Europe

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.

• • 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:

• • 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:

• • “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?

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:

1. 1. Tag the plug (weight test where applicable)
   2. Inflow test
   3. Pressure test
   4. Static bubble observation – checking for gas migration
   5. 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

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.

McKinsey & Co deliver a presentation regarding the value of North Sea well Intervention.

CHALLENGE

During a routine test, a major operator in the Danish North Sea determined that a Sub-surface Safety Valve (SSSV) of a well on an offshore platform would not successfully perform a routine inflow pressure test. The operator believed this was due to scale buildup in the upper completion.

Two separate interventions were attempted using conventional chemical and mechanical methods, but these failed to re-activate the SSSV. The operator had heard about electro-hydraulic stimulation (EHS), which can break up scale using shock waves and pressure pulses. The operator decided to mobilize Blue Spark’s WASP® technology, with its ability to remove scale from complex downhole completion equipment items, without risking any damage to them.

It was also decided to acquire a multi-fingered caliper log through a section of tubing to confirm the build-up of scale, then treat that scale, and lastly run the calipers again after the WASP® treatment to validate the removal of scale.

The post-treatment caliper log was then acquired, confirming that the scale was removed from the tubing (see figure at right). The scale was approximately 0.36 inches thick.

OUTCOME

• The WASP® tool is efficient to operate as it is deployed using a standard mono-conductor wireline unit. The treatment replaced either multiple slickline runs or a coiled tubing operation.
• The treatment was completed in less than 15 hours total operating time, while strictly following all normal protocols. The technology allows for the treatment of multiple intervals on the same run in the hole, further increasing efficiency.
• The technology is ideally suited for small footprint platforms and does not require an excessive amount of rig-up height or unusual lifting capability.
• The technology requires no chemicals, explosives or controlled goods, and as such is environmentally friendly and extremely safe.
• The technology was proven to be a very cost-effective solution to remove scale inside any completion equipment, including tubing, Subsurface Safety Valves, Side Pocket Mandrels, and Gas Lift Valves.

Cutting costs is imperative, but total life-cycle costs and sustainability are critical

Prolonged challenging market conditions have posed existential threats to operators, contractors and in the case of the North Sea, arguably, an entire basin. The severity and rate of market deterioration has made deep blanket cost reductions an imperative of survival, with little scope to consider more surgical approaches. However, as an impending potential market recovery, performance improvement and efficiency gains begin to appear, it is critical that measures taken to-date are carefully evaluated to ensure gains are sustainable and present a sound basis for long-term value creation for all stakeholders – operators, contractors and investors alike. For example, in February, Statoil said extensive cost cuts had brought the breakeven cost of projects set to start production by 2022 down to $41 per barrel from the $70 seen in 2013. There are initiatives in place to further improve this, but the question remains how much is attributable to margin pressure and how much is truly sustainable, structural, cost and performance improvement.

Operators: focus must now shift firmly towards structural cost savings

Despite the ongoing oversupply across much of the depth and breadth of the supply chain, the temptation to excessively leverage this to further reduce costs should be resisted. Any additional short-term benefits of this approach are far outweighed by the potential long-term damage this may do to the supply chain and ultimate impact on future supply and total life-cycle costs. Instead, by focusing on establishing more meaningful partnerships with contractors where risks and rewards can be shared, opportunities exist to develop sustainable structural cost savings through a collective focus on operational excellence and efficiency. By taking more integrated approaches to working and aligning the incentives of operators and contractors, the full benefits of standardisation, cross-functional optimisation and decision streamlining can be realised.

In more practical terms, to ensure cost savings can be sustained in the longer-term and real value is created for shareholders, operators must:

• Clearly identify key suppliers that can help deliver essential operational performance improvements and work closely with them to identify and prioritise areas that can have the greatest impact on reducing costs, saving time and creating net savings.
• Recognise the need for contracts to be financially viable for both parties, so that contractors can retain the necessary capability, competence and flexibility to fully support operators’ initiatives throughout the downturn and eventual market recovery without creating conditions that ultimately underpin rapid cost inflation and erosion of cost and performance improvements.
• Develop consistent working processes and templates that allow best practices and efficiency gains to be quickly captured and widely deployed across all operations.
  
  

Supply chain: focus on delivering sustainable value to operators by bridging gaps in understanding

At OFS Partners, a particular focus of our work with oilfield management teams (and oilfield service sector investors) is to help them better understand the needs of operators, improve their chances of success in procurement processes, and ensure products, services and precious R&D spend best positions them to deliver value to operators and create sustainable competitive advantages. Through this work, we consistently discover significant disconnects between what operators’ requirements, objectives and preferences are and how the supply chain in general is seeking to provide solutions. Resolving such misalignments in understanding is crucial to developing long-term sustainable cost improvements, and determining the winners and losers in the downturn.

To increase the likelihood of being a beneficiary of understanding gaps and current market disruption, contractors should:

• Engage early and often with operators to understand their needs and invest time and resources into building relationships rather than making grand assumptions based on static information or analysts’ assertions as to what is required, when and where.
• Efficiently deploy R&D capital to provide specific solutions for specific, well known, understood and actionable operator needs. This will ensure maximum value is created, captured by contractors and delivered to operators, while also avoiding the risk of innovations being scoped out by operators choosing to take alternative approaches.
• Seek strategic alliances, JVs or Mergers & Acquisitions that can truly enhance propositions and deliver real and immediate value to specific operator challenges. It’s essential such ventures are as closely linked to operational execution as possible and not simply tenuous thought leadership around collaboration.

Investors: look beyond the macro to unlock significant value creation opportunities

Macro market uncertainty and difficulties identifying attractive actionable investment opportunities has led many investors to either de-prioritise oil and gas as an investment theme altogether or take an approach of waiting until there are clear signs of a sustainable recovery in progress. Nonetheless, significant opportunities exist, particularly in market segments where the focus on cost reduction and performance improvement by some businesses is creating substantial market disruption by challenging conventional thinking with alternative solutions. Investors can best position themselves to create considerable value by leveraging a deep understanding of structural industry changes and how micro-market recovery expectations vary across the sector. In this regard, OFS Partners are actively working with investors to make timely and intelligent investment in new opportunities or building cases to deploy growth capital to safeguard the market positions of existing investments.

While well intervention spending has been hit harder than average industry cuts, the opportunities are still there to be had, not least from mature North Sea assets, delegates at Offshore Network’s Offshore Well Intervention Europe Conference heard this morning.

But, companies need to have the right attitude, processes and resources in place to get what could be double digit percentage increases in production that could be achieved. They also need to increase well intervention intensity and use a broad range of tools to benefit the most, says Dan Cole, General Manager, Energy Insights, McKinsey & Company. Setting out the industry context, Cole says: “We have been at $50/bbl or so for a year, more or less, and there are signs investment is starting to pick up. But it is hard to ignore the backdrop. A third of the cost has been taken out of the sector since its peak in 2014. Spending levels are the same as they were seven years ago. North Sea well maintenance spending has seen an even greater decrease, down 43%, from $1.3 billion in 2014*. Could it be the opportunity is not there? Absolutely not.”

To see what exactly the opportunity is, McKinsey looked at various metrics. One was the number of shut-in wells, relative to their maturity, measured by water cut. “There are more shut-in wells as fields become more depleted and have higher water cut,” he says. “One in five depleted wells are shut-in, some permanently. But if some could be restored to a level similar to [comparable] onstream wells, you could very quickly get some good production numbers. From a rough calculation, you could get to a couple of hundred thousand barrels of oil equivalent a day production [across the North Sea].”

Another metric McKinsey looked at was production losses, i.e. maximum production capacity compared with actual production. The losses are split into two categories: reservoirs losses, i.e. where a well is not producing as expected, maybe due to mechanical impairment, sand inflow, lack of pressure support, etc.; and losses incurred due to well work, i.e. testing and intervention work.

“From 2008-12, the amount of losses incurred increased year on year and peaked in 2012 (partly driven by the Elgin Franklin well control incident),” Cole says. “Since then, every year has seen fewer losses. The share of the losses has also moved from reservoir losses to losses due to well work [i.e. testing and intervention work], which is encouraging to see.”

The industry also knows more now about what better well work and reservoir management looks like, through more experience and benchmarking. Examples can be given which show that when two operators with similar assets are compared, the one which performs more interventions and with a wider range of intervention tools and techniques sees greater production increases than the other.

McKinsey compared two such operators, one who intervened in one in 15 wells and the other one in three. The second had 9-10% increase in production, compared with 2% on the first. “Consistently, operators with higher levels of intervention and production use a broader range of intervention tools,” says Cole. “Add a broader range of tools and more intensive intervention levels drives overall better performance around well intervention and reservoir management.”

By seeking additional recovery, restoring shut-in wells, improving reservoir management, increasing the ratio of water injection and doing infill drilling (increasing the number of wells per reservoir), could bring $70-350 million additional returns in the first year, says Cole, according to studies by McKinsey. Cole says he’s been talking to operators recently which have been getting 5-7% increases from wells that are years and even months from their cessation of production date.

Previous work the firm has done has shown that well intervention can give higher – and faster – rates of return on investment. “We found, as a portfolio activity, intervention stacked up very well against drilling on payback time and also on over all returns, at about 1.5 X better then drilling,” Cole says.

McKinsey has also looked at the difference between companies with successful intervention programs and those that are less successful. “Typically, the difference between the good and the not so good are; differences in technical system, i.e. the process side; the organisation and how it is organised; and the philosophy or attitudes towards the activity,” Cole says. “Making sure there is a process in place, identifying the opportunities and getting them through the operation, performance tracking and a good way to transfer knowledge between jobs that go well and those that fail,” all help to put the process in place, he says. “It also matters, having an organisation lined up around this and you need clear responsibilities, key performance indicators and targets as resources – cash and capability. It is also important that they [decision makers] understand this is a core part of the business and considered at the top level. We know some interventions fail and some are extremely successful. The success rate overall is more than 50%, but people remember the ones that fail. That needs to be challenged.” Poor plant reliability and poor execution of interventions also results in poor performance in this area he says. “To get this activity humming, you need all of the cogs to work,” he says. The North Sea industry could also learn from outside Europe, including the way onshore North America operators “ruthlessly” approach their wells.

Offshore Network’s event, being held in Aberdeen, continues today and tomorrow.

*Based on data from across 50 assets in the Norwegian, UK and Danish sectors of the North Sea.