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Contents INTERVIEW ‘Economics of oil & gas does not make India attractive to Russia right now’ 16 VOL. 11 NO. 6 OCTOBER - NOVEMBER 2014 MUMBAI ` 150
– T N R Rao, Former Petroleum Secretary, MoPNG
OFFSHORE WORLD R.NO. MAH ENG/ 2003/13269 Chairman Publisher & Printer Chief Executive Officer
EDITORIAL
Editor Features Writer Editorial Advisory Board Design Team Events Management Team Subscription Team Production Team
‘India is a key market for Schneider Electric’s global operations’ 18
Jasu Shah Maulik Jasubhai Shah Hemant Shetty Mittravinda Ranjan (mittra_ranjan@jasubhai.com) Rakesh Roy (rakesh_roy@jasubhai.com) D P Mishra, H K Krishnamurthy, N G Ashar, Prof M C Dwivedi Arun Parab, Prasenjit Bhowmick Abhijeet Mirashi Dilip Parab V Raj Misquitta (Head), Arun Madye
– Prabhat Saxena, Director - Oil & Gas Solutions, Schneider Electric
GUEST COLUMN Oil Glut or Oil Cut? –Jenik Radon & Genevieve Signoret
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guest column
Oil Glut or Oil Cut? A Scenario Approach to Envisioning Oil Prices in 2015–2016 We present two scenarios for oil prices and the global economy over the next two years. In one, OPEC does not act (cut output) to stabilise prices. Brent dips to USD 60/barrel in 2014, but, by the end of 2015, starts to rebound. In our second scenario, OPEC does cut output. At first, this succeeds: Brent quickly climbs back up to USD 90. By the end of 2015, however, Brent again starts sliding. Our stories illustrate how, regardless of policy, oil prices over the long run tend to self-correct. They also show how OPEC may hold some sway over the timing of the Fed’s first rate hike.
A
After plunging in 2008 from their July 14 bubble peak of USD 142/barrel (Brent) down to USD 34/barrel on December 26, global oil prices recovered to a new equilibrium around USD 100/barrel. Since July of this year, however, they show signs of entering a new phase. Brent crude has dropped 27 per cent and is still falling. Business leaders and investors have no choice but to formulate views on what this new oil price phase might look like. It’s a daunting task, one we tackle by limiting our forecast horizon to two years, and by adopting the scenario approach.
Jenik Radon1, Esq Adjunct Professor School of International and Public Affairs Columbia University Why the Scenario Approach? Life is unpredictable. Hence, forecast accuracy is a pipedream and risk a constant. Risk management is the only way forward. A power tool for coping with risk and uncertainty is scenario-based planning 2.
Genevieve Signoret President and Head - Asset Allocation TransEconomics www.oswindia.com
To build alternative scenarios for the global economy and oil prices, we start by gathering an interdisciplinary team to develop two or three clusters of assumptions, one for each scenario. These cover unpredictable oil price drivers that we won’t be modeling: policy, politics and geopolitics, weather, and pandemics. Upon each cluster of assumptions, we build a rich scenario narrative and a forecast model. The scenario we deem most plausible we dub ‘central scenario’; the others we call ‘risk scenarios’. Once having built the scenarios, Offshore World | 6 | October - November 2014
guest column A good oil price scenario will require assumptions as to OPEC and Saudi behavior. While, owing to the shale boom, OPEC’s market share has slid recently to 39.9 per cent and is expected to drop by 2018 a further 2 percentage points to 37.9 per cent.
either with or for clients, we can formulate strategies designed to be robust under all scenarios. Periodically, we update our tool by repeating the exercise.
make up in volume for losses caused by falling prices. If Saudi Arabia has its way, then, a rebellious coalition could form—a cartel within a cartel—to coordinate an output cut.
OPEC—and Specifically Saudi Arabia—are Drivers A good oil price scenario will require assumptions as to OPEC and Saudi behavior. While, owing to the shale boom, OPEC’s market share has slid recently to 39.9 per cent and is expected to drop 3 by 2018 a further 2 percentage points to 37.9 per cent, OPEC output generally and Saudi output specifically remain strong drivers of oil prices. Saudi Arabia’s special leverage derives from its outsized spare capacity.
Evidence abounds of ‘unilateral’ cheating by OPEC producers through production in excess of quotas. Here the cheating we envision is multilateral (coalitionbased), and works in the opposite direction, through underproduction. Under Oil Glut, we assume that no such cheating occurs—Saudi Arabia wins not only the vote but also hearts and minds. Additional Scenario Assumptions
Saudi Arabia Aims and Future Tactics are Unknowns Theories abound as to Saudi intentions and coming chess moves. One popular story circulating is that Saudi Arabia aims to regain OPEC market share by persuading its fellow cartel members to refrain from cutting quotas and actual output and thus keep prices down. In more conspiratorial versions, Saudi Arabia targets an oil price just low enough to put small US shale oil producers out of business or to exact vengeance on Russia for its loyalty to Syrian President Bashar al-Assad. While these theories make for racy reading, the fact is, actual Saudi aims and future tactical moves are unknowable. To be able to plan, we can only make plausible ‘assumptions’ as to what Saudi Arabia might do and why, and based thereon, compute projections. Two Sets of Assumptions as to OPEC Behavior Our central scenario, called ‘Oil Glut’, assumes that OPEC decides not to cut output. Saudi Arabia seeks this and extracts the decision at OPEC. It assumes, further, that dissenting OPEC voters either don’t try, or they try but fail, to form coalitions for coordinated cheating. We mention coalitions for cheating because our devious minds detect a potential for multilateral cheating should OPEC decide not to cut quotas. Saudi Arabia may deem it can afford low oil prices fiscally. But several other OPEC producers may well not—few have much spare capacity, so most can’t www.oswindia.com
We make the following additional assumptions under both scenarios: Weather and Conflict: No weather event or conflict materially restricts or threatens oil or other commodity supplies. Notwithstanding intermittent spikes in Russia–Ukraine tensions, Russia never cuts off gas to Europe via Ukraine. Market fears raised at moments of spiking Russia–Ukraine tension remain contained—they never spill over to oil markets. Diplomatic and trade relations among China, Japan, and Korea continue to thaw. Policy: Chinese authorities manage to avert an outright financial crisis. Central bankers do not err: the Bank of Japan (BoJ) keeps up its asset purchase (quantitative easing) programme, and the European Central Bank (ECB) launches a second round of quantitative easing, this one targeting public debt securities as well as private ones; and both the US Federal Reserve and the Bank of England are careful not to raise interest rates prematurely. In fiscal policy, Japan smartly postpones the tax hike scheduled for next year, but the euro area continues to flirt with deflation by failing to work in concert with monetary policymakers and loosen its fiscal stance. Neither Japan nor the euro area passes bold enough reforms to materially boost potential GDP or animal spirits. China does continue on its reform path, in the direction of tilting its skewed economy back toward consumption and away from saving and investment. Necessarily, this slows down Chinese growth. Oil Glut: The Narrative Under Oil Glut, for whatever reason, Saudi Arabia wants prices to stay low and, during the forecast period, manages repeatedly to sway
Offshore World | 8 | October - November 2014
guest column In more conspiratorial versions, Saudi Arabia targets an oil price just low enough to put small US shale oil producers out of business or to exact vengeance on Russia for its loyalty to Syrian President Bashar al-Assad.
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OPEC opinion against output cuts. Moreover, no rebellious coalition emerges that’s capable, through coordinated cheating, of pushing oil prices back up. Brent oil falls to a new equilibrium around USD 60.
June - July 2014 Vol. 11 No. 4 ` 150
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By December 2016, Brent has bounced back to USD 70 and continues to climb. Oil Cut: The Narrative In Oil Cut, OPEC votes to cut production quotas and cheating becomes impossible. In the short run, this strategy bears fruit: Brent crude bounces back to around USD 100. In the medium term, however, it backfires. With oil prices recovering in 2015, the Fed and the Bank of England cut rates in June. Even though these two central banks normalise rates slowly, the rate hikes slow the global economy back down. With growth (and demand for oil) again moving at a snail’s pace, by the end of the forecast period, prices again slide. 2016 ends with Brent already back down to USD 90 and falling fast. Commodity Markets Self-correct Our stories have two morals. First, energy markets self-correct. Falling prices spur demand and lure producers back online, causing prices to recover. Rising prices do the opposite. Second, low oil prices could end up giving the Fed and Bank of England room to maneuver in inflation space to postpone hiking rates. The delay can provide so much stimulus as to end up boosting oil demand and prices both. Reference 1) Moisés Arizpe of TransEconomics provided valuable research support. 2) Our approach is an adaptation of the Shell approach, as laid out by Peter Schwartz in The Art of the Long View: Planning for the Future in an Uncertain World, and Kees van der Heijden
` 150
By the second half of 2016, demand for oil has begun to surge. But low prices have taken their toll: some smaller US shale producers were forced to shut down, while new investment in infrastructure and ongoing projects were put on ice. Together, these renewed demand- and supply-side pressures push back up on prices.
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Although oil exporting countries suffer, most OECD countries enjoy what economists call a ‘Goldilocks’ economy, in which inflation slows down even while growth speeds up. Disinflation frees the Fed and the Bank of England to postpone rate hikes to early 2016. By this time, UK and US labour markets and domestic demand indicators are so healthy that financial market shrug off the hike. The bull market continues.
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in Scenarios: The Art of Strategic Conversation. 3) http://www.reuters.com/article/2014/11/06/us-opec-outlook-idUSKBN0IQ22H20141106 www.oswindia.com
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guest column
Organisational Changes: A Focus on Safety and Avoid Hazards
Dr Zafar Khan HSE Leader
Change is pertinent in today’s world and we have to adopt with the changes. Changes bring new vigour to the organisation and also help them to grow in this ever-changing world and its new requirement. Obviously changes are done for better world and system, but sometime they bring risk along, especially when we are talking about oil gas and other high risk industry. The author provides a brief guidance for employers responsible for major hazards on how to manage the impact of organisational change on their control of the hazards. There are also pitfalls to look for, suggests a three-part framework for managing organisational change, and explains the duties of the employer too.
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Organisational change is a normal and inevitable part of business life in all sectors. But organisations associated with major accident hazards - like Oil & Gas exploration (both Onshore & Offshore), Refinery, Chemical Process industries - have a greater potential for disastrous consequences and higher costs in terms of lives and money. These consequences mean that organisations managing major hazards must aim for much higher reliability than is normally necessary in commercial decision making. Organisational change is often an opportunity to improve health and safety, for example though reappraisal of safeguards or clarification of personal accountabilities. However experience is that in many instances organisational changes are not analysed and controlled as thoroughly as plant changes, resulting in reduced defences against major accidents, sometimes with fatal consequences. This is because, unlike management of plant change, impacts of organisational change are less well understood, and there is a lack of robust, generally accepted approaches to ensuring safety. This guidance aims to help employers manage change that impacts on health and safety.
• business process re-engineering; • delayering; • introduction of ‘self-managed’ teams; • multi-skilling; • outsourcing/contracterisation; • mergers, de-mergers and acquisitions; • downsizing; • changes to key personnel; • centralisation or dispersion of functions; and • changes to communication systems or reporting relationships.
Overstressed Manager In 1992, an organisation in UK, in Castleford fires killed five employees during the cleaning of a vessel containing potentially unstable sludge. Because of a recent company reorganisation, the cleaning task had been organised by inexperienced team leaders reporting to an overworked area manager. The incident report said: ‘Companies should the workload and other implications of to ensure that key personnel have adequate resources, including time and cover, to discharge their responsibilities.’ What Changes? Many forms of organisational change can affect management of major hazards. These changes could be - changes to roles and responsibilities, organisational structure, staffing levels, staff disposition or any other change that may directly or indirectly affect the control of the hazard. The following are some common management terms for such changes: www.oswindia.com
The main focus of this write up on changes at operational and site level. It is also relevant to changes at corporate level which can have a significant impact on safety at operational level. Examples of this include changes in reporting relationships, objectives, resources, management system, available expertise for design, engineering support, procurement and so on. How to Manage Risk of Organisational Change: Follow a three-step framework: Step 1 - Getting organised for change Step 2 - Assessing risks
Offshore World | 12 | October - November 2014
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guest column Step 3 - Implementing and monitoring the change Use these steps to plan and manage your organisational changes. Commitment and Resources Although the motivation for the change may be commercial, and not obviously connected with safety, major accident prevention must be regarded as core business, not a side issue. Senior management need to demonstrate a clear commitment to safety by their actions, from the outset. There should be a distinct safety focus within overall change processes, with positive objectives. Make a senior, highly influential manager the sponsor or champion for this.
Step 1: Getting organised Have a strong policy Make senior-level managers accountable Have a clear change-management procedure Communicate and include everyone Review and challenge
Participation & Communication The process of organisational change should involve all those concerned from an early Stage. This is not only for industrial relations reasons, staff at all levels will have unique knowledge of what their own work involves and how it is really done; this may include contractor and agency staff. This knowledge is often crucial and must be given proper consideration. Review & Challenge Senior management need to be given adequate information to review progress regularly. The organisation should be prepared to change plans if risk assessment shows a potential risk. Preparation of contingency plans can be helpful.
Step 2: Risk assessment Identify the people involved Identify all changes Assess the risks Consider human factors, competence and workload Test scenarios
STEP 2: RISK ASSESSMENT The key aim of risk assessment is to ensure that following the change, the organisation will have the resources (human, time, information etc), competence and motivation to ensure safety without making unrealistic expectations of people. Two aspects of the change need risk assessment; they are related but different and should not be confused: • risks and opportunities resulting from the change (where you want to get to); • risks arising from the process of change (how you get there).
Step 3: Implementing & monitoring Provide enough resources to make the change safety Monitor risks during changes Keep your plan under review, track actions Monitor performance after changes Review your change policy
Clear Systems Organisational change should be planned in a thorough, systematic, and realistic way. You should follow a documented and structured procedure for each element of organisational change management. This is similar to the processes for managing plant change. www.oswindia.com
STEP 1: GETTING ORGANISED A clear implementation plan, such as a project plan, must be produced and approved at a senior level of management. This should be reviewed on a regular basis. Avoid trying to do too much too quickly.
The first aspect is dealt with in this section, the second is dealt with in Stage 3. The risk assessment needs to consider potential impacts upon safe operation in the full range of foreseeable conditions and scenarios. Assessment Procedures There are two complementary approaches to ensure that the main risks are identified: • mapping of tasks and individuals from the old to the new organisation; • scenario assessments when the reorganisation impacts staff who may have a role in handling or responding to crises such as upsets and emergencies. In both cases it is important that organisations use all of the knowledge and expertise available to them and involve the workforce in the risk assessment process.
Offshore World | 14 | October - November 2014
guest column Mapping Mapping is the painstaking process of understanding and tracking the detail of the change. It involves: • Identifying all people in the existing and proposed organisations who will be affected by the change. It is important that this data is accurate and complete eg maintain a register of all staff in the organisation with relevant roles. • Identify the tasks each person carries out, including non-production tasks such as: communication or paperwork; relevant roles and responsibilities they have, including those that are not their mainstream daily duties such as roles in emergency response; and the competences required (special knowledge or skill that each task or responsibility requires); and the working time required for the tasks. • Compare the information carefully and this process becomes more complex in larger organisations where there may be simultaneous changes that may interact with each other, eg roles or responsibilities passing from one area to another. A specific person or body (such as a ‘management of change project board’) can be allocated responsibility to ensure that these crossorganisation issues are tracked and co-ordinated.
• Past Experience • Risks from using contractors • Assessing workload • Action tracking Human reliability and competence, human factors are generally less well understood than engineering risks, the risk assessment should consider potential human failures (see Reducing error and influencing behaviour. Performance Indicators The risk assessments should result in action plans, milestones and identify key performance indicators that can be used to monitor the impact of the change process on the management of major hazards. This is particularly important where consequences could be subtle or long term, such as reducing maintenance staff. Wherever possible use ‘lead’ indicators measuring the control of risks rather than ‘lag’ indicators of the realisation of risk. STAGE 3: IMPLEMENTING AND MONITORING Safety during the Transition Step 2 was about looking ahead to the proposed change and anticipating risks arising from it. Step 3 concerns management of the transition itself. It is important that plans are carefully reviewed to ensure that exposure to risks is not significantly increased during this time. Even where a planned change involves reducing the workforce, you will usually need to plan for an increase in workload during the transition. There are risks during the change that uncertainty and the effect it has on individuals may affect their performance. However, most responsible companies will seek to reduce periods of uncertainty to a minimum. Monitoring the Change There will always be a degree of uncertainty as to the impact of organisational change. Effects can be subtle and not immediately apparent, eg degradation of activities following increased workload or span of work, or changed priorities. Unrecorded or informal activities or communications that contribute to safety performance can be overlooked and lost. Risk assessments and plans for both the transition and progress should be regularly reviewed. You will have set objectives and devised key performance indicators. Periodic, planned reviews should assess whether these have been achieved. Be ready ultimately to change or even reverse decisions where there is evidence that there may be significant risk, however uncomfortable this might be.
Scenario Assessments These are realistic, structured appraisals that the proposed new arrangements will perform adequately in a range of foreseeable upsets, incidents and emergencies. Assessing the safety of staffing arrangements for process operations in the chemical and allied industries contains an example which assesses staffing arrangement at chemical sites. Factors to Consider During the assessment consider the following factors:
It is important to plan-in reviews as the effects of change can be subtle or delayed eg six months to a year afterwards. These reviews should be led by the senior manager responsible for championing the change but may also involve independent reviewers. It is important that the lessons learnt from the change process are identified (strengths and weaknesses) and used to amend the organisation’s own change procedure. Organisations that maintain a register of people involved in managing the major hazard will need to review this periodically to ensure that it is up to date and complete. ‘SAFETY FIRST AND ALWAYS’ should get treated with priority all the time, during the phases of changes and for a future safer company process.
Offshore World | 15 | October - November 2014
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Features
Russia-West Stand-off for Oil-Hegemony A scenario approach to envisage the impact of Western sanctions on Russia to its hydrocarbon market, ban on technology transfer to Russian oil and gas companies and Moscow’s eagerness for new allies for exploration, development and marketing of its vast, rich hydrocarbons. Text: Rakesh Roy
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In the context of Russian involvement in Ukraine and the annexation of the Crimea, the US, EU, and other countries has leveled sanctions against Kremlin. The sanctions are to target Russia’s financial institutions, energy sector and Russian entities in the energy and defence sectors. As the world’s largest producer of crude oil, including lease condensate, and the world’s second-largest producer of dry natural gas in 2013, Russia’s economy is highly dependent on its hydrocarbons. And the sanctions on Russian hydrocarbon market will really matter a lot to the country’s economy. As per US Energy Information Administration, Oil and gas revenues account for more than 50 per cent of the country’s federal budget revenues and EU is the main importer of Russian’s hydrocarbon. As per report, Russia currently exports approximately 5 million barrels of crude oil and nearly 2 million barrels of refined products per day, mostly shipped to Europe. Approximately 33 per cent of Russia’s exports in 2013 was crude oil, primarily going to Europe and the other hand Europe depends on natural gas imports from Russia delivered via pipelines through Ukraine.
These sanctions have not immediately impacted the export of Russian oil and gas but do raise concerns about future economy of the country that mostly depends upon the exploration, development and marketing of its vast, rich hydrocarbons. The long-term financial prospects of the Russian oil sector will depend on its ability to searching new countries to export its highly rich hydrocarbon. This may lead Russian hydrocarbon exports pivoted to Asia Pacific. China has already the upper hand with the recent pipe gas deal with Kremlin and especially now that Western sanctions on Russia have made Moscow eager for new allies in these regions. One of the most oil consumption countries in Asian region - India, which is the fourth-largest oil consumer and third-largest net importer of crude oil globally, depends heavily on imported crude oil, mostly from the Middle East. The oil cut from Iran due to western sanction and geopolitical instability at some of the countries in Middle East & African region, India is imperative looking for some relevant kind of options like Sino-Russia pipe gas deal to secure interrupted energy supply. At the same time, energy sufficient US is apparently searching new regions to export its Shale & domestic crude oil which is now in its peak.
Russia Gross Export Sales, 2013, USD bn
Source: Vox.com www.oswindia.com
Offshore World | 16 | October - November 2014
interview
‘Economics of oil & gas does not make India attractive to Russia right now’ In this context, T N R Rao, Former Petroleum Secretary, MoPNG, shares his view on the impact of the long-term financial prospects of the Russian oil sector amidst the sanction & India’s stand in this East-West stand-off in accessing oil & gas for its energy requirement, with Offshore World…Excerpts:
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What is your take on the Western Sanction on Russia especially by the same European Union which usually endorses trade Liberalisation and Globalisation? I don’t think in matters of realpolitik, these issues are relevant. The security of a nation or a group of nations dictates how they act in their self-interest and such issues become relevant only when their interests are secured. What will be the immediate impact of the entire sanction to the European Hydrocarbon Market & the Russian Oil Supremacy in the Artic & Asia Pacific? This will be farfetched. .Even western companies are competing for Russian oil & gas assets. Western superiority in hydrocarbon technology does not need recourse to such means. Russia cannot offer either capital or technology in this area but only oil & gas. But economics do matter. Growing production in greater parts of Africa easily outprice supplies from Russia to south-east Asia.
What should be the wise approach of India in this East-West standoff in accessing hydrocarbon to fulfill its energy requirement? It is difficult to see its proximate impact on India, either economically or politically. This seems localised and even international markets have not shown any signs of nervousness on account of this. With the sanction in place, Russia will certainly look to explore the Indian market and at the same time US will use all the diplomatic might to foil the Russian proximity with Indian market, so according to you, who will be the right choice to go for in the long run to meet our energy requirements? It is difficult to subscribe to this view. Economics of oil & gas does not make India attractive to Russia right now. There are plenty of supplies nearby India. The very fact that oil markets have fallen and are falling despite this and the crisis in Middle East shows that this contingency is very remote. Geopolitical hazards are great in transporting oil/gas from Russia through several transit countries to India.
It is difficult to see the East-West stand-off proximate impact on India, either economically or politically. This seems localised.
Is it possible to uphold the Oil-Hegemony of West without Terrorism, Sanctions & wars? It is not clear what is meant by the oil hegemony of the west. West has superiority in capital and technology, but 80 per cent of the hydrocarbon resources are in economies with state control. Without attaining commanding heights of the global market, no one region can claim hegemony. The dollar denomination is one strength, but that is only as far as it goes. US is becoming self-sufficient in oil and gas and has less and less military interest in areas like the middle east, but may retain strategic oversight, because of the growing anti-US militancy in those areas. The sanctions and wars are only to protect their sphere of influence and prevent encroachment by Russia, China or any such move by a bloc or a region.
Offshore World | 17 | October - November 2014
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interview
‘India is a key market for Schneider Electric’s global operations’ “Today we are able to deliver our systems and solutions to entire oil & gas industry starting from PSUs to EPC companies executing projects in India and overseas. We have been here in a big way with our products, solutions and services,” says Prabhat Saxena, Director - Oil & Gas Solutions, Schneider Electric. He recounts SE’s end-to-end integrated solutions, project involvements, basic bidding approaches, etc for Indian hydrocarbon industry, in an exclusive interaction with Mittravinda Ranjan.
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Schneider Electric (SE) has been involved in project execution for the oil & gas industry irrespective of the size and scale of the project and offers turnkey solutions as the main electrical and automation contractor. Saxena says: “SE has the capabilities to deliver project execution in timely manner; we offer not only the solutions but also support the design before it comes in.” SE’s project involvement to the industry typically at the stage of FEED, supports the basis of calculation and at the time of Basic Design which is almost three or five years in advance before the project goes for bidding. “Working at FEED stage with Indian PSUs was not easy few years back and also some global engineering companies in India were a restricted domain in the past; but I have seen some opening and good signs of change in their approach in last one and half year,” recalls Saxena.
Safety is most imperative to any end user in the EPC industry in giving the bound document that has to be followed. Safety is foremost for global EPC companies, and SE very well understands the requirement and delivers accordingly and this counts for the customers. www.oswindia.com
FEED requires a large amount of support for chemical process design & electrical equipment, plant layouts etc – a very engineering intensive job. So our approach here is that customers tend to buy the goods that will have long-term impact on energy efficiency and hence all your profits, he says. Indian EPC companies are typically preferred bidders on the basis of lowest common denominator rather than looking at performance parameters. The impetus here is on keeping the capital cost low.
Offshore World | 18 | October - November 2014
interview Substandard bidder and keeping lowest Capex without recognising the quality standard not only impacts the plant performance but also puts productivity and production at stake. It may lead to non-availability of services or suppliers of purchased products/technologies which may become obsolete in the due course.
“Substandard bidder and keeping lowest Capex without recognising the quality standard not only impacts the plant performance but also puts productivity and production at stake. It may lead to non-availability of services or suppliers of purchased products/technologies which may become obsolete in the due course”, he says.
Schneider Electric considers countries like - Vietnam and Indonesia as the emerging markets in Southeast Asia and has a strong presence in Indonesia with huge manufacturing and engineering footprint in Jakarta.
Safety is most imperative to any end user in the EPC industry in giving the bound document that has to be followed. Safety is foremost for global EPC companies, and SE very well understands the requirement and delivers accordingly and this counts for the customers.
Middle East market is one of the best discerning markets globally. The project owners in these countries are prefer best of everything in terms of quality, engineering, project management, timely deliveries and after sales services. The beauty of the market is in its strong engineering expertise as well as resources and capital that they have like many other developed economies.
“But in comparison to international companies, where safety cannot be compromised, as far as my global experience goes, I am yet to see the seriousness towards safety in Indian EPC industry,” he says.
“The differentiator is – the Mindset. In Middle East, customer satisfaction is only criteria to get the right price for quality services and timely deliveries. But in India that is not the case,” Saxena says.
While EPC companies are judged on the basis of their HSE track record in accessing projects in international markets, SE’s basic philosophy is to review any past accident, production lapse of the project before going for bidding. “Lastly, what is important is the customer satisfaction - where we make sure to attend to any complaint regarding any of the equipment we had supplied at any point of time in the past. Our strong customer relations are built around our strong commitment towards providing services throughout the life cycle of the equipment we supply,” Saxena adds.
“I keep the same things for our Indian customers regarding the products and the services, however when it comes to pricing, many a times we are told that their hands are tied – they are not flexible with the price part,” he adds.
“People involved with SE’s oil & gas operations globally have imbibed our commitment towards customer satisfaction and a strong expertise in core areas,” he says. India is a key market for SE’s global operations and it is now looking at expanding its operations in the country. “We are now manufacturing products in India of global standards both for the Indian and International markets. We have manufacturing facilities of global standards in the country and have the ability to produce equipment in compliance with the Indian market.” On an international front, SE has its presence all over the globe in all the major markets. SE has been working extensively in African nations and adds another success story to its overseas footprint by successfully completing LNG plant at Angola. SE also has a huge presence in Egypt, Algeria in North Africa and Nigeria.
Lack of proper valuation of equipment that one needs to buy is the biggest challenge in Indian market. Despite that, India has done a fairly good job in setting up world class refineries and has pipeline running across the country. Indian EPC companies are still very immature and need to adopt a much serious approach. Documentation is one of the biggest challenges that EPC companies need to address in ensuring smooth work processes. This requires that documentation should be done with the real time data. Availability of skilled labour is another issue as many people who even though are trained are not employable. Success of any project is the inherent reliance of three key stakeholders the project owner, the manufacturer and the EPC. “Intrinsic trust between the manufacturer and the project owner should be to such an extent that manufacturer can share the manufacturing cost with the customer and - where customer will realise the actual cost and would ensure profitability to manufacturer. This would help to sustain business in true manner,” says Saxena.
Offshore World | 19 | October - November 2014
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Features Reservoir Simulation
How Well Did You Complete? A Marcellus Shale Completions Optimisation Case Study The article explains an integrated analysis of hydraulic fracturing treatments in the Marcellus Shale that was conducted to investigate the relationship between reservoir geology, wellbore completion, stimulation design, and microseismic data to evaluate the correlation between hydrocarbon production and microseismic results relative to changes in geology and the stimulation approach.
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Over the last decade, microseismic monitoring has become an accepted industry practice and, some might say, a standard when frac’ing in unconventional reservoirs. Contrary to the bi-wing type textbook example that’s been recognised in the industry, fractures that are created in shale plays during hydraulic stimulation are quite different. In reality, the fracture network created in unconventional plays is extremely complex and accurate imaging is necessary to understand the formation and enable completions optimisation and maximise asset value and recoverable reserves. Microseismic data can be used to model a Discrete Fracture Network (DFN) that serves as an important input for reservoir simulation. The model allows the total rock volume affected by the treatment to be calculated. This can be taken a step further by placing proppant in the DFN to help identify the part of the Stimulated Rock Volume (SRV) that likely contains proppant and should therefore be productive. This type of analysis using microseismic data allows operators to understand where the proppant went and what proportion of the reservoir is actually productive to help determine ideal well spacing, stage length, and alternate treatment options. Currently, three core monitoring methods are commercially available to record microseismic data: downhole, surface, and near-surface. Though single-well downhole monitoring is sufficient in some cases, the broad areal coverage of surface and near-surface monitoring usually provides more detailed information. Surface monitoring makes it possible to determine the way in which the formation is breaking (strike, dip, rake), which is essential to build the desired, highly accurate DFN (Williams-Stroud 2008). As a result, some operators are choosing to implement a hybrid monitoring technique that combines downhole and surface to achieve an even higher resolution and accuracy. After a monitoring method has been selected and the proper data has been acquired, the DFN is built in two steps. First, the strike and dip of the failure plane is determined for each individual event. Then, the geometry of the failure plane is determined by incorporating the magnitude of each event, as well as the calculated rigidity of the rock and the injected fluid volumes. Once the DFN is completed, the SRV can be determined. In addition, the proportion of the SRV that contains proppant, and is therefore productive in the long term, can be estimated.
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Calculating how much of the fracture volume will be productive begins by estimating the propped half-length. Estimation of the propped half-length is performed by filling the subset DFN with proppant from the wellbore outward, on a stage-by-stage basis. The packing density of the proppant is variable and can be adjusted based on the specific gravity of the proppant and hydraulic fracture simulation. For each stage, the fracture volume inside the DFN is filled with proppant until all of the proppant that was pumped is accounted for. The estimated propped half-length is determined by looking at the statistical distribution of proppant filled fractures around the wellbore. This accounts for the fact that the fractures are centered on the microseismic events while honoring the distribution of fracture sizes for a given stage. In order to calculate how much production can be expected of the stimulated rock volume, a three-dimensional grid is applied to the proppant-filled DFN. Every grid-cell containing a non-zero fracture property that was filled with proppant is included in the productive area of treatment. This yields a rock volume that is expected to contribute to production in the long term as illustrated in Figure 1 on next page. Based on the DFN and the SRV, the permeability tensor can be calculated for the rock volume containing microseismic activity (Oda, 1985). The permeability derived is the fracture permeability for a dual-porosity, dual-permeability reservoir model. It should be noted that it is not representative or in any way indicative of the matrix permeability. In addition to the fracture permeability calculated from the DFN, a system or bulk permeability can be obtained from an evaluation of the spatio-temporal dynamics of the microseismic events and the apparent system diffusivity. This evaluation can help to characterise the reservoir and estimate the results of hydraulic fracturing by calculating permeability on a stage-by-stage basis. Case Study An integrated analysis of hydraulic fracturing treatments in the Marcellus Shale was conducted to investigate the relationship between reservoir geology, wellbore completion, stimulation design, and microseismic data. These findings were then used to evaluate the correlation between hydrocarbon production
Offshore World | 20 | October - November 2014
Features
Fracture network created in unconventional plays is extremely complex and accurate imaging is necessary to understand the formation and enable completions optimisation and maximise asset value and recoverable reserves. and microseismic results relative to changes in geology and the stimulation approach. The observed variability in the microseismic response was used to derive regional trends and optimise field development. Initial production was compared to reservoir and engineering parameters, such as treatment pressures, sequence of treatments (toe-to-heel vs. zipper-frac), net pressures, and stage spacing, to determine if the variability in the microseismic results is due to engineering differences or to spatially-varying reservoir properties. The microseismic data set was acquired with a permanently-installed near-surface array consisting of 101 geophones, as seen below in Figure 2 on next page. Two fracture sets are present in the Marcellus shale. J1 fractures are oriented northeast to southwest and were formed as natural hydraulic fractures during the Alleghenian Orogeny (Engelder et al., 2009). J2 fractures (oriented northwest to southeast) were formed during hydrocarbon generation and cross-cut the older J1 fracture set (Duncan and Williams-Stroud, 2009).
Ideally, a horizontal well attempting to produce from the Marcellus Shale should activate the J1 fracture set to exploit the high permeability of these fractures and activate the J2 fractures to connect parallel J1 fractures. If the J2 fracture sets are stimulated, those fractures will inevitably intersect the J1 fracture set allowing production from those fractures. Operators drilling in the Marcellus Shale have found that orienting well-bores to activate both the J1 and J2 fracture sets yield the highest production. Additionally, in this case, zipper-frac’ing was found to better activate both fracture sets and further improve production. To analyse different treatment attributes, a base DFN model was created and varied on five dimensions (flow rate, treatment pressure, stage duration, stage length, number of perforations, and perforation cluster spacing) with the goal of refining completions designs for optimal economic return. In this case, stage length had the greatest economic impact. Given the natural fracture density observed in the outcrops of the Marcellus shale, it was found
Figure 1: Total productive rock volume. The total DFN can be seen in blue in the upper left corner. The proppant filled portion of the total DFN can be seen in red in the upper right corner. From the total DFN the total SRV can be determined as illustrated in blue in the bottom left corner. The productive portion of the SRV due to proppant filled fractures is shown in red in the bottom right corner. Offshore World | 21 | October - November 2014
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Figure 2: Map view of surface microseismic monitoring array. Recording stations can be seen as turquoise circles. Well pads are named with letters.
that an additional 5 feet between each of the five perforation clusters would only minutely change the hydraulic fracture network. This finding could permit the elimination of one stage per well, effectively saving the operator time, energy, and costs. Applied across the entire well pad, the potential savings could have approached a seven figure dollar amount. Additionally, zipperfrac’ing was found to better activate both the J1 and J2 fracture sets to improve production. To further optimise field development in the Marcellus, calculation of how much of the reservoir was actually propped during treatment can be used to provide information for well spacing and ensure that hydrocarbons are not being left behind.
Implications for Generating Fracture Flow Properties for Reservoir Simulation” SPE 119895,
These new advances in technology integrating geophysical and engineering results can clearly demonstrate real value to oil and gas companies operating in unconventional shale plays. The ability to understand what proportion of the stimulated rock volume is actually productive allows operators to improve production and recoverable reserves and lower costs by optimising well spacing and determining ideal stage lengths.
AB, Canada, October 30 – November 1, 2012
References 1) Williams-Stroud S., “Using Microseismic Events to Constrain Fracture Network Models and www.oswindia.com
SPE Shale Gas Production Conference, Fort Worth, TX, USA, November 16-18, 2008 2) Oda M., “Permeability tensor for discontinuous rock masses”, Geotechnique, Vol. 35 (4), pp. 483-495, 1985 3) Engelder T., Lash G.G., Uzcategui R.S., “Joint sets that enhance production from Middle and Devonian gas shales of the Appalachian Basin”, AAPG Bulletin, Vol. 93, pp. 857-889, July 2009 4) Williams-Stroud S., Neuhaus C.W., Telker C., Remington C., Barker W.B., Neshyba G., Blair K., “Temporal Evolution of Stress States from Hydraulic Fracturing Source Mechanisms in the Marcellus Shale” SPE 162786, SPE Canadian Unconventional Resources Conference, Calgary,
Carl Neuhaus Product Champion - Completions Evaluation MicroSeismic Inc Email: cneuhaus@microseismic.com
Offshore World | 22 | October - November 2014
Features BOP Risk Model
Blowout Preventer (BOP) for Deepwater Drilling Rigs Aftermath Macondo well failure, the offshore drilling industry have been escalated the demand for products that improved the operational reliability and visibility of safety-critical components such as the Blowout Preventer (BOP) for deepwater drilling rigs. The article explains about the development & application of BOP Risk Model, which was designed to reduce the Non-Productive Time (NPT) and the time it takes to assess the implications of BOP component failure, providing objective and consistent criteria by which decisions to suspend drilling operations can be made.
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The technical advances in the types of assets and systems used by the offshore drilling industry in the past decade have resulted in much safer operations. Despite some high-profile incidents since the turn of the decade, the industry in general is now safer by design. So much so that there is an increasingly popular school of thought whose proponents believe that the next significant incremental advances in worker safety are most likely to come from a better understanding of human factors. But while more research into the influence that the human element has on safe operations certainly holds great promise, it would be a mistake to assume that equally qualitative safety-related advances have been exhausted for the present systems and equipment. Case Study For the offshore drilling industry, April 20, 2010 will always serve as a watershed moment. While tragic, the Macondo well failure prompted the industry to re-examine the effectiveness of prescriptive regulation regimes, made mandatory independent technical oversight for drilling operations in US waters, and escalated the demand for products that improved the operational reliability and visibility of safety-critical components such as the Blowout Preventer (BOP) for deepwater rigs. Simply put, the BOP is one of the most critical parts of the safety system for any offshore drilling rig. Solution at Place It was in the shadow of Macondo that Lloyd’s Register Energy developed the BOP Risk Model, which has been embraced by the drilling industry for its ability to limit Non-Productive Time (NPT), greatly reduces the time it takes to assess the implications of BOP component failure, and provides objective and consistent criteria by which decisions to suspend drilling operations can be made. In purely commercial terms, reducing NPT boosts revenue and profits for rig owners and operators, as well as external shareholders such as the increasingly sophisticated institutional and retail investors in listed offshore companies.
But it also appeals to other stakeholders such as regulators and the general public, who like the safety and environmental implications associated with a reduction in NPT. Improving the operational reliability of offshore assets has obvious positive implications for worker safety and environmental stewardship. The transparency offered by products such as the BOP Risk Model also provides clear evidence to stakeholders that operational risks are understood and they are managed effectively. In the post-Macondo era – where the cost of BP’s single asset failure has reached USD 42.2 billion, and counting – stakeholders are increasingly demanding more transparent risk-management strategies. And, as the offshore industry expands into more hostile environs to find new sources of energy, those demands will only grow louder. BOP Risk Model Development & Application The software behind the BOP Risk Model was created for the nuclear industry. RiskSpectrum is proven technology created by Lloyd’s Register Consulting to support the stringent regulatory demands for monitoring the operational performance of the world’s nuclear reactors. RiskSpectrum was created for an energy sector that has no tolerance for asset failure, and it is presently used in more than 50 per cent of the world’s nuclear power plants. On the face of it, there may not appear to be a lot of operational commonality between running a nuclear reactor and extracting hydrocarbons from the seabed. But any industry in which a comprehensive commitment to performance monitoring and regular testing to detect equipment or operator failures has delivered just three major accidents in more than 15,000 reactor-years of commercial power generation probably has something to offer any high-risk asset safety programme. Certainly, the offshore industry would be well counselled to aspire to the same levels of safety performance and operational dependability. And, with
Offshore World | 23 | October - November 2014
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Features the high quality of today’s asset and system technology, such high goals are not something that is beyond our reach.
Simply put, the Blowout Preventer (BOP) is one of the most critical parts of the safety system for any offshore drilling rig.
In the aftermath of Macondo, well-operators continue to face some very complex technical challenges in relation to BOP performance. Most operational risk assessments, particularly those concerning whether or not to suspend operations until the problem can be resolved, are for the most part still being made without consistently applied methodologies or logic. This often makes the rationale for any related decision unclear to senior management and other stakeholders such as industry regulators. BOPs and their control systems are very complex: a typical BOP stack can comprise thousands of components. So a comprehensive analysis of which component(s) failed, why they failed, and any failure’s impact on present levels of operational risk can take many days, if not weeks, to perform. The commercial pressures can be overwhelming; one of our clients claimed to have lost more than USD 100 million due to NPT associated with BOP problems in the Gulf of Mexico in 2012 alone. Other companies working in other regions have offered anecdotal evidence of even greater losses. The BOP Risk Model supports a decision-making process that is verifiable and objective, giving any stakeholders both the confidence and the evidence that the right decision has been taken, and can be taken consistently in the future. In doing so, the BOP Risk Model addresses some of the industry weaknesses identified in the final report on Macondo to the Bureau of Safety and Environmental Enforcement (BSEE) and the subsequent Outer Continental Shelf Lands Act in which Congress directed the Secretary of the Interior to require, wherever practicable, ‘the best available and safest technologies’ that are economically feasible. The final report identified the need to create incentives that would spur the development of technology to eliminate the reliance on human judgment, where possible.
risk-decision methodology is based on regulations and the oil and gas industry’s specifications.
The report noted that one of the biggest surprises of the investigation was the US offshore industry’s ‘inadequate focus on technology’, saying it ‘appeared to lag behind other industries when it comes to safety-related technologies’, particularly when there was no concurrent pay-off in drilling efficiency.
The BOP Risk Model itself was designed in consultation with a joint industry panel comprised of Lloyd’s Register Energy – Drilling’s BOP subject-matter experts, Lloyd’s Register Energy Consulting, well-control experts, subsea specialists and drilling contractor companies working in the Gulf of Mexico.
It recommended eliminating human judgment as much as possible where a mistake could have huge consequences.
Each BOP Risk Model is customised to the components of the specific BOP stack, and the operating and regulatory environment in which the rig will operate. In the planning mode, its programming flexibility allows clients to use the tool to train personnel, run scenarios that help to develop emergency plans, and run ‘what-if ’ scenarios to discover the domino effects that can be caused by specific component failures.
With the BOP Risk Model’s use of customised fault-tree modelling -- it models up to 750 of the BOP’s most critical components and about 1,350 possible failure modes -- it can objectively highlight any changes in operational risk associated with component failure within seconds; the subsequent identification of the failed component may take a few minutes or hours longer. It is able to do so because the risk assessments used to populate the data are performed in advance by a team of BOP subject-matter experts equipped with the most up to date diagrams and documentation; the www.oswindia.com
During operation, the user can manually remove components from service and the BOP Risk Model will calculate the risk, displaying the levels in the RiskWatcher software application -- also created by Lloyd’s Register Consulting -- which presents as a series of colour-coded dashboards.
Offshore World | 24 | October - November 2014
Features BOP Risk Model, which has been embraced by the drilling industry for its ability to limit Non-Productive Time (NPT), greatly reduces the time it takes to assess the implications of BOP component failure.
The simple operator interface is designed so that the user does not require extensive knowledge of the BOP Risk Model, but he or she can easily alter the input parameters to visualise the changing levels of risk caused by failed components. It is intuitive and doesn’t require extensive knowledge of risk modelling to use. Components are easily taken out of service and risk is calculated and displayed according to the colour schematic in a matter of seconds. While the results are transparent and compelling, committing to new systems, methodologies and products such as the BOP Risk Model will require the drilling industry to make a step-change in the way it assesses and manages the risk of a BOP failure, and the monitoring and maintenance of high-risk, safety-critical assets in general. It will also require rig-owners to make an investment that, while only a fraction of what could be lost through NPT or the much bigger liabilities of a total well failure, is not insignificant. However, the product is a significant enough advance on present safety practices, systems and products in the market to be commercially compelling. At present, four BOP Risk Models have been delivered to companies operating in the Gulf of Mexico, while interest from operators in Brazil and West Africa has also begun to peak. Aside from growing the commercial interest, it recently won an ‘meritorious award for engineering innovation’ from a leading industry organization, an independent accolade which annually recognises the best new tools and techniques for finding, developing and producing hydrocarbons; entries, restricted to products developed for the upstream sector, were adjudged on their game-changing potential, both technically and economically. It was also recognised by the EIC, a non-profit European trade organisation, for its ‘demonstration of superiority within the energy supply chain’. While the accolades and commercial suppor t continue to justify the investment, time and effort that went into developing BOP Risk Model, it is what lies ahead for the product that continues to inspire the team at Lloyd’s Register Energy.
It may have brought greater safety, certainty and consistency to the decisionmaking process regarding whether to pull a BOP stack upon discovery of a potential component failure, and it may have reduced by up to 95 per cent the time it takes to assess that failure’s impact on the asset’s overall operating risk, but we are conscious that the product has yet to reach the real-time monitoring capabilities that have made the nuclear industry a leader in worker safety and asset reliability. The next step will probably require the development of a new sensorrelated solution for the BOP Risk Model, perhaps by marrying it with other technologies, perhaps developed in partnership with the original equipment manufacturers that presently produce the BOP. And the potential for the technology and methodologies at the core of the risk model are not necessarily limited to supporting the assessment of the operational health of the BOP. For us, there is no technical reason why they could not be applied to monitor and assess all safety-critical components of the offshore assets deployed in the extraction of hydrocarbons from deep-water or other equally difficult environments such as the arctic. Lloyd’s Register Energy is presently engaging some the world’s top in offshore rig designers and builders to explore how the programmes at the core of the BOP Risk Model could be used to monitor all of the critical systems on drillships and semi-subs to give the user an asset-wide operational drillingrisk assessment. It believes that having the ability to design, build and offer the market a variety of offshore assets that are equipped with systems to provide comprehensive operational health checks could be the competitive advantage which will clearly differentiate any offshore design and fabrication yard from the pack. And along with the commercial advantages would come improved levels of asset reliability, worker safety and environmental stewardship. Scotty Roper Commercial Manager Lloyd’s Register Energy Email: scotty.roper@lr.org
Offshore World | 25 | October - November 2014
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Features Relief Load Calculation
Relief Load Estimation of Gases, Vapors and Supercritical Fluids The article explains various rigorous methods to evaluate relief load calculation of a pressure relief valve (PRV) located on vessels containing gases, vapors, or supercritical fluids.
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Process plants comprising of pressure vessels, heat exchangers, operating equipment and piping are generally designed to withstand the pressures of the process system. The design pressure of the system is based on the normal operating pressure at operating temperatures and the process involved during the operation. If the normal operational flow is unbalanced or if the control system starts malfunctioning, then this may build up excess pressure which may exceed the system’s design pressure. This will result in over pressurisation of the system. Hence a process designer should define the minimum pressure relief capacity required to protect the system against the over pressurisation.
Supercritical Fluid Relief as PSV Discharge: A typical example of such a situation is a vessel containing liquid, which is protected against over pressurization (due to fire) by installing a PSV which will relieve pressure above the fluid’s critical point. Here, the liquid will vaporize completely, while reaching its critical point. Beyond the critical point, the pressure build up is only due to vapor/gas expansion.
One of the major causes of over pressurisation is fire. Fire exposure can over pressurise the vessel due to vapor generation (boiling of liquid contents) or due to fluid (gas) expansion.
The most simple and contemporary method based on the phenomenon of ideal gas expansion, is considered to evaluate relief load in such cases. In this method it is assumed that ‘the fluid behaves as per ideal gas law’.
There are several methods suggested to evaluate the relief load calculation of a pressure relief valve (PRV), located on vessels containing gases, vapors, or supercritical fluids.
Based on the gas expansion method, relief flow rate is calculated with:
Supercritical Fluids A supercritical fluid is defined as a substance above its critical temperature (T C) and critical pressure (P C). The critical point represents the highest temperature and pressure at which the substance can exist as a vapor and liquid in equilibrium.
Till date, several methods have been suggested for relief load evaluation of a supercritical fluid exposed to external heat source.
………………………………………………… Eq. (1) The relief flow evaluation is based on molecular weight (M), relieving absolute pressure (P 1), exposed area of vessel (A), maximum allowable vessel wall temperature (MAWT) of vessel (Tw) and relieving temperature (T 1 ) where relieving temperature (T 1) is calculated based on ideal gas law. However, it is observed that supercritical fluid behaves differently from an ideal gas. Supercritical fluids exhibit typical characteristics of both liquids and vapors. Properties such as viscosity and diffusion rate are close to a normal vapor, while solvent strength resembles a typical liquid. Also, hydrocarbon vapors do not behave as an ideal gas. Thus, gas expansion phenomenon cannot always be relied upon to estimate the relieving flow rate. This requires a more rigorous method of calculations as specified in the API 521. The pressure relieving rate can be derived from an unsteady state analysis. Rigorous Method To evaluate reliving flow rate for vessels containing gases, vapors, or supercritical fluids API 521, 2014, suggests more rigorous method of calculation.
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Offshore World | 26 | October - November 2014
Features
The most simple and contemporary method based on the phenomenon of ideal gas expansion, is considered to evaluate relief load in such cases. In this method it is assumed that ‘the fluid behaves as per ideal gas law’. In such cases, evaluation via volume expansion method is one such alternative. As the title suggests, the relief load is calculated based on the expansion in the volume of fluid due to heat absorption. This method can be used for any fluid, including vapor and supercritical fluids, provided their phase doesn’t change. To maintain a constant pressure at a fixed volume, the additional volume created by the volume expansion due to heat, should be relieved. However, some assumptions must be made and some basis must be set to make this method viable: a. Other than the relieving stream, no fluid enters or leaves the vessel during the course of relief b. There is no change of phase during the course of relief. The desired physical properties of the containing fluid can be estimated by using simulation software. While using the simulation, properties based on the fluid composition, its pressure – temperature profile and compatibility of the selected thermo package should be verified.
is the density calculated at step (n), expressed in kg/m 3 (lb/ft 3);
is the enthalpy calculated at step (n+1), expressed in KJ/kg (Btu/lb);
is the enthalpy calculated at step (n), expressed in KJ/kg (Btu/lb)
Case Study Numerical Example of Relief Load Calculation: Estimate the relief load for a vessel containing n-hexane which absorbs 5 million Btu/hr of heat and has a relieving pressure of 770 psia. The normal operating conditions of a vessel are 300 psia at 280 degrees Fahrenheit and the vessel having dimensions of 6.5 ft. diameter and 16 ft. length, contains 1000 lb. of n - hexane.
The steps involved in evaluating the relief load are as follows: Assume that the pressure of a vessel increases via a constant volume process from its operating pressure and temperature until the relieving pressure is reached. This relieving pressure point will be the starting point for determining the relief rate. 1. The fire heat input [kW (Btu/h)] can be calculated using the analytical method given in Annex ‘A’ of API 521. Selection of an appropriate time or temperature increment and estimation of incremental fire heat input. The effect of incremental heat input performs constant pressure expansion. With the generated property table, expanded volume to be relieved can be calculated as:
………………………………………………… Eq. (2) Where, is the volume calculated at step (n+1), expressed in m 3 (ft 3);
is the volume calculated at step (n) after the incremental volume has been relieved, and is equal to the initial volume V 0, expressed in m 3 (ft 3);
is the heat input into the system for the selected increment represented by the step from (n) to (n+1), expressed in KJ (Btu);
is the density calculated at step (n+1), expressed in kg/m 3 (lb/ft 3);
The critical pressure (Pcr) and critical temperature (Tcr) of n – Hexane are 439.7 psia and 454.6 degree Fahrenheit respectively. Thus, at relieving conditions the fluid is in supercritical zone. For the selected case study, the relief rate calculation is demonstrated with traditional gas expansion method, along with two different incremental rigorous methods. Gas Expansion Method: Step 1: As per API 521, gas expansion method is applicable for vapors, gases and supercritical fluids. At operating conditions, n-Hexane is in liquid form. But, as mentioned above, the relieving pressure is well above the fluid’s critical
Offshore World | 27 | October - November 2014
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Features pressure point. At critical point, the fluid phase will change to vapor. Thus, to evaluate the gas expansion method, critical point of n- Hexane is considered as the initial operating point.
Step 2: The first relieving pressure point will be the starting condition, for determining the relief rate. Assuming the moderate time interval and a number of increments, a property table at a relieving pressure of 770 psia is generated.
Molecular weight (M) Relieving absolute pressure (P 1) MAWT of vessel – CS (Tw) Operating absolute pressure (p n) Operating absolute temperature (T n)
Calculation: Due to continuous heat input, heat content / enthalpy of fluid increases. Based on the time increment of 5 seconds, for 20 increments, upper bound for enthalpy is specified to generate a property table at constant relieving pressure of 770 psia.
= 86.18, = 770 psia, = 1100 °F = 1560 oR = 439.7 psia = 454.6 °F = 914.27 oR
Relieving temperature of the vessel can be calculated based on deal gas law i.e. Relieving temperature (T 1) = 1601.06 oR = 1141.06 °F In this case, calculated relieving temperature exceeds MAWT. This indicates the high probability of vessel failure due to rupture before the opening of safety relief valve. In this case, API -521 recommends provision of additional measures like water spray, fire proofing etc. However, it is observed that, this relieving temperature of n- Hexane is calculated based on ideal gas law and thus resulting in high conservative reliving temperature value. As n- Hexane is a hydrocarbon, it does not behave as per the ideal gas law. Hence, a rigorous method can be applied to evaluate relief conditions according to API-521. Method 1: Volume Expansion with Time Increment:
Step 3: Using the generated property table, we estimate the relieving flow rate due to volume expansion. The peak volumetric rate is to be reported as maximum relief rate. Calculation: With the help of above mentioned equation (1), volumetric relieving flow rate is estimated for continuous heat input at 5 MM Btu/hr i.e. 6944.44 Btu / 5 sec.
Step 1: Assuming that there is no change of phase in this method. The critical point of n- Hexane can be considered as initial operating point. With the help of process simulator, this initial point fluid pressure will be increased to relieving pressure of 770 psia. Calculation: Through compression, the pressure of n-Hexane is increased to 770 psia. (Corresponding properties to be noted)
From above table, the peak volumetric rate occurs when the temperature in the vessel reaches 564.99°F as 13668.44 ft 3/hr. Alternative Method 2: Volume Expansion with Temperature Increment With appropriate temperature increment consideration, similar steps as described in Method 1 can be followed to evaluate relief load. www.oswindia.com
Offshore World | 28 | October - November 2014
Features Step 1: Same as method 1 Step 2: This first relieving pressure point will be the starting condition for determining the relief rate. Assume moderate temperature interval and number of increments. Generate a property table at relieving pressure of 770 psia. Calculation: Due to continuous heat input, heat content / enthalpy and in turn temperature of fluid increases. Based on the temperature increment of 7.5 deg F, for 20 increments, upper bound for temperature is specified to generate property table at constant relieving pressure of 660 psia.
The main objectives of this exercise are, to estimate the more realistic relief load and to estimate appropriate size of the PRV orifice. • Sometimes the traditional gas expansion method cannot be used to estimate relief loads, as the relieving temperature calculated by ideal gas law, crosses the maximum allowable temperature for the vessel. In such cases, the more realistic approach of rigorous method can give appropriate solution. • It is observed that both these methods give similar relief load results, if the considered effective increment is the same. • Also the calculation precision can be improved with smaller increment. Points to be Considered for Rigorous Method: • Always, maximum required orifice area is in line with maximum volumetric relief rate. Thus, the peak volumetric flow rate must be considered as the reliving flow rate for the correct estimation of the required orifice area • The quantity of fluid to be relieved during fire depends on the total heat input rate to the vessel under any contingency. It also plays an important role to evaluate relief temperature.
Step 3: Make use of generated property table to estimate relieving flow rate due to volume expansion. The peak volumetric rate is to be reported as maximum relief rate. Calculation: With the help above mentioned equation (1), Volumetric relieving flow rate is estimated for continuous heat input due to fire. However, it is to be noted that for each temperature increment, heat input valve ‘Q’ changes.
Takeaway • The conventional gas expansion method produces conservative results. Whereas, PSV relief load calculated using rigorous method can be significantly smaller and appropriate, resulting in cost saving. • For a single phase fluid, a rigorous evaluation method can be opted to evaluate the relief load with the help of process simulation software. The more appropriate relief load estimation through this method and its corresponding relief orifice area can avoid chattering of a safety valve. • The rigorous method can be extended to multicomponent mixtures. However, based on the component properties, number of relief load peaks will arise. A process engineer must ensure the selection of proper highest volumetric peak as the governing relief load.
From above table, the peak volumetric rate occurs, when the temperature in the vessel reaches 549.5°F as 14522.48 ft 3/hr. Prajakta Joshi Senior Process Engineer Aker Powergas Pvt Ltd Email: Prajakta.Joshi@akersolutions.com Offshore World | 29 | October - November 2014
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Features Clay Analysis
Evaluation of Reactive Clay in Indian Shale Shale formations are composed of clays, feldspars, carbonates, and quartz as major ingredients. Among all the constituents, clays are the most important parameter from an application point of view because of their possibly sensitive nature; they are further categorised as migrating (illite, kaolinite, and chlorite) and reactive (smectite and mixed layers) clays. Smectite is always considered as reactive clay, and it appears in shale as an individual phase or as a component of mixed layer clay. This article outlines the laboratory methods used to measure the concentration of reactive clay minerals in shale and their controlling parameters. The process includes analysis of samples by X-ray Diffraction (XRD), Cation Exchange Capacity (CEC), and Capillary Suction Time (CST) tests. The samples used for the study include shale samples from Indian origin. The data obtained from each method are reported, including the effect of brines for inhibiting clay reactivity.
S
Source rock shale formations have become one of the primary sources for future oil and gas exploration in many parts of the world, including India. However, even though the term shale is often used to describe the unconventional reservoirs that are being exploited today, only a few shales are capable of producing hydrocarbons; productive shale reservoirs would be more accurately defined as organic-rich source rocks, and most of their oil or gas generated has been expulsed over geologic time and trapped in conventional reservoir rocks1. Shale formations are defined as a fine-grained, clastic sedimentary rock having low permeability, containing highly diverse mineralogy, ranging from carbonate-rich formations dominated by calcite, dolomite, and siderite to lesser amounts of aluminosilicates. However, many shale formations are rich in silicates, including quartz, feldspar, and clay minerals, as dominant phases, and carbonates are a minor component. Shale formations with rich clay concentrations should be handled systematically because the interaction between the rock materials and water-based fluids (used during well operations) is an important parameter that affects successful production. The presence of reactive (swelling) clays, such as smectite and/or mixed layer clays, causes a formation to be considered water sensitive. Both qualitative and quantitative measures of shale characteristics can be used to informally classify shale as having high, moderate, or low reactivity. The objective of this approach is to determine the type of tests required to anticipate problems likely to be encountered with reactive clays present in shale. The six shale samples considered in this study were derived from producing wells. X-ray Diffraction (XRD) XRD can be performed on formation cuttings or cores. Preferably, samples are washed with suitable organic solvent and dried before XRD analysis is conducted. XRD is used for the identification of minerals present in shale samples. The sample is crushed and powdered to pass through a 200-micron screen, loaded in a specially designed sample holder, and placed in the instrument. The sample is scanned from a series of angles by X-ray beam. The crystalline structures of
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individual minerals present diffract the X-ray beam, resulting in a XRD pattern for each mineral in the sample. Software identifies the minerals present and determines semi-quantitative amounts of each. Dry sample powder analysis is often supplemented by a clay fraction analysis, which is achieved by separating the clay fraction from the bulk sample. A water dispersion is prepared from the powdered sample. The coarse non-clay portion is allowed to settle, and the clay fraction from the upper layer of the fluid is placed onto a glass slide. The glass slide, along with the clay portion, is dried and analysed by XRD for clay phases. The presence of smectite clays is further enhanced by treating the clay slide with glycol and scanning the slide on the XRD instrument. Because of the limitations of obtaining pure standards and because of the crystalline nature of the samples, XRD provides only semi-quantitative data for the mineralogical composition. The higher the smectite clay content, the more likely the shale will be reactive to swelling. Therefore, XRD data can be used in conjunction with other results when determining treatment options for shale formations with high clay content. Cation Exchange Capacity (CEC) CEC is a measure of the exchangeable cations present in the shale as clays. These exchangeable cations are positively charged ions that neutralise the negatively charged clay particles. Most of the exchangeable ions in shale samples are from the smectite clay. The CEC measurements are expressed as milliequivalents per 100 g (meq/100 g) of clay. Typically, CEC is measured using the API recommended process Methylene Blue Capacity Test2. This test requires one gram of finely ground dried sample be dispersed in water using a small amount of dispersant (diluted sulfuric acid and hydrogen peroxide), which is then boiled gently for few minutes, allowed to cool to room temperature, and titrated with methylene
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Features
Reactive shale with a high smectite content usually has a high CST value. Therefore, CEC is directly proportional to the CST value. In addition, CST can be used to evaluate the effect of saline water on shale dispersion tendencies for specific shale formations. blue solution. The end point is reached when a drop of sample suspension placed on a filter paper results in a faint blue color surrounding the dyed solids. The CEC can be analyzed in a laboratory or at the wellsite with a minimum amount of equipment. The higher the CEC value, the more reactive is the shale. The non-reactive phases (quartz, carbonates, etc.) typically have very low CEC values (≤ 1). Other clays (illite, muscovite, chlorite, and kaolinite) exhibit CEC values better than nonreactive phases but lower than reactive phases. However, reactive clays (smectite and mixed layer) exhibit higher values, depending on their concentration. Capillary Suction Time (CST) Test The Institute of Water Pollution Control in the UK originally used the CST device to measure the time required for a slurry filtrate to travel a given distance on a thick porous filter paper3. This technique is adapted to measure the CST of clay or shale slurries. The CST test studies the filtration characteristics of aqueous systems utilizing the capillary suction pressure of a porous paper to affect filtration. When a suspension is filtered under the influence of this suction pressure, the rate at which filtrate spreads away from the suspension is controlled predominately by the filterability of the suspension. The CST automatically measures the time (in sec) for the filtrate to advance between radially separated electrodes when a fixed area of special filter paper is exposed to the suspension. A small amount of sample is mixed with the desired quantity of water or brine in a small commercial blender cup, and the mixture is used for the test. Time is measured using a stop watch. Reactive shale with a high smectite content usually has a high CST value. Therefore, CEC is directly proportional to the CST value. In addition, CST can be used to evaluate the effect of saline water on shale dispersion tendencies for specific shale formations. A study was conducted to measure the effect of deionized (DI) and saline water of different concentrations on the reactive nature of clays. Samples Taken for Study Six subterranean shale formation samples from Indian origin were studied for mineralogy by XRD, and the presence of swelling clay characteristics were studied by CEC and CST tests. All samples were taken from producing wells. The results showed a correlation with the presence of swelling (reactive) and non-swelling clays. Samples not containing swelling clays showed small CEC values and a minimum response to CST. All samples were treated and analysed using similar processes to help avoid errors. Results of XRD Analysis The samples were scanned for XRD study (Table 1). XRD patterns were generated for six samples, and data were analyzed using library data from the International
Center for Diffraction Data (ICDD). None of the samples were observed to have an individual smectite phase. However, smectite was observed as a component of the mixed layer clay, along with illite. Carbonate phases were observed in all samples, except Sample 6, which was dominated by aluminosilicates. Moderate carbonate concentrations (< 20%) were observed in Samples 1 and 4, and Samples 2, 3, and 5 were observed to contain high carbonates. Table 1: XRD Analysis of Shale Samples 1 through 6 Phases
Shale 1 Shale 2 Shale 3
Shale 4 Shale 5 Shale 6
Quartz (%)
39
10
30
43
21
19
Calcite (%)
11
79
11
12
49
—
Dolomite (%)
7
2
21
—
—
—
Na-feldspar (%) 11
4
6
9
8
2
K-feldspar (%)
1
Trace
2
4
4
—
Pyrite (%)
2
Trace
2
—
—
4
Illite (%)
23
4
23
17
8
14
Chlorite (%)
6
1
5
5
3
—
Kaolinite (%)
—
—
—
—
—
46
Illite-Smectite — Mixed Layer
—
—
10
7
15
Results of CEC Analysis The samples presented different CEC values (Table 2) in accordance with the concentration of swelling clay in the samples. Samples 1, 2, and 3 displayed very low CEC values because of the absence of swelling (reactive) clays. Samples 4, 5, and 6 were observed with some CEC value because of the presence of smectite as part of the mixed layer clay. Table 2: CEC Values of Shale Samples 1 through 6 Parameter
Shale 1 Shale 2 Shale 3 Shale 4 Shale 5 Shale 6
CEC (meq/100 g) 2
1
2
5
4
6
Results of CST Analysis The samples with the presence of reactive clay were observed to have higher CST values when treated with DI water (Table 3). Results were also tabulated for change (decrease) in CST values when the samples were treated with various saline solutions (Figure 1). The study showed that (among the solutions tested) the best control in CST values was obtained with a 3% potassium chloride (KCl) solution. The KCl solution at a 7% concentration also helped to further decrease the CST values; however, from a commercial feasibility viewpoint, the 3% KCl solution was more acceptable for field application. The CST values in Table 3 were determined as an average of three readings. Samples 1, 2, and 3 were not
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Features
The integrated study of different parameters can reveal the nature of reactive clay in shale samples so that the proper assessment and treatment of a shale formation can be determined, enabling the use of drilling or fracturing processes.
observed to contain any smectite or mixed layer phase, but some CST values were observed in the samples. This might be a result of the presence of illite, which was also determined to be controlled by the salt solutions. Table 3: CST Values (in sec) of Shale Samples 1 through 6 Parameter
Shale 1 Shale 2 Shale 3 Shale 4 Shale 5 Shale 6
CST in DI Water
40.2
31.5
39.4
113.0
66.8
144.6
CST in 3% KCl
28.3
28.1
27.6
31.2
29.2
34.0
CST in 7% KCl
27.6
27.4
26.8
30.6
28.4
33.8
CST in 5% NH4Cl
31.2
30.6
28.4
31.5
29.6
34.3
CST in 3% NaCl
36.7
30.9
33.4
39.3
37.6
40.7
CST in 1.5% KCl + 32.7 1.5% NaCl
29.4
31.6
35.5
34.8
35.1
CST in 2% KCl + 29.7 1% NaCl
28.8
28.3
32.0
30.4
34.1
• CEC and CST tests are directly proportional parameters to the reactive clay (smectite or mixed layer) concentration in shale, and this can be controlled using saline water. • Migrating clays (illite, kaolinite, and chlorite) show some sensitivity toward CST values, which also can be regulated using saline water. • A KCl (3 and 7%) solution in water was determined to be the most suitable for controlling reactive clay, though other types of saline waters or saline waters with mixtures of salts also can be used, depending on commercial and technical parameters. • A minor development in CST value was observed with the 7% KCl solution compared to the 3% solution. From a commercial viewpoint, 3% KCl brine was recommended. References: 1. Dusterhoft, R., Williams, K., Kumar, A., and Croy, M. 2013. Understanding Complex Source Rock Petroleum Systems to Achieve Success in Shale Developments. Paper SPE 164271 presented at the SPE Middle East Oil and Gas Show and Conference, Manama, Bahrain, 10–13 March. http://dx.doi.org/10.2118/167271-MS. 2. Methylene Blue Test for Drill Solids and Commercial Bentonites, in API RP 13I, Laboratory Testing for Drilling Fluids and ISO 10416:2002, seventh edition. 2004. Washington, DC: API. 3. Wilcox, R.D., Fisk, J.V., and Corbett, G.E. Filtration Method Characterizes Dispersive Properties of Shales. SPE Drilling Engineering 2 (2): 149–158. (This article was published in June July 2014 issue of Offshore World.)
Figure 1: Change in CST values (in sec) before and after treatment with salt solutions.
Conclusion The integrated study of different parameters can reveal the nature of reactive clay in shale samples so that the proper assessment and treatment of a shale formation can be determined, enabling the use of drilling or fracturing processes. The quantitative and semi-quantitative methods recommended in this study can be used in combination to interpret and understand the chemistry of a shale formation, and proper classification can be used to categorize the reactivity and anticipate the potential instability mechanism with fluids. The study infers the following: • The reactive nature of clay samples can be measured by CEC and CST tests. These are simple tests and can be performed at any location. www.oswindia.com
Jajati Nanda Sr Scientist Halliburton Technology E-mail: jajati.nanda@halliburton.com Anil Patil Sr Scientist Halliburton Technology E-mail: anil.patil@halliburton.com Jyoti Waikar Sr Lab Professional Halliburton Technology E-mail: jyoti.waikar@halliburton.com
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Features Resid Conversion Technology
Slurry Phase Hydrocracking: Bottoms Upgrading for Todayâ&#x20AC;&#x2122;s Market The article focuses on the significance of resid processing methods which has emerged as a big concern for many refiners as they struggle to improve product qualities and refinery margins simultaneously while dealing with their large residuum pool. The authors share insights into the Residuum Landscape and advocates on â&#x20AC;&#x2DC;Slurry Phase Hydrocarckingâ&#x20AC;&#x2122; which has not enjoyed widespread acceptance as the technology as choice for resid upgrading.
I
In the face of high crude oil prices, low natural gas prices, and ever increasing product quality regulations, refiners are presented with an unprecedented situation of improving margins by re-evaluating their resid processing options. The ability to reliably eliminate fuel oil production, maximise high quality distillate yields, and achieve almost complete conversion to high value transportation fuels, is essential for sustaining the value of installed assets in the years to come. In its simplest form, refining is a process of changing the carbon to hydrogen ratio of naturally occurring crude oils. At a molecular level, the operation of all refineries in the world is essentially targeted at converting low hydrogen to carbon ratio feedstocks into high hydrogen to carbon ratio transportation fuels. Changing the H/C (Hydrogen/Carbon) ratio between feedstocks and products can only be accomplished through the rejection of carbon molecules or the addition of hydrogen molecules. Carbon rejection is favoured by low crude prices and high hydrogen prices. Under these conditions it is more economical to reject the residuum as petroleum coke, while producing the required transport fuel volumes by incremental crude oil processing. Conversely, hydrogen addition is favored by high crude prices and low hydrogen prices, when it is more economical to upgrade nearly every molecule of residuum to transport fuels, while also maximising transport fuels production from the base crude capacity. In the United States, shale gas produc tion has had a dramatically
reduced the price of natural gas, relative to crude oil, on a comparable energy basis. This provides a relatively low cost source of hydrogen in many geographical regions. Converting inexpensive hydrogen into high value liquid transportation fuels by hydrogen addition to low H/C ratio feedstocks provides a good economic return. Economic analysis clearly points to a transition from carbon rejection to hydrogen addition at USD 50-60/barrel crude, even when considering natural gas prices of USD 10/ MMBTU. Lower natural gas prices provide an even more significant tailwind to hydrogen addition economics. As the new gas production techniques spread to other parts of the world, projections are that hydrogen addition economics will remain favored for many years to. Another significant fac tor in bottoms upgrading economics is the problem of stranded streams. Many refineries are littered with low value streams that must be blended off, disposed or sold at loss in order to accommodate processing equipment limitations from a different era. The bulk of operating refineries around the world have little or no residuum processing capability and produce large volumes of high sulfur fuel oil and bunker fuel. Falling demand for these undesirable products will continue into the future and already negative margins for these streams will only get worse. Regulatory pressures on residuum outlets such as marine bunker fuels are expected to worsen in the future. As world governments move towards cleaner
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Features
bunker fuels, refiners will be forced to find new ways to deal with their large residuum pool. It is a task that is becoming more pressing as oil producers bring to market increasing amounts of heavy crudes, which cost less, but feature substantial increase in resid content. While shale oil production has provided a temporary respite from declining average API and rising sulfur contents, most projections do not expect shale oil production increases to offset the increasingly heavy sources of crude oil production from new discoveries and reserve development. Not only refinery products but also by-products must be considered when evaluating bottoms upgrading process technology. The market for coke from delayed cokers is highly dependent on availability of local outlets for the material, such as power plants. An abundance of coke on the market creates prices that only marginally cover costs or are negative. Combined with the economic considerations are the environmental considerations of burning or disposing of this low H/C material. On the product side of the economic equation, the gasoline to distillate ratio continues to move in favour of distillate on a worldwide basis. Even
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in markets where Fluid Catalytic Cracking (FCC) units are the primar y conversion process and gasoline the predominant transpor tation fuel, rising worldwide demand is driving investments aimed at maximising production of high cetane, ultra low sulfur diesel. The rising D/G (Diesel/ Gasoline) ratio is forecast to continue, with most of the incremental i n c re a s e i n t r a n s p o r t a t i o n f u e l v o l u m e f o r f u t u re y e a r s c o m i n g from distillate. This is an important consideration for refiners, when making long-term, high CAPEX investment decisions. Current economics clearly point to hydrogen addition as opposed to carbon rejection especially for increased distillate production. Today, the market imposed challenge to refiners is to find a hydrogen addition based resid conversion technology which supports the strong economics of near complete conversion, high selectivity towards diesel, Euro V quality and high operating reliability â&#x20AC;&#x201C; all at a reasonable capital investment and strong ROI. A convincing case for slurry bed hydrocracking as the technology choice for todayâ&#x20AC;&#x2122;s market conditions will be laid out in this paper.
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Features The Residuum Landscape Residuum oils can be broadly classified by their contaminant metal (Ni + V) and Conradson Carbon Residue (CCR) content. These two parameters broadly define the suitability and type of conversion technology which can be applied to these heavy oils.
More recently, ebullated bed hydrocracking technology has been the choice for hydrogen addition to residue with higher levels of metals and CCR. Conversion is higher than prior technologies but still limited to less than 80 per cent conversion and in some cases, significantly less. The nature of the e-bed conversion process creates an unstable asphaltene phase which usually limits overall conversion by causing severe fouling in downstream equipment. Introducing aromatic solvents and high recycle rates can help maintain asphaltene solubility and reduce fouling but these solutions have a cost and there is still an upper limit on the level of asphaltene conversion which can be achieved. Slurry phase hydrocracking offers the greatest potential for a robust residue conversion technology which encompasses the entire residue landscape. Only coking is as immune to high levels of CCR or metals content in the feed and, being a hydrogen addition process, slurry hydrocracking has the advantage over coking of ne near complete conversion of the residuum to high value products. One such slurr y phase technology is Veba Combi Cracking ( VCC™), a commercially proven bottoms upgrading technology suitable for converting 95 wt% of residues into high quality distillates.
Fixed bed hydroprocessing is suitable for processing atmospheric or vacuum residue with modest amounts of metals and CCR and mainly for desulfurisation rather than conversion. Conversion is typically 15-20 per cent and further conversion of the products in other units is necessary. Nonetheless, operating pressures are high, increasing investment costs and operating costs can be high as well due to catalyst deactivation from metals and coke. Resid FCC (RFCC) is a seemingly attractive way to convert resid with no unconver ted product to deal with. Unfor tunately, the more hydrogen deficient the feedstock the more of it forms coke on catalyst. This sets a limit on the amount or heaviness of the residue processed in the RFCC while keeping regenerator temperatures at an acceptable level. Catalyst coolers and other methods of heat removal can improve the range of feedstock processing possible but RFCC is still very limited.
VCC™: Veba Combi Cracking The origin of slurry phase hydrocracking and the VCC™ process dates back to 1913, when Freidrich Berguis was awarded his first patents for the process of liquefying coal. The 1931 Nobel laureate had demonstrated that liquid products can be produced by simply subjecting coal to a high enough temperature and hydrogen pressure.Using these principles, 12 commercial units were built and operated in Germany between 1927 and 1945, producing about 100,000 BPSD of transportation fuels from coal and coal tar. After WWII, several of these units were dismantled and sent to Eastern block countries. The remaining units, including the six operating trains at Gelsenkirchen, were converted to 10,000 BPSD trains for processing refinery vacuum residues. The first true VCC™ units were developed in the 1950’s when an integrated second stage fixed bed reactor was added to the slurry phase reactor. It was realised that mild hydrofinishing of the slurry phase products could
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Features VCC™ Process Flow
result in higher quality distillate. This integrally coupled combination of slurry phase hydrocracker and trickle bed hydrofinisher was the origin of the VCC™ process as it is known today. These original VCC™ units operated on residues until 1967 when very low crude oil prices and the end of government subsidies forced the units to be shutdown and subsequently dismantled. Low crude oil prices make it uneconomic to add hydrogen to residue, in particular for this period when outlets for residue, such as fuel oil, existed. VCC™ technology went dormant for a period until viable economics would once again surface. The trigger for resurrection of VCC™ was the hike in crude oil prices resulting from the oil embargo of the 1970’s. Economics of hydrogen addition and high conversion of residues turned positive and Veba Oel constructed a 3500 BPD in Bottrop, which started up in 1981. In addition, 200, 3.5 and 1 BPD pilot plants were built for developing the technology. Over its operating period, significant improvements were made to the process through equipment design modifications and operational adjustments. Two units were licensed by Veba to utilise VCC™ technology, but, once again, oil prices fell to levels which would not support project economics. Bottrop was decommissioned and shutdown in 2001 after a period of sustained low oil prices.
Slurry Phase Hydrocracking While slurry phase hydrocracking has been reliably practiced for several decades, it has not enjoyed widespread acceptance as the technology of choice for resid upgrading. Even with its strengths of high asphaltene conversion and distillate selec tivit y, the specific set of economics supporting VCC was elusive until recently. Higher hydrogen consumption and CAPEX compared to alternative resid conversion technologies was not economically justified without sustained higher crude and product prices. The appropriateness of any technology choice must be weighed against the prevalent market conditions, and its relevance is deeply rooted in the principles of molecule management. Embedded in this approach is the core belief that refining margins are maximised by selectively maximising the value of every molecule in naturally occurring crude oils in every stage of
Following BP’s acquisition of Veba and a rise in crude oil prices from increasing market demand rather than exogenous events, VCC™ was added to BP’s Vision 2030 portfolio and the BP Advanced Refining Program. In 2008 a new 1 BPD VCC™ pilot plant was designed, built and commissioned at BP’s research facilities in Naperville, USA. In 2010, BP and KBR agreed to a marketing, licensing and engineering alliance to promote the technology. www.oswindia.com
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VCC™ Product Properties
Features processing. Vacuum residues can be broadly classified by SARA analysis (Saturates, Aromatics, Resins and Asphaltenes). These properties set the severity of operation (pressure and temperature), hydrogen uptake, and capital investment required to convert the material. Since asphaltenes are the most hydrogen deficient part of the resid and contain virtually all the impurities, the decision to convert them or remove them can be complex. 1. Will crude oil prices remain high? 2. Are outlets for byproducts, such as pet coke or fuel oil, available? 3. Is hydrogen inexpensive relative to crude? 4. Are markets for high quality distillate products growing? The economics of not upgrading, partially upgrading or fully upgrading high C/H molecules is substantially influenced by: crude price, natural gas price, and capital investment. Historical low crude oil prices, high natural gas prices, and until recently, an acceptable margin for fuel oil relative to lighter products all had an inhibiting effect on the value of upgrading asphaltene molecules. It was both economical and convenient to discard these molecules as coke or as unconverted residual fuel oil. While slurry hydrocracking technology was sound, the market and regulatory landscape did not support the additional capital and operating cost to bring it to commercial application. The past decade has seen a shift in the market dynamics affecting residue upgrading – crude oil prices have been sustainably higher, natural gas prices are lower, the market for high quality distillate is strong and growing and there is a shrinking market for fuel oil and petroleum coke. Conversion of asphaltenic molecules to lighter products can now be economically justified. Slurry phase hydrocracking is the preferred choice for these new market conditions and specifically VCC™ since it has been developed through decades of innovation.
Conver ting inexpensive hydrogen into high value liquid transportation fuels by hydrogen addition to low H/C ratio feedstocks provides a good economic return. Economic analysis clearly points to a transition from carbon rejection to hydrogen addition at USD 50-60/barrel crude, even when considering natural gas prices of USD 10/MMBTU. A comparison of the net present value (NPV) of three technology routes derived from upgrading a refinery residue as a function of bench mark crude price shows a remarkable trend in favor of slurry phase hydrocracking. Both the economic and regulatory trends are heavily weighted in favor of VCC™, and the current and future market conditions are aligned with the inherent features of this technology. The economic evaluation for one North American refinery clearly shows that the net present value of the ebullated bed process exceeds that of the delayed coker at a bench mark crude price of $85/bbl. This is primarily because of the lower conversion of e-bed, larger volume of lower value unconverted residuum, and the production of aromatic distillate products that need retreatment. On the other hand, the net present value of VCC™ exceeds that of the delayed coker at a bench mark crude price of $50/bbl, making it the clear choice for hydrogen addition technology. Reliability The value of any technology can only be extracted if reliable long term operations can be sustained. In the case of VCC™, this reliability can only be achieved if high asphaltenes conversion can be accomplished without fouling the unit. A molecular evaluation of residuum will reveal that the asphaltenes are held in solution by the aromaticity of the solvent phase.
Comparison of 1st Stage Yields
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Features Th e b a s i c co nve r s i o n c h e m i s t r y f o r s l u rr y p h a s e hyd ro c ra c ki n g i s essentially thermal in nature and relatively similar to that seen in other carbon rejection processes. The condensation chemistry associated with these cracked molecules, which would normally lead to coke formation, is interrupted by the high hydrogen partial pressure. Therefore, unlike a typical thermal conversion processes, the reaction system produces a ve r y h i g h l e ve l o f l i g hte r p ro d u c t s w i t h l i t t l e co n d e n s at i o n o r coke formation. As conversion progresses, the side chains that hold asphaltenes in solution are easily cracked causing them to lose solvency, and eventually precipitate. An analogy can be made to the operation of a solvent deasphalting process. In that case, when the asphaltenes are dissolved in a light paraffinic solvent, phase separation occurs, resulting in precipitation as pitch. Unconverted asphaltenes precipitate and adhere to equipment surfaces – the walls of the reactor, piping, heat exchanger, etc. This severe fouling limitation leads other resid hydrocracking technologies to reduce their per pass conversion or to resort to recycle with the addition of a large volume aromatic solvent stream in an attempt to keep these unconverted asphaltenes in solution.
The bulk of operating refineries around the world have little or no residuum processing capability and produce large volumes of high sulfur fuel oil and bunker fuel. Falling demand for these undesirable products will continue into the future and already negative margins for these streams will only get worse. material is key to the technology. Each stage does the job for which it was designed and this eliminates the issues often seen when using catalysts for residue conversion. The reliability of the process has been proven by operating factors that have consistently exceeded 90% over many years of operation. Conclusion Current market and regulatory conditions substantially favor investment in hydrogen addition technologies. Slurry phase hydrocracking in general and VCC™ technology in specific, are ideally positioned to exploit the new market conditions. With VCC™ near complete, once through, distillate selective conversion to high quality finished products can be reliably achieved with high on-stream factors. (This article was published in February March 2014 issue of Offshore World.)
VCC™ technology operates with stability and high conversion in a mode that eliminates fouling. This issue has been researched over several decades dating back to the origins of the technology. Over 1,000 patents and over 2,000 filings were made, covering the entire landscape of catalytic and additive options. These efforts lead to the discovery and commercialisation of a non- catalytic, non-metallic additive which all but eliminates fouling tendencies and allows unprecedented high asphaltene conversion. Asphaltene molecules are adsorbed to the high surface area of the additive where the required residence time is made available for the asphaltenes to continue to crack. The lighter, cracked products are released from the additive surface and the heavier, unconverted asphaltenes, containing all the contaminant metals, remain on the additive. Later, the additive is removed from the process along with the captured unconver ted asphaltenes and any contaminant metals. This chemistr y is possible because of the higher operating pressures of VCC™ which allow the unit to operate in a non-catalytic mode by inhibiting condensation chemistry. This combination of high hydrogen par tial pressure and non-catalytic additive system is unique to VCC™ and is a major reason it has decades of reliable operation at high (>95%), once-though conversion, with no signs of fouling. Hydrogen addition needed to meet final product quality is met by adjusting the trickle bed hydrofinishing conditions. This separation of thermal conversion of residue from the catalytic conversion of converted www.oswindia.com
Offshore World | 38 | October - November 2014
Steve Mayo Director - VCC Technology KBR Technology, Houston E-mail: steve.mayo@kbr.com Mitra Motaghi Business Development Manager KBR Technology, Houston E-mail: mitra.motaghi@kbr.com Rahul Ravi Senior Technical Professional - Process KBR Technology, India E-mail: rahul.ravi@kbr.com
Features Energy Watch
Energy Commodity Prices Move Down Energy Column (Price Review): September - October 2014 Energy commodities showcased price decline across the board in the two-month period of September and October 2014, albeit in varied proportions. Interestingly, in these two months, while European Union allowances (EUA) futures prices fell by least i.e. 0.47 per cent, CER (Carbon Emission Reduction) futures continued its south-bound march by dropping the most amongst energy commodities i.e. by 37.50 per cent (albeit with low price base).
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NYMEX (CME) crude oil (light sweet) futures started the month of September at USD 92.88 per barrel, down by 3.2 per cent from previous months’ close. Weak Chinese manufacturing data prevailed along with stronger dollar pulled oil prices down. Further with oil prices steadily moving down almost through the months of September and October, the opening day’s high of USD 95.89 eventually emerged as the period’s high.
By mid-September, crude oil prices staged some recovery largely helped by bargain hunting from refiners and other commercial buyers. But subsequent release of weaker-than-expected Chinese and US industrial data heightening concerns about global demand for oil kept price under check. Later, oil prices got some support after the OPEC head said that the cartel could cut its output target for next year.
Later, following a session of brief respite largely at the prospect of a cease-fire in eastern Ukraine spurring hopes for stability in the region, oil prices continued to move down. Initially a smaller-than-expected decline in US inventories, and later a weaker-than-expected US jobs report revived fears of less demand for the crude oil. Release of weak macroeconomic data from Asia (poor Chinese import data and more than expected contraction in Japanese economy in second quarter) spurring demand concerns and a stronger dollar kept oil prices under pressure. Further, OPEC reducing its expectations for demand of its own oil added to the bearish sentiments, followed by International Energy Agency cutting its forecast for global oil demand for the third month in a row.
However, oil prices continued to face pressure from a rising dollar and growing crude supplies. By end of the month of September, Reuters survey showed that OPEC output in September was at its highest level in nearly two years, led by Libya as well as Saudi Arabia and other Gulf oil-exporting countries. Also, HSBC’s China Manufacturing PMI stayed unchanged at 50.2 in September from August, indicating sluggish growth in the world’s second-largest economy. As a result, oil prices started the month of October with price decline as well. Oil prices continued to slump as the International Monetary Fund cut its outlook for global growth – feeding concerns about lackluster oil demand. As such IMF
Futures price movement ( September - October 2014)
300
100
280
93
260
86
240
79
220
72
200
NYMEX Heating oil (USd/gal) - LHS
NYMEX Gasoline (USd/gal) - LHS
NYMEX WTI crude oil (USD/barrel)
ICE Rotterdam Monthly Coal (USD/MT)
65
Source: Bloomberg
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Features
Futures price movement (September - October 2014) 0.20
7.00
0.16
6.20
0.12
5.40
0.08
4.60
0.04
3.80 ICE-ECX CERs (Euro/tonne) - LHS
NYMEX Natural gas (USD/mmBtu)
0.00
ICE-ECX EUAs (Euro/tonne)
3.00
Source: Bloomberg
cut its forecast for 2014 global growth to 3.3 per cent from an earlier estimate of 3.4 per cent and projected a 2015 expansion of 3.8 per cent versus an earlier forecast of 4 per cent. Surprise increase in US oil inventories (reported weekly) further added to the bearish sentiments. Significant Libyan production amidst weakening global demand, particularly in Europe and Asia, continued to keep oil prices under pressure. In fact, even positive Chinese trade data and an increase in September crude imports failed to halt falling oil prices.
major energy commodity natural gas futures traded on NYMEX (CME) platform registered a price fall of 4.72 per cent in past two months. Rise in US gas stock levels and weather forecasts especially in October calling for warmer-thannormal temperatures for parts of the US through early November kept prices down. At the fag-end of the month of October, change in forecast of much colder weather moving into the eastern part of US raised expectations of increased gas demand and hence helped some recovery in gas prices.
Later, following a brief respite to falling oil prices from modestly upbeat data on European and Chinese manufacturing in second fortnight of October, the supply glut and petering demand continued to drag oil prices lower. With Goldman Sachs slashing its 2015 forecast for oil prices, crude oil futures at NYMEX stooped down to the two-month low of USD 79.44 on October 27.
Amongst other energy commodities, ICE Rotterdam monthly coal futures prices moved down by 5.33 per cent in the two-month period. Falling demand especially in China for imported coal, combined with plentiful supply and a weak global economy contributed to the fall in coal prices. Moreover, Chinese governmentâ&#x20AC;&#x2122;s deliberation on a quality-based import ban on thermal coal is adding to the pressure on coal prices. Finally in emission segment, flagging growth in the euro zone amidst price fall across energy commodities, kept EUA futures prices traded on ICE-ECX platform under check. Moreover, at a summit on October 23-24, European Council endorsed a binding EU target of a reduction of at least 40 per cent by 2030 compared to 1990 levels - in line with the Commissionâ&#x20AC;&#x2122;s original proposal. Notably amidst continual uncertainty over the future of carbon credit market, CER futures prices (traded on ICE-ECX platform) continued to move down.
Finally at the fag-end of the month of October, the low prices attracted bargain hunting in turn helping oil prices some recovery. Later, oil prices were also boosted from a weekly US supply report that showed an increase in inventories was slightly below expectations. However the recovery in oil prices again remained brief as US Federal Open Market Committee statement, offered an optimistic outlook for the US economy, which along with stronger-than-expected US gross domestic product data helped the strengthening of US dollar. In turn, oil prices moved down. At the end of the month, dollar was also helped especially against Japanese Yen as Bank of Japan shocked global financial markets by expanding its massive stimulus spending. Finally, MCX crude oil futures closed the month at ` 4,931, registering a monthly fall of 13.08 per cent. Finally, NYMEX crude oil futures closed the month of October at USD 80.54 registering a fall in excess of 16 per cent in two-month period of September and October. Like crude oil prices, futures prices of its derivate i.e. heating oil and gasoline (both traded on NYMEX-CME platform) also moved down in the two-month period of September-October. While heating oil futures prices declined by about 12 per cent, gasoline futures prices moved down by about 22 per cent helped by ample gasoline inventory levels in US amidst rise in US oil production. The other www.oswindia.com
(The views expressed by the authors are their personal opinions.) Niteen M Jain Senior Analyst, Department of Research & Strategy Multi Commodity Exchange of India Ltd E-mail: niteen.jain@mcxindia.com Nazir Ahmed Moulvi Senior Analyst, Department of Research & Strategy Multi Commodity Exchange of India Ltd E-mail: nazir.moulvi@mcxindia.com
Offshore World | 40 | October - November 2014
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APAC to Account for 70% of Global Oil Demand by 2020 Rising Economic growth, coupled with a growing populace, Asia-Pacific has been emerged as a huge & growing market for the oil and gas industry and is estimated account for 70 per cent of global oil demand by 2020. In light of these trends, OSEA 2014 International Conference’s Opening Joint Keynote speakers John Westwood, Group Chairman, Douglas-Westwood and Dan K Eberhart, CEO, Canary, are of the view that there will be promising prospects for business opportunities in the AsiaPacific region, and together they share their views with OSEA 2014 on the current and future of the oil and gas landscape.
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The Asia-Pacific is a huge, growing market for the oil and gas industry—from 2000 to 2010, accounting for 56 per cent of the increase in global primary oil demand. The Baker Institute estimates that it will account for 70 per cent of global oil demand from 2010 to 2020.
not only by increasing supplies and their diversity, but by improving energy efficiency. In this, the need for progressive removal of fuel subsidies in countries such as Indonesia is a vital element,” adds Westwood. Asia’s Foray into Foreign Energy Ventures
The region will also be boosted by the development of both onshore and offshore gas markets, driven by growing regional demand and high gas prices in Japan and South Korea. Countries such as China, Indonesia and Australia are developing shale gas and Coal Bed Methane (CBM) projects in the long term, while the offshore market will see Floating Liquefied Natural Gas (FLNG) projects and drilling projects at shallow water gas well and some deepwater areas. As the region relies heavily on imports, this growth in demand is an opportunity for international companies to tap into the burgeoning Asia Pacific market.
“China has been investing tens of billions of dollars per annum in foreign energy ventures, effectively forward buying access to oil & gas supplies – a situation driven by its growing demand. Others meantime are also facing oil production decline – Australia, Brunei, Indonesia and Malaysia were all down last year,” says Westwood. “According to BP, in 2013 total regional production fell 1.7 per cent while consumption increased 1.5 per cent. Meantime, regional gas production increased by 1.1 per cent; however, consumption grew by 2.2 per cent. So yes, expect to see a lot more deal-doing,” adds Westwood.
Pegging Gas to Oil Prices on Industry Growth – Impact on Asia “The impact of low US gas prices is already being felt in Europe with evidence of some large energy user industries planning to locate new build projects in the US. At the same time, the cost of building new LNG plant onshore Australia – a key supplier to Asia – has soared to the point where it has become economically unviable. The country stands to lose USD 97 billion of potential LNG projects to East Africa and North America unless radical cost reduction is applied,” says Westwood. “Furthermore, Russia and China’s USD 400 billion gas deal could possibly also undermine some of Australia’s gas projects. In order to assure its industrial future, the APAC region needs to be taking a very long-term view on energy,
“Asian energy consumption is skyrocketing, and so is their population. There’s really no reason to believe that state-owned companies won’t continue to make deals with foreign oil and gas suppliers. For example, the biggest deal in 2013 was China National Petroleum Corporation (CNPC) paying USD 60 billion as upfront payment for Rosneft of Russia’s crude of 300,000 b/d for the next 25 years. Plus, China Petroleum and Chemical Corporation (Sinopec Group), an NOC, recently established a strategic alliance with Exxon, with a goal of establishing a refinery complex in Eastern China and become a major marketer of petrochemicals throughout China,” says Eberhart. “Japan and Singapore have also made diversified acquisitions. Like China, Singapore is working on initiatives with Exxon, including an expansion on a refinery and petrochemical facility that will be the largest integrated manufacturing site in the world,” adds Eberhart. Opportunities for Non-Oil Producing Regions in Offshore Production
“We should see annual development well numbers exceed 1,600 by 2020 in APAC region, a growth of over 30 per cent over 2013 numbers.“ - John Westwood
“Offshore market in Asia Pacific regions will see large gains in shallow water gas production with Shell and Petronas both having FLNG projects planned. High gas prices in Japan and South Korea will further boost regional activity. This could see shallow water drilling grow 29 per cent over 2013-20. Deepwater gas developments will come mainly from China as China National Offshore Oil Corporation (CNOOC) look to boost production from
Offshore World | 41 | October - November 2014
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news features “Asian energy consumption is skyrocketing, and so is their population. There’s really no reason to believe that stateowned companies won’t continue to make deals with foreign oil and gas suppliers.“ - Dan K Eberhart greenfield projects in order to meet the rapidly growing domestic consumption,” says Westwood. “We expect increasing numbers of development wells to be drilled offshore Asia-Pacific in 2014, with Thailand heading the league table with some 370, followed by China and India each drilling around 200. In all, we should see annual development well numbers exceed 1,600 by 2020, a growth of over 30 per cent over 2013 numbers,” adds Westwood. “Amongst the non-oil producers, Singapore and Korea as the world’s major offshore vessel builders face growing challenges from the on-going development of the Chinese yards and will need to continually review and develop their strategies, focussing more into high value high technology products such as Floating Liquefied Natural Gas (FLNG), and perhaps growing their non-vessel activity – an example has been Korea’s work on LNG modules,” adds Westwood. He adds: Singapore is, I think, a special situation, combining a major commercial centre with a can-do attitude from government plus a great workforce has made it the de-facto hub for the Asia-Pacific offshore industry – which is why my firm has its regional base here. “The biggest hotspots are the South and East China Seas. For National Oil Companies (NOCs), the biggest challenge in those areas is the territorial disputes between neighbouring countries that may be affected the exploration activities in the areas. The South China Sea, for example, is shared among Vietnam, China, Philippines, Taiwan, and others and any exploration activities in this area may be required new arbitration & rules. Of course, it’s not much easier for international oil companies there, which also must navigate the aggressive offshore drilling claims,” says Eberhart. “The growing demand for gas in Myanmar has turned the Bay of Bengal into an another offshore hotspot and international oil companies. There are continuous disputes in that area that will require new arbitration and rules. The role of international oil and gas majors may be important here for exploring and developing Myanmar natural resources, as are opportunities, but the conflicts between nations on the coast claiming oil and gas assets may retard exploration efforts,” adds Eberhart. He adds: Singapore is a good example, because although it is non-oil producing, the country has attracted multi-billion dollar fixed capital investments by major oil companies for its oil refining industry, which is in www.oswindia.com
the top three in the world. The country’s transparent business and mature legal and financial systems have made it very attractive to gas stakeholders. It may be a non-oil producing country, but they’ve made oil refining central to their economy. Myanmar – A Rising Oil & Gas Landmark “After the historic political and economic reform in 2011 and the lifted sanctions in 2012, Myanmar has generated serious interest for international oil E&P majors to invest the country’s rich hydrocarbon potential. International oil majors such as Chevron, ExxonMobil, Shell and Statoil amongst others have alraedy participated in its first offshore bidding round of 19 deepwater and 11 shallow water blocks.” Although the outlook for Myanmar gas production remains uncertain as there is no capacity indication for those offered blocks, but I expect further developments and an upward trend in the gas sector thanks to operators’ confidence based on sound historical performance of Myanmar’s large gas fields such as Shwe, Yadana and Yetagun,” says Westwood. “I think Myanmar could be the game-changer for this region. Not only does it have abundant natural resource potential, but the opening up of its oil and gas sector has generated huge interest internationally. Data from the Myanmar Investment Commission put oil and gas foreign investments at USD 14.372 billion last year,” says Eberhart. “The country has awarded both onshore and offshore exploration tenders to international energy companies, including major players like ConocoPhillips, Shell, and Total,” Eberhart adds. Asia’s Potential for Exploration Activities “Exploration of shale resources in China will require sophisticated multilateral negotiation with Chinese NOCs which will likely result in technology trade agreements and assistance first rather than outright drilling/fracking contracts in the Chinese mainland,” says Eberhart. “In other words, China might take a while. Malaysia might be a better bet: That country has put in substantial efforts to arrest the drop in crude oil production and accelerate natural gas output. Supported by its NOC, the country has been very proactive in improving its fiscal regime to attract foreign investments and expertise,” adds Eberhart.
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- Rakesh Roy
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Environmental protection with a FLIR optical gas imaging camera
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Some industrial, pharmaceutical and petrochemical plants emit gases that can harm the environment and impede the health of company employees and inhabitants of the surrounding area. Environmental protection agencies have the responsibility to make sure that these emissions fall within governmental and international policy guidelines. To help them with that task environmental protection agencies can use an optical gas imaging camera. One of the first European environmental protection agencies to embrace this technology is the Dutch agency DCMR Environmental Protection Agency Rijnmond. “This technology helps us to get a clear view of the real life fugitive emissions by companies within our jurisdiction” explains Rob van Doorn, technical manager of DCMR. “This really is a great tool for agencies such as DMCR to actively and efficiently enforce emission control policies.” Arguably the most important task of the DCMR is to uphold the regulations regarding fugitive gas emissions, as it directly influences the health and quality of life of inhabitants in the surrounding area. According to Van Doorn it was very difficult, however, to monitor fugitive emissions before the purchase of the FLIR GF-Series optical gas imaging camera. “There are calculations and models that can be used to attain a theoretic value for fugitive emission of storage tanks and pipelines and such, but many recent international studies have shown that the real life emission figures are usually much higher than the theoretical value predicted by the formulas. These formulas do not take into account the possibilities that storage facilities might contain broken man holes that do not close properly without any of the company employees noticing or other forms of unnoticed maintenance issues which may cause additional fugitive emissions.” At first Van Doorn hired external consultants to investigate the real life fugitive emissions. “We soon found that this was not an efficient solution in the long term, however. Consultants charge hefty fees for each inspection and with the inspection frequency we wanted to achieve the total of fees would exceed our budget. That is why we decided to look into buying a fugitive gas monitoring tool ourselves.” DCMR Environmental Protection Agency Rijnmond: DCMR is the regional environmental agency operating in Rijnmond, the larger ‘Port of Rotterdam’-area in the Netherlands. Due to the presence of the largest seaport of Europe this area is filled with heavy industry, including refineries, waste incinerators, several waste dumping sites, many large chemical plants and metallurgy plants. All of these plants bring with them a risk of pollution. That is why the DCMR was founded in 1972 in order to improve environmental protection in the Rotterdam-Rijnmond region. It supervises and monitors clean-up programs to minimize the impact of soil pollution, waste disposal and noise. FLIR GF-Series requires little to no training After comparing several techniques Van Doorn and his colleagues opted for a FLIR GF320 optical gas imaging camera. “The external consultants we had hired previously utilized technologies like SOF (solar occultation flux) and DIAL (differential absorption light detection and ranging). Although these techniques are robust and can quantify the emissions these technologies are very expensive to purchase, they are unwieldy, requiring large trucks to carry the equipment, and also complicated to use, requiring a lot of training to be used effectively. In comparison the GF-Series camera is a much more affordable solution. It is also compact,
The FLIR GF320 optical gas detection camera can visualize most hydrocarbons used in the petrochemical industry.
lightweight, portable, and it is very easy to use, requiring very little training.” An optical gas imaging camera is a quick, non-contact measuring instrument that can immediately give the camera operator an overview of the situation. It can also be used in hard-to-access locations, since it can detect small leaks from several meters away and big leaks from hundreds of meters away, and it can also show leaks in moving transport vehicles, such as tanker trucks, but also barges and rail wagons. User friendly The purchase of the FLIR GF320 optical gas imaging camera included a three day training course at the Infrared Training Center (ITC) for the inspectors that were expected to work with the camera. According to Van Doorn the FLIR GF320 optical gas imaging camera is very user friendly. “I was surprised to see that we were able to work quickly and efficiently with the camera, attaining a high level of accuracy, immediately after the three day training course. And perhaps that three day course was not even necessary, to be completely honest. The camera is so easy to use that you can probably even use it to ascertain whether or not a leak is present without any training whatsoever. You could say that it is rather self-explanatory.” Infrared absorption The FLIR GF320 optical gas imaging camera contains a cooled Indium Antimonide (InSb) infrared detector that produces thermal images with a resolution of 320 x 240 pixels at a thermal sensitivity 25 mK (0,025 °C). The gas visualization functionality of the FLIR GF-Series optical gas imaging cameras is based on the absorption of electromagnetic radiation in the infrared wavelength by gases. Most gases absorb infrared radiation at specific wavelengths. In other words, there are infrared wavelengths where the gas is essentially opaque. All FLIR GF-Series optical gas imaging cameras contain a spectral filter, a focal plane array and an optical system that are all specifically tuned to very narrow spectral ranges where certain gases absorb infrared radiation. With the gas absorbing the infrared radiation
Offshore World | 45 | October - November 2014
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DCMR Environmental Protection Agency Rijnmond’s technical manager Rob van Doorn demonstrates the use of the FLIR GF320 optical gas imaging camera.
Optical gas imaging cameras can detect small leaks from several meters and big leaks from distances of hundreds of meters.
and effectively blocking the radiation coming from the objects behind the leak, a gas leak will show up as either a black or a white plume in the thermal image, depending on whether the user opted for the ‘white hot’ or the ‘black hot’ settings.
camera automatically embeds GPS location data in the video recordings. With the date, time and GPS data embedded in the video’s metadata it is much easier to keep your video archive tidy. All FLIR GF-Series optical gas imaging cameras are also ergonomically designed with a rotating handle, direct access buttons and a tiltable viewfinder and LCD screen. With a weight of 2.4 kg the FLIR GF320 optical gas imaging camera is also relatively light and compact in comparison to other gas detection tools. Designed from the end-user’s perspective, the FLIR GF320 optical gas imaging camera offers advanced ergonomics to improve worker safety and individual performance, not to mention reducing back and arm strain.
The FLIR GF320 optical gas imaging camera is tuned to the electromagnetic wavelengths between 3.2 and 3.4 μm, which is the section of the electromagnetic spectrum where most hydrocarbons absorb infrared radiation. Although the FLIR GF320 optical gas imaging camera will likely be able to detect a multitude of different gases it has been laboratory tested against 19 gases that are commonly found in the petrochemical industries: • Benzene • Butane • Ethane • Ethylbenzene • Ethylene • Heptane • Hexane • Isoprene • Methyl Ethyl Ketone (MEK)
• Methane • Methanol • MIBK • Octane • Pentane • 1-Pentane • Propane • Propylene • Toluene
These chemical compounds and gases are normally invisible to the naked eye, but due to the infrared absorption properties of these gases the FLIR GF320 optical gas imaging camera allows the inspector to see gas leaks as moving smoke-like plumes in the real time thermal video footage displayed in the eyepiece or on the LCD screen of the camera. Ergonomic design Apart from real time visualization the FLIR GF320 optical gas imaging camera is also capable of recording both visual light video and thermal video footage. “This is very important, because the moving smoke like plume shows up much more clearly in a video than in a still picture”, explains Van Doorn. “So for the reporting of leaks the ability to record video is crucial.” During an inspection the operator often makes many video recordings. Keeping your video archive tidy can be a challenge due to the sheer quantity of recorded videos. To make this task a little bit easier the FLIR GF320 optical gas imaging www.oswindia.com
After using the FLIR GF320 optical gas imaging camera for a few months Van Doorn was pleasantly surprised by the accuracy with which he could detect leaks using the camera. “The camera is much more sensitive than we had anticipated, especially when operating in the high sensitivity mode”, says Van Doorn. “We were surprised to find that even very small leaks are clearly visible with the camera, even when you are inspecting from a distance.” High Sensitivity Mode The High Sensitivity Mode (HSM) is an additional special feature included in all GF-Series optical gas imaging cameras. It is an image subtraction video processing technique that effectively enhances the thermal sensitivity of the camera. The HSM feature subtracts a percentage of individual pixel signals from frames in the video stream from the subsequent frames, thus enhancing the differences between frames, which make leaks stand out more clearly in the resulting images. Preventing future emissions “We’ve been working with the camera for some time now and it has allowed us to detect leaks and ascertain regulation transgressions that would have remained undetected without the camera. Storage tanks that we always supposed to be in good working order and well maintained turned out to be leaking quite badly. This allowed us to take action in order to prevent further emissions. So I would definitively say that it has already proved to be worthwhile.” For more information, please contact: FLIR SYSTEMS INDIA PVT LTD. 1111, D-mall, Netaji subhash place, Pitampura, New Delhi – 110034 Tel.: +91-11-45603555, Fax:+91-11-47212006, E-mail: flirindia@flir.com.hk
Offshore World | 46 | October - November 2014
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Oil and Gas â&#x20AC;&#x201C; Downhole Completions Sandvik Control Lines and Chemical Injection Lines
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Well completion is the interface between the reservoir and surface production. Completions usually form a major part of the well control envelope and barrier between the reservoir and surface. Control lines essentially are hydraulic steel tubes that help control the opening and closing of a Sub Surface Safety Valve (SSSV). Since the SSSV operates on a fail-safe condition, the control line contains pressurised fluid for its entire time of operation. There are 3 grades of steel that essentially can be used for making the control line tubing, i.e SS316L, Super Duplex SAF 2507 and Alloy 825. Since the control lines are run down the well annulus, they may be subject to various well conditions of pressure, temperature and sourness. In order to impart physical protection, control lines are often encapsulated with various polymers / plastics. The selection of encapsulation too is dependent on the well conditions.
SEAMLESS CONTROL LINES Seamless control lines undoubtedly are a safer option and offer better reliability and ensure safety even at higher operating pressures and temperatures. Pressure however is just one aspect. Seamless tubing can provide better ID cleanliness class (NAS Class 6) and it is a safer material to operate the safety valves SSSV, once it is free from solid particles that can clog the lines and therefore the safety valve.
A control line essentially should have following characteristics: 1. Sustain high pressures repeatedly (depending on SSSV operation) 2. Steel that resists corrosion in the well service 3. Encapsulation that imparts protection and makes it robust Sandvik Materials Technology is a world leading producer of control line tubing. With an established manufacturing setup in Arnprior, Canada and a warehouse in Houston. Sandvik can cater to a variety of requirements globally. A unique standpoint for Sandvik is its INTEGRATED (Steel melt to finished tube). This makes it easy to control the quality of the tube and ensure full traceability to the heat and Lot number of the melt.
Another point of importance is connections between the tubing and fittings. When connecting the tube to the connector, in the safety valves and chemical injection mandrill, a seamless tube offers the same cross sectional uniformity and hardness. The tight tolerance in the OD guarantees no leaking points, which is of extreme importance for this applications. SUPER DUPLEX CONTROL LINES As we see more technological advances and forays into deep water explorations, the necessity for equipment that sustains tough operation conditions is equally important. Super Duplex is a grade of steel that has very high strength and can sustain very high pressures for the same size of control lines that an Alloy 825 or and SS316L would be able to sustain. Super Duplex as a grade consists of 2 phases (Austenitic and Ferritic) and has a moderate resistance to H2S. It however is very resistant to sea water. It also has high resistance levels to pitting corrosion, crevice corrosion and Stress Corrosion Cracking (SCC) in chloride containing environments. Karan Jain Technical Marketing Manager - Oil and Gas, India Sandvik Materials Technology Email: karan.jain@sandvik.com
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india news Panel on Manufacturing in Petroleum Sector to ONGC to Raise Production in Western Offshore Fields Work out Incentives for Industry New Delhi: Oil and Natural Gas Corp, India’s biggest energy explorer, plans to New Delhi: The petroleum ministry has said its committee on boosting local manufacturing in the oil and gas sector will work out suitable incentives for the industry, after identifying reasons for low investment levels. The move is a part of the ‘Make in India’ campaign launched by Prime Minister Narendra Modi. Rajive Kumar, Additional Secretary, MoPNG
The committee, headed by the Rajive Kumar, Additional Secretary, MoPNG, will assess reasons for relatively lower levels of investment in the manufacturing sector in the oil and gas industry, compulsions for imports and market potential for fabricated materials. The committee will review the current status of infrastructure, related policies, skills and raw material requirement apart from steps taken by other countries to promote local manufacturing.
The project is designed to carry forward the success of the previous two phases of redevelopment project and give a new lease of life to the giant field, which has been in production for over three decades. The project comprises drilling 36 new wells and 34 sidetrack wells, and facilities. The facilities under the project are scheduled to be installed by April, 2017. Drilling of wells and the overall project completion is scheduled for March, 2019. It “aims to further develop of L-II, S1 and Basal Clastic reservoirs along with the major L-III reservoir and integrating the required inputs,” the statement said.
Kelkar Panel Opposes Revenue-Sharing Model for Deepwater Discoveries
GSPC Demands Higher Gas Price Ahmedabad: Gujarat State Petroleum Corporation (GSPC), the Gujarat government firm, has shown its dissatisfaction over the new domestic gas pricing set by the India government by saying it cannot be forced to sell fuel at a rate which is less than the cost of production. After Union government decision to raise natural gas prices to USD 5.61 per unit from USD 4.2, Gujarat State Petroleum Corp (GSPC) shot off a letter to the Oil Ministry, demanding ‘market determined price’ for its ready-to-produce Deen Dayal West (DDW) fields in Bay of Bengal. The firm owned and run by the Gujarat government had last year discovered a market formula that gives a price of about USD 10.5 per million British thermal unit at current oil rate of USD 80 per barrel. India is not endowed with rich natural resources and most of the reserves are in ultra-deep water, deepsea, and High Pressure-High Temperature (HPHT) areas which requires investment of substantial capital to develop the gas fields irrespective of time of discoveries. Company, it said, “Invested substantial capital in these areas with the assumption of having freedom for marketing the natural gas at market determined price which was the essential and most important feature of NELP contracts”. GSPC had won the Block KG-OSN-2001/3 in the third round of auctions under New Exploration Licensing Policy (NELP). DDW field in the block was discovered in 2005-06.
GAIL Inks Pact with Azerbaijan’s State Oil Firm New Delhi: State gas utility GAIL India Ltd has signed an initial agreement with State Oil Company of Republic of Azerbaijan (SOCAR) for jointly pursuing LNG opportunities. Under the Memorandum of Understanding, GAIL and SOCAR intend to jointly pursue LNG opportunities through capacity booking, LNG procurement and promotion of LNG projects globally. Both companies shall also cooperate in optimisation of LNG marketing, sourcing and shipping requirements. In addition, GAIL and SOCAR will pursue business opportunities in upstream assets across the world and joint investment in petrochemical projects. www.oswindia.com
invest ` 106 billion for raising production from its western offshore fields. ONGC board has approved third phase of redevelopment of its prime Mumbai High South oil and gas field at a cost of ` 60.69 billion and integrated development of Mukta, Bassein and Panna formations at an investment of ` 46.20 billion. The Mumbai High South Redevelopment (Phase-III) will lead to incremental gain of 7.547 million ton crude oil and 3.864 billion cubic meter gas by 2030, the company said in a statement.
New Delhi: An expert panel headed by Vijay Kelkar has recommended the current production sharing regime for oil and gas exploration over the revenue-sharing model that is being considered for the next round of auction. The 10-member Committee, headed by former petroleum and finance secretary Kelkar, said the Production Sharing Contract (PSC) regime was more suited for Indian conditions rather than the revenue-sharing model based on the Rangarajan panel which was adopted by the previous UPA government. Under the present regime, oil companies can recover all costs - of successful and unsuccessful wells - from sales of oil and gas before sharing profit with the government. “The Committee has reservations against accepting the ‘biddable’ Revenue Sharing Contract (RSC) model due to the inherently misaligned risk-return structure which leads either (i) to lower levels of production due to resultant reduced exploration efforts and lower recovery ratio, or (ii) to high windfall gains to operators encouraging contract instability due to political economy factors,” it said. It suggested two fiscal regimes - PSC linked to investment multiple with modified contract administration including self-certification of costs by the contractors, or PSC with biddable supernormal profits tax. For boosting local production of oil and gas, the Kelkar committee has suggested improving contract stability and administration as also maintaining contract stability and sanctity and prevent retrospective contract changes. It also favoured contract extension for perpetuity or up to the end of the economic life of the asset and empowering boards of state-owned oil companies for approving equity participation in fields they had got from the government on nomination basis. “Increasing oil production from existing mature fields would require access to advanced global expertise and technologies. Hence, the government should empower board of national oil companies to offer equity participation by foreign and domestic private companies with access to such technologies,” it said.
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india news State Run Oil Marketing COs Seek Flexible Deals to Tap New Markets
S anjiv Singh, Head of Refineries, IOCL
New Delhi: PSU refiners, who account for about two-thirds of the country’s oil processing capacity, are seeking more flexibility in import contracts as they look to tap new sources of supply flushed out by the US shale boom. India, the world’s fourth-biggest oil consumer with refining capacity of 4.3 million barrels per day, imports 80 per cent of its crude needs and has traditionally relied on the Middle East for heavy oil supplies and West Africa for lighter, sweet crude.
A push to include both fixed and optional volumes in contracts would allow refiners to fill some of their needs from cheaper spot cargoes now on offer from suppliers such as Algeria, Latin America and Canada as US demand has dwindled. “It’s a buyer’s market now,” said Sanjiv Singh, Head of Refineries, Indian Oil Corp, the country’s biggest refiner.
Govt Making Efforts to Reduce Import Bill New Delhi: The government has turned to oil diplomacy to secure better fuel supply contracts, a move that industry officials say can cut India’s import bill by at least ` 10,000 crore.
Dharmendra Pradhan, Minister of State for Petroleum and Natural Gas
The initiative comes at a time when the members of the Organization of the Petroleum Exporting Countries (OPEC) are battling for market share amid competition from new energy suppliers. Gulf countries too have shown heightened interest in investing in India.
India depends heavily on term contracts with Middle East countries, which announce a monthly official selling price. Oil industry executives and officials say the country will save about ` 9,000 crore a year for every USD 1 reduction in price. Recently, Saudi Arabia raised the price for Asian buyers, but cut it for the US, where the shale revolution has lifted oil output to the highest in three decadesIndia feels that as one of the largest importers from the Middle-east it too is entitled to such concessions. OPEC heavyweights like Saudi Arabia are fighting to protect their market share, and have resisted calls for a supply cut even after crude prices slumped 30 per cent. Oil Minister Dharmendra Pradhan has recently been to Saudi Arabia, OPEC’s biggest supplier. “Price of crude oil is not the only issue. There are several investment proposals as many oil producers have shown interest in India,” says Pradhan, but did not elaborate saying that these were sensitive negotiations.
OVL Eyes Stake in Tullow Oil’s Africa Assets Mumbai: ONGC Videsh Ltd (OVL), the overseas investment arm of Oil and Natural Gas Corp (ONGC), is looking to buy a stake in the assets of Africa-focused exploration company Tullow Oil Plc. The company is keen to buy a stake in the African properties of Tullow that includes assets in Ghana and Kenya. The state-run oil company also wants to acquire assets in stable geographies like North America, Canada and Mexico, and expand its presence in Africa. OVL also aims to get 400,000 barrels per day (bpd) of crude from its overseas assets by 2018, compared with about 167,000 bpd produced from overseas holdings in the fiscal year to March 2014.
India to Receive its Biggest LNG Cargo ahead of US Shipments New Delhi: India will receive its biggest shipment of liquefied natural gas (LNG) by ship end of the yaer as it prepares to import the fuel from North America. The Q-Max LNG vessel, the largest in its class with a capacity of about 260,000 cubic meters, is expected to reach Dahej in Gujarat in the first week of December, Petronet LNG Ltd. State-run Gail India Ltd has agreed to buy 3.5 million tonnes of LNG a year for two decades from Houston-based Cheniere Energy Inc’s Sabine Pass terminal in western Cameron Parish, Louisiana. The New Delhi-based company also booked 2.3 million tons a year capacity in the Cove Point LNG liquefaction terminal at Lusby, Maryland. The shipments are expected to start in 2017 or 2018.
Govt can Renegotiate Fiscal Terms of Cairn Block New Delhi: The government may alter terms of Cairn India’s Rajasthan oil block after Law Ministry opined that fiscal terms can be renegotiated while granting extension beyond contractual period. The government can look at raising its share of oil from the fields from a current cap of up to 50 per cent as well as allowing state-owned ONGC, which is the licensee of the block, to raise its stake. Cairn’s contractual term for exploring and producing oil from the Rajasthan Block RJ-ON-90/2 expires in 2020 and the company has made a formal application for extending the license by another 10 years saying the block also has significant potential to produce natural gas.
India Weighs Piping Diesel to Bangladesh New Delhi: India is studying the feasibility of exporting diesel to Bangladesh through a pipeline as part of the government’s plans to develop the northeast as the gateway for the proposed economic corridor with its eastern neighbours. BPCL’s subsidiary, Numaligarh Refineries Ltd, proposes to export about a million ton of diesel per year from its refinery in Assam if the ` 200-crore pipeline project finally works out. The pipeline would revive an old trade between the two countries.
Offshore World | 49 | October - November 2014
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india news Domestic Gas Price to Dip USD 5 in 3 Yrs: Goldman
Kelkar Slams New Gas Pricing Norms New Delhi: Vijay Kelkar, Former Petroleum Secretary, said the new gas pricing mechanism will not attract investments in exploration and criticised the decision to give a premium on price of gas from challenging deep-sea fields saying that it reflected a cost-plus approach.
New Delhi: The new natural gas price of USD 5.61, which is already among the lowest in Asia Pacific, is likely to drop to around USD 5 per unit in three years due to the variables included in the formula, Goldman Sachs has said. “While the Indian government introduced a new gas price regime in October, we believe clear direction is needed on gas pricing for higher-cost projects, such as deepwater, to induce more E&P capex,” the global financial major said in a report. Stating that Indian prices for new projects are among the lowest in Asia Pacific, Goldman said China pays explorers USD 11.9 per mmBtu (million British Thermal Unit) rate for new projects while Indonesia and the Philippines price the fuel at USD 11 and USD 10.5 respectively. Gas from offshore fields in Myanmar, where ONGC and GAIL have stake, are sold to China for USD 7.72. Thailand prices gas from new projects at USD 8.2 per mmBtu. The only nations with lower rates are Vietnam (USD 5.2) and Malaysia (USD 5), it said. “This, along with uncertain prospects in largely unexplored basins, could reduce the attractiveness of India as a future E&P destination, in our view,” it said. “We note that apart from high oil import dependence at 80 per cent, India’s gas import dependence has also jumped to 35 per cent today vs. 20 per cent in FY10,” it said.
India in a Sweet Spot as LNG Prices Crash in Asia New Delhi: Spot LNG prices are plunging and are expected to fall further notwithstanding the onset of winter, which traditionally drives prices higher. The fall is not just an outcome of drop in oil prices, but also a strategic shift in the demand-supply balance, and augurs well for Indian consumers. “KOGAS in South Korea has been diverting some of its long-term contractual obligations. Similarly, utility buyers in Japan are well-balanced now. The demand from Taiwan and China, too, has been relatively slow. This has disturbed the supply demand balance,” said Roman Kazmin, Editor of ICIS LNG Market Daily, a global publisher of pricing data. India imported a total 13 mt LNG in FY14 for USD 8.5 billion, according to the export-import data published by the ministry of commerce. India is the fourth biggest LNG importer with consumption of natural gas slated to grow faster than oil. Hence, the crash in spot prices is good for India. Recent spot LNG contracts were struck at prices as low as USD 10.5 per mmbtu, nearly 45 per cent down from year ago period and 25 per cent down from those struck in October 2014. These contracts are for delivery after two months; hence, contracts in November related to deliveries in January 2015. There are indications the trend will continue well in future. www.oswindia.com
“The approved formula is not transparent as some of its components such as Russian price is not market driven and this pricing model will encourage gold plating,” he said. Government officials disagreed with this and said the Russian price was reliable and closer to the Indian reality compared to the National Balancing Point price. With the new gas pricing formula the price works out to be USD 5.61.
Vijay Kelkar, Former Petroleum Secretary
Big Oil Discovery Made near Ahmedabad Ahmedabad: A significant oil discovery has been made near Ahmedabad in the Cambay basin that by some estimates may be the biggest on-land find this year. Jay Polychem (India) Ltd, a unit of city-based Jay Madhok Group, made the oil discovery in the very first well it drilled on the block CB-ONN-2009/8 in Gujarat’s Cambay basin. The discovery in the well Kharenti-A has been notified to the upstream regulator DGH and the government. Sources said the discovery by Jay Polychem is huge and similar to oil being produced by ONGC in the neighbouring Padra field as also by GSPC in Ingoli field. Cambay basin, which extends from Surat in the south to Sanchor in the north, covers an area of about 59,000 sq km with a hydrocarbon resource of more than 15 billion barrels.
No CMD for Oil India Now New Delhi: Government may invite fresh applications for top job at Oil after its headhunters PESB did not find any of the six applicants, including the firm’s Director (Finance) R S Borah, suitable. Public Enterprise Selection Board (PESB) interviewed six candidates including Borah, to select a new Chairman and Managing Director of the nation’s second biggest state explorer. Besides Borah, PESB said it interviewed S K Acharya, Director (HR), Neyveli Corp Ltd; N K Jain, Director (Personnel), Air India; Rajiv Chopra, Director Marketing, State Trading Corp (STC); S P S Bakshi, Chairman and Managing Director, Engineering Projects India Ltd and V K Gaur, CMD, National Seeds Corp Ltd.
Offshore World | 50 | October - November 2014
india news Regulator Approves Commerciality of Discoveries in ONGC’s D5 Block
Kolkata: Upstream oil regulator Directorate General of Hydrocarbons (DGH) has approved commerciality of oil and gas discoveries in the northern area of state-owned Oil and Natural Gas Corp’s (ONGC) prolific KG-D5 block in Bay of Bengal. ONGC has so far made 11 oil and gas discoveries in the Krishna Godavari basin block KG-DWN-98/2 or KG-D5 sits next to Reliance Industries’ KG-D6 area. The discoveries in KG-D5 are divided into northern and southern areas, with the former having a total of 10 finds and the later the ultra-deep UD-1 discovery. Sources said ONGC had divided these and a couple of finds in a neighbouring block, into three clusters. The gas discoveries D and E in the northern part of KG-D5 will be brought to production together with G-4 find in a neighbouring KG block at an investment of USD 1.92 billion. The remaining eight discoveries in the Northern Development Area (NDA) will be brought to production as Cluster-II.
NRL to Raise Capacity Expansion Guwahati: State-run oil refiner-marketer Bharat Petroleum Corporation Ltd’s Assam based refinery, Numaligarh Refinery Limited (NRL) has projected huge increase business opportunities with the proposed massive capacity addition.
P Padmanabhan, Managing Director, NRL
According to the refinery, NRL at present is rolling out business worth ` 400-500 crores annually, which will increase to the level of ` 1500-2000 crores once the Refinery expansion project takes off.
P Padmanabhan, Managing Director, NRL, during the first ever vendors meet informed NRL is moving ahead with proposed Refinery expansion that will increase the present capacity of 3 MMTPA (million metric tones per annum) to 9 MMTPA which will call for a capital expenditure to the tune of ` 20,000.00 crores, about 6 times the present net worth of the Company.
Decision on Premium for Deep Sea Gas Discoveries by Early 2015: Chandra
New Delhi: The government will by early next year decide on the premium that will be paid for new gas discoveries in deep sea over and above the recently approved rate of USD 5.61, said Saurabh Chandra, Oil Secretary.
Saurabh Chandra, Oil Secretary, MoPNG
Mr Chandra said stakeholders will be consulted on the mechanism of premium determination and pricing of these three categories. “A transparent process will determine this. Apprehensions that there will be discretion will be addressed,” he said, adding that consultations with stakeholders and experts will begin shortly and the mechanism will be in place in “coming new year”.
National Interest, Energy Security More Important than Procedures: CAG New Delhi: Comptroller and Auditor General of India (CAG), the national auditor, in a clear departure from its past stance, has asked the oil ministry to let national interest and energy security determine its approach towards commercial discoveries instead of niggling with procedural issues and sought ‘critical review and rationalisation’ of contractual provisions that have troubled the industry. In a keenly watched report on production sharing contracts for oil and exploration firms, the Comptroller & Auditor General (CAG) said in view of energy security, the country cannot afford to lose out on even a small discovery as it urged the government to speed up approvals of budgets and work programmes of blocks, which have been delayed by as much as 16 months after the end of the fiscal year.
IOC Eyes to Set up Refinery Project at West Coast New Delhi: Indian Oil Corporation Ltd (IOCL), the country’s biggest oil company, plans to set up greenfield refinery on the West coast as part of its expansion plans.
GSPC Gas may Pick up Stake in Vadodara Gas Ahmedabad: GSPC Gas Co Ltd, a subsidiary of Gujarat government-owned Gujarat State Petroleum Corp Ltd (GSPC), is looking to pick up stakes in Vadodara Gas Co Ltd (VGCL), which services the Vadodara municipality area, and Sabarmati Gas Ltd (SGL) that supplies gas in three northern districts, according to sources. VGCL is a 50:50 joint venture between GAIL Gas Ltd (50 per cent), a subsidiary of GAIL (India) Ltd, and Vadodara Mahanagar Seva Sadan (VMSS), the municipal corporation of Vadodara. GSPC Gas is in advanced talks with GAIL to buy its entire 50 per cent stake.
CCEA had decided that for all discoveries after this decision, in ultra deep water areas, deep water areas and high pressure-high temperature areas, a premium would be given on the gas price to be determined as per the prescribed procedure”.
B Ashok, Chairman, Indian Oil Corporation Ltd (IOCL)
Offshore World | 51 | October - November 2014
“With the growth in the economy, we see there is a need for greenfield refinery by 2021-22. After setting up of Paradip Refinery in East coast, we are now looking at setting up of refinery in West coast region, for which we are looking for suitable state and place,” said B Ashok, Chairman, IOCL. www.oswindia.com
india news Govt to Divest CIL, ONGC, SAIL by Jan 2015 New Delhi: With just four months left for the fiscal year to end, the government is rushing to complete at least a part of its FY15 disinvestment plan. Finance Ministry officials sound confident that the big four big PSUs of this year’s disinvestment roadmap, namely Coal India, ONGC, SAIL, and NHPC will hit the market by January-end. Officials also expect the stake sale in either Coal India or ONGC to happen in the next two weeks. Sources who spoke to Business Standard, however, admitted that there is lesser clarity on the smaller stake sales of Concor, REC, and PFC, as well as the two market debuts, that of HAL and RINL. Officials said some of these may be shelved. Based on the share price of the companies at afternoon trade on November 25, a 10 per cent stake sale in Coal India will fetch about ` 217.788 billion, a 5 per cent stake sale in ONGC will garner ` 160.80 billion, while a 11 per cent sale in NHPC and a 5 per cent sale in SAIL, will garner ` 26.72 billion and ` 17.408 billion, respectively. The combined proceeds from these four behemoths will be about ` 423.616 billion, compared to the FY15 PSU disinvestment budgeted estimates (BE) of ` 434.25 billion. More importantly, the combined proceeds from these four sales would have been about ` 463.02 billion, had the sale happened in mid-July.
Existing Deepwater Discoveries are not Eligible for Premium: Oil Minister New Delhi: ONGC and Reliance Industries will not get a premium for the gas they extract from deep and ultra-deepwater discoveries already made. The new price formula, announced on October 18, said that for all discoveries in deep and ultra-deepwater as well as high pressure-high temperature areas, a premium would be paid based on the prescribed procedure. But “we are very clear in our policy… The premium will be given to only those discoveries that are made or notified after November 1, 2014. The categories have been defined,” said Dharmendra Pradhan, Petroleum & Natural Gas Minister. “The contractors will have to approach the Directorate-General of Hydrocarbons (DGH) if they make any new discoveries in these (deep/ultra-deep) areas. The DGH will evaluate them. Based on the DGH views, the Government will take a call on the quantum of the premium,” the Minister said.
Paradip Refinery to commission by March 2015 Bhubaneswar: The ` 34,555-crore 15 million tonnes per annum Paradip Refinery will be commissioned in phases from March 2015 onwards, said B Ashok, Chirman, IOCL. The refinery is capable for processing a broad basket of crude oil grades, including cheaper high-sulphur heavy crudes. The company is also setting up a polypropylene project with capacity of 680 KTA at Paradip. The INDMAX FCC Unit of 4.2 MMTPA capacity at Paradip, one of the major secondary processing units, is designed to operate in petrochemicals mode to maximise propylene/ethylene production. The unit will produce 700 KTA of propylene. Based on the availability of propylene, a polypropylene plant of 700 KTA capacity will be set up with an estimated capex of ` 31.50 billion. www.oswindia.com
Maheshwari Appointed CEO – Exploration & Production at Essar Mumbai: Essar Oil Limited has announced the appointment of Manish Maheshwari as Chief Executive Officer - Exploration & Production. With around 23 years of experience, Maheshwari till recently was the Managing Director of Hindustan Oil Exploration Company Ltd. Manish Maheshwari, CEO - Exploration & Production, Essar Oil
As CEO-E&P, Maheshwari would be responsible for Essar’s entire E&P business, which includes 15 blocks and fields in various stages of exploration and production in India, Indonesia, Madagascar, Nigeria and Vietnam.
Gas Production to Rise by Two-Thirds over Five Years: Oil Ministry New Delhi: India’s domestic gas production is set to rise by two-thirds from 100 million standard cubic metres per day (mscmd) in the current financial year to 163 mscmd over the next five years through March 2019, said Oil Ministry. India’s domestic production fell 13 per cent from 111 mscmd in 2012-13 to 97 mscmd the previous financial year (2013-14). Output is expected to pick up marginally to 100 mscmd (or 36 bcm) in the current financial year, including 24 bcm from state-run Oil and Natural Gas Corporation (ONGC), 2.8 bcm from Oil India Limited (OIL) and 9.7 bcm from production sharing contracts (PSC) regime blocks. The bulk of the additional gas would come from ONGC’s ramp-up in output from the 24 bcm in the current financial year to 35 bcm by 2019, on the back of development of the C-26 cluster next financial year, the Daman offshore block, additional production in east coast from deepwater wells of the G1 field and from commissioning of Nelp (New Exploration Licensing Policy) block KG-98/2 in the Krishna Godavari basin after 2017. OIL is expected to increase production from the current 2.8 bcm to 4 bcm by 2018-19. Production begins from the Baghjan field in Assam next financial year and incremental output will be from NELP blocks in the northeast and KG-basin in 2018-19.
ONGC to Increase Spending Spree New Delhi: India’s Oil and Natural Gas Corporation plans to launch a ‘huge’ global acquisition spree, as the state-backed energy flagship delivers an aggressive Rs 11 trillion (USD 180 billion) investment push to take on Chinese rivals and drive foreign production up sevenfold by 2030. Dinesh Sarraf, Chairman, ONGC, said that the group aimed to raise its international oil and gas output from 8.5 million tonnes of oil and oil equivalent last year to 60 million tonnes over that period, as India prepares to meet projections of rapidly rising domestic energy demand.
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international news Oil Falls as OPEC Opts Not to Cut Production
Ali Al-Naimi, Oil minister, Saudi Arabia
UAE: The Organization of Petroleum Exporting Countries (OPEC) has decided not to cut oil production, despite sliding oil prices. Brent crude oil fell more than USD 3 to under USD 75 a barrel—a fresh four-year low—on the news while West Texas Intermediate (WTI)—dropped below USD 70. Global oil prices have plunged since peaking in June, and Brent crude has lost around a third of its price from USD 115 a barrel.
Following a meeting of OPEC in Vienna, Ali Al-Naimi, Oil minister, Saudi Arabia, was asked whether the group had decided not to reduce its output from 30 million barrels per day. He responded: “That is right”. Nigeria’s Petroleum Minister and newly elected OPEC President, Diezani AlisonMadueke, said that non-OPEC oil producers had to share the burden; of any future cut in production.
Russian Oil-Output Cuts to Support OPEC Seen as Unlikely Russia: Each time oil takes a dive, the idea of Russia allying with OPEC to shore up prices gets an airing. It happened in the months after 9/11 and again during the 2008 financial crisis. Now it’s back on the agenda. Russia’s top two oil officials are in Vienna to meet OPEC nations before this week’s meeting maps out the group’s response to this year’s tumble in prices. In many ways it’s a natural alliance. Like the countries that make up the producer group, Russia depends on energy exports for the bulk of state revenue, and at 10 million barrels a day, or more than 10 percent of global output, it has the scale to make a difference in the world oil market. Little ever results from the talk though -- even a 2002 agreement for Russia to hold back exports unraveled after a few months. This time probably won’t be any different for several reasons: a lot of oil in Russia is pumped by private sector companies beyond the reach of state edicts, and the extreme cold of Siberia’s winter makes it difficult to turn wells off and back on quickly. In addition, cutting supply would be financially painful for a Russian economy battered by sanctions and a crash in the ruble.
Global Consumers can Ride High on Low Crude Prices USA: A renewed plunge in oil prices is a worrying sign of weakness in the global economy that could shake governments dependent on oil revenues. Yet it is also a bonus for consumers as prices fall at the pump, giving individuals more spending money and lowering costs for many businesses. The latest slide follows OPEC’s decision to leave its production target at 30 million barrels a day. Partly because of the shale oil boom in the US, the world is awash in oil at a time when demand from major economies is weak — so prices are falling. Citibank analysts wrote in a report that global supplies exceed demand by about 700,000 barrels a day now. Tom Kloza, Chief - Oil Analyst, Oil Price Information Service, expects the price to fall by another USD 5 or 10 a barrel before stopping. “It’s that kind of rout,” he said. Overall, the slide is a boon for consumers in oil-importing regions like Asia, Europe and North America.
Crude Prices may Slide again by 2015 UK: Crude oil prices may slide again to test a new low of USD 60 per barrel levels in the middle of next year on expectations before rising in the early part of the year as a likely removal of curbs on exports by the United States may add supplies in the world market. United States, the second biggest oil producer after Saudi Arabia, produced 9 million barrels per day recently, its highest level in 29 years, as against Saudi’s output of 9.6 million barrels per day. According to the International Energy Agency, the US will become the world’s largest oil producer by about 2020. Companies such as ConocoPhillips, the largest US independent oil and gas Company, have been urging the government to remove the 1970-era export ban, which was put in place when US oil production was falling. Brent crude, which has fallen 25 per cent since the start of the year, traded at USD 78 per barrel, its lowest level in four years.
Dana Gas in Talks with Egypt over Revising Gas Prices
“Post the winter by March April, we think that prices will slide again and we could see USD 60 per barrel by the middle of next year. We see this level as the low for 2015. This dip to USD 60 will be driven by oversupply from the United States,” said Arjuna Mahendran, Chief Investment Officer at Emirates NBD.
Abu Dhabi: UAE-based Dana Gas said it was in talks with the Egyptian government to secure a higher price for some of the natural gas it extracts, as the North African country moves to encourage investment in energy.
Kuwait to Raise Oil Output of 4m bpd by 2020
Steadily declining gas production and foreign firms’ wariness about any increase in investment have combined with price subsidies and rising consumption to create Egypt’s worst energy crisis in decades. Cairo has begun negotiating with international energy firms including Italy’s Eni and Germany’s RWE DEA, to raise the price it pays them for gas, particularly when prices are not high enough to cover the costs of production.
Kuwait: Kuwait plans to invest around USD 40 billion to boost its oil production capacity to 4 million barrels per day (bpd) by 2020, an executive from Kuwait’s state oil company (KOC) said. The Opec state has a crude oil production capacity of around 3.4 million bpd and its production is in the range of 3 million bpd, said Saeed al-Shaheen, Manager of Well Surveillance at KOC. “There are plans to spend USD 40 billion to lift the capacity up to 4 million by 2020 and maintain that figure till 2030,” he said.
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international news Iran to Double Oil Exports if Sanctions End Iran: Iran will double its oil exports within two months if sanctions against it end, said Bijan Zanganeh, Oil Minister, Iran.
Bijan Zanganeh, Oil Minister, Iran
Iran currently exports around 1.3 million barrels per day (bpd) of oil. Zanganeh said Iran could increase oil exports by 500,000 bpd immediately after any lifting of sanctions and could pump 4 million bpd in less than three months after.
“The countries in the south of the Gulf are interested in keeping their market share and a decrease in market share will be difficult,” Zanganeh told. “Under no circumstance, will we reduce our global market share, even by one barrel.” Analysts said it will take longer for Iran to ramp up exports, noting that sanctions on its energy sector may be the last to be lifted if the system is dismantled.
UAE: The UAE has said that falling oil prices has not impacted its economy and it will continue to invest in the oil and gas sector to deal with the demand for energy.
Suhail Bin Mohammad Al Mazroui, Minister of Energy, UAE
Suhail Bin Mohammad Al Mazroui, Minister of Energy, UAE, said it is not the first time that prices have dropped. He said in 2008 oil prices were USD 40 (Dh146) and the country did not stop production.
He said the contribution of oil revenue towards the UAE’s Gross Domestic Product (GDP) is less than 30 per cent. “The recent oil price is not a setback for us. We have a long-term strategy and vision. Our economy is based on diversification.” The UAE produces around 2.8 million barrels of oil per day and has pledged to increase the capacity to 3.5 million barrels per day by 2017.
Oil ‘Price Rout’ not Over: IEA USA: Oil prices are expected to keep sliding well into 2015, held down by weak demand and increased shale production, said the International Energy Agency, as it maintained its full-year forecast for slow global consumption growth. The IEA said while there had been speculation that the high cost of shale extraction “might set a new equilibrium for Brent prices in the USD 80 to 90 range, supply/demand balances suggest that the price rout has yet to run its course”. “Our supply and demand forecasts indicate that barring any new supply disruption, downward price pressures could build further in the first half of 2015,” it added.
OPEC Predicts Global Energy Demand Soaring 60% by 2040 Vienna: Global energy demand will increase by 60 per cent by 2040 compared to 2010 levels, the Organization for the Petroleum Exporting Countries (OPEC) said, with greenhouse-gas-emitting fossil fuels remaining by far humanity’s main source of power. World oil output is projected to soar from 81.8 million barrels per day (mbpd) to 99.6 mbpd over the same period, OPEC said in its new annual report. The share of oil in global energy use is however projected to fall from 31.9 per cent to 24.3 per cent, while that of all fossil fuels — oil, coal and gas — will dip from 81.6 per cent to 78.4 per cent. Hydro, biomass and other renewables will account for 15.8 per cent, up from 12.7 in 2010 and nuclear power will represent 5.7 per cent, little changed from 5.6 per cent, the 12-member OPEC said. www.oswindia.com
UAE Pledges to Invest in Oil and Gas Sector despite Falling Prices
Mubadala Commences Oil Production in Thailand Thailand: Mubadala Petroleum has announced that production commenced at its Manora oilfield in the northern Gulf of Thailand. Production is expected to reach a peak rate of approximately 15,000 barrels per day as production wells are completed. Up to 10 production wells and five injection wells in the main reservoir sequence are planned. The field is located within the G1/48 concession, approximately 80 km offshore in 44 meters of water depth. The Manora project has been delivered with other partners including Tap Energy (Thailand) Pty Ltd and Northern Gulf Petroleum Pte Ltd. The total investment in the development is approximately USD 300 million.
Santos Finds Gas at Cooper Basin Australia: Drillsearch Energy Ltd, Australia-based oil and natural gas explorer and developer, has announced that a new wet gas discovery on the Western Cooper Wet Gas Fairway of the Cooper Basin in South Australia. The Varanus South-1 well in PEL 513 (Drillsearch 40 per cent and Santos 60 per cent and Operator) is the first well to be drilled by Santos and Drillsearch under the joint venture between the companies announced in July 2013. Varanus South-1 was drilled to a total depth of 10,347 feet (3,154 meters) as a near-field exploration well. Drillsearch’s preliminary interpretation of wireline logs has confirmed an aggregate best estimate of 59 feet (18 meters) of net gas pay over a gross interval of 1,197 feet (365 meters) in the Patchawarra Formation and an additional 29 feet (9 meters) of net hydrocarbon pay over a gross interval of 121 feet (37 meters) in the Tirrawarra Formation, which was considered a secondary target.
Offshore World | 54 | October - November 2014
international news GE Opens Offshore R&D Center in Brazil
Shell Appoints New Chairman
Brazil: GE has opened its USD 500-million GE Brazil Technology Center in Rio de Janeiro, which will focus on developing advanced subsea oil and gas technology. The center, GE’s first in Latin America, will be a hub for the region and is expected to employ as many as 400 researchers. Through the GE Brazil Technology Center, GE is engaged with several of its oil and gas customer partners to develop all the pieces that will make subsea oil and gas processing facility a reality. GE has announced the first of these efforts, unveiling initial plans to work with customers Petrobras and BG Group.
Charles O Holliday, Chairman, Shell
Lufeng Oil Find Underlines Paleogene Potential China: CNOOC has proven a new oil field in the eastern South China Sea. The Lufeng 14-4 structure is within the Lufeng Sag in the Pearl River Mouth basin in a water depth of 145 m (476 ft). The discovery well Lufeng 14-4-1, completed at a depth of 4,098 m (13,445 ft), intersected oil pay zones with a total thickness of 150 m (492 ft), with the well testing at a rate of 1,320 b/d. CNOOC says the result underlines the exploration potential of the Paleogene system in the basin.
The Netherlands: The board of directors of Royal Dutch Shell plc has appointed Charles O Holliday as chairman with effect from the conclusion of the 2015 Annual General Meeting, subject to his re-appointment as a director of the company by shareholders at the meeting. Holliday was appointed as a non-executive director of the company with effect from September 2010, and is currently chairman of the Corporate and Social Responsibility Committee and member of the Remuneration Committee.
He was CEO of DuPont from 1998 to 2009, and chairman from 1999 to 2009. He is a member of the board of directors of Bank of America Corp., having previously served as chairman up until September 2014, and is also a director of Deere & Co. Holliday will succeed Jorma Ollila, who will step down from the board with effect from the conclusion of the 2015 AGM. He served as chairman for nine years.
Indonesia Appoints New Oil and Gas Chief
Tullow to Explore Offshore Jamaica Jamaica: Tullow has signed a production-sharing agreement covering 10 full blocks and one part-block offshore Jamaica. The Walton basin and Morant basin areas cover 32,065 sq km (12,380 sq mi) in shallow water south of Jamaica. Tullow has committed to perform low-cost studies, reprocessing work and – if it decides to proceed further – acquisition of new 2D and 3D seismic during the initial three-and-a-half-year exploration period. Oil or gas shows have been reported in 10 of the 11 offshore/onshore drilled in Jamaica to date, the company adds.
UAE/India Group to Revamp Mumbai High North UAE: ONGC has awarded a consortium of Valentine Maritime and Indian contractor Supreme Offshore Construction & Technical Services a USD 215-million contract for the MHNRD Phase III pipeline project for the Mumbai High North field in the Arabian Sea. The location is 165 km (102 mi) northwest of Mumbai. Scope of work includes survey, detailed engineering, procurement, fabrication, transportation, pipe coatings, installation, hook-up, and commissioning of: 171 km (106 mi) of pipe segments, comprising well fluid, lift gas, water injection, and gas evacuation lines with pipeline end manifold. Additionally, the consortium will modify 12 existing platforms and remove redundant facilities. All work is due to be completed by April 2016.
Total Names de Margerie’s Successors Russia: Total has appointed Thierry Desmarest as chairman of the board of directors and Patrick Pouyanné as CEO and president of the Executive Committee. They succeed Christophe de Margerie, who died in a plane crash in Moscow.
Indonesia: Indonesia Energy and Mineral Resources Minister Sudirman Said has appointed Naryanto Wagimin as the acting chief for the oil and gas directorate general, a post previously led by Edy Hermantoro. Prior to the appointment, Naryanto served as the director for upstream oil and gas at the directorate general. According to the Jakarta Post noted that Sudirman, who was sworn in as a minister last week, has vowed to settle problems in the country’s energy and mining sector and that part of the moves would include ‘refreshing’ several posts.
First Oil Shipment Leaves Offshore Sakhalin Russia: Rosneft has started to ship crude oil extracted at the northern tip of the Chayvo license offshore Sakhalin Island. The first tanker carrying Sokol-grade crude left port. The tanker was loaded at the Sokol single-point oil terminal, 5.7 km east of the DeKastri terminal in the Khabarovsk Krai region. DeKastri is the first terminal in Russia to ship crude oil year-round in the harsh Arctic environment. Another shipment is expected to be on its way before year-end. A purpose-built fleet of ice class, double-hull tankers, each 100,000 metric tons (110,231 tons) dwt, will transport the cargoes escorted by icebreakers.
Italy Approves Offshore Route for TAP Pipeline Italy: Gianluca Galletti, Italy’s Environment Minister, has signed a decree of environmental compatibility for the Italian section of the Trans-Adriatic Pipeline (TAP) project. TAP will transport natural gas from the Shah Deniz II field development in the Azeri sector to markets in eastern and southern Europe.The 870-km (540-mi) long pipeline will traverse an onshore route through the Balkan states, with the final section crossing the Adriatic Sea to make landfall in southeast Italy.
Offshore World | 55 | October - November 2014
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products
MASS FLOWMETER
DIGITAL OIL FLOW METER
KROHNE, Inc offers OPTIMASS 6400, an allnew twin bent tube Coriolis mass flowmeter, ideal for standard liquid and gas applications in the chemical and petrochemical, oil and gas, pharma, food and beverage, and energy and power industries. It is equipped with a new signal converter that features advanced device and process diagnostics, compliant to NAMUR NE 107. It has been approved for custody transfers of both liquids and gases, making it ideal for process industries and specialist applications like LNG, CNG or supercritical gases in terminal or storage/bunkering, along with custody transfer applications. It is the first Coriolis mass flowmeter to feature advanced entrained gas management (EGM), with no loss of measurement with gas entrainment up to 100 per cent of volume. The OPTIMASS 6400 with EGM can follow and correct for the varying amplitudes. EGM continues to present an actual measured reading, together with an indication or configurable alarm that improves processes by identifying transient gas entrainments. Available in a range of sizes from DN 08 to 250, the OPTIMASS 6400 is offered in SS-316L, Hastelloy C22 and Duplex steel UNS S31803. Compliant to NAMUR standard installation lengths, the OPTIMASS 6400 operates in high temp up to 400°C, as well as cryogenic applications down to -200°C. It also handles pressures up to 200 bar (2900 psi). It is the first KROHNE mass flowmeter to feature the new MFC 400 signal converter. The MFC 400’s fast, completely digital signal processing enables the EGM feature and outstanding dynamic density measurement, as well as enhanced diagnostic and status indications. For details contact: Krohne, Inc 7 Dearborn Rd, Peabody, MA 01960, U.S.A. Tel: (800) 356-9464, (978) 535-6060 E-mail: olley@KROHNE.com
CVG Technocrafts India offers digital gas flow meter using micro controller, which provides highly accurate measurement and direct digital read out of gas flow rate. The time required for the soap film to pass through a known fixed volume is measured. The soap film is sensed by IR sensor. When the soap film passes through first sensor, it activates the timer of micro controller. Timer is stopped when the film crosses the second sensor. The flow rate is then calculated by micro controller and instantly displayed in cc/min.
www.oswindia.com
For details contact: Chintan Engineers 47 Bhagirath Estate, Part-1, Nagarvel Hanuman Road, Rakhial Ahmedabad, Gujarat 380 026 E-mail: chintanengineers24@gmail.com / info@achieverspumpsandvalves.com
RPD TYPE DIGITAL OIL FLOW METER MYKO Electronics Pvt Ltd offers RPD Type digital oil flow meter. Features fuel consumption monitoring in industrial power generators, boilers burners; flow rate monitoring and control in close loop systems for bearing lubrication, etc; state of the art design with electronic counter flow indication analogue and digital output signals and limiting value switch; high vibration resistance; and independent of viscosity and temperature. For details contact: MYKO Electronics Pvt Ltd 204, B-2, Sakivihar Complex, Sakinaka, Andheri (E ) Mumbai 400 072 Tel: 022-28575634, 28581020
FLAMMABLE GAS DETECTORS
For details contact: CVG Technocrafts India 2 Ashpaque Compound, Ganesh Nagar Behrambaug, Jogeshwari (W), Mumbai 400 102 Tel: 022-26741043
Chintan Engineers offer high quality digital oil flow meter known for their rich features such as longer operational life and perfect finish and durability. These products are highly appreciated in the market.
ELECTRONIC FUEL FLOW METER Acclaimed widely for its performance, accuracy and service life, the offered electronic fuel flow meter is known to be amongst the finest that is available on the market. Manufactured in accordance with the set industry norms and guidelines, utilizing the finest raw materials and technology, its quality never deteriorates. For details contact: SMIS Instrumentation 21, Gr Flr, 2nd Main, B/h Bharath Petrol Bunk Attiguppe, Vijayanagar Bengaluru, Karnataka 560 040
Offshore World | 56 | October - November 2014
project update
Media Barter with gulfoilandgas.com
Projects Database Petrochemical Plants and Refineries
Major Projects in the Middle East, Africa and Caspian Sea
Project
Country
Value ($)
Status
Bahrain Deep Gas Exploration Project
Bahrain
-
Execution
Bahrain Field Development Project
Bahrain
1,500,000,000
Execution
Bina Bawi Block
Iraq
100,000,000
Execution
Dohuk License Area
Iraq
40,000,000
Execution
Miran Exploration License
Iraq
140,000,000
Execution
Shaikan Block
Iraq
-
Execution
Kuwait Manifold Project
Kuwait
-
Bidding
New Oil Gathering Centres
Kuwait
2,300,000,000
Execution
APEX - Block 36
Oman
-
Execution
Oman Block 8
Oman
-
Execution
West Bukha Offshore Field Development
Oman
200,000,000
Execution
Al Khalij North Development Project - Phase III
Qatar
200,000,000
Execution
Block D Concession
Qatar
200,000,000
Execution
Dukhan Oil & Gas Field Development
Qatar
-
Execution
Al-Khafji Offshore Field Development
Saudi Arabia
1,200,000,000
Execution
Khurais Light Crude Increment Program
Saudi Arabia
3,000,000,000
Execution
Petrokemya Butadiene Debottleneck Project
Saudi Arabia
-
FEED
Wasit Gas Development Program - Processing Facilities
Saudi Arabia
-
Execution
ADMA-OPCO Nasr Field Development
UAE
2,000,000,000
Bidding
ADMA-OPCO/ZADCO - Umm Lulu Oil Field Development
UAE
1,500,000,000
Execution
Saleh Offshore Field
UAE
-
Execution
Umm Lulu Full Field Development - Phase 2
UAE
2,300,000,000
Execution
Africa
Country
Value ($)
Status
Block 15/06 West Hub Project
Angola
-
Execution
Kaombo Project
Angola
16.000,000,000
Study
Abu Sennan Concession (Block III)
Egypt
-
Execution
North El Mahala (Block 2)
Egypt
-
Study
North West Gemsa Concession
Egypt
-
Execution
Middle East
Offshore World | 57 | October - November 2014
www.oswindia.com
project update
Afar License Area (Gewane-EI Wiha Block)
Ethiopia
-
Execution
West Cape Three Points (WCTP) Block
Ghana
-
Execution
Equatorial Guinea - Block I
Guinea
-
Execution
Block CI-26 / Espoir Development
Ivory Coast
-
Execution
Block 10BA
Kenya
-
Execution
Kenya - Block 2B
Kenya
-
Execution
Liberia Bid Round 2014
Liberia
-
Completed
Area B Block 4 - Chinguetti Field Development
Mauritania
720,000,000
Execution
Block C19
Mauritania
-
Execution
Circle Oil - Sebou Block
Morocco
-
Execution
Sidi Moussa Licence
Morocco
-
Execution
R1/R2 Permit
Niger
-
Execution
Agbami Field
Nigeria
1,900,000,000
Execution
Oil Mining Licence (OML) 115
Nigeria
-
Execution
Offshore Nyuni/East Songo-Songo Licence
Tanzania
-
Execution
Robbana Concession
Tunisia
-
Execution
2014 Uganda Exploration License Round
Uganda
-
Planning
Caspian Region
Country
Value ($)
Status
Gunashli Oil Field Development
Azerbaijan
500,000,000
Execution
Neft Dashlari Field Development
Azerbaijan
-
Execution
Shah Deniz Stage 2 Development
Azerbaijan
25,000,000,000
FEED
Umid & Babek Fields
Azerbaijan
-
Execution
Khangiran Gas Field
Iran
-
Execution
Kish Gas Field Development
Iran
12,000,000,000
Execution
South Pars Gas Project
Iran
16,000,000,000
Execution
South Pars Phase 12 Development
Iran
7,650,000,000
Execution
South Pars Phases 15-16 Onshore & Offshore Development
Iran
2,900,000,000
Execution
Yadavaran Oilfield Development
Iran
2,000,000,000
Execution
Akkulka Shallow Gas Exploration Project
Kazakhstan
-
Execution
Block 31
Kazakhstan
450,000,000
Execution
BNG Contract Area
Kazakhstan
100,000,000
Execution
Galaz Contract Area
Kazakhstan
-
Execution
Munaily Contract Area
Kazakhstan
-
Execution
Tengiz Field
Kazakhstan
23,000,000,000
Execution
Bortovoy Licence
Russia
180,000,000
Execution
Exillon WS Fields
Russia
-
Execution
Messoyakha Oil and Gas Fields Development
Russia
18,000,000,000
Execution
Prirazlomnoye Oil Field Development
Russia
5,000,000,000
Execution
Verkhnechonskoye Oil & Gas Condensate Field Development
Russia
5,000,000,000
Execution
Vostochny-Makarovskoye (VM) License Area
Russia
-
Execution
www.oswindia.com
Offshore World | 58 | October - November 2014
World Future Energy Summit Date: 19 - 22 January 2015 Venue: Abu Dhabi National Exhibition Centre Event: The World Future Energy Summit (WFES) is the world’s foremost event dedicated to renewable energies, energy efficiency and clean technologies. Held under the patronage of His Highness Sheikh Mohammed Bin Zayed Al Nahyan, Crown Prince of Abu Dhabi and Deputy Supreme Commander of the UAE Armed Forces, WFES includes a world-class Conference, an international Exhibition, the Project & Finance Village, the Young Future Energy Leaders program, as well as a number of corporate meetings and concurrent social events. The WFES Exhibition is an international business platform that connects project owners and solution providers to investors and buyers from the public and private sector.WFES 2015 will present energy sector stakeholders with a unique opportunity to meet with their peers, exchange technology, share best practice and form business partnerships that will further promote the global effort for a better future. For details contact: Reed Exhibitions Claude Talj, Group Sales Director T:+971 2 409 0409 M:+971 50 452 8168 Email: claude.talj@reedexpo.ae
Providing an exclusive source of information for over 18 years, Offshore West Africa 2015 will showcase the most innovative technologies and groundbreaking solutions within the Offsore exploration and production industry. Combining both a high-quality conference and rich exhibition of services and equipment, Offshore West Africa offers a unique insight into this exciting and progressive marketplace. Including Offshore West Africa as a key component of your company’s marketing strategy ensures one-on-one access to key industry professionals and decision makers from around the world. The conference will deliver the latest technological innovations, solutions and lessons learned from leading industry professionals and will focus on the process of managing major projects with its inherent cost implications. For Detail Contact: Europe, Middle East & Asia T: +44 (0) 1992 656 658 E: tonybm@pennwell.com
Offshore Middle East Date: 26 - 28 January 2015 Venue: Qatar National Convention Centre Event: Offshore Middle East is the region’s leading event dedicated to the offshore exploration and production industries of the Gulf region. With its excellent networking opportunities, this event provides the ideal location from which to collaborate, conduct business and experience exploration & production in action. Offshore Middle East is the premier event dedicated to the offshore exploration and production industries of the Gulf region, providing excellent networking opportunities and a forum for sharing of ideas and experiences. For details contact: David Paganie Conference Director T: +1 713 963 6217 E: davidp@pennwell.com
Offshore West Africa Date: 20 - 22 January 2015 Venue: The Eko Hotel & Suites, Lagos, Nigeria Event: Offshore West Africa, the region’s premier technical forum focused exclusively on West Africa’s offshore oil and gas industry will return to Nigeria in 2015.
Myanmar Oil & Gas Date: 18 - 21 March 2015 Venue: Sule Shangri-La Hotel Event: Taking place over four interactive days, Myanmar Oil & Gas Week will cover the latest challenges for developing an oil and gas industry within a newly reformed economic and social environment. Key topics include: overcoming challenges for downstream and upstream operators; uncovering the real potential of domestic exploration and production; infrastructure developments; domestic obligation requirements; understanding the capabilities of the domestic workforce; engaging with local communities, plus much more. Technical workshops in deepwater exploration and corporate briefings for ‘doing business in Myanmar’ are also included in the event schedule, to ensure potential investors gain a holistic overview of this exciting new market. For details contact: ITE Group Plc 105 Salusbury Road London, NW6 6RG, UK T: +(44) 020 7596 5000
Offshore World | 59 | October - November 2014
www.oswindia.com
book shelf A D VA N C E D W E L L C O M P L E T I O N E N G I N E E R I N G , T H I R D E D I T I O N Author: Wan Renpu Hardcover: 736 Pages Price: USD 152.66 Publisher: Gulf Professional Publishing Book Description: Once a natural gas or oil well is drilled, and it has been verified that commercially viable, it must be ‘completed’ to allow for the flow of petroleum or natural gas out of the formation and up to the surface. This process includes: casing, pressure and temperature evaluation, and the proper instillation of equipment to ensure an efficient flow out of the well. In recent years, these processes have been greatly enhanced by new technologies. The book summarises and explains these advances while providing expert advice for deploying these new breakthrough engineering systems. The book has two themes: one, the idea of preventing damage, and preventing formation from drilling into an oil formation to putting the well introduction stage; and two, the utilization of nodal system analysis method, which optimizes the pressure distribution from reservoir to well head, and plays the sensitivity analysis to design the tubing diameters first and then the production casing size, so as to achieve whole system optimization. With this book, drilling and production engineers should be able to improve operational efficiency by applying the latest state of the art technology in all facets of well completion during development drilling-completion and work over operations. WELL COMPLETION DESIGN, FIRST EDITION Author: J Bellarby Paperback: 726 Pages Price: USD 185 Publisher: Elsevier Science
Book Description: Completions are the conduit between hydrocarbon reservoirs and surface facilities. They are a fundamental part of any hydrocarbon field development project. The have to be designed for safely maximising the hydrocarbon recovery from the well and may have to last for many years under ever changing conditions. The book has issues include: connection with the reservoir rock, avoiding sand production, selecting the correct interval, pumps and other forms of artificial lift, safety and integrity, equipment selection and installation and future well inter ventions.and in all management students’ curriculums. www.oswindia.com
RESERVOIR MODEL DESIGN: A PRACTITIONER’S GUIDE Authors: Philip Ringrose & Mark Bentley Hardcover: 249 Pages Price: USD 75.68 Publisher: Springer Book Description: This book gives practical advice and ready to use tips on the design and construction of subsurface reservoir models. The design elements cover rock architecture, petrophysical property modelling, multi-scale data integration, upscaling and uncertainty analysis. Philip Ringrose and Mark Bentley share their experience, gained from over a hundred reservoir modelling studies in 25 countries covering clastic, carbonate and fractured reservoir types. The intimate relationship between geology and fluid flow is explored throughout, showing how the impact of fluid type, production mechanism and the subtleties of single- and multi-phase flow combine to influence reservoir model design. The main audience for this book is the community of applied geoscientists and engineers involved in the development and use of subsurface fluid resources. The book is suitable for a range of Master’s level courses in reservoir characterisation, modelling and engineering. WELL PRODUCTIVITY HANDBOOK Authors: Boyun Guo, Kai Sun, & Ali Ghalambor Hardcover: 368 Pages Price: USD 160.04 Publisher: Gulf Publishing Company Book Description: With rapid changes in field development methods being created over the past few decades, there is a growing need for more information regarding energizing well production, this book provides updated information on well productivity that is essential for making oil and gas field development plans. Well Productivity Handbook provides updated knowledge for modeling oil and gas wells with simple and complex trajectories. Covering critical topics, such as petroleum fluid properties, reservoir deliverability, wellbore flow performance and productivity of intelligent well systems, this handbook explains real-world applications illustrated with example problems. Computer programs are also provided in a complimentary CD, easy to use by petroleum and reservoir engineers of all levels.
Offshore World | 60 | October - November 2014