If you’re intervening, generally something’s wrong and it’s only going to get worse unless you do something about it. Is there something in the very name and nature of well intervention that is undermining its true potential in the North Sea and the wider global market? Let’s explore why interventions typically take place, what is done and what could be done differently.
A case study by 3M explored the issues caused by sand production and tested their ceramic sand screen against a utility disrupted by this problem
Many factors such as the strength of a reservoir, cementation and reduction in pore pressure, fluid viscosity, and drawdown can all induce sand production. This can cause damage to downhole, subsea and surface equipment and can even lead to catastrophic failure. Production engineers across the industry have grappled with this potentially serious problem with solutions focused on reducing wellbore stress, improving consolidation, or transferring stress to some form of mechanical retention.
3M have recognised this issue, and have developed a ceramic sand screen as a solution. They have released a case study to test their product against a facility restricted by sand production:
The Challenge:
At a facility in the Caspian Sea, due to reservoir depletion, the operator was forced to restrict flow rate in order to achieve sand-free production. Without sand control already in place, the operator sought a cost-effective retrofit sand control solution to assure desired production rate in a high flux and impingement velocities environment.
The Solution:
The ceramic sand screen solution was speced-in to a given wellbore restriction and to set across the perforation zone using a rigless deployment technique. The coil tubing unit was utilised for wellbore clean out and subsequent deployment of the screen BHA in 2 runs.
The Results:
The case study demonstrated the applicability of ceramic sand screen as a stand-alone screen solution in unconsolidated, poorly sorted sand with nearly 30% fines content. The industry rule of thumb would have led to complaint sand control techniques adding complexity and cost. The operator achieved his goal of increasing production through a cost-effective retrofit solution deployed on coil tubing. Sand control was maintained at a higher drawdown so that within 5 days the equipment was paid back based on incremental oil production.
A strong collaboration and team effort between the operator, coil tubing service provider and 3M as a technology provider, enabled a cost-effective approach to achieve sand free production and unlocked the production potential from a challenging offshore oil producing well.
Visit https://multimedia.3m.com/mws/media/1903939O/3m-ceramic-san-screens.pdf to find out more.
In our previous article, I promised to address the doubts of the readers around the material that could be placed in the hole as a barrier for plug and abandonment, and whether those materials differ depending on time span defined for the barrier’s life.
I gave you a spoiler when I told you that cement IS NOT the only material for well abandonment. So now, let’s dig further into the matter.
This article was originally published 25. October 2017 by former Wellcem employee Miguel Diaz. An updated version is republished now by Svein Normann, in order to introduce this important topic to our new blog readers and followers since then:
Hopefully, you all remember that we defined the Gulf of Mexico (GoM) and the North Sea as the two more relevant places regarding the availability of detailed and comprehensive legislation that addresses the well abandonment process.
Moreover, we gave special attention to the UK offshore oil and gas organization (UKOG) (https://oilandgasuk.co.uk) series of three documents on well abandonment practices. They include a “Guideline on qualification of materials for the abandonment of wells.”
It was issued in 2012 and reviewed three years after with contributions from experts from Shell, the University of Dundee, ConocoPhillips, SINTEF, TNO, Schlumberger, BP, Chevron, ExxonMobil, Los Alamos National Lab, Sandaband, Halliburton, Baker BJ Services, TOTAL, Raw water and Wellcem.
Read also: Our cases “Collapse in the tubing and casing” and “Plugging a well with no mechanical integrity“
TEMPORAL OR PERMANENT IT IS ALL THE SAME
When we place barriers in the well to isolate formations from each other and the surface with no intention to ever re-enter the abandoned part of the wellbore, the abandonment is considered a permanent one.
Where there is an intention to re-enter, we call it temporary abandonment (typically a matter of months). Besides the timeline of the application, the only other difference between permanent and temporary abandonment is that a temporary barrier is not required to extend across the full section of the well and include all annuli.
Other than that, a temporary barrier must fulfil some functions, which we discuss below, and they do not differ from those of permanent barriers, except possibly for a relaxed timescale of required durability.
FUNCTIONAL REQUIREMENTS OF PERMANENT BARRIERS
Again, the UKOG guideline defines the requirements for a well abandonment barrier to be successful, those are:
1. Sealing
A leak is a breach of integrity which passes entirely through the barrier. Such a gap can take the form of a crack or channel and may be present from the start of placement or develop over a long or short period. Failure can occur due to debonding, dissolution or cracking.
The primary function of a permanent barrier is to provide a seal against leaks. But, the curious thing is that the guideline considers inevitable that fluid within the well will ultimately migrate past a barrier, albeit at a low rate.
Thus, appropriate barriers are those through which the rate of permeation is acceptably low. The approach taken is to require that the barrier permits leakage of fluids at the same or a lower rate than the caprock. The permeability of caprock is typically within the range of 0.001-1 micro Darcy.
But from historical industry experience, barriers of 30m (100 ft) of “good” cement (usually with a permeability of 10 micro Darcy) are performing to a level satisfying the oil and gas industry.
A maximum permeability of 10 micro Darcy has then become the acceptance criteria for the qualification of a cement barrier of the sort discussed above. If permeability is lower, a shorter barrier may be installed. Longer barriers could be used for more permeable materials.
2.Position
Once placed, the barrier should not move, either along the wellbore or in a lateral direction. For instance, the barriers should not be pushed upwards by pressure developing below. The barrier materials are required to remain attached to interfaces to where it was installed.
Materials used for P&A should pass shear bond stress tests demonstrating what delta pressures are needed to extrude the materials out of a cylindrical cell that mimics a cased well.
3.Placement
The permanent barrier material should be easily placed in a wellbore at the desired depth and perform as required. Therefore, it should have appropriate properties that allow it to displace the existing fluids and form a continuous sealing medium, even when considering its inevitable contamination.
Where a barrier material undergoes a transformation from liquid to a solid, this period of change must be sufficiently short to prevent an escape of fluid and unacceptable disruption of the barrier.
Verification of the barrier placement must be possible even in deviated wells.
Read more: Lab tests to review when designing a “gas-tight” cement slurry
4.Durability
The barrier material should not degrade such that its sealing capabilities or position are compromised. It should be able to withstand wellbore changing conditions for ages.
5.Removal and reparability
Being removable is a fundamental element if the abandonment was a temporal one. The barrier should be easy to remove with existing conventional industry methods (drill bits, mills, acid, etc.). Also, if a leak through a barrier would develop, there should be a method to remove/repair it to regain integrity.
6.Operating conditions
After placement and activation, the permanent barrier material will have to withstand external loadings that could vary with time, among those are:
MATERIALS
Having read these expected requirements for a material to be considered a qualified abandonment barrier;
Cement is currently used in wells as the prime material for abandonment purposes because it is found to have similar properties to the rock that it is replacing. However, given its operational limitations, alternative materials, which offer significant advantages over cement, are being proposed and developed by the industry.
These substances, however, still don’t replace cement. That’s because – when compared with cement that has been used for hundred years or so – uncertainty with regards to long-term integrity of the alternative materials acts as disincentive for their use.
The legislation, as reviewed last week, also play a role in the incentive to use cement for P&As; some countries refer only to cement as abandonment material in their legislation, while some others ask for an abandonment material to be “equivalent to cement.”
The UKOG guideline for qualification of materials then defines (see table above) a list of materials that offer characteristics that meet all the functional requirements for permanent barriers that we reviewed above.
I will give you a summary:
INTERESTING CASE STORIES
From the list, the two that have made more advances in recent years are Thermo-setting polymers (Group C) and the modified in-situ materials (group J).
This last case particularly refers to “Melting the cap rock,” which consists of using a thermite plug to seal off the well by melting both the well components and the rock formation around them to recreate the cap rock.
This method was trialed in 2016 by Centrica in Canada claiming it could potentially reduce well P&A costs by more than 50%.
The Thermo-setting slurries have been around for a slightly longer time. Once introduced, it was evident that resins have a lot to offer. Using the “requirements for permanent barriers” as a checklist – and with a comparison against cement in mind – the resins have:
In 2012, the first couple of cases of bull-heading abandonment were documented in the Gulf of Mexico (Charpiot & Jones, Offshore Magazin, May 2013). In the first one, a weighted resin with low-viscosity was used to abandon a well due to its ability to be placed with minimal injectivity and yet provide high-compressive strength after setting. The well represented a closed system because the platform sheared away during a hurricane.
The same year in another Gulf of Mexico-well, bubbles were coming from the annulus after an initial cut on the casing. In this case, the resin was used in a squeeze application, stopping the annular leak. Subsequently, a 50-ft (15-m) resin plug was set. The resin had a low yield point, and due to its ability to be formulated free of solids, it penetrated small cracks and micro-annuli without the risk of particle bridging.
In March 2016, the Gulf of Mexico’s first lower abandonment using resin took place. Because there was a downhole obstruction, the operator of this particular field determined that it could not reliably carry out a lower temporary abandonment with cement. Cement could have separated or dehydrated under tight spaces in the restricted flow paths, whereas resin would have had no such issues. In this particular case, dual-coiled tubing risers were used to deliver fluids from the waterline down to the mudline.
In June 2017, another interesting P&A operation was carried out in the Middle East, with a thermos-setting polyester resin. The well involved was drilled in November 1979 and in April 2017 it developed 1,100 psi of sustain casing pressure in the 4½” x 9⅝” tubing-casing annulus (TCA). At the same time, the H2S Rupture Exposure Radius (RER) for the well was reported as 63 meters to the half “Low flammable limit” (LFL) and 1049 meters to the 30 ppm concentration threshold.
As per client definition, a well is located in a populated area “if the population exceeds 20 persons residing, working, or otherwise located within the 30 ppm rupture exposure radius (RER)”. In this case, significant civilian’s structures existed within that radius; a Highway at 524 meters and a hospital at 786 meters, for instance.
The ultimate goal of the workover operation was to re-complete the well running a 4-1/2” liner inside the 7-inch liner (covering the existing perforations). But before a rig could move in and remove the existing completion, the integrity of the well have to be re-gained taking into consideration the limitations given by the pressurized annulus, H2S levels present on the formation and the well surface location.
The operation was set to be done with a 1-1/2” Coiled tubing giving the ID restrictions of the 2-7/8” completion tubing in the well. Resin was chosen as the barrier. The low viscosity allowed lower pumping pressures while placement, and the solid free nature enabled maximum penetration during the squeeze operation. (1,000 – 1,200 psi pressure limitation set for the job due to casing conditions).
Nine and a half barrels of an 88 pcf thermo-activated polymer resin was spotted without inconvenience.
The resin plug was then pressure tested and milled allowing the well to be circulated with full returns and a new 4-1/2” liner cemented in place.
The job was a success proving resins can be used for P&A and, also, it can be placed safely with one of the smaller available coiled tubing pipes in the market.
By Svein Normann
Svein Normann has a MSc from the Norwegian University of Science and Technology and 27 years’ experience in the oilfield. 10 years in field operations as cement operator, design engineer and operations manager. Further on 16 years in oilfield equipment engineering and development. He is today working as VP Global Operations & Technology at Wellcem AS.
Thanks to the unique properties of technical ceramics, ceramic sand screens from 3M™ work beyond the limits of competing sand control techniques and outlast steel screens in an extreme hardness erosion test. Our Ceramic Sand Screen Systems resist chemical attack by hot sulfuric acid, aggressive completion fluids and other corrosive chemicals in the oil and gas operations industry. See the difference.
– Do you produce unmanageable sand when maximizing your asset production?
– Is well-stock non-productive or shut-in resultant of failed sand control technology?
We would like to understand better your sand control challenges and to introduce further technical knowledge, case studies, and how to deliver value to your operation.
Custom design of 3M™ Ceramic Sand Screens was developed and qualified to address reservoir challenges and target production rates.
– Do you produce unmanageable sand when maximizing your asset production?
– Is well-stock non-productive or shut-in resultant of failed sand control technology?
We would like to understand better your sand control challenges and to introduce further technical knowledge, case studies, and how to deliver value to your operation.
Annulus pressure on the well caused the Stainless Expandable Seamless (SES) casing patch to collapse. Previous attempts to recover the casing patch had proven unsuccessful, with insufficient rig power being a major issue in the recovery.
This is the second in our line of ‘Unconventional Fishing’ case studies, read more on delivering up to 5x power directly to stuck fish.
The downhole adaptability of the TITAN System ensures and maximises the recoverable casing by utilizing the pulling capacity of the hydraulic power tool with added repeatable casing cutting capability in a single trip.
In unconsolidated reservoirs, formation sand can cause major disruption to oil and gas production. It can contaminate product, plug the wellbore, slow production, damage equipment – and even spread downstream to pipelines and refining facilities.
Conventional metallic sand screens, one of the most common sand control methods, are vulnerable to abrasion and erosion – challenges that are prevalent in the unconsolidated formations where sand control is most critical. 3M™ Ceramic Sand Screens offer a proven alternative. Made from extremely hard, erosion-resistant materials, 3M™ Ceramic Sand Screens are more durable, more reliable and longer lasting than metallic screens.
3M™ Ceramic Sand Screens can help maximize your flow capacity, productivity and well life. Check out our new video to see this breakthrough technology in action!
3M™ Ceramic Sand Screens show minimal wear under reservoir conditions, even under high velocity flows.
3M™ Ceramic Sand Screens offer an alternative to gravel packing, with simpler logistics and completion design. They can be deployed in new or existing horizontal, deviated or vertical wells and can unlock wells where sand failure has occurred – giving you a unique opportunity to produce reserves that would otherwise be lost.
That’s sand control – made simple.
– Do you produce unmanageable sand when maximizing your asset production?
– Do you manage sand rather than control sand, resulting in lost daily production?
– Is well-stock non-productive or shut-in resultant of failed sand control technology?
We would like to understand better your sand control challenges and to introduce further technical knowledge, case studies, and how to deliver value to your operation.
Following the article from Colin Beharie (“P&A: Are you absolutely sure it’s plugged?“), we got a significant amount of questions on well’s plugging/abandonment.
In this article, I will try to answer as many as possible.
These were some of the questions popping out from our readers.
I have organized our answers in three main areas:
The scope of the article is quite broad, so I’ll split it into three sections; one for each area.
The topic should be straightforward since well abandonment is an inevitable stage in the life of a well and one that should be as obvious as drilling and casing it, but it is not. So let’s get started.
From a legislation perspective, at least for offshore wells, the 1958 Geneva Convention rules, and the 1982 Law of the Sea regulations are the accepted framework for removal and disposal of offshore structures. Obviously, regulating offshore structures, it doesn’t apply to land wells for which there is no universal international regulation nor standard.
That said, the specificity, significance and in general, the approach towards well abandonment and decommissioning vary significantly by country. While some countries, especially the major oil and gas hubs, such as the Gulf of Mexico (GoM) and the North Sea, possess a detailed and specific legislation dictating the do’s and don’ts of decommissioning a well, other countries, like Italy, Ukraine, Angola, and Australia, only go as far as setting the goals of the P&A operation. Also, essential niches for the industry, such as Venezuela, Oman, Egypt, and Russia, have no known legislation on this matter.
Two of the most highly-regulated areas for well abandonment and intervention are the GoM and the North Sea. In both areas, most fields are reaching the end of their productive lives and are made up of aging infrastructure. These long-life producing regions that once pioneered offshore drilling are, under pressure. The public opinion focuses on environmental concerns and the official regulatory agencies actively intervening, getting ready to plug and abandon (P&A) a substantial number of wells in the next few years.
In the UK sector of the North Sea, (according to Abshire, Desai, Mueller, Paulsen, Robertson & Solheim, Oilfield Review, 2012) it was estimated that more than 500 structures with about 3,000 wells were slated for permanent abandonment as soon as possible. In the Norwegian sector, more than 350 platforms and more than 3,700 wells must be permanently abandoned. Additionally, there are more than 200 structures slated for decommissioning offshore the Netherlands, Denmark, Ireland, Spain, and Germany.
Globally, (according to Smith, Olstad & Segura, Offshore 71, 2011) an estimated 20,000 offshore idle wells have been identified for abandonment, with 60% located in GoM. Some of the GoM wells have been idle for five years or longer. The “Idle Iron” regulation (NTL No. 2010-N05) states that if a GoM well has not been productive for three or more years, the operator must put forward a plan, including a timeframe and methodology, to abandon it.
This proliferation of present and future P&A lead local regulatory bodies in these regions to set leading edge legislation that serves as an example to the industry and establishes “best practices” worldwide.
In the GoM, (regulated by the federal government’s Bureau of Safety and Environmental Enforcement) the “Idle Iron” regulations and guidelines for nonproducing wells were introduced in October 2010. They aim to provide some clarity about the required standards and outcomes expected from oil and gas companies as part of an abandonment philosophy.
The website of the Cornell Law School (https://www.law.cornell.edu/cfr/text/30/250.1715) offers (for free) an excellent summary of the “Code of Federal Regulation,” title 30, Chapter II, Subchapter B, part 250, subpart Q, section 250.1715. This summary contains specifications on the length and location of barriers in the well and points towards the use of tools such as bridge plugs, retainers, baskets or cement as a barrier:
In the North Sea, regulated in the UK by the government’s Health and Safety Executive, and in Norway by NORSOK standards, similar legislation is available. But what is more interesting is that the UK offshore oil and gas organization (https://oilandgasuk.co.uk) offers a series of three comprehensive documents on well abandonment practices:
We will refer again next week to these documents as they will help us answer questions like “Can only cement be used as a barrier?”, but for now, let’s focus more on how to do it instead of on what to use.
The guideline defines that “abandonment of wells is concerned with the isolation of rock formations that have flow potential” and defines flow potential as coming from “formations with permeability and pressure differential with other formations or surface.” The assessment of flow potential is expected to consider the likelihood of flow under future conditions, i.e., “re-development for hydrocarbon extraction (possibly with enhanced recovery techniques),” underground gas storage projects, etc. So, all penetrated zones with the potential to flow require isolation from each other and surface by a minimum of one permanent barrier or two when appropriate. Two barriers from the surface are required if the zone is hydrocarbon bearing or contains over-pressurized water.
Click on picture for larger version
The barriers should be set in front of a suitable caprock (impermeable, laterally continuous and with adequate strength and thickness). It should overlap annular cement and meet a specific list of best practices. See figure 1 for more details.
Image not available
Figure 4. Example of open hole permanent barriers if potential internal pressure exceeds the casing shoe fracture pressure (two permanent barriers are required). Source: Guidelines for the Abandonment of Wells, p16 (OGUK, 2015).
The need for one or two barriers to isolate an open hole section is dictated by the conditions defined above regarding flow potential, and examples of its placement in open hole situations are shown in the guideline, see figure 2,3 and 4 for details.
For case hole sections, casing alone is not considered a barrier to the lateral flow, due to the potential for casing leaks, but cemented casing could be “as long as there is sufficient confidence in the quantity and quality of the cement in the annulus.” What this means is: If a log is available, 100 ft of good cement will do. If no logs are available then 1,000 ft of cement, using the theoretical top of cement as calculated by “differential pressures or monitored volumes during the original cement job,” would be required to allow for uncertainty. See figure 5.
Figure 5. Example of a cased hole abandonment schematic. The right side shows annulus cement verified by a log and the left side an estimated cement top. Source: Guidelines for the Abandonment of Wells, p19 (OGUK, 2015).
A great place to get more information or examples of other countries legislation is the website of the Global Carbon Capture and Storage Institute which “presents an overview of official regulations concerning well abandonment for a selected number of countries and states… (based on) …countries and regions considered (…) significantly engaged in oil and gas production (and/or with good) accessibility of regulatory data”.
The main European producers, the US/Canada, China, Japan, Australia and the International conventions are discussed there.
For those of you sitting in a country that falls in the goal-setting approach group, you’ll have greater flexibility to design a fit-for-purpose well abandonment plan (which more likely will be significantly cheaper, too).
Having less clear guidelines in place puts increased emphasis on the regulatory bodies to carefully review, and subsequently approve, any plans for well decommissioning to ensure they will achieve long-term well integrity. In countries like Venezuela, with no clear governmental guidelines documented, well abandonment plans drafted by the operators go to the ministry of energy and mines and (sometimes) to the ministry of environment and waters. There, they are evaluated and approved case by case.
In these countries that have adopted a goal-setting approach, it is common to see the operators refer to guidelines like the one from OGUK to demonstrate that they have followed “industry best practice.” To experience their governments adopting international regulations, with slight modifications suitable for their geographic areas and demands, and to abide their needs and laws, wouldn’t be a surprise.
The guidelines, as mentioned earlier, also state what materials and tools can be used when and how. In the next article, I will cover how cement is not the only alternative to abandon wells, and what “melting the cap rock” means for well abandonment.
Since the regulations varies so much from country to country and operators take different approaches to P&A based as much on local legislation as on their own standards, please share with us your experiences from where you have worked. What did the law say, and what can you recall from the standards for P&A from those operators you worked with?
See you all next month!
Guidelines for setting Cement Plugs
Written by Svein Normann
Svein Normann has a MSc from the Norwegian University of Science and Technology and 27 years’ experience in the oilfield. 10 years in field operations as cement operator, design engineer and operations manager. Further on 16 years in oilfield equipment engineering and development. He is today working as VP Global Operations & Technology at Wellcem AS.
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