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Today's oil companies around the world produce reconciliations on various disclosures such as proved reserves, probable reserves, future net reserves, standardized measure of discounted future net reserves, and many kinds of sensitivities as a means to measuring a company's performance over time. The reconciliation process consists of attributing the relative importance of change that has impacted reserves or value to different categories like technical revisions, improved recovery, purchase and sales, economic parameters, and many others. Reconciliations provide very useful benchmark information on a company's performance, as well as the required disclosures to various regulatory agencies. However, are the results good enough to rely on for important decision making? Are the results repeatable? Are they worth the effort?

Currently, reconciliations are a very time consuming and a predominantly manual process that lacks consistent standardization. For the most part, oil companies construct in-house methodology for producing reconciliation analysis that is the most expedient for the data and the tools they have on hand. There is no global consensus on how to perform reconciliation calculations nor is there a clear definition of what the terms (such as "Technical Revisions") really mean. Various software solutions have taken different approaches to solving this problem, but they can yield dramatically different results. A standardized approach would lead to consistency in the values reported, thus providing a more useful measure of performance. A standardized approach to reconciliations further opens the door for automation, which greatly reduces the time and manpower needed for this task.

Two Predominant Methods of Calculating Reconciliation Results
The goal of a reconciliation analysis is to quantify those factors that have impacted company reserves or value over a given time period and determine the relative importance of those factors. For example: Over the last year, was it changes in price, operating costs, or reservoir performance that most impacted the company's present worth? To what degree were these factors important and were there any other factors that had significant impact?

There are two widely used methods for determining the impact of these change factors. For discussion purposes, I call them Incremental Logging and Isolation Sensitivities.

Incremental Logging has most likely been around the longest and has lended itself to the highest degree of automation. It is very simple and consists of tracking the change to the bottom line, also known as the Reconciliation Basis, every time any kind of change is performed on a company evaluation. An example of this would be tracking the resulting positive or negative change in present worth when the oil price in a given field was changed. Subsequent to that, a change in reservoir performance prediction yields a further positive or negative change to company present worth at the end of the year.

Similarly, the resulting change to Net BOE from recalculated economic limits could be tracked with each change to price or reservoir performance. The main problem with Incremental Logging is that the results are order-biased. This method does a poor job of separating the components of price and reservoir. When the initial change to price is tracked, the result is a change due only to Price. But when the second (or third, or any other factor is tracked), the result is due to the sum of all changes made to that point, not just the individual factor. Thus, the relative impact of a change is biased according to the order it was tracked. Using this method yields consistent results only if the types of changes (price, opcosts, projections) are made in the exact same order each time.

The second method of determining the impact of change factors is called Isolation Sensitivities. This method employs pulling a variable out of one revision and substituting it into the other. Then, the economic and reservoir forecasts are recalculated and compared against the original.

Isolation Sensitivities do not rely on tracking the changes as they are made in real time like the Incremental Logging method does. They only rely on the state of the reserves or cash flow evaluation at the beginning of the reconciliation period and at the end of the reconciliation period. Because of this, there is no bias associated with the order in which the calculations are run and consistent results can be expected.

Interrelated Change
The inherent problem with both of these methods is that they cannot deal adequately with the change in value or reserves that is associated with multiple interrelated change factors. When a reservoir forecast is increased to yield a higher volume, and then the prices are also changed, the sum of the impact of both changes is less than what the total change ends up being. There is an amount of change due to the increased price that acts not only on the original volume, but on the changed volume as well. Incremental Logging lumps all the interrelated change to that point into whatever change is being tracked at the time. Isolation Sensitivities do a good job of separating each individual change and its associated impact, but, when you sum all the individual changes they do not equal the total amount of net change.

Isolation Sensitivities and a Standard Method for Distributing Interrelated Change
A method that would yield consistent and reproducible results would most likely be one utilizing Isolation Sensitivities and a defined procedure for distributing the interrelated change to its components. Such a method would eliminate any order based bias, and it could be defined to the degree that different companies would be able to reproduce consistent results even if those results were generated by different software applications or in-house procedures.

In this manner, the value of change associated with each factor is inflated or deflated in a proportionate amount so that the sum of all individual changes equals the total net change.

Conclusion
One of the realities in performing Reconciliation analysis for Oil and Gas companies today is that various methods are very often used within the same company just to get the job done. If the results are intuitively adverse to what the engineers or scientists know to be true, reconciliation calculations can be run in a different order or method until arriving at a solution that "feels" right with regard to what factors have the greatest impact on the changing status of the corporate reserves. This is neither an efficient nor unbiased way to measure a company's performance over time. It also can be unavoidably misleading to disclose reconciliation information when the method for arriving at those reports is undefined. Standardization of reconciliation methods can help the industry provide corporate benchmarks in a much more efficient manner and better communicate those findings.

Note: This summary was taken from a 40 page document called Standardized Order and Calculation Method to Reconcile Reserves, which was the basis of a short presentation at the SPEE 2008 Annual Meeting. It represents the opinions of the author on the subject.

Labels: methods of calculation, oil gas, Russia, standards for reconciliation

posted by The Rogtec Team @ 11:43  0 Comments

ROGTEC talks to the market leaders.

Contributors:

Konstantin Timoshechkin, Head of SGS Systems & Services Certification in Eastern Europe

Chris Renwick, International Development Manager and General Director of Lloyd’s Register Kazakhstan LLP

1) Quality management, assessment and certification programs are vitally important to be championed and driven by top management down through the organizations. What are the general levels of acceptance and adoption by senior management in Russia and the Caspian? How are any problems to this overcome by your organization? How can they provide real benefits to the organisation?

Konstantin: Implementation of a quality management system and its further certification cannot be initiated without top management endorsement. However, once launched, in many cases the quality management and certification program tend, in fact, to be fully the responsibility of a Quality Manager without much support from CEO.

But the good thing is that, as a rule, after a while we acknowledge a transformation in mentality of both line personnel and managers. Normally, within 1 year after the program was launched people are getting used to the new system and realize the advantages it has given to each staff member, e.g. clear distribution of tasks and responsibilities in the organization. Facing the real effect of a QMS on business performance, its impact on daily work of personnel and its contribution to decision making process top management starts paying more attention to the subject in question. And this attention is crucial for the success of the program's implementation and its further maintenance, since resistance to change is a natural response to changes that confront our usual way of doing things. The speed of adoption of the changes by an organization directly depends on the leadership. It is top management's responsibility to indicate the right direction, to motivate and also to neutralize the inevitable opposition.

Within the regional oil & gas sector, we face quite a high level of understanding of the significance of system certification compared with other industries, which is due to a large extent to their high risk exposure and export orientation, and many players within oil & gas are certified according to ISO 14001 and OHSAS 18000. Nevertheless, overall situation with top management attitude towards quality management programs fits into the general market trends as described above. This attitude is gradually changing. Partly, this is due to the public training activities that SGS in particular has been performing regularly for the last few years in Moscow and other locations all over the region. Moreover, while conducting certification and surveillance audits we put maximum efforts in involving top management deeply into the process. Even if sometimes initially the company's primary objective consists in just obtaining a certificate for PR purposes, we consider as one of our key tasks to help regional leaders realizing true benefits of a quality management system implementation, and it does result in mentality change.

Chris: Nowadays senior management increasingly realise that development and implementation of management systems will bring benefits to their business if they do it correctly. That is why many companies strive to receive not just a certificate on the wall but to establish a strong system with defined processes and responsibilities for their organisation.

Top management of companies which operated in the Soviet Union era can face some difficulties in adoption and adaptation related to effectively delivering the management system’s idea to their employees. Not only middle management but all employees can have important input to delivering value from the management system, but they may see it as an additional burden. Senior management then face the challenge of looking for ways that they can demonstrate how it will benefit the workforce to help gain their support and creative input. We do not see this as a major issue and we find that this can be resolved by actively involving staff at all levels from senior management down in appropriate management systems’ training and practical tasks to encourage ownership at all levels,

Most of the senior managers we speak to are interested in management systems as they understand the benefits such as: Defined and established processes, roles & responsibilities; Clear picture for all of the company strategy, mission, policy and objectives; Best practices to satisfy customers and improve the quality of services/production cycle through analysis and preventive/corrective actions; decreasing the number of rejections and deficiencies

2) Recently a major international operator was found to have cut back on their inspection practices with tragic consequences within several sections of their operations. What is the attitude to inspection and assessments in the FSU? How could these be improved further?

Konstantin: Reactive inspection practice still prevails over pro-active behaviour. However, there are more and more cases when we get the order to perform a preventive inspection for certain reasons. Firstly, there is a new generation of managers that graduated from European or American Business School and have a Western experience of using inspection services regularly and not ad hoc. Secondly, once the operator confronted the problem related to lack of preventive inspection, he would most probably tend to avoid such problem in the future by allocating costs on inspection activities in his budget. To cite an example, after one of our clients found himself with equipment purchased from China that didn’t comply he has not placed any order without involving SGS as a third party inspector ever since. Thirdly, obviously our sales process contains an educational element. We teach clients on what are the risk management tools, on what could be outsourced, on the economic benefits of inspection services, on what can be assessed and which parameters to control.

Chris: Inspection and assessment is often closely monitored and many certificates can be requried to get and maintain a permit to operate. The issue is not the willingness or the quality of the inspections it is the appropriateness of them. For the oil industry the Piper Alpha disaster was a wake up call. The process and practices were examined in detail and found wanting in a number of key areas. One of the biggest issues was the fact that the prescriptive approach failed to properly address the risks involved. The result was a move to a risk-based approach where the operator had to provide evidence that the inspections and assessments and other risk control mechanisms were appropriate for the hazards concerned. Increasing the adoption of such hard learned lessons will help to improve the value of inspection and assessments in the FSU.

3) The FSU, traditionally, had the attitude of if it is not broken don't touch it, towards quality and assessment, how is this changing?

Konstantin: Such attitude has been gradually changing - see answers to Q. 2

Chris: With the increasing adoption of international business practices and the easing of trade barriers there is a growing appreciation that process improvement can provide significant benefit to the organisation, its clients and the community, from improved revenues for the company and improved products for the clients to better operational safety and environmental compliance that will benefit the wider community. The situation will not change overnight but with improved access to investment many industries in the FSU are now more able to make such changes which can only be good news for all concerned.

4) Russia often employs its own certification standards, a) how to these differ to EU standards b) What effect do they have on companies entering the market? c) or Russian companies exporting?

Konstantin: When we talk about product certification in oil & gas, we do face various discrepancies between standards employed in Russia and in the EU. For example, Russian steel classification principles do not match the European ones. In Russia, so far standards to be used for Q&Q assessment in LNG sector simply do not exist, which causes serious problems for the market players. Testing methods for oil products in Russian and the EU differ. And the list of examples could be prolonged. The fact that Russia has not signed Mutual Recognition Agreement with any of the recognised European accreditation bodies is the reason why producers have to test their products more than once and cannot use one single test report for certification in an export market. The other consequence of the discrepancies in standardization for both exporters and importers can be that in some cases design of certain equipment has to be altered to comply with foreign standards or safety rules.

Chris: In considering how they differ we should consider not just if they are different but we must also ask ourselves if the differences really matter. The fundamental issue is does an FSU standard and an equivalent EU standard both provide an acceptable level of safety? If the answer is yes then is it a real issue?.

In reality the issue may be more one of needing a certificate of compliance with the standard rather than any consideration of equivalent safety etc. It is this that can have the biggest effect on companies entering the market where they are asked to provide for additional testing and approval prior to importing the equipment. The result can be increased costs and difficulty in competing in the local market. The good news is that there are a steadily increasing number of international standards that are recognised, adopted or harmonised in the FSU states so barriers are coming down, albeit not as fast as some may want. For FSU companies exporting they are normally free to adopt whatever standards they like for export production so provided they can manufacture and obtain certification to the required EU standards then the export market is open to them.

5) How can assessment and conformity programs aid an organisations performance?
One of the good examples is the help that such programs provide in terms of supplier management. Procedures established as a result of a QMS implementation and auditing programs (either outsorced or conducted by own staff) are the effective tools to select an organisation’s suppliers and to further monitor their performance. Taking in mind that mutually beneficial supplier relationships is one of the eight key quality management principles, these programs directly boost the organisation’s performance.

Konstantin: One of the good examples is the help that such programs provide in terms of supplier management. Procedures established as a result of a QMS implementation and auditing programs (either outsourced or conducted by internal staff) are the effective tools to select an organisation’s suppliers and to further monitor their performance. Taking in mind that mutually beneficial supplier relationships is one of the eight key quality management principles, these programs directly boost the organisation’s performance.

Chris: The evolution of the global marketplace has made customers and regulators increasingly dependent not only on standards but also on the methods used to ensure that products comply with the requirements of those standards such as conformity assessment. Therefore conformity assessment programs form a vital link between standards (which define the necessary characteristics or requirements) and the products themselves. The choice of the most appropriate assessment processes can have a significant effect on the confidence and reliance of the organisations’ operations activities.

Conformity assessment can verify that a particular product meets a given level of quality or safety. The organisation will receive explicit (and implicit) information about the product’s characteristics, the consistency of those characteristics or the performance of the product. Assessment can also increase a customer’s confidence in a product, providing the information about product’s safety and suitability.

Using the results from the assessment the organization can develop and implement strategies which can improve its operations and will help develop closer cooperation with partners and customers

6) Are the regional companies looking at the ISO 9000 and 14000 series as practical solutions to improving their quality and environmental practices?

Konstantin: The answer is yes for both but not equal yes. With ISO 9001, Russian companies do not realize the standard’s benefits immediately, whereas the ISO 14001 is much clearer since it gives direct economic effect one can feel straight away as a result of the implementation: reduction in energy consumption, cost-saving thanks to waste management, decrease of penalties for non-compliance with environmental legal requirements etc.

Chris: From what we can see our local regional companies intend to develop and implement management systems based on ISO9001 and 14001 elements to improve their processes, improve quality to satisfy customers and meet social expectations of good environmental practices. They understand that implementation is beneficial as it will help them understand the strengths and weaknesses of current practices. We see companies are moving easily into ISO 9001 & 14001 because they were already doing many of the things it requires There is often a keen interest to look first at the existing approach, the business and financial implications of any weaknesses and how a management system according to ISO 9001 & 14000 could add value though improving what they are currently doing.

Dependant on the region there may be government programs which support companies interested in ISO 9001 & 14000. This sort of positive support is helping drive the success of ISO 9001 & 14000 adoption

7) How effective are environmental standards at improving the situation in the region? How closely are they adhered to?

Konstantin: Environmental risks are evidently high in upstream since equipment is getting worn out and the area that should be monitored with regard to leakage and contamination is vast. Implementation of the ISO 14001 helps indeed to improve the situation by raising environmental awareness and social responsibility of O&G operators.

Chris: Governments are improving the legislation and publishing new regulations for the protection of the environment. The issue then becomes one of understanding and effective implementation. The challenge for the regulators is to provide a consistent and workable implementation so that the business community can put in place the requried plans and processes to achieve compliance. The more practical the implementation the better the compliance will be. There appears to be general willingness to adopt the standards but clearly the industries want to see the implementation done in a way that supports environmental improvement and not used simply for punitive measures.

8) Within risk assessment, what are the key risks and operations for operators to study? How do they impact on performance?

Chris: The source of risk is 50% asset integrity and 50% organizational integrity. The following two example support this:

DuPont’s – May 2007 NPRA Paper –says "85% of availability losses over previous 5 years were associated with Mechanical Integrity related failures."

British Petroleum’s Website - I “Approximately one third of all the major and high potential incidents reported in the group are related to integrity management – in other words, incidents where there has been loss of containment or failure of an engineering system.”

Risk technology can determine the highest-risk pieces of equipment the process-variable limits within which a customer can operate and not degrade the pressure boundary faster than expected/predicted. The variables need to be tied to monitored process variables, alarmed, and communicated to operations with instructions as to what operations need to be performed in the event of a deviation. Risk brings visibility and accountability to the organization and measures the ongoing success or lack of success in terms of reduced high potential incidents.

How do they impact on performance?
Well a few statistics provide a good illustration. Equipment failures cost the US refining industry over $2 billion per year and 2/3 of those costs are associated with failures of static equipment The average refinery has a risk between $10 million and $70 million per year due to failures of static equipment and 2/3 of those costs are associated with piping failures

A reliability based mechanical integrity program for all asset families including fixed equipment, pipelines, piping, relief devices, rotating equipment, electrical systems and instrumentation and control systems will greatly contribute to productivity and safety through asset integrity. A good reliability mechanical program will reduce 75% of a plants total risk and dramatically decrease equipment failures.

So actively managing these risks is good for your business – no matter where you are operating

9) How comfortable are you that the risks associated with operations have been clearly identified and that your inspection and certification programs are aligned with those risks?

Chris: With many types of operations the generic risks are well known. The challenge often comes when moving established practice, from for example USA or Europe, to new locations, such as the Caspian and Russia, where the physical environment or legislative requirements may impose conditions that create risks not seen as significant before. So the first thing is to accept that industry best practice is a very good guide but we cannot afford to be complacent and adopt a one size fits all approach. Local awareness of conditions is critical if the risks are to be understood and managed and supported with inspection and certification programs that are appropriate. So are we comfortable that we have everything identified? No, because we need to remain alert. Comfort can lead to complacency and from that to disaster something none of us want

10) Is there a place for Risk Based Inspection in the Caspian and Russian markets?

Konstantin: In fact, Risk Based Inspection is in demand in Russia. However, the Russian companies are not yet ready to outsource this function to a specialized organisation and so far use own staff and own equipment to implement the work.

Chris: Yes, one of the chief advantages of risk reduction technologies is the ability to measure and manage the risk to the assets due to equipment failures. Implementation of this technology permits the higher risk items to be appropriately managed to a lower risk, while diverting inspection resources from low risk items. The overall risk can be decreased dramatically by focusing inspection efforts on the high risks. The goal will be to not only estimate but measure the overall reduction in the risk of failure. Risk reductions are real and mature tools are on the market to clearly understand the savings. Risk technologies enable a sustainable and continuously improving business process best practice for asset integrity management. Additionally, the risk capabilities can help promote environmental protection, personnel safety, community responsibility and safety while improving equipment integrity and reliability.

11) What tools can you supply to help organizations manage risk?

Konstantin: SGS offers a number of risk management solutions to O&G upstream sector. Firstly, these are testing and inspection services: integrity management and risk-based inspection, project monitoring, supply chain services, non-destructive testing, inspections of tanks, pumps and valves, pipes, welding and coating inspection. Secondly, these are certification services of an organization's management systems according to international standards such as ISO 9001, ISO 14001 and OHSAS 18000.

Among the many SGS services to upstream customers, there is one in particular that stands out in its potential to add value and reduce risk. SGS uses leading-edge technology to help clients detect the presence of mercury in oil and gas production. Mercury, a naturally existing element, is inherent in oil and gas. However its presence can cause catastrophic consequences. Mercury is highly corrosive and has-been proven to be the cause of many major plant failures, resulting not only in the loss of property and production but also loss of life. SGS provides its customers with crucial detection capabilities and helps them find solutions to remediate the problem thereby maintaining plant security and integrity – thus preventing costly shutdowns.

Chris: We are able to provide tools and techniques to our clients to help them manage their risks. It is all about being selective and pragmatic in the choice. The tools vary widely and may be asset based, operational process or activity based. For assets there are well established methods such as classification and verification to more specific tools such as risk based mechanical integrity (RBMI). While for the operational activity our management systems business assurance approach helps clients focus on the areas of business where they may have the greatest risk.

12) How do you see risk management, as a business tool, developing in Russia over the next 5 years?

Konstantin: I am confident that within the next 5 years regional O&G operators will have made an enormous step forward towards a more systematic risk management approach adopted by the leadership. The latter would be well acquainted with fundamentals of risk management and aware of what are the various tools and how to use them to an organization's benefit.

Chris: As I said before risk reductions are real and mature tools are on the market to clearly understand the savings. The application of appropriate processes and technologies enable a sustainable and continuously improving business environment that looks to create and adopt process best practice. It is hard to imagine that there will not be a strong take up of this approach in the next five or so years. For business in general the door is clearly open. For asset risk the rate of development will be influenced to some extent by the rate of change of legislation to allow adoption of more risk based practices as a viable alternative to prescriptive practices.

Labels: certification, Lloyd´s Register, oil gas, quality assurance, risk based inspection, Russia, SGS

posted by The Rogtec Team @ 11:40  0 Comments

David Bamford bamford_neweyes@hotmail.co.uk

Many years ago, my first boss at BP said something along the lines of "If you have $100 to spend on geophysics, spend $99 on seismic and the $1 on a good cup of coffee!"

However, as we moved into the 21st Century, I began to wonder if he was no longer right - there seemed to be enough 'fuss' around the non-seismic methods, namely gravity, magnetics and especially electro-magnetics, that I wondered out loud - and wrote about - whether as acquisition and processing techniques improved these neglected technologies of the geophysical world would finally take their place alongside seismic as powerful contributors, especially to exploration. About two and a half years ago, I wrote in the on-line magazine OilBarrel about four companies offering such technologies along these lines:

GETECH is an enterprise of relatively long standing that was founded in the University of Leeds in the UK almost 20 years ago, floating on the London AIM market in September 2006. Their speciality is potential field data; although they offer consultancy in gravity and magnetic interpretation, their forte is compiling large, homogeneous, quality-assured data bases from a myriad of historic, heterogeneous surveys. For example, a current major offering is of Siberian gravity and magnetic data bases compiled from the many years of Soviet surveying, and an earlier offering was a similar compilation of data over Iraq. This type of data lacks resolution but is important when an explorer is faced with a huge onshore area and has to decide where to focus - potential field data can show the shape and depth of sedimentary basins, imply where source rock might be deeply buried enough to be mature and so on; these insights can focus the next stage - the shooting of expensive seismic data.

OHM of the UK, and EMGS of Norway are both players in the electro-magnetic (EM) arena; this type of data has received quite a lot of publicity recently to the effect that it can significantly improve exploration success rates. This assertion is based on the fact that normal oils and formation waters have completely different electrical conductivities, and that therefore the presence of an oil-charged reservoir at depth should lead to an 'anomalous' EM signal being recorded as compared to the water-filled case. Applied technology may be winning through, and with the addition of higher frequency sources and a change in the basic geophysical technique, EM methods have recently undergone a metamorphosis and the new Controlled Source Electro-Magnetics (CSEM) techniques are now showing that modern EM techniques can and are being used to help evaluate the fluid content of reservoirs and define reservoir extent. MTEM is another UK company that works in the EM arena, using a different approach that may offer a more 'seismic-like' method. Like other geophysical tools EM results are proving of value when integrated with other geoscience data and understanding.

Unfortunately, I seem to have been wrong about all of what I said above - I have to confess that over the last couple of years I have seen and heard no evidence that experienced explorers - as opposed to the marketing departments of the 'niche' service providers - are willing to stand up and be counted by pointing to transformed exploration success rates as a result of using these non-seismic techniques.

In fact, you can see that two markets are providing their own judgement. In the oil field services market, two of the leading electro-magnetics acquisition companies, EMGS and OHM, have in their latest Trading Updates reported weak revenues and order books, on 12th August and 2nd September 2008 respectively, at a time when seismic companies report unprecedented revenues, full order books and 3D vessel day rates driven sky-high by a skewed demand/supply imbalance. This has not passed unnoticed by the investment community with the shares of some 'niche' non-seismic companies trading in the market at 20% - or less - of the price seen two years ago.

It seems like these non-seismic technologies are hovering over what some technologists would term the Valley of Death! To explain briefly, if you think of the proof-of-principle of a new technology as one mountain peak and the successful commercialization of that technology as another peak, then the space representing the period of time between those two peaks can be seen as a valley. This period in the transition from discovery to market is littered with the good ideas that never completed the flight across the valley. In technology commercialization parlance, this graveyard of inventions and intentions is known as the Valley of Death!

As when any new technology sees zero or low take-up, it is easy to blame the customer - perhaps they are too lazy, conservative, untrained or disinterested to bother with the new ideas? However, my observation of explorers is that exploration is so difficult - and nowadays ever more so - that they will leap on and devour any new idea that will help them succeed more often, drill less dry holes.

However, when my first BP boss said what he did, he was relying on an understanding of classical physics that was written down in the 19th Century - a hundred years before either of us joined BP, by gentlemen such as Laplace, Poisson, Maxwell and Zoeppritz. For reasons buried in the subtleties of their equations governing potential fields, electro-magnetic radiation and seismic wave propagation, if they had thought about it these gentlemen would have recognized and declared that "Seismic is King!"...and so it seems to remain.

I pin my final hope for the fortunes of non-seismic techniques on integration - perhaps working inside the frame work provided by the fantastic seismic data we have nowadays, there is still a chance for a premium contribution to exploration success?

Or perhaps I should just lean back and smell the coffee!

Labels: Non seismic exploration, oil gas, Russia

posted by The Rogtec Team @ 11:34  1 Comments

Mixing and pumping barite slugs to dry the drill pipe before tripping out of a well is one of the most common of all rig operations, yet when the pipe fails to pull dry, it can be frustrating for the crew and expensive for the operator. Slugging procedures on many rigs are a haphazard affair and often, if the slug attempt fails, the crew is not really sure what went wrong.

Slugging is often ignored in well planning because in comparison to other operations, it is a rather small detail. Some operators that are aware of potential waist, do have slugging policies. Some only allow the use of sack barite for slugs: others set limits for slug densities. Such policies can be difficult to enforce and sometimes result in false information appearing on reports.

Pulling the pipe dry is important for several reasons. More well control incidents, leading to blowouts, have occurred on trips than during any other routine rig operation. When tripping out of a well, it is essential that the volume of steel removed from the well be replaced with an equal volume of the working liquid (mud) in order to maintain bottom hole pressure. It is difficult to measure hole fill-up accurately when pulling a wet string.

Personnel safety is also a primary concern. When mud is spraying around at every broken connection the floor and tools are quickly covered. It is difficult for the crew to work safely while trying to maintain their balance on the slippery floor. Mud lost on wet trips also represents money spent unnecessarily. Not only is whole mud lost during the trip, but there is also the cost of time and material required to re-build volume. Finally, drillfloor morale is an important consideration. No crew enjoys working in a constant shower of drilling mud. Spirits sag, and so does efficiency. The fluid technician (mud engineer) who tries to keep accurate records of the barite used for slugs may be shocked at the cost over a 30-day period, especially if bulk material is used.

The discussion below takes a look at the slugging process in order to develop some procedures that, when applied to most rigs, should enable the drill crew to pull dry pipe consistently.

If the drilled borehole with the drillstem inside is thought of as a U-tube, and both sides of the tube are filled with the same density fluid, the hydrostatic pressure exerted by the fluid is equal on both sides of the tube. When a fluid of different density is added to one side of the tube, the side with the denser, (heavier) fluid will displace the lighter side until the tube returns to a balanced condition. This phenomenon can be seen on the rig when drilling fast, in tophole formations. The annulus becomes charged with cuttings if the drilling rate exceeds the circulating rate. The cuttings increase the effective density of the fluid in the annulus, and when the kelly or topdrive is broken off to make a connection, mud flies in all directions. The mud on the annulus side of the U-tube is displacing the cleaner, lighter mud on the dillpipe side.

When slugging the pipe, the goal is to deliberately unbalance the system so that the drillpipe side of the U-tube will slightly displace the annulus side. In other words, the hydrostatic pressure in the drilpipe must be greater than that in the annulus for the slug to be effective.

Since hydrostatic pressure depends upon the height and the density of a column of fluid, the pipe can be slugged with a small (short) heavy slug, or a large (long) lighter slug, provided that the mud system was balanced before the slug was pumped. So long as the hydrostatic pressure is greater in the drillpipe, the system will become unbalanced and the fluid level inside the drillpipe will fall to the point of balance.

There are no established standards for slug fall. Rig equipment, experience, present operations, and company preferences are all variables that must be considered. However, given certain conditions, it is possible to make some estimates in order to determine the density and length required for a good slug. In other words, what slug density and volume would create enough imbalance to ensure that the drillpipe would pull dry throughout the trip?

The first step in calculating slug densities is to decide what length of empty drillpipe would the slug create, or how far should the slug drop? The slug density required to achieve the drop in a balanced system can be estimated once the desired slug drop is determined.

Assume the following:

5 inch, 19.5 lbs/ft drillpipe. Capacity 0.01776 bbls/ft (0.0093 m3/m)
Slugging pit with 25 barrels (4 m3) available to the pump
Mud weight of 12.0 ppg (1.4 sg)

1. Solve for the approximate length of a 25 bbl slug in the 5-inch drillpipe.

Bbls / bbls/ft = ft
25 / 0.01776 = 1408 ft. (429 m)

One joint of Range II drillpipe is about 31 ft (9.43 m) therefore, if the rig pulls triples, that is, three joints to a stand, one stand will be about 93 ft (28.3 m) long. Assume that a slug drop of about a stand and a half, that is, 150 ft. (45.7 m), is desired.

Solve for the slug density required to cause a drop of 150 ft (45.7 m).
Fluid density x [(slug drop / slug length)] + 1 = slug density
12 x [(150 / 1408) + 1)] = 13.27 or 13.3 ppg (1.6 sg)

As long as the desired slug drop and the pipe diameter remain constant, the ratio of the slug drop to its length can be treated as a constant value and used for various system densities as shown in the examples below.

The constant for the example well is:

(150 / 1408) + 1 = 1.106534

Assuming 150 feet of drop, determine the slug densities required in 9.0 ppg, 14.0 ppg, and 16.0 ppg systems respectively.

9.0 ppg system x 1.106534 = 9.95 or 10.0 ppg (1.2 sg) slug
14.0 ppg system x 1.106534 = 15.5 ppg (1.9 sg) slug
16.0 ppg system x 1.106534 = 17.7 ppg (2.1 sg) slug

Notice that as the system density increases, a heavier slug is required to realize the same 150 ft slug drop. In order to maintain the same slug drop in systems with higher mud weights, either a greater slug volume, or a higher slug density is required. Suppose the slug volume is increased from 25 to 30 barrels (4.7 m3).

Length of slug in drillpipe is 30 / 0.01776 = 1689 ft (515 m)

Ratio from the formula with the longer slug is (150/1689) + 1 = 1.108881

9.0 ppg system x 1.108881 = 9.8 ppg (1.2 sg) slug

14.0 ppg system x 1.108881 = 15.2 ppg (1.8 sg) slug

16 ppg system x 1.108881 = 17.7 ppg (2.1 sg) slug

It can be seen that the additional 5 barrels (0.79 m3) makes little difference in density requirements, even though the slug occupies an additional 281 ft (85.6 m) of drillpipe (1689 - 1408 = 281).

It is not necessary to work the calculations often. The drillpipe size does not change frequently, and the slugging pit has a limited capacity. The decision between pumping a long, lighter slug or a short, heavier slug is a matter of operational preference. If the U-tube is unbalanced, the slug should fall. If the slugs are mixed according to these guidelines, then there is little else that the worker who mixes the slug can do. There are, however, some other factors that will influence the effectiveness of slugs.

The U-tube should be balanced before the pipe is slugged. A difference of 0.2 or 0.3 ppg between the mud weight at the flowline and the mud weight going down the hole may make a considerable difference in slug fall. If the system is known to be out off balance and cannot be circulated, then a longer or heavier slug than normal will be required. The best solution is to circulate the annulus clean before slugging the pipe.

The slug must be displaced properly. If the driller leaves the slug above the rotary table, the fluid will not fall and the connection will be wet. Likewise, if the slug is greatly over-displaced, it will be ineffective. Slug displacement errors are fairly common. That is why some crews seem to have more trouble slugging the pipe than others. The blame, if there is any, should not always be borne by the mud hand. He is not responsible for circulating the annulus clean, or displacing the slug. Below are some suggestions for getting a good slug.

Learn, or calculate the volume in the lines from the slugging pit to the rotary table. Do not accept some number that has been passed on for years. Either look at the rig plans, or trace and measure the lines. This may be time consuming, but it only has to be done once. When an accurate volume has been determined, post it in barrels (m3) and pump strokes so all drillers will chase their slugs in the same manner. Using time rather than strokes for guide is not accurate.

When the pump efficiency is checked (as when bumping a cementing plug), apply the revised pump efficiency to the slugging process.

Calculate and post the information needed to build a good slug under several different conditions. For example, slug densities and volumes for various mud system densities, various drillstring diameters, volume per inch (cm) of the slugging pit, and the height of the suction off the bottom of the slugging pit. This should encourage all rig personnel to follow the same procedures.

In most cases it is not a good practice to mix a slug far in advance of its use. If it must be mixed in advance, good agitation is a must.

Be certain that the mud weight returning from the annulus is as accurate as possible before building the slug and make certain that the slug is weighed carefully a few minutes after the barite is mixed.

Agitate or stir the slug constantly.

Mix, rather than dump the barite into the hopper. Dumping causes settling and inaccurate weights. It may also plug the bit nozzles.

If the hopper discharge into the slugging pit is directly above the suction, rig up some sort of splash shield. Discharging on top of the suction will cause aeration, resulting the inaccurate weights and inefficient pumping.

If the slug is very thick, pump efficiency and slug fall will be affected. The best viscosity for a slug is about the same as that of the mud system. If slug viscosity is a problem, have the fluid technician (mud engineer) recommend the best type and amount of thinner required to adjust the viscosity of the slug.

In order to reduce waste; it is a good idea to estimate the amount of barite that will be required for the slug. Mix the estimated amount, or a little less; let it mix well, then weigh the slug.

If barite is packaged in 100 lbs sacks, then about 60 sacks (6000 lbs) will increase the density of 100 bbls 1.0 ppg. A 25 barrel slug should require about ¼ that much, or about 15 sacks (1500 pounds). Estimate the surge tank, mix about 15 sacks and weigh the slug. If barite is packaged in 50 kg sacks, mix about 12 sacks to 4 m3. Mixing in this way is faster, less work, and more economical.

There are several operations and conditions that can make slugging the pipe difficult or impractical, no matter how careful and conscientious the crew. Fishing jobs, long tapered strings, very small or partially plugged nozzles and extremely viscous mud fall into this category. In these cases, the driller must be patient and try to vary his techniques, seeking the right combination. Most of the time, with a little planning and good communication between crews, slugging problems can be all but eliminated. One thing is certain, good slugs save time, money and hard work.

To request the full 40 page document from PHD Precise in Russian or English, please email: support-ru@phdprecise.com

Labels: Drill pipe, dry pipe slugs, oil gas, slugging

posted by The Rogtec Team @ 11:33  1 Comments

David Nims (David.Nims@bp.com) Mikhail Kholodov (MVKholodov@tnk-bp.com),

Upstream Technology
It is commonly acknowledged throughout the TNK-BP drilling community that the last five years were about building the capability, embedding some basic technology in the Company, increasing the volume of work - from 250 wells in 2004 to 850 wells this year. As Darryl Willis, Vice President Upstream Technology, puts it, the past has been about the growth.

The future is about not drilling more, but drilling smarter – drilling right wells in the right places, shifting from single-well bores to multilateral-well bores, etc. To drill smarter, numerous changes are currently underway in TNK-BP use of drilling technology, most of which are part of two major trends:

- Enhanced rig capability

- Cutting-edge drilling technology

Enhanced Rig Capability
Three years ago the Uvat project developed a hybrid Russian / international design that encompassed the best of both worlds. It combined a proven Russian BU-3000 rig structure that facilitates easier inspection, certification and familiarization with state of the art international internal components. These internal components had best in class electronics, bearings, modularization and reliability. The hybrid design increased the drilling distance of the rig from 1.5 km to almost 5 km.

This capability in conjunction with high angle Frac capability "J type wells" helped save $480 mln NPV by cutting the pads / wells ratio per field from 24 / 175 to 6 / 130. Most of this saving was the reduced infrastructure costs resulting from the ability to drill all the wells from six pads versus the original 24 pad design. Building on this learning, our OFS internal drilling contractor, NvBN, developed a rig enhancement design for 22 rigs in our internal fleet. This $280 mln investment was one of the key levers in improving our drilling capability to drill the much more complex wells. These well designs have evolved from simple S-Shape wells to high angle 850m horizontal wells with step-outs in excess of 3,500 m. This has kept TNK-BP's drilling investment ratios at circa $35 per ton for the last three years despite double digit inflation.

Again, building upon this learning the VCNG project has introduced three new high technology rigs into the VCNG program and consequently the well construction cycle have fallen from an average of 125 days per well pre-project (2006) to an average of 35 days with one well with a best in class delivery of 26 days. These new rig designs are safer and capable of drilling much faster and further than conventional rig designs. This knowledge and the new hybrid coiled tubing drilling (HCTD) learnings will be applied on future Greenfield projects as well as selective applications on our existing fields.

Our exploration program is one of the most successful in Russia with a reserves replacement track record that is the envy of the Western world. This capability and performance will be further enhanced by the development of high technology heli-rig capability. Currently our exploration rigs in the more remote regions manage to drill around two wells per year before the departing winter leaves them isolated from our supply lines. Heli-rigs open up the possibility of pre-supplying up to six wells per rig and flying the rig into location on a year-round basis. This is much more equipment-efficient and is common practice in the more remote parts of North America. Firm proposals are being developed for a pilot application in TNK-BP; again this will be another proven technology 'first' for TNK-BP in the Russian market.

Following the Long Term Tendering exercise Company went through in the second half of 2007, 35 new high technology rigs are due to be operational in the field by January 2009. These rigs vary in size from 125-ton to 325-ton units and represent the state of the art for their respective sizes. Taking this innovative approach will result in TNK-BP having one of most modern rig fleet in Russia

Cutting-Edge Drilling Technology
Samotlor BU has successfully developed extended reach drilling (ERD) capability using rotary-steerable systems that enable the bit to independently track a predetermined optimum path through the production sand. This provides very accurate well placement in the production sweet spot for horizontal lengths in excess of 800 m. Using this technology Samotlor BU has delivered initial production rates four time larger than normal and exceeding 1,000 tpd. Moreover, ERD has allowed us to reduce the number of pads and wells per field.

This ERD technology has now been adopted by Orenburg BU while Samotlor BU is moving the technology even further ahead by developing ERD capability for their future sidetrack program.

Orenburg BU has developed a 15-well pilot program for the introduction of underbalanced coiled tubing drilling (UB CTD) with Schlumberger. This combination of underbalanced and coiled tubing drilling allows reservoir penetration with minimal formation damage and is key to unlocking tight reservoirs - applications in other places in Russia have resulted in a four fold increase in production rates. Successful introduction in Orenburg opens the opportunity for application in more difficult areas such as Talinskoye with its massive reserves potential.

Hybrid Coiled Tubing drilling is a relatively new technique which combines fast moving trailer rigs of up to 200 t capacity with coiled tubing technology. They have been used extensively in Canada with 5,000 wells drilled every year for the last four years. These are fast, highly safe, automated, reliable, environmentally friendly, PLC (Programmable Logic Controller) electronic rigs that permit operations with five-man crews. The 35 km pad to pad move times from tree on to spud of less than eight hours with 1,500 m wells completed in less than a day is transformational.

Samotlor BU is taking the lead in developing the HCTD technology in Russia, the first new rigs are expected in field by the end of this year and by 3Q 2009 we expect to be operating six of these world class units. On the environmental side, in addition to the low footprint of the HCTD rigs we will also be developing a pilot for drill cutting re-injection back into the ground. This will allow us to dispose of our drilling waste in a more environmentally friendly, hygienic manner than the current systems and permit the use of more exotic, higher performing mud systems.

The new and upgraded rigs allow us to develop more productive reservoir access technologies such as multilaterals where up to four or more long reservoir penetrations can be drilled from a single mother bore. This eliminates the access costs of drilling the over burden on three of the four bores and significantly reduces overall drilling costs.

Currently four to six multilateral wells will be drilled by the end of 2008. Less spectacular but equally important developments in bit design, especially PDC bits, have decimated the well times in hard rock areas such as VCNG where average well times of 55 days per well have been cut to a "best in class" well delivery of 26 days. These are early days and there is still much work and delivery to come for applying this technology across the rest of our well portfolio. Other upcoming technologies include the adoption of oil based mud to speed up the rate of drilling, reduce torque, provide better borehole stability and increase our well step-out capability.

Managing the Technologies
These technologies are further complimented by new exciting methods of benchmarking our performance using enhanced performance management systems such as the new STEPS contractor management system which is already yielding and applying significant value in Samotlor BU.

All of this technology should be managed in a measured manner and consequently Tyumen BU will implement a new remote operations performance center (ROPC) in 2009. This center will take real time drilling data from multiple rigs and transfer it to a centrally resourced technical expert center. This center will have directional drilling, geological, mud and other experts monitor, map and benchmark the performance of each well against a predetermined best in class model.

This will help the specialists make real time immediate changes of well trajectories to optimize reservoir sweet spots to enhance production and allow identification of potential performance shortfalls before the failure occurs. All this technology is tried and tested and is essential to unlocking the tighter, more difficult reserves of our upcoming programs.

However, perhaps more importantly, these technologies are the fundamental basis for success in the offshore ventures of the future and commercial performance delivery will grant us the permission to develop and apply even more radical access technologies.

We are breaking the mold and creating new access opportunities to increase our production potential. We are creating world class drilling capability in Russia and accelerating the development of our younger highly capable staff. We will have the best equipment for them to test and develop the new boundaries of the future. The sheer volume of TNK-BP business opens huge opportunities to try new ideas provided we can change the mindset to an acceptable tolerance of failure, "if you never fail, you haven't tested the boundary."

Labels: Darryl Willis, drilling, ERD, Exploration, Extended Reach Drilling, oil gas, Orenburg, Rigs, Russia, TNK BP, Uvat

posted by The Rogtec Team @ 11:32  0 Comments

Paul Jukes PhD CEng FIMarEST Ayman Eltaher PhD PE James Wang MSc Billy Duron BSc J P Kenny, Inc. Houston, TX USA

USE ADVANCED FINITE ELEMENT ANALYSIS?

The world is consuming oil and gas at an ever increasing rate and, as a result, there is demand to exploit new opportunities and make projects that were once not technically or commercially feasible, now viable in a cost-effective manner.

Technical Challenges
Technology gaps exist and the inability to bridge that gap, due to technology either being unavailable or just too expensive to implement, has put some projects 'on-hold' for many years. A number of engineering challenges, or technology gaps, have been identified that has a significant impact on the design of oil and gas pipelines, and subsea equipment [Ref. 1]. The main technical challenges that exist are identified as; deep water, high pressure/high temperature, flow assurance, and thermal buckle management. It is now common place for subsea systems and pipelines to be installed in water depths in excess of 1,000 meters (3,300ft). Flowline designs are presently being considered, for a major operator, in the Gulf of Mexico (GoM) for water depths down to 3,000 meters (10,000ft). High Pressure and High Temperature (HP/HT) with pressures in the order 700bar (10,000PSI) or more, and temperatures being considered up to 160°C (320°F) are not uncommon. For a major operator in the GoM, temperatures up to 177°C (350°F) are presently being considered. This can present real design challenges in the choice of materials and in the design methodology. Stress based design codes are no longer applicable at these high temperatures, and the solution is to design such pipelines using a limit state methodology.

Routing and Survey
The routing of subsea oil and gas pipelines and flowlines pose particular challenges. The importing of 3-D survey data efficiently is a numerical challenge and can be computational expensive to undertake. Routing can have significant financial benefits if the length of the pipeline is reduced, and it can also minimize undue bending and stress on the pipeline if the pipeline is re-routed around onerous undulating seabed, rocks, or imperfections. Importing survey data into a 3-D visualization tool quickly, and efficiently, is key to success. Generally, routing is undertaken by integrating third party software with FE analysis tools, as will be demonstrated within this paper.

Viable Solution
In recent times, there has been a greater requirement for pipeline and subsea design companies to tackle these engineering challenges in a cost-effective manner. One such way is to use more advanced analysis tools, such as finite element analysis to model, simulate, and design both pipelines and subsea components. This will allow designs to be optimized with a greater understanding of the Engineering complexities, without having to undertake expensive large scale tests, and hence a viable, workable, solution can then be obtained.

Cost Savings
An optimized design will provide 'added-value', and ultimately provide capital cost savings to a Project. The detailed factors for a successful project have been identified [Ref. 1] as the following:

• Innovation: Novel ideas, lateral thinking, and original ideas;
• Advanced Numerical Tools: 'Bespoke' software, path dependent, highly non-linear;
• Competency: Range of backgrounds, highly qualified, years of experience.

These factors allow you to drive down to an optimised solution, and experience from a project is then feedback into the next one, and this allows projects to deliver and evolve. By knowing what you are doing, through the use of analysis tools and experience, 'added-value' can then be given to a project. It is the combination of all three elements that allows design solutions to be developed, optimised, and then achieve cost savings.

Advanced Finite Element Analysis can be used to undertake global modeling of pipelines, and this allows the simulation and response to be obtained. This is a highly non-linear process, due to material non-linearity, large displacements, and pipe/soil interaction. This type of analysis can be used to undertake span analysis, lateral buckling and reeling analysis. Examples of these are described within the following sections of this paper. Non-linearities can be a particular issue when designing pipelines at high temperatures, stress based design can no longer be used, and a limit state based design is adopted.

Secondly, Finite Element Analysis can be used to undertake 'local' solid modeling of complex subsea components such as; bulkheads, flanges, field joints and spiral pipe. Constructing FE models efficiently, and quickly, is key and it allows design iterations to be efficiently undertaken to allow an optimized design to be achieved.

Thirdly, an 'integrated' approach to route selection, using 3-D software and stress analysis, to reduce pipeline length and minimise intervention is important. If the survey data, route selection and stress analysis can be undertaken quickly and efficiently, this will allow design iterations to take place in a cost effective manner. Time spent at this iterative design stage, when undertaken efficiently, could then have a significant financial saving in terms of the

Engineering
Through advanced analysis tools, the challenges of deepwater and HP/HT can be addressed by integrating analysis tools with pipeline design methods, such as Limit State Based Design (LSBD). Pipelines are designed using this approach, and optimised wall thicknesses can be obtained, and this then allows significant financial savings, in linepipe costs, if undertaken correctly.

To accurately model and predict the ultimate failure of a pipeline requires looking at the limit states so as to gain an adequate margin of safety between the design loads and ultimate failure. The major target is to investigate the ultimate limit states, and a FE model is used to provide all of the pipeline response data as input for each limit state.

ADVANCED PIPELINE ANALYSIS AND DESIGN TOOLS

The key to undertaking complex designs of pipeline systems is to use advanced analysis tools. These analysis tools can undertake global modeling of pipelines, local modeling of subsea components, and micro modeling of pipeline welds. Examples of these different types of FE modeling is described in the following sections.

1. Global Modeling
The wide range of proprietary advanced FEA tools that allow the accurate prediction of pipeline responses, which has been developed, is called 'Simulator'. The FE engine is the commercial software ABAQUS [Ref. 2]. The models include elasto-plastic materials, 3-D route geometry, peak, and residual modeling of axial and lateral soil pipe forces. Pipe-in-Pipe (PIP) and single pipe models have been developed. Each model is fully checked and validated. Many of the models have been benchmarked against observed pipeline behavior. The 'Simulator' analysis is a static large deflection analysis and includes all relevant non-linearities such as large deflection and large rotations, elasto-plastic pipe materials interpolated over relevant temperature ranges, and non-linear pipe-soil interactions.

Tools have been developed that undertake the following design activities;

• Upheaval Buckling;
• Lateral Buckling;
• Single pipe and PIP response;
• Reeling Analysis;
• Pipe/Soil interaction;
• Expansion/Span Analysis;
• Ice Scour/Pipe/Soil interaction.

These tools allow the simulation of the pipeline response and the prediction of possible buckles in the pipelines, as shown in Figure 1. This is particularly important for high temperature pipelines.


The use of 'Simulator' during the design stage allows Limit State Based Designs, and allows the following to be undertaken;

• Change and optimize the design;
• Undertake a range of sensitivities;
• Simulate Pipeline response, displacements and expansion;
• Obtain forces, moments and stress/strain.

The design can be iterated and, through the adoption of limit states, the design can be optimized resulting in possibly significant financial savings.

Detailed Description of 'Simulator'
The model runs using ABAQUS [Ref.2] and is designed to analyse the initial, prior to the moment of instability, and post lateral buckling behaviour, and expansion behaviour of straight, single pipe-in-pipe system flowline lying on a flat seabed. This model is applicable for shallow or deepwater condition and/or a HTHP PIP system. The modules can perform parametric studies if required, by simply changing the input parameters of the input script code.

Upon completion of a single analysis, the following results can be presented:

• Submerged Weight;
• DNV Load Controlled Utilization (if required);
• Axial, Lateral Movement;
• Effective Axial Force;
• Axial and Hoop Stress;
• Von Mises Stress;
• Bending Moment;
• Plastic Strain, Buckling Curvature.

The FE elements used are PIPE31H, which are the hybrid formulation pipe elements within ABAQUS/Standard. These elements are selected, as they are particularly well suited to modeling long, slender pipelines with better convergence behaviour than the standard pipe elements.

The friction between the pipeline and the seabed is one of the factors affecting the buckling performance. A friction model, that uses an ABAQUS user subroutine has been developed, and enables non-linear axial and lateral friction to be defined, as shown in Figure 2.



The form of the friction-slip subroutine is similar in both axial and lateral directions. Starting at the origin O, the friction value starts to increase until a peak is reached at point A. Further slip is undertaken with decreasing friction values until a residual value of friction is reached at point B.

The seabed friction dominates the boundary conditions to the pipeline. However, connectors aligned with the pipeline at either end of the pipe are specified to simulate weak springs to remove any potential singularities before friction begins to act.

The global modeling of pipelines has been used on a number of Projects, and also used for undertaking detailed studies. Such studies include an investigation into 'Strain Localisation' [Ref. 9] and the analysis of 'Loadshare' components [Ref. 11]. Some global model examples are presented in the following sections.

Global Model Example: Pipeline Walking
The conventional expansion response of a short flowline involves a virtual anchor point close to the centre of the line and expansion from this anchor towards the ends of the flowline. After early start-up/shut-down, the cyclic expansion is of constant amplitude. Flowline walking can occur for short free-ended flowlines subject to a high thermal cyclic loading. If startup/shut-down cycles involve significant thermal gradients then axial ratcheting of the flowline can occur, with displacements toward the cold end. Over a number of cycles this movement can lead to very large global axial displacement with associated overload of the spool piece or jumper if any. This cumulative axial displacement is described as 'Pipeline Walking'.

The key to this phenomenon is the transient thermal profile developed during heat-up, as shown in Figure 3.


In high pressure flowlines the internal pressure is almost enough to mobilize the friction force over the whole flowline. For this reason the pressure in the analysis is kept constant. A typical pipeline walking response, for a number of start-up and shut-down cycles, is shown in Figure 4

Labels: Advanced finite element analysis tools, Arctic conditions, modelling, Pipeline Analysis, Russia

posted by The Rogtec Team @ 11:30  0 Comments