the issue about this products is the cost. The cheaper alternative is the cement, but for specific purposes or needs like thixotropic slurries activated by shear stress or resins that can penetrate even where micro-cement cannot this products becomes a cost-effective alternative.
Also, green products have been developed to meet regulatory requirements. So as an answer the need to replace cement depends on the conditions of the well itself, the regulations of the country, the technical resources available on site (or in the region) and the cost-benefit relationship.
Bimal Bhattacharya The set cement has typical properties within which it would support the well, behind casing; provided that cement has been ideally placed in the annulus by thoroughly displacing mud/mud cake and bonded well with formation and casing.
Any deviation from this ideal situation will affect zonal isolation. To mitigate some of these possible deviations, in spite of adopting the best cementing practices; it is worth using some products (like swell packers, well life materials etc.) not precisely as alternatives but in combination to the cement. That may enhance cost but still prove to be cheaper considering (a) total cost of well and (b) cost due to possible future well problems leading to stoppage of production and workover cost.
Further, cement in the well, in general, would deteriorate with time due to various reasons and hence will demand necessary remediation or account for it during the well design stage itself. Well integrity will have a wider scope of deliberation over zonal isolation.
marco farci “….a blue service company talked about the future on well integrity not being around cement anymore….. “When I worked in Kazakhstan” I executed a cement job with WellLife cement ( contractor a red service company ) with the excellent result above our expectations. We achieve a perfect zonal isolation I’ve never seen a CBL and VDL in the whole of my work life! AMAZING
Don Purvis Cement was a convenient and readily available substance when first pumped in the early 1900s. We have spent the last 100 years trying to make it work.
Assuming the data is correct, we have failed. Based on a study performed by the United States Mineral Management Service; sustained annular pressure during the life of the well occurs in over 50% of wells in the outer continental shelf of the Gulf of Mexico. A publication by Watson and Bachu, (SPE 106817) places the percentage of wells with gas migration or surface casing valve flow over 60% in deviated on-shore wells. Even with expensive additives cement is not working.
We need a wellbore isolation material that is impermeable, flexible, and durable with zero fluid loss and free fluid as well as high tensile strength. Let us quit focusing on the uniaxial compressive strength that is meaningless in a wellbore. We need something that behaves more like a hockey puck than a sidewalk. It is time for a paradigm shift.
Michael Mehle I recall a project years ago where an operator was planning a permanent abandonment plug for a well that would ultimately be located beneath a municipal water reservoir. It really got me thinking about how we define “the life of a well”.
I think the responsible thing is to begin to think beyond the operating life of the well to what it would take to create a 1,000 year or longer seal. We are, after all, creating a pathway for nasties below to travel to the surface, what should we do to make sure that we are never, ever concerned about our ability to keep it down there if we need to?
On a separate note, I recall a few years ago reading about a deepwater x-prize being awarded to a high-temperature delayed-set epoxy system for zonal isolation. Though expensive, I would imagine that would create a near-perfect seal. Has much been done with this type of isolation?
Bimal Bhattacharya Michael, there is no method or technique to claim with certainty about the well integrity even though all precautions have been taken and best practices followed in abandoning a well. There are enough disclaimers for every process that is executed by service companies to safeguard them from any possible failure that may surface later on. That is obvious.
Regarding temperature aspect (with reference to HPHT wells), the industry has limited knowledge and data – about the performance aspect of materials and processes. For example, do we know with certainty about which material will fail at what maximum temperature with consistency, that too with other influential factors incorporated? On the contrary, we have a better understanding of the pressure aspect in our industry.
Matteo Loizzo Don Purvis, at the cost of sounding obsessed with concrete I’m not sure we have failed: the MMS study conflated A annulus failures (arguably packer and connection issues) with outer annuli SCP, which account for 10-20% of the total. Even the statistics of Watson & Bachu suggest the same failure rate Alberta-wide. All in all, 20% of wells seem to be leaking, half of them to the wellhead and half through the soil.
However, bear in mind that failure rate is really local and ruled by geology: this is one of the reasons why wells leak less in Texas than in the GoM.
Cement is impermeable and flexible enough. But if you debond it from the casing you’ll get a (small) leak even if cement as a material hasn’t failed (i.e. hasn’t cracked). I’m not convinced other materials will necessarily perform better in the same circumstances.
Bimal Bhattacharya In an ideal case, the cement is supposed to be impermeable. It is found to be permeable in reality in several cases.
Don Purvis Matteo Loizzo, thanks for your comments. I believe that regardless of the number of wells with a failed annular seal is 60% or 20% it is unacceptably high
Continuing the conversation about cement substitutes
Did we cover all aspects of the conversation about cement substitutes for oil wells? Is there technology from other industries that can be integrated? Perhaps you’re reading this ‘in the future’ and there is something new to add to the comments section below?
You can also follow this conversation about cement substitutes on LinkedIn.