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.
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.
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.
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.
This Video of the Month showcases how the application of SandVA, paired with Optis Infinity technology, helped the operator of a gas well to confirm the integrity of their asset and demonstrate compliance with regulatory requirements.
Sand control or sand management is estimated to be required in more than 50% of wells globally during their productive lives. The need arises in both conventional and unconventional wells with high rate gas production from unconsolidated sandstones reservoirs and flowback from hydraulically fractured wells providing common examples. In certain regions the use of slotted liners or sand screens to control sand production is widespread. In these locations production from unconsolidated sands would not be economically possible without their use.
A gas storage well operator in continental Europe required detailed assessment and visual confirmation of the condition of sand screens within the well. Sand control in this well is further complicated by frequently alternating periods of injection and production. Regulatory requirements entail periodically confirming the condition of sand screens and other downhole components.
EV’s Optis Infinity M125 tool was deployed on slickline with both downview and sideview video footage acquired over the entire well. Four screen sections with an average length of 6m (20 feet) were captured. The resulting images were subsequently visually inspected and measured to evaluate both erosion and plugging of the screens, to provide a quantitative evaluation of screen integrity and inflow performance.
Having demonstrated that the integrity of the screen was indeed intact, the operator satisfied the legislative requirements to continue operation of the well. The plugging of the base holes was noted, but the operator elected to take no further action at this time and would assess changes in the levels of plugging during subsequent inspections. From this time-lapse information a rate of change could be calculated to provide input for decision making on when to schedule wellbore and screen clean-up interventions. This quantified information provided by SandVA allows patterns and trends to be identified, helping diagnose the causes of problems and understand their severity. This information helps operators implement effective sand management programs, enabling them to maximize the performance and productive life of their assets.
North Sea oil and gas operators are failing to make the most from their existing well stocks, with some 30% (600) shut-in and 33 million barrels of oil equivalent (boe) lost due to well losses – the equivalent of a new west of Shetland field.
The figures, from 2017 but reflective also of 2018, were presented by Margaret Copland, senior wells and technical manager at the Oil & Gas Authority (OGA) at this morning’s Offshore Well Intervention Europe (OWIE) conference in Aberdeen.
Restoring shut-in wells can add production at economic rates said Copland. According to the OGA’s data, 22 million boe of production was added in 2017, through intervention operations, at an average well restoration costs in 2017 averaged just US$6.4/boe. “That’s an amazing rate of return,” Copland told the event, which continues tomorrow. Yet, well intervention was carried out on just 14% of wells in 2017, she said. “We need to think about these wells in terms of economics. Given that 30% of wells are sitting shut-in – that’s not wells that are in cessation of production (COP), it’s 30% of the active well stock – there is something wrong with a 14% intervention rate. We should be at 30%, trying to get these shut-in wells online, assuming facilities can handle it (eg. water handling etc.).”
The biggest cause of shut-in wells is integrity issues, which drove 45% of intervention operations in 2017. The second biggest is water production, either being too much and choking off hydrocarbon production or there not being enough capacity to handle the water topside, said Copland.
Production losses, which amounted to 26 million boe in 2015, 37 million boe in 2016, and 33 million boe, hasn’t seen an obvious trend, said Copland. “33 million boe is the equivalent of a big field west of Shetland,” she said. “That’s the potential. These well losses are not an issue with compressors or pipelines, it’s issues with wells and we are not seeing this being addressed. We are not sure that the industry knows at a granular level what’s causing these losses. Some are obvious: wells falling over and nothing being done about it, but that’s not the majority of losses. We are often asking if they understand their well losses, are they doing failure mode analysis, what are they doing to prevent it happening and we are getting a lot of blank faces.”
A big concern is the lack of well surveillance. Operators appear to not be doing enough to learn about what is happening in their wells. The rate of well surveillance work was just 8% of the active well stock in 2017, despite a large prize that could be had by doing well intervention, Copland said. “I don’t know what that number should have been but 8% is too low. We need to increase surveillance. The amount of data gathering going on is abysmal. Many companies have performance standards for data gathering, but how many have met it? I think not many. Without surveillance data, without going in to get data, without using new technology like the logging on fibre line, we cannot make the business case to make these projects work.”
John Hand, Technology Program Manager, Conventional Assets, ConocoPhillips, agrees. Opening the second day of the OWIE conference this morning, he said that, for the US onshore conventional business, increasing production rates, “is a big data problem and all you have to do is get that data and get it in a form people can look at across disciplines. In the Eagle Ford (play), we used data analytics to cut the time to drill in half over four years.” At 22 days per well, drilling teams had said they were at their technical limit. That time was reduced to 12 days and then seven days, over a four year period, Hand said.
Shut-in wells that are not going to be brought back online should be abandoned instead of left until cessation of production for abandonment work, added Copland. “It would be more economic to do something to isolate the well and preliminary log well before that,” she said. “Maybe an operator will be short of trees, they could get a tree off one of these wells and get it turned around ready for the next time a tree falls over. Waiting until the end of field life doesn’t help anyone.”
The bigger picture is a UK North Sea that’s largely mature but still with remaining potential. Some 7500 wells have been drilled in the UK to date, with 44 billion barrels of oil produced. More wells are now being plugged and abandoned than drilled, and exploration drilling is at an all time low. But, production efficiency in existing fields has been improved, new seismic data is being shot, and “Elephant fields” could still be found west of Shetland, said Copland.
Improving well intervention and increasing production could help push back COP dates and extend the life of the UK Continental Shelf, she said. To aid that drive, Copland says the OGA is close to finalising a wells strategy which it will then use to question operators on their own activities to make sure they’re doing all they can. This strategy was due to be published by the end of Q1 2019.
Today I’ll like to share with you a case history within a well integrity application. Several of our articles on this blog have focused on the importance of doing proper planning before mobilization. I hope this story will give you insight into how we execute all stages in operation from designing a suitable solution, recipe design, execution and to end-of-well reporting.
We are situated on a platform in the Norwegian sector of the North Sea. During pressure testing of a near completed injection well, a leak has been found. The leak point was located with the use of an acoustic log to the 7-in liner lap. The situation must be rectified as it is not possible to hand the well over without ensuring full integrity. We are called out to seal the liner lap and reestablish the integrity of the well.
THE CHALLENGE
This is the challenge we are facing: We are offshore on a fixed platform in the Norwegian sector of the North Sea. A water injector failed the final pressure test before it was to be perforated and put on-line. It is not a large leak, only 1.5 to 3 lpm at pressures from 150 to 340 bar.
Using an acoustic log, the leak was identified to be at or in the 7-in liner lap inside the 9-5/8” casing. The liner packer is not sealing as it should and allows fluid to pass. The required pressure test is to 345 bar.
Well data:
The client has few options. Running a straddle packer is possible, but very expensive and will lead to reduced ID and limit the access to the reservoir. Cement will be very difficult if not impossible to squeeze into such small leaks. Besides, it will easily be mixed with- and thinned out by the brine. Using resin will be a good solution, but the challenge is how to get it to the right place. A rig or CT is not available, so a different delivery method must be found.
There is no doubt – ThermaSet can seal the leak if we get it to the right place. To get sufficient intact volume of ThermaSet to the critical position in an effective enough way to seal the leak is the most challenging undertaking in this case.
More to read: Effective ways of reducing well integrity problems
Our objective was to plug the leak in the liner hanger with resin and leave the bore of the well intact and open.
A typical scope for us in this type of operation is as follows:
THE PLAN
After designing the delivery solution and agreeing with the customer, we optimized a recipe for this application and performed lab testing for stability, rheology, setting time and compressive strength development as well as contamination tests with the two brines.
The delivery was to be done with an extended dump bailer on wireline allowing for a volume of 185 L delivered to the target depth.
To protect the 7-in liner, a bridge plug was to be set just inside the liner. A first run with the bailer would dump heavy (1.7 SG CaBr2) brine on top of the bridge plug to protect it from the ThermaSet and enable the retrieving tool to latch on and pull out the bridge plug after the job.
The ThermaSet resin recipe was designed at 1.3 SG to balance between the heavy brine on top of the bridge plug and the lighter brine (1.06 SG NaCl) in the well. ThermaSet is immiscible with brine (and any water-based fluid) so it was expected that the delivery would be possible with very little intermixing of fluids in the interfaces.
After dumping the heavy brine, the well was pressured up to squeeze away some of the brine so that the top of the heavy brine would be precisely at the leakage point at the liner hanger top. 185 L of ThermaSet was dumped at the interface, the bailer was pulled out, and pressure was applied to squeeze away the ThermaSet. It was important not to over-displace and open up the leak path again, so the plan was to leave around 1/3 of the ThermaSet volume inside the liner.
The recipe allowed for over 18 hours curing time, so there should be enough time to run in and pull out the bridge plug after placement. The plan was to release the bridge plug and allow the heavy brine and remaining ThermaSet to drop by gravity to the bottom of the 7-in liner where it would set up, but not be to any hindrance for future operations or the well performance.
A detailed program was created together with the operator. The following was our plan for execution:
After the heavy brine was in place on top of the bridge plug:
THE JOB AND RESULT
The job was done according to plan; however, the bridge plug was not possible to latch onto (it was set with the neck was sticking out into a part of the well with very large ID and we could not latch onto it). Hence the remaining ThermaSet cured and it had to be milled out with CT. After doing this, latching onto the bridge plug was successful, it was released and pushed down to the 7” rat hole. The well was then successfully tested and could be completed according to plan.
More to read: Dealing with micro-annuli in casing cement
The last couple of months we have covered several topics within the Well integrity, and I believe around ten articles have been elaborating on subjects related to sustained casing pressure (SCP).
This is one of the articles which you also can read to learn more: 5 keys to the successful remediation of sustained annular pressure.
Lessons Learned and Takeaways:
ThermaSet can be mixed at higher densities and long setting time enabling a stable resin to be dumped at depth using a bailer on wireline.
We are pleased to announce that the Oil and Gas Authority will be speaking at OWI EU 2019 for the first time and are allowing us to distribute their latest Well Insights report to our audience of well intervention experts.
EV’s RT120 Drillpipe Camera was utilized to aid the fishing operations an operator was undertaking in a subsea completed well in which the operator was pulling the completion in order to sidetrack the well.
Hear Bjørn Bjerke, Chief Executive Officer, Petro Well Services share a case study outlining their role in the plug and abandonment of the Jotun B wells.
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.
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