Access three initial case studies from new technology provider Wellvene, who have launched a full range of Tubing Hanger, DHSV and SSD Isolation and Hold Open Protection Sleeves.
Europe
- Region: North Sea
- Topics: All Topics
- Date: Jun, 2018
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- Region: North Sea
- Topics: All Topics
- Date: Jun, 2018
Hear David Smith of TAM International discuss how sometimes inflatable technologies are the only option – including when and where they provides a cost effective P&A or intervention solution.
- Region: North Sea
- Topics: All Topics
- Date: May, 2018
Well integrity (or leaks) have well safety and environmental aspects. You should also take aspects related to production, reputation and asset value into serious consideration.
WHAT IS WELL INTEGRITY?
Well Integrity may be defined as: “application of technical, operational and organizational solutions to reduce the risk of uncontrolled release of formation fluids throughout the life cycle of a well” (from Norsok D-010).
D-010 as well as other guidelines and standards, only set out the minimum requirements to a well in very general terms and at a very high level that is not always very helpful during an actual operation.
In this blog post I will share with you a checklist made to reduce well integrity problems.
TAKE NO SHORTCUTS IN THE PLANNING OF A WELL
The preferred way of doing things is planning and executing the construction of the well and particularly the primary cement jobs in an optimum way, rather than fixing things later.
Constructing a well is complicated and expensive business, it is often tempting to take some short-cuts at some stage that seems ok and insignificant but can lead to problems later in the life of the well.
Another important, but often forgotten aspect of planning is that although the plan is maybe good and well executed if somebody at a later stage suddenly wants to use the well differently, all the good planning and execution may be wasted.
CHECKLIST FOR PREVENTING PROBLEMS IN THE FIRST PLACE:
1. Risk analysis
When planning an operation, check if the operation has been done before on previous wells.
If it has, preferably several times, check if it was successful in all cases. If it was, check carefully if your operation has ANY factors different from the previous wells. Even factors you do not initially think could be important.
Any difference, list it and do a risk analysis (see point 4) on all possible ways that this change could lead to problems. Make sure you do not get the same problem again.
2. Money, time and quality
Even if you have a previously accepted and well-proven program, sometimes you want to, or maybe more often, you are told to find some ways to save money.
Now there are many ways to do that of course, but there is a strong link between money, time and quality: Changing any of these factors can easily, and most often will, affect the other two negatively.
Now this is not always a problem, since quality does not have to be better than “good enough.” Now when do you know it is “good enough”, see that is the challenge. And of course, anytime you change something from a well-proven and established system, you run the risk of unwanted/unexpected negative consequences.
Saving money is easy. But saving money without affecting quality in a significant way, is much harder.
3. Technical solutions
When selecting technical solutions, it is important to define the requirements for the well barrier to ensure the well integrity is maintained throughout the life of the well, and choose the right equipment specifications accordingly.
Often the reason for the leak is due to equipment in the well that is not designed for the conditions, or the conditions have changed, or the well is used differently from its original intended use.
Most will count the producing years as the life of a well, but really, we have made a vertical pathway that will be there for hundreds, if not, thousands of years. That should be considered both when constructing a well and when abandoning it.
If something new, it needs to have been tested and qualified according to good standards. DNV-RP-A203 is a great reference system.
4. Identify and eliminate risks
If something has not been done before, a thorough risk analysis should always be done.
Failure modes, effects, and criticality analysis (FMECA) is a widely used method for system reliability assessment and there are plenty links on the internet on how to use this process.
Now just because a risk analysis has been done, doesn’t mean you are safe. Identifying any and all risks is very difficult, and it is the unknown unknowns that get you. Finding the unknown unknowns, are by definition impossible.
The only thing you can do is to be thorough and systematic. Get in touch with any and all people around you with experience and knowledge to help you list all the elements of the operation. For each element, make a list of the potential risk or what can possibly go wrong. That is the essential part of a risk analysis!
To eliminate a risk or mitigate it, is somewhat easy, but if you have not identified it, well… then you cannot do anything to eliminate or mitigate it.
5. People and equipment
Further on, many reasons for integrity issues arise from operational errors during construction or completion of the well.
These reasons have very much to do with proper planning, training, and execution per plan.
- People. It is essential that you have people in place that makes correct decisions on well integrity issues or aspects that relates to well integrity. They must be well and correctly trained for the job and the responsibility they have.
- Use equipment and methods that are established and approved by the company, or if lacking, in compliance with acceptable industry standards
6. Updated overview
Good visual schematic overview over all leak pathways and of barriers in place. Keeping this schematic visual and correctly updated at all time is essential.
George E. King presented a study for the United States Energy Association in November 2014 focusing on well integrity. You can watch the presentation on this link: Well integrity – Basics, Prevention, Monitoring, Red Flags & Repair options
Mr. King pointed out three important red flags looking into the future:
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- There are very few well integrity failures that do not show signs of their approach
- Corrosion possibly creates more damage than all other failures combined
- To predict future problems – take a look at the past
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- What era of technology was the well built in?
- What level of maintenance has the asset received?
- Who is responsible?
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If you manage to keep on track with these bits of advice, you will have a good chance of keeping your well tight and safe for many years to come.
![[Free Guide] The most common causes for leaks in oil wells and 8 questions to consider before you select solution](/images/2018/05/checklist-1.jpeg)
- Region: North Sea
- Topics: All Topics
- Date: May, 2018
We are situated on a platform in the Dutch sector of the North Sea. During pressure bleed-off of the annulus, both gas and oil-like fluid has been observed. The situation is unwanted and it can potentially escalate without remedial work. We are called out to reestablish the integrity of the oil producing well.
The last couple of months we have covered several topics within the Well integrity, and I believe around ten articles have been elaborating around subjects related to sustained casing pressure (SCP).
Today I’ll like to share with you a case history within a SCP application.
Several of our articles have focused on the importance of doing proper planning before mobilization. I hope this story will give you good insight into how we execute all stages in operation from designing a suitable solution, recipe design, execution and to end of well reporting.
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- Region: North Sea
- Topics: All Topics
- Date: Mar, 2018
Offshore Network have created a 2018 Market Forecast. The whitepaper, titled 2018 Market Forecast: What does the oil price mean for well intervention? Highlights the likely path of the oil price throughout 2018 and the correlating well services which will be in demand. The paper includes a forecast of the Brent and WTI oil price throughout 2018, an overview of the uplift works operators can utilize to take advantage of increased oil price and an analysis of why P&A activity will still increase in 2018, even when a higher oil price makes more fields economic.
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- Region: North Sea
- Topics: All Topics
- Date: Jan, 2018
A Major North Sea operator required scale-free sections of tubing to perform a plug set and tubing cut prior to pulling the completion. Calcium carbonate scale (CaCO3) forms inside the tubing and is very difficult to remove using mechanical or chemical methods. This objective was previously achieved from a jack-up rig using coiled-tubing and jetting technology (fluids & abrasives). The operator had previous success using Blue Spark’s WASP® tool (Wireline Applied Stimulation Pulsing) to remove scale from other completion hardware, so they decided to use WASP® to clean sections of the tubing.
The workover was done without a jack-up rig or coiled tubing. The WASP® tool was deployed on the operator’s preferred wireline provider’s E-Line from the platform, prior to the jack-up’s arrival. The treatment was performed at 5,800 ft. MD in a section of the wellbore that was at 30° deviation. Two 20-foot intervals were treated in one wireline run in less than 4 hours of treatment time.
A multi-finger caliper (MFC) log was performed on wireline to verify the scale removal. The caliper log (see Figure 1) confirmed that the WASP® had completely removed the CaCO3 scale from the inside of tubing over the two treated sections. Subsequently, the plug was set across the WASP® treated tubing interval and pressure tested successfully. The tubing cut was also completed successfully at the WASP® treated tubing interval, and on recovery of the tubing it was shown that all the scale had indeed been removed from this interval.
As a result of using WASP® to clean the sections of tubing:
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- Coiled Tubing was not required, eliminating the cost of that service – mobilisation, rig-up, rig-down and reduced crew.
- There was a reduction of 8 days of jack-up rig time, as the WASP® operation was performed offline.
- The workover required no chemicals, explosives or controlled goods, and as such was environmentally friendly and extremely safe.
- The workover to remove scale inside tubing was completed in a very cost-effective and efficient manner.
This customer has also used WASP® to remove scale in other completion equipment, including Sub-surface Safety Valves, Side Pocket Mandrels, and Gas Lift Valves.
- Region: North Sea
- Topics: All Topics, Decommissioning
- Date: Jan, 2018
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.
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- How many plugs are we supposed to pump?
- Is cement the only material existing for well abandonment?
- Is there an international standard governing the decommissioning of wells?
- Are there differences when it comes to permanent or temporal abandonment?
These were some of the questions popping out from our readers.
I have organized our answers in three main areas:
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- Requirements for plug and abandonment of an oil/gas well – Legislation and Job design
- Materials to be used
- Abandonment techniques (placement methods, etc. including some of the new technologies that are out there already).
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.
REQUIREMENTS FOR PLUG & ABANDONMENT (LEGISLATION)
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:
Source: 30 CFR 250.1715 (Legal Information Institute, 2015)
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:
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- “Guidelines for the Suspension and Abandonment of Wells.”
- “Guideline on qualification of materials for the abandonment of wells.”
- “Guideline on Cost Estimation of well abandonment operations.”
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.
Figure 1. Source: Guidelines for the Abandonment of Wells, p12 (OGUK, 2015)
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.
Figure 2. Example of permanent barriers for an open hole if potential internal pressure does not exceed the casing shoe fracture pressure. Source: Guidelines for the Abandonment of Wells, p16 (OGUK, 2015).
Figure 3. Example of open hole permanent barriers if zone A requires isolation from zone B, but the potential pressure from zone A does not exceed the casing shoe fracture pressure (one permanent barrier is adequate). Source: Guidelines for the Abandonment of Wells, p17 (OGUK, 2015).
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).
WHAT ABOUT THE REST OF THE WORLD?
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.
WHAT’S NEXT?
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 approachs 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?
Miguel Diaz
Miguel has 20 years’ experience from operations, technical advisor, quality assurance, business development and management positions in the oil & gas industry from all areas of the high-pressure pumping services. He has worked in South America, the Caribbean Sea, central and eastern Europe, Sub-Sahara Africa and the middle east. Miguel serves as one of our cementing experts and is our Business Development Manager for the Middle East and North Africa region.
- Region: North Sea
- Topics: All Topics, Decommissioning
- Date: Dec, 2017
In the world of oilfield cementing, verification that the plug is in place and withstands the pressure is an important part of plugging operations. The consequences can be substantial under certain circumstances if the set plug does not hold as expected.
The famous words “I am confident it will work or has worked” can sometimes come back to haunt us. Planning and execution of an operation are not enough – it is also important to verify that execution and that the planned objectives have been achieved.
FOLLOWING THE STANDARDS
Typical government regulations require a leak test by application of a differential pressure to prove that the plug is indeed holding.
NORSOK Standard D-010 states that the pressure should be applied in the direction of the flow. However, if this is impractical, the pressure can be applied against the flow direction. It further states low-pressure leak test (1,5 MPa to 2 MPa for 5 min) should be performed before high-pressure leak testing. High-pressure testing should last for 10 min.
In the event, leak testing is not possible. Verification through assessment of job planning and actual job performance parameters are available options. These would include verification of the slurry sample under the pressure and temperature conditions of the well.
It is also noted. “For practical purposes acceptance criteria should be established to allow for volume, temperature effects, air entrapment and media compressibility. For situations where the leak-rate cannot be monitored or measured, the criteria for maximum allowable pressure leak (stable reading) shall be established.”
For open hole type plugs, tagging is essential. It’s recommended to pressure-test plugs at 1000 psi above estimated formation strength. The top of the plug should be located/identified with wireline. A weight test can also be carried out to ensure depth and integrity of the plug.
Read more: Cement plugging: A nightmare waiting to happen?
OTHER SOUND HABITS
There is no doubt that verification of barriers is necessary to make sure that plugs are holding as designed. For a good plug, bonding is a major factor. Therefore, hole preparation and placement are the first factors in achieving a successful verification.
Other sound habits include conducting use of an injectivity test to ensure the material can be placed as designed. Accurate placement and excellent bonding are the twin factors of plugging success.
Choice of material can also be a vital factor. Plugs for particular types of reservoirs can be improved by pumping a resin ahead of the cement plugs to ensure better sealing and reduce the chance for micro-annulus.
Read more: Dealing with micro annuli in casing cement
CHALLENGES OF INTERPRETATION
Common ways of conducting verification are tagging, pressure testing and long-term negative pressure testing. Under certain circumstances logging is also used. Interpretation of logging data can sometimes be more of an art than a science. Often due to the challenges of interpretation – which sometimes not very straightforward. Practical understanding is the key.
While there are several methods for barrier verification, pressure testing is the most effective. Negative and positive tests are in order. Industry literature points out that tests from the surface are best applied to reservoir/perforated zone area. Leaks in the secondary plugs may reflect a casing leak rather than plug failure.
WHERE DO WE GO FROM HERE?
Follow these simple steps to test your plug:
- Tag the plug (weight test where applicable)
- Inflow test
- Pressure test
- Static bubble observation – checking for gas migration
- Logging – for annular plugs
In the future, there will be technologies available that will make it easier to verify the integrity of plugs. Regardless of verification methods, the key to success is effective planning, proper material selection and accurate placement in the wellbore.
It’s difficult and costly to remediate a leaking barrier.
Read more: Plugging in depleted reservoirs
By Colin Beharie, Regional Manager Europe/Eurasia at Wellcem.
This article was sourced from Wellcem: https://blog.wellcem.com/plug-and-abandonment-are-you-absolutely-sure-its-plugged
For more information from Wellcem you can see their blog here: https://blog.wellcem.com
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- Region: North Sea
- Topics: All Topics
- Date: Jun, 2017
Marie Morkved, Head of Production Technology from Maersk Oil, presents a case study of a recent well intervention using coilhose technology, noting how it allows deployment with slick line equipment but still enables pumping to offer flexibility and efficiency.
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