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Contents INTERVIEW ‘CMPDI is making all out efforts to commercially harness methane from mining areas’ VOL. 12 NO. 1 DECEMBER 2014 - JANUARY 2015 MUMBAI ` 150
– A K Debnath, Chairman & Managing Director, Central Mine Planning and Design Institute (CMPDI)
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
‘FLNG projects will overcome the challenges of onshore projects’ 10 – Bill Breckenridge, Technology Manager - Oil & Gas, Black & Veatch and G Sathiamoorthy, Country Manager & Managing Director, Black & Veatch India
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
GUEST COLUMN The Trans-Afghan Pipeline Initiative: No Pipe Dream 12 – Marc Grossman, Vice Chairman, The Cohen Group
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Digital Oil Field: Online Management of Oil and Gas Asset Lifecycle 15
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– Carol Piovesan & Jess Kozman Tackling the Big Data Bottleneck 19 – Richard Bailey, Tore Hartvigsen & Arild Waaler Enhancing Oil Recovery with Autonomous Inflow Control Devices – Georgina Corona Cortes & John Fitzpatrick New LNG Supplies and Price – Oil or Hub Indexed? 25 – Priyank Srivastava Smart Refinery: Enhance the Productivity of Plant in Manifold 28 – Tim Olsen Energy Commodity Prices Continues to Move Down 30 – Niteen M Jain & Nazir Ahmed Moulvi
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interview
‘CMPDI is making all out efforts to commercially harness methane from mining areas’ India’s rapidly increasing energy demand coupled with limitations in making use of conventional energy resources like Coal and paucity of adequate petroleum resources compel to develop coal based non-conventional energy resources like CBM/CMM/UCG and shale gas. While the country announced CBM policy in 1997 which facilitated allotment of 33 prospective CBM blocks through global bidding having CBM resources of 1.78 TCM, but the success of harness methane from the blocks is merely 0.5 MMCMD at present. A K Debnath, Chairman & Managing Director, Central Mine Planning and Design Institute (CMPDI) - the nodal agency for CBM/CMM reserves in India - details about the potential, challenges, pricing and policy for exploring the coal based non-conventional resources in the country, in an email interaction with Rakesh Roy.
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To meet the rapidly increasing demand for energy and faster depletion of conventional energy resources, India is looking for alternate resources like coal bed methane (CBM). Can you please apprise us the potential of CBM exploration in India & the role of CMPDI in the country’s CBM programme? Development of non-conventional energy resources is a priority in India keeping in view of the rapidly increasing energy demand and limitation of production from conventional energy resources like Coal and paucity of adequate petroleum resources. Therefore there is focus for development of different resources renewable/conventional/non-conventional. In this regard harnessing of coal based non-conventional resources like CBM/ CMM/UCG and shale gas is under active consideration.
As far as pricing is concerned going by the CBM policy, the operators of the CBM projects are free to market the gas and the price is determined based on arm length price of energy resources, subject to the approval of the Government of India. www.oswindia.com
To expedite development of CBM, Government of India announced CBM policy in 1997 which facilitated allotment of 33 prospective CBM Blocks through global bidding having CBM resources of 1.78 TCM of CBM resources are expected to be available in the allotted blocks. The allottee of the blocks is undertaking envisaged activities for facilitating commercial development of CBM. CMPDI has played a major role in the identification of the blocks and has also prepared data dossiers for most of the allotted blocks facilitating their allotment. CBM production has started from the few blocks allotted in the 1 st round of bidding and the blocks allotted subsequently are undergoing the exploratory/pilot test.
Offshore World | 6 | December 2014 - January 2015
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interview CMPDI has successfully implemented a demonstration project at Moonidih mine of BCCL proving the efficacy of the process in Indian Geo-mining condition and identified five prospective areas for CMM development.
It is a fact that the envisaged production of CBM could start in the country as the industry is fraught with several challenges which include administrative and technical in nature. Further, being a new technology area in the country there is a limitation in the technical support and local issues have also contributed in slow progress in certain cases. It is however, expected that production which stands at 0.5 MMCMD at present will be augmented in the coming years. In addition CMPDI is making all out efforts to commercially harness methane from mining areas generally called Coal Mine Methane (CMM) which in any case is otherwise a wasted resource. The projects will be taken up after getting approval of the Government which is under serious consideration. Exploit of coal bed methane (CBM) started in 2002 and 33 blocks were awarded for exploration, but enormous delays in government permission for drilling and pricing have held up production till now. What is your take on it? Although DGH monitors the activities related to development of CBM and will be in a better position to give full details on this point but we are aware that there are several administrative and technical problems including local problem and delay in getting the requisite petroleum exploration and mining leases (PEL & PML), environmental clearance etc. It is expected that this will be expedited and the envisaged activities will be taken up by the operators. As far as pricing is concerned going by the CBM policy, the operators of the CBM projects are free to market the gas and the price is determined based on arm length price of energy resources, subject to the approval of the Government of India. In this way CBM operators are better placed in marketing CBM. CBM licenses can extract only gas, not the associated coal, which is a major bottleneck for the private explorer to develop CBM in coal blocks. According to you, how should both - petroleum & Natural Gas and Coal Ministries - work out for a similar consensus to develop CBM along with coal, which has been a success globally? As far as development of virgin CBM is concerned the blocks are carved out in such areas where mining operation either not going on nor projectised, www.oswindia.com
therefore, the question of extraction of Coal and CBM from the same areas generally does not arise. Further, for taking up methane from projectised areas called Coal Mine Methane (CMM) the government is in process of formulation of a policy and CIL/CMPDI has been actively pursuing this issue as it would be of immediate interest to CIL/CMPDI for safety of its on-going mining operations. In this regard, CMPDI has successfully implemented a demonstration project at Moonidih mine of BCCL proving the efficacy of the process in Indian Geo-mining condition and identified five prospective areas for CMM development. Further, CMPDI will take up action for commercial development after getting consent of the Government. In the backdrop of the recent de-allocation of coal blocks by the Supreme Court, leading to pressure on Coal India (CIL) to enhance out put, CBM could be a worthwhile option to explore. As CMPDI is called think-tank of CIL, how you going to make best out of it? As far as CBM resource in de-allocated coal block is concerned CMPDI has not carried out the studies in such blocks related to availability of CBM resource. However, it may be worthwhile to go ahead with such studies so that optimal harnessing of both resources could be taken up in a given area. There is much heated debate about offshore gas production, but silence on the astounding failure to expedite gas production from coal blocks. According to you, what the changes should be in policy regime in CBM that could offer opportunities to prospective. As indicated earlier CIL/CMPDI is contemplating for commercial development of CMM within the CIL leasehold areas and is actively pursuing for getting clearance from the Government. We understand that the policy on CMM is under formulation and CIL may get the approval for harnessing CMM, which in any case is otherwise a resource. The process will not only environment friendly but will have a positive bearing on the safety of the mines as well as it will facilitate availability of clean energy resource in addition to incremental revenue which may facilitate taking up costly underground mining operation.
Offshore World | 8 | December 2014 - January 2015
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interview
‘FLNG projects will overcome the challenges of onshore projects’ Increasing demand for crude oil & natural gas has made it possible to explore remote and smaller oil & gas fields where construction of a land-based facility and associated infrastructure are seemingly not much more feasible. “While there are currently no FLNG vessels in operation, FLNG/FSRU provides many advantages over conventional land based approaches in minimising capital cost and project schedule time in these regions,” says Bill Breckenridge, Technology Manager - Oil & Gas, Black & Veatch. In Indian context, FLNG can provide another diverse market for the country’s suppliers to develop a secure gas supply, says G Sathiamoorthy, Country Manager & Managing Director, Black & Veatch India. Excerpts: E-mail interaction with Rakesh Roy
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While setting up onshore LNG terminals are more expensive nowa-days, how FLNGV be a more viable option to tap offshore natural gas resources in cost-effective manner by conventional mode? Breckenridge: Many recent global land based LNG export projects have realised significant cost and schedule overruns. FLNG provides many advantages over conventional land based approaches. The capital cost of an FLNG facility is much less than a traditional onshore project. The project schedule is greatly reduced as well. Issues such as land acquisition and permitting can add months or years to a land based-project execution schedule. Base load onshore LNG facilities have grown very large in scale (10+ MMTPA) to achieve the economy of scale necessary to make them commercially viable. This requires a large gas field to sustain the required gas volumes over a 30-year project life. Such large gas fields are on the decline or are in regions of the world without the infrastructure to support a land-based plant. As such, much of the world’s gas is ‘stranded’. FLNG projects have gained more attention in recent years to overcome the challenges of onshore projects.
There are currently no FLNG vessels in operation. However, Black & Veatch has two projects in the construction stage and several other projects in various stages of development. Black & Veatch’s proven PRICO® technology is ideally suited for FLNG projects due to its simplicity and compact layout. Our first FLNG vessel will become operational in 2015. Our barge and ship FLNG designs can handle a range of capacities from 0.5 MMTPA to 5.0 MMTPA. Our PRICO® technology, which is a single mixed refrigerant process, is very flexible to address a wide range of feed gas compositions and can operate efficiently in a marine environment considering wave motions. Today’s E&P activities are moving from onshore to offshore as most of the global onshore crude reservoirs in on mature stage, how do you look the global FLNG market is likely in near future? Breckenridge: There are many stranded gas fields that have not been developed because they are not of sufficient size to support the construction of a base load facility and/or they are in a remote area where construction of a land based facility and associated infrastructure are not feasible. FLNG
FLNG will open the market to small/mid-scale producers and other small companies looking to vertically integrate through production, liquefaction, transportation and marketing. - Bill Breckenridge www.oswindia.com
Offshore World | 10 | December 2014 - January 2015
interview
FSRU’s are proven in the industry and offer some of the same advantages of FLNG projects relative to cost, schedule and infrastructure requirements. - G Sathiamoorthy
projects are attractive for small/midscale facilities (0.5 – 5 MMTPA). The FLNG vessel is built in a controlled shipyard atmosphere and can then be deployed to remote locations without the need for costly infrastructure development in a remote area that may not have sufficient skilled labour or resources. Further, the FLNG vessel can easily be re-deployed as smaller gas fields deplete over time, extending the life of the asset. This small/mid-scale concept opens the doors for producers at a much smaller scale than conventional base-load facilities.
There will also be opportunities for domestic gas companies to buy stakes in smaller scale liquefaction projects to secure gas for importation. As Indian major hydrocarbon players are establishing linkages to meet the growing energy need of the country, how will the growing LNG demand for the consumer sectors like power & fertiliser accelerate the investment of LNG terminals in the country?
What are the factors, you foresee, that will drive the emergence of floating liquefaction to the growth of FLNG Sector?
Sathiamoorthy: India’s demand for gas will continue to outpace the supply requiring more and more importation. Currently, India imports ~20 MMTPA of LNG and this is expected to grow to 50-70 MMTPA by 2020 and could grow to even greater numbers with a strong Indian economy.
Breckenridge: The LNG market has traditionally been dominated by the major public E&P companies and major state-owned oil & gas companies. FLNG will open the market to small/mid-scale producers and other small companies looking to vertically integrate through production, liquefaction, transportation and marketing.
India gas suppliers are looking for partners around the world to secure the supply of LNG to meet its growing demand. FLNG will provide another alternative for India to secure the supply and possibly take an equity position in the development of such projects to ensure a more stable pricing model. While India’s 56 per cent of crude reserves are in offshore, how will FLNG/FSRU Industry drive the LNG re-gasification market in the coming year? Sathiamoorthy: The demand for natural gas in India continues to grow at a pace that cannot be supported by domestic production. Importation of additional LNG will be required to fill the supply-demand gap. There will be new import terminals built in India to support the required import. This demand will likely be met through a combination of expansion of existing import terminals, new onshore import terminals and new FSRU terminals.
Global Capex on FLNG Facilities by Region, 2013-2019
Global capex on FLNG facilities is set to total USD 47.4 billion over the 2013-2019 period with over USD 28 billion spent on FLNG liquefaction and USD 19.1 billion on import terminals. - Douglas-Westwood
FSRU’s are proven in the industry and offer some of the same advantages of FLNG projects relative to cost, schedule and infrastructure requirements. As LNG imports grow in India, domestic gas companies will be looking at various alternatives to ensure security of gas supply and long-term price stability. We have already seen domestic producers look to invest in foreign projects in the USA, Africa and Middle East to ensure competitive gas supply to India. FLNG can provide another diverse market for India suppliers to develop a secure gas supply.
Offshore World | 11 | December 2014 - January 2015
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guest column
The Trans-Afghan Pipeline Initiative: No Pipe Dream Despite a stream of bad news around the global political arena, development plans are underway even among nations with adversarial relations. This past summer, a step forward was taken for the realisation of the Trans-Afghan natural gas pipeline project, Afghanistan, Turkmenistan, Pakistan and India signed an agreement in early July to move forward with a 1,700-kilometer natural gas pipeline. “This USD 7.5 billion project has the potential to catalyse investment and trading opportunities in a region sorely in need of both,” says Marc Grossman, Vice Chairman, The Cohen Group, and the former US Special Representative for Afghanistan and Pakistan. He further adds: The four countries and the Asian Development Bank now have a clearer path forward on creating the conditions for a successful project.
A
An avalanche of bad news has engulfed the world – murder in the skies over Ukraine, renewed war between Israel and Hamas, and a terrorist resurgence in Iraq. Amid the global chaos, one positive development got little attention – a development that could help advance peace between India and Pakistan, improve chances for reconciliation in Afghanistan, undermine energy blackmail by Russia, and keep economic pressure on Iran while nuclear negotiations continue. On July 8, 2014, Turkmenistan, Afghanistan, Pakistan and India signed an agreement in Ashgabat to move forward with a 1,078-mile natural gas pipeline. This USD 7.5 billion project known as TAPI, or the Trans-Afghan Pipeline Initiative, has the potential to catalyse investment and trading opportunities in a region sorely in need of both by bringing gas from Turkmenistan through Afghanistan and Pakistan into India. The project will have to overcome many hurdles but TAPI could also have serious geopolitical implications. Consider the benefits a completed pipeline could bring: First, TAPI has the potential to promote more positive political and economic interaction between Afghanistan and Pakistan. Tensions between Kabul and Islamabad over trade and terrorism are deep, but TAPI would give each side something larger to gain by providing an avenue for mutually-beneficial economic cooperation.
of the region is dependent on Moscow for energy. Turkmenistan has the world’s sixth largest reserves of natural gas. With further energy infrastructure investments, the country could become a major energy exporter. The more natural gas that gets into world markets, the less power Moscow and Gazprom have to coerce America’s allies and friends. Finally, TAPI would create a viable alternative to the proposed Iran-Pakistan pipeline, which could help western negotiators maintain the economic pressure on Tehran to end its nuclear weapons’ programme. With TAPI, Pakistan can find a way to meet some of its energy needs without providing Tehran with an economic windfall and undermining western economic sanctions. For these and other reasons, Washington has been a strong advocate for TAPI. The project is a key foundation for the New Silk Road initiative announced by then-Secretary of State Hillary Clinton in India in July 2011. The idea is to use this historic trade route in a modern way: to connect the vibrant economies in Central Asia and India’s thriving markets with Afghanistan and Pakistan in the center, where they could both benefit first from transit trade and ultimately from direct investments. TAPI would play a critical role in such an effort to support economic integration in the region – and by extension, US political and security objectives in the area. With TAPI as its core, is about acting on diverse opportunities and challenges simultaneously.
Second, TAPI could help improve relations between India and Pakistan and reduce chances of armed conflict between these two nuclear powers. Joint support for TAPI could – along with enhanced trade through most favored nation status and liberalised visa regimes for business people – support an effort by Indian Prime Minister Narendra Modi and Pakistani Prime Minister Nawaz Sharif to enhance political ties through commercial opportunities.
Under the current arrangement, Pakistan and India will each receive 42 per cent of the gas and Afghanistan 16 per cent. Today’s estimates envisage a construction period of four to five years, given the long delays the project has experienced so far. With more hard work yet to be done to move TAPI from concept to concrete, some observers expect the project to take longer to complete and the bill to rise to USD 10 billion.
Third, TAPI has the potential to contribute to reconciliation in Afghanistan by creating economic opportunity for the Afghan people. TAPI could change the calculations of at least some Afghan Taliban fighters, who might see it as a way to give up guns for jobs.
As part of the July 8 accord, the four TAPI-partner countries have asked the Asian Development Bank – ADB has acted as the TAPI Secretariat since 2002 – to establish a lead consortium by November 2014 so that construction work can start as soon as possible. The recent development says that the four member nations will be met on February 11-12, 2015, in Islamabad to finalise the consortium partner for executing the project. The ADB’s role will be crucial to getting the project financed with as much private sector money as possible.
Fourth, TAPI could undermine Russian President Vladimir Putin’s ability to blackmail his neighbours by threatening their energy supplies. Today, much www.oswindia.com
Offshore World | 12 | December 2014 - January 2015
guest column
Dotted line shows proposed pipeline to cross Turkmenistan, Afghanistan, Pakistan into India (Source: 2008 map, Canadian Centre for Policy Alternatives)
The Bloch Factor While the TAPI pipeline has the potential to transform the entire region, the project does face some major hurdles.
But the ongoing turmoil in Afghanistan by fierce Taliban attacks across the country and lingering uncertainty about US and allied military support to the country are all cause for hesitation in both government and private sector offices.
For example, although Total, Chevron and ExxonMobil have shown interest in financing and running the pipeline project and have been shortlisted for the contract, no company or consortium has stepped forward to take the necessary lead to manage the finance, design, construction and operation of the pipeline. Crucially, the energy companies with the capacity to support TAPI have told the government in Ashgabat that they will require exploration rights in Turkmenistan’s onshore gas fields, mainly Dauletabad, to make the project economically attractive. Turkmenistan so far will only consent to offshore exploration. This impasse has made any deal impossible.
So how can TAPI succeed? Energy expert David Goldwyn offers the reminder that there are three parts to any successful gas pipeline project: a seller committed to making enough gas economically available for a viable project; a buyer ready to commit to longterm contracts; and a builder, with the right financing to create the physical project. The July 8 accord is an important step in aligning the interests of Turkmenistan, Afghanistan, Pakistan and India. The four countries and the Asian Development Bank now have a clearer path forward on creating the conditions for a successful project. There is still a long, slow road to travel before gas moves from Turkmenistan through Afghanistan and Pakistan to India, and the next phase is to convince the private sector that the project is commercially sound and technically feasible.
Another major challenge facing construction is the security and political situation in Afghanistan. Kabul views the pipeline as a significant revenue stream as well as a source of energy as the country builds its economy. Sediq Seddiqi, Spokesman for the Ministry of Interior Affairs has said that Afghan security forces are fully motivated to provide security for the project, and Afghan authorities have promised to deploy 5,000 to 7,000 security personnel to safeguard the route.
Much work remains. But in the midst of many other seemingly intractable challenges the world has faced the last summer, the agreement reached in Ashgabat on taking the next step toward the TAPI pipeline is an achievement worth acknowledging.
Offshore World | 13 | December 2014 - January 2015
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The Future of Pipeline
Where the Industry is heading? • What are the Actions that can Assure Integrity in Pipelines? • Rehabilitation or Decommissioning of Pipelines? • How Reliable is the Pipeline Systems? and many more topics to be presented....
Join the Discussion in Kuala Lumpur this April 2015
3rd Annual APAC Pipeline Integrity Management Forum 8-9 April 2015 || Kuala Lumpur, Malaysia
Contact Details : rina.james@fleminggulf.com || T: +603 2027 4767
Features Big Data Analytics
Digital Oil Field: Online Management of Oil and Gas Asset Lifecycle Global oil & gas industry, which is capital and risk intensive, is now approaching asset lifecycle processes that recognise the need for online tracking of the data, information, knowledge, and business intelligence to support key decisions. The article explains on Big Data and predictive analytics techniques for tracking key milestones and ‘stage gates’ from exploration through abandonment for large offshore projects to protect asset lifecycles.
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The oil and gas industry has recently begun to adopt and leverage standards and best practices from other industries with capital and risk intensive asset lifecycles. The intersection of advances and capability maturity in the areas of Big Data and predictive analytics are resulting in measurable benefits, especially for operators of large offshore projects with long asset lifecycles. Data and Asset Lifecycles Many large international offshore operators have enterprise level asset lifecycle processes that recognise the need for online tracking of the data, information, knowledge, and business intelligence that supports key decisions. Most of
these online systems track key milestones and ‘stage gates’ from exploration through abandonment. Note that in this standard business reference model, providing Information Technology (IT) services is one of the key execution and support processes at each stage. The identifying conventions for IT include the provision of applications and databases for asset lifecycle maintenance. Recently, there has been interest in how applying online predictive analytic techniques might improve the efficiency of these processes and give
An exploration and production Business Process Reference Model to support online asset management. Copyright Energistics, 2014, all rights reserved. Used by permission. Offshore World | 15 | December 2014 - January 2015
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Features
organisations a competitive advantage in the next cycle of lower commodity prices. This interest has coincided with an understanding of the business case for using what is now known as Big Data, and with the acceptance of methodologies for applying predictive analytics to asset management. With the release in 2014 of ISO 55000, an international standard for asset management, there are now agreed principles and terminologies that can be applied to measure progress with offshore oil and gas assets and benchmark against other industries (ISO, 2014). This standard provides a definition of predictive capabilities, as opposed to preventative or corrective, that allows the industry to measure capability maturity on a standard scale for the digital aspects of offshore assets (Davey et al, 2014). In understanding capabilities for online management of asset lifecycles, organisations must be prepared to evaluate a range of facets that can be grouped into the general categories of people, information, systems, and processes. It is important to remember that several industry studies have shown that among these, data and information are consistently rated as the most important factor (up to 38 per cent) in understanding of subsurface risk factors that impact performance of complex assets (CDA, 2011). Big Data and Predictive Analytics Some common characteristics make oil and gas asset lifecycle management comparable to other capital intensive industries and able to benefit from the application of standard processes. One is the critical role of data and technology in opening new opportunities and driving the profitability of assets in the
face of fluctuating commodity prices, and the importance of an organisation’s agility in transforming information into insight (Glenn, 2009). Another is the sheer volume of data created by offshore oil and gas operations. Oil and gas has worked with data volumes in the multiple petabyte range for over a decade, and has also had the requisite facets of velocity and variety to make it one of the first verifiable producers and consumers of Big Data (Vesset et al, 2012). Other factors driving both the value of predictive data analytics and the adoption of standards around it are the prevalence of mergers and acquisition activity in the oil and gas industry (Deloitte & Touche, 2012), and the level of government regulation (IQ Business Group, 2014), with energy ranking in the top 3 in each category. Yet the oil and gas industry has been perceived to be slower than others in demonstrating, publishing and sharing the financial benefits that can be derived from online predictive analytics, which are reported to be as high as incremental returns on investment of 241 per cent (Nucleus Research, 2012). While some research indicates that this reluctance is the result of innovations being held by oil and gas service providers (Perrons, 2013), we present here some recent evidence of publically available examples of the value of predictive analytics in the asset lifecycle. Predictive analytics in oil and gas can be viewed as the next step in the evolution of data management capability maturity models, moving up the value chain from data. At each step in the capability maturity model, value is added and deleterious elements are removed. This is accomplished by applying
The relationship between organisational maturity levels and the capabilities and digital facets required to achieve them. Adapted from http://en.wikipedia.org/wiki/DIKW_Pyramid, after Solien, M., Green, A.R., and White, L.P., 2003, American Association of Petroleum Geologists International Conference, Barcelona, Spain www.oswindia.com
Offshore World | 16 | December 2014 - January 2015
Features Predictive analytics in oil and gas can be viewed as the next step in the evolution of data management capability maturity models, moving up the value chain from data. capabilities and by managing unique facets of Big Data for oil and gas. In the latest model (Evans and Kozman, 2014), capability maturity is measured against the complexity of an organisation to understand benchmarking and impact on financial performance. The complexity of the intelligence used for predictive analytics can be quantitatively measured with industry standard IT tools and processes that capture four important and unique aspects of oil and gas Big Data. These are referred to in the industry as the four ‘P’s’, proliferation, propagation, pervasiveness and persistence. Each of these digital facets is a unique multiplicative combination of the traditional and accepted three ‘V’s’ of Big Data but is created by the unique usages and business cases for predictive analytics in oil and gas offshore operations. Proliferation results from the rapid multiplication of data in specialised tools with potentially contradictory interpretations. It is measured by the ‘churn rate’ on data storage systems, or the percentage of data that is created, read, updated or deleted on storage systems over time. The proliferation of data creates information, but it also introduces noise into the system, which must be reduced through the application of organisational structures and the use of specialised tools and technology. Propagation is the product of distribution and duplication of information by iterative workflows in disparate disciplines. Its defining metric is a combination of variety and volume, and it can be measured by looking at the duplication of data files across storage areas managed by different functional silos in the organisation. Propagation introduces some perception into information
in the form of knowledge, but it also introduces sources of error that must be managed with standardised processes and procedures. Pervasiveness describes how knowledge expands to fill the available storage space through probabilistic and statistical realisations and heuristics. While necessary to create actionable business intelligence through reflection on the value of knowledge, this process also introduces a measurable level of uncertainty which becomes a business critical piece of metadata to be managed with optimum accepted practices. Pervasiveness can be measured by the time taken for different formats of the same information to appear on a storage system in multiple working versions and scenarios. Finally, persistence is the characteristic value of intelligence over the decadal and generational life spans of offshore oil and gas assets. This value is derived through collaborative and collective inquiry to reduce risk, and it is this value that can be measured by the results of a successful predictive analytics implementation. Demonstrated metrics for this characteristic can be obtained by analyzing the frequency, duration, and repeatability of data access across between disciplines and functions, and over time. Business and Use Cases The value of predictive analytics has been recently demonstrated through application to the large volume of maintenance and performance data available from offshore equipment. It has been repeatedly shown that surface equipment failure contributes to more non-productive time on offshore rigs than any other cause (SAS, 2014) including subsurface geologic risk, and the rapidly expanding
Online display of precursor events to an electric submersible pump failure. While these events would not have triggered static threshold alarms set by the equipment manufacturers, predictive analytics and the output of an artificial neural network were able to use this intelligence to successfully predict the failure. (Data courtesy of APO Offshore, used by permission). Offshore World | 17 | December 2014 - January 2015
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Features volume of data available from online sensors on that equipment can yield insights and predictive capabilities that improve considerably on either equipment vendor provided maintenance schedules or strictly reactive thresholds and alarms. Case studies have shown that critical equipment failures can be predicted between as much as 72 hours to 8 days before the event with suitable historical input to artificial neural networks (Kozman, 2014) and for items such as electric submersible pumps (Brule and Fair, 2014). This success would allow reductions in workover costs of as much as 4 per cent, for a return on investment of over USD 20 million per year. Further use of the same techniques has been demonstrated to be able to predict nitrogen oxide (NOX) emission levels from offshore power generation equipment in order to proactively keep them below environmental regulatory levels and avoid operating fines, and the system has been recommended for predictive capabilities around hydrate formation in subsea flow lines and stress on offshore mooring lines. Recently a business case has been built to use predictive analytics in the monitoring and control of chemical injection for pipelines. In this application, the optimum dosage of corrosion inhibitor is calculated based on the actual pipeline flow rate to control costs and guarantee integrity and safety. Other recent developments of online predictive analytics for the digital oilfield have focused on monitoring combinations of drill string vibration amplitudes and frequencies, mud pit volumes, rock sample pyrolysis and cuttings, hydrogen sulfide levels, overpull and underpull, pore pressure and drilling trajectory in order to optimise drilling penetration rates and avoid instability and failure (Bhandari, 2012). At a recent workshop sponsored by the SPE Petroleum Data-Driven Analytics Committee on Decision Making and Value Delivery, several vendors noted recent progress in using holistic predictive analytics to predict and avoid stuck pipe problems while drilling, with resulting decreases in problems that account for up to 20 per cent of non-productive time on rigs and over USD 2 billion in losses to the industry (Priyadarshy, 2014). Other operators have expressed interest in improving reliability in digital oilfield applications by using online monitoring of chemical injection skids and sample tracking to reduce downtime due to chemical injection, reduce reprocessing of products that are out of specification, and ultimately reduce operational costs by factors of between USD 1 and 10 million per year. References • The following Energistics (c) products were used in the creation of this work: Energistics, 2009: “E&P Business Process Reference Model”, Version 2.0, December 2009, http://www.energistics. org/Assets/bprefmodeldocumentfinaldec09.pdf • Bhandari, A., 2012,”Drilling & Production Data Repository & Analytics for E&P; Memory Based Reasoning Techniques for Predictive Safety and Analytics”, PointCross Inc. White Paper, 2-Jul-2012, http://pointcross.com/docs/E&P%20Data%20Repository%20for%20Analytics. pdf, retrieved 29-Dec-2014, used with permission. • Brulé, M.R. and Fair, Jr., W.B., “Fusion of Empirics and Physics Boosts Predictive Analytics”, SPE Workshop—Petroleum Data-Driven Analytics: Decision Making and Value Delivery, November 19-20, 2014, Galveston Texas, U.S.A., http://www.spe.org/events/14agal/documents/14AGALTechnical-Program.pdf • Common Data Access, Oil and Gas U.K., 2011 “Data Management Value Study”, April 2011, http://www.oilandgasuk.co.uk/knowledgecentre/DataManagementValueStudy.cfm www.oswindia.com
• Davey, M., Dohr, L., Durga, A., Elias, M., Kompella, K., Lipsey, D., and Regli, T., “Digital Asset Management Maturity Model Enables Audit, Improvement of Digital Asset Management Capabilities”, October 2014, Digital Asset Management Foundation, The DAM Maturity Model Version 2.1 http://dammaturitymodel.org • Deloitte & Touche, 2014, “M&A Trends Report 2014”, May 1 2014, http://www2.deloitte. com/content/dam/Deloitte/us/Documents/MA/us_ma_deloitte_ma_trends_full_ report_2014_052814.pdf • Evans, E. and Kozman, J., 2014, “Using Business Intelligence Maturity to Survive Change”, SMi’s 15th annual E&P Information and Data Management Conference, 6th February to 7th February 2013, London, United Kingdom http://www.ndbteam.com/media/2488/ bim5_history_and_background_update_2014_v2_4.pdf • Glenn, M., 2009, “Organisational Agility; How business can survive and thrive in turbulent times”, EMC Economist Intelligence Unit, March 2009, http://www.emc.com/collateral/ leadership/organisational-agility-230309.pdf • IQ Business Group, 2014, “Highly Regulated Industries”, IQ Business Group Technical Center of Excellence, http://iqbginc.com/clients/highly-regulated-industries • ISO, 2014: “Asset management -- Overview, principles and terminology”, International Organisation for Standardisation, http://www.iso.org/iso/catalogue_detail?csnumber=55088 • Kozman, J., 2014, “Predictive Analytics for Asset Optimisation”, UNI Strategic 2nd Annual Next Generation Digital Oilfields Conference, Kuala Lumpur, Malaysia, November 2014 and SPE Singapore section Technical Presentation, 8-jan-2015. https://www.facebook.com/ SPESingapore?fref=ts • Nucleus Research, 2012, “The Big Returns from Big Data”, Research Report M20, April 2012, https://nucleusresearch.com/research/single/the-big-returns-from-big-data/ • Perrons, R.K., 2013, “How Does Innovation Happen in the Upstream Oil and Gas Industry? Insights From a Global Survey”, DOI http://dx.doi.org/10.2118/166084-MSDocument IDSPE166084-MS Publisher Society of Petroleum Engineers Source SPE Annual Technical Conference and Exhibition, 30 September-2013 October, New Orleans, Louisiana, USA Publication Date2013 Document Type: Conference PaperLanguage: English ISBN978-1-61399-240-1 Copyright 2013, Society of Petroleum Engineers. https://www.onepetro.org/conference-paper/SPE-166084-MS • Priyadarshy, Dr. S., 2014, “Leveraging Big Data Explosion in Oil and Gas Industry: A Paradigm Shift is Needed to Remain Competitive”, Society of Petroleum Engineers, Petroleum Data-Driven Analytics Workshop, Decision Making and Value Delivery, 18-19 November, 2014, Galveston, Texas, U.S.A., http://www.spe.org/events/14agal/ • SAS, 2014, “How do we improve drilling efficiency and predict events that adversely affect safety and cost – in near-real time?”, SAS Oil and Gas Solution Brief, http://www.sas.com/content/ dam/SAS/en_us/doc/solutionbrief/oil-and-gas-improve-drilling-efficiency-106477.pdf • Solien, M., Green, A.R., and White, L.P., 2003, “Human Technology: Leadership in the Application of Intellect”, American Association of Petroleum Geologists International Conference, Barcelona, Spain, Management Forum: People, Technology, and Data - What it Takes to Get Ahead in the E & P Game • Vesset, D., Woo, B., Morris, H.D., Villars, R.L., Little, G., Bozman, J.S., Borovick, L., Olofson, C.W., Feldman, S., Conway, S., Eastwood, M.,Yezhkova, N., 2012, “Market Analysis: Worldwide Big Data Technology and Services 2012-2015 Forecast”, IDC March 2012, http://www.idc.com/ research/viewtoc.jsp?containerId=233485
Carol Piovesan Chief Executive Officer APO Offshore Email: cpiovesan@apooffshore.com Jess Kozman Chief Technology Officer APO Offshore Email: jkozman@apooffshore.com
Offshore World | 18 | December 2014 - January 2015
Features Big Data Solution
Tackling the Big Data Bottleneck The Oil & Gas industry has been constantly facing the problem of ability in accessing real-time, digital information generated by multiple fields and plants, especially in larger, deeper and more remote operations. In the backdrop of falling global oil price which is currentely a six-year low and the industry is trying to drive for minimise costs and improve efficiency, it is paramount to not only handle this explosion of information effectively, but also to be able to access important data at a moment’s notice. The article explains on Big Data solutions that aim to effectively aid decision-making, allowing users to work more effectively by focusing on accurate information and how to use it when required.
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Oil and gas companies face a longstanding industry problem in accessing data. It is one of the challenges of larger, deeper and more remote operations, but now comes with the added complexity of collecting and interpreting a huge surge of real-time, digital information generated by multiple fields and plants. In order to maintain a leading position in industry, it is paramount to not only handle this explosion of information effectively, but also to be able to access important data at a moment’s notice. Big data solutions aim to effectively aid decision-making, allowing users to work more effectively by focusing on accurate information and how to use it when required. Asia Pacific has generally been an early adopter of big data initiatives but it remains under leveraged in the oil and gas industry. Despite the fact that the amount of data is increasing exponentially, the industry’s ability to access and interpret this information is not. In the current economic climate, where the oil price has dropped to a six-year low, the drive to constrain costs and improve efficiency, particularly in areas such as smart metering, E&P and remote monitoring and diagnostics, there is increased interest in the benefits this IT revolution can bring to the bottom line.
A Collaborative Response As companies seek smarter ways to handle the influx of complex data, joint industry projects (JIPs) have begun to explore ways of saving time, money and energy through shared goals. One such initiative is Optique, a four-year JIP between several world-leading academic institutions and industry partners. It exploits recent advances in semantic technologies, in which the meaning of data is explicitly represented as part of the data model. Optique will deliver a comprehensive programme of research and technological development by bringing together leading experts from European academia and industry. University of Oslo (UiO) Professor Arild Waaler, who coordinates Optique, initiated the project in 2010 and has received backing from Norwegian oil company Statoil, DNV GL, German engineering group Siemens, and fluid Operations, a German provider of innovative cloud and data management solutions. The EURO 13.8 million (USD 17.5 million) programme was launched in December 2012, with EURO 9.7 million European Union funding.
Over recent years, a range of advanced tools have come to the market to help operators make sense of the complexities of the big data, to understand how to bolster performance across thousands of wells and, in real-time, monitor the condition of advanced equipment. But the technical limitations of today’s computing systems are already struggling to manage the amount of information that some operators are required to handle, sparking a search for smarter ways in which data could, and should, be analysed.
Built on open standards and protocols, it will integrate effortlessly with existing systems to provide a complete and generic solution to the data access challenges posed by big data. The aim is to develop a software platform to provide end-users with flexible, comprehensive, and timely access to large and complex industrial data sets – processing petabytes of well data, for example – this will allow computers to use the language users understand and are accustomed to.
Big data is often characterised and quantified by reference to ‘the three Vs’ – volume, velocity, and variety – a description originally coined by Doug Laney, now Research Vice President of technology analysts Gartner Research.¹
By enabling the end user to focus solely on the information and not where to locate complicated data stores, it allows the engineer or geologist to gather all aspects of data. This is necessary in making difficult decisions quickly, as all the information required could be stored in a combination of sources.
In explorative drilling, for instance, a company will evaluate an area, drill a well, gather real-time data and input this into its system to inform planning for the next well before drilling it. Companies may re-evaluate fields every week and in many places, drive the volume of data ever upwards.
Geologists and engineers know what they need, but the problem is posting a complex query to multiple databases. This is impossible without sending a request to IT experts, a scarce resource. End users must wait for these experts
Offshore World | 19 | December 2014 - January 2015
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Features to create complex queries. This may take up to several weeks and considerably delays decision-making. The Optique team expects its approach to reduce turnaround time for information requests from days to minutes, while also advancing data sets whose size and complexity is beyond the reach of existing technologies.
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Waaler believes that the majority of current solutions for big data focus solely on volume and processing large amounts quickly. The Optique project adds another dimension to the three Vs: complexity. The Big Picture Though traditional technologies are extremely adept at volume, they compromise
Offshore World | 20 | December 2014 - January 2015
Features on variety, velocity and complexity. Optique is unique in focusing on all these dimensions simultaneously. It also addresses trustworthiness by showing where data came from and how it has changed, providing transparency for the end user. Major oil and gas players in Asia like Sinopec or CNOOC, for example, have hundreds of terabytes of stratigraphy and seismic interpretation data that needs analysis in large and very complex databases. Current methods are inadequate with only the methods developed for big volumes of data. The goal of Optique is to focus on variety, velocity and complexity, then consume as much data as possible without compromising too much of the other dimensions. Optique aims to test and implement a long-term solution for data access that creates a tool for end users to find data on their own, which they cannot do now. Optique plans to develop tools to allow a user to query data without assistance from IT experts, and obtain the result in minutes. This can work in a similar way to an internet search engine. The user is currently highly dependent on the IT specialists, who have had years of training, navigating complicated databases. This will open up new exploratory and interactive ways of working as users will be able to access relevant data sets much quicker. Optique will be used as the central tool for exploring information and returning timely, complete, and accurate results. The current process can take around 70-80 per cent of the end users’ time but will now be able to focus fully on the task in hand. This difference also allows added time for key decision-makers, giving confidence that decisions will be based on all data available. A Challenge to Industry The Optique solution has been tried and tested in the laboratory. The next step is to implement it within the industry. DNV GL has taken on the role of bridge builder between the theoretical and practical worlds. Remaining challenges include speeding up the performance of the back end by applying massively parallelised solutions and also tools to ease establishing and maintaining installations of the Optique platform. In early 2015, the Optique team plans to present current results at a conference in Høvik, Norway. The aim is to recruit interested companies as partners to the project. The vision is that by 2020, Optique methods and technology will be incorporated into mainstream information management products delivered by trusted vendors worldwide. References Laney, D: ‘3D Data Management: Controlling data volume, velocity, and variety’; Meta Group (now Gartner) (2001)
Richard Bailey Vice President & Director - Asia Pacific & Middle East DNV GL Email: richard.bailey@dnvgl.com Tore Hartvigsen Project Manager DNV GL Email: tore.hartvigsen@dnvgl.com Arild Waaler Professor University of Oslo Email: arild@ifi.uio.no
Dear Readers, Offshore World (OSW), a bimonthly publication of Jasubhai Media & CHEMTECH Foundation, disseminates into the entire hydrocarbon industry from upstream to midstream to downstream. The endeavour of OSW is to become a vehicle in making “Hydrocarbon Vision 2025” a reality in terms of technologies, markets and new directions, and to stand as a medium of reflection of the achievements and aspirations of Indian hydrocarbon industry. OSW, the niche bi-monthly publication, has been extensively covered technological advances, reviews & forecasts, new products, processes & solutions, upcoming projects, market trends, R&D, events, products review, book review, industry surveys, environment management, news & views, interviews, awards, outstanding performance by individuals & organizations, case studies and practice oriented and well researched articles and features by industry experts for more than a decade. You can contribute in the magazine with technical articles, case studies, and product write-ups. The length of the article should not exceed 1500 words with maximum three illustrations, images, graphs, charts, etc. All the images should be high resolution (300 DPI) and attached separately in JPEG or JPG format. Have a look at Editorial calnder of OSW - www.oswindia.com To know more about Chemtech Foundation, Jasubhai Media and other publication and events, please our website – w w w.chemtech-online.com Thank you, Regards, Mittravinda Ranjan Editor Jasubhai Media Pvt Ltd Tel: +91 22 4037 3636 ( Dir: 40373615) E-mail: mittra_ranjan@jasubhai.com
Offshore World | 21 | December 2014 - January 2015
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Features Maximising Production
Enhancing Oil Recovery with Autonomous Inflow Control Devices Reservoir Inflow Control has become one of the effective strategies to maximise oil recovery. Traditional/passive inflow control devices (ICDs) are designed to balance the influx across production zones and delay the production of water and gas. Unfortunately, once these undesirable fluids do break through, a passive ICD is no longer helpful. Autonomous Inflow Control Devices (AICDs) are a new generation of ICDs with innovative fluid dynamics technology which continues restricting the production of gas and water at breakthrough improving sweep efficiency and reducing operating costs.
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As fields become mature, operators are looking into different techniques and technologies to optimise and increase the oil recovery of the reservoirs. Horizontal wells have become a common practice for increasing the reservoir drainage area by maximising contact with the payzone. Drilling technology has made this possible, but with the opportunity new challenges in the completion have arisen. A common challenge in the completion is the uneven production of the fluid along the length of the wellbore, which can occur both in homogeneous and heterogeneous formations. In a homogeneous reservoir, the fluid tends to enter the heel at a higher velocity than at the toe, also commonly known as the Heelto-toe effect. Reservoir heterogeneity also contributes to uneven influx since reservoir fluids would tend to travel easier through high permeability sections, promoting water movement through the wellbore. Reservoir flow control is important to maximise hydrocarbon production and delay the production of unwanted fluids. Inflow control devices (ICDs) integrated with a sand screen or debris filter have become a common technology to balance the influx and delaying water and/or gas breakthrough; while at the same time reducing operating costs, increasing the longevity and enhancing the oil recovery of the wells. For zonal isolation purposes, Inflow control devices (ICDs) are usually paired with swellable packers to optimise the management of the reservoir. Traditional inflow control devices or passive ICDs are an intentional choke in the completion designed to balance pressure differential across the completion in order to even flow from the production zones. Passive ICDs include nozzles, tube and helix type, each one has a different method of creating the desired pressure drop. But when undesired fluids breakthrough, passive ICDs are no longer suited to retard its influx. Halliburton’s EquiFlowŽ autonomous inflow control devices (AICDs) are the next generation of ICDs. An AICD has the ability to respond to changing well conditions without any action by the operator. When unwanted fluids reach the wellbore,
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the local AICD changes the way the fluid is moving inside. This results in a greater restriction to flow while other zones continue producing with a low restriction. Autonomous Inflow Control Devices Principles A traditional horizontal completion, exemplified on the left in Figure 1 (below), without inflow control devices naturally has an imbalanced influx rate across the length of the completion induced by frictional pressure drop in the tubing string. This problem becomes much worse with well length. Because of the high flow rate at the heel, water is able to quickly cone as shown in the left of Figure 1. Commonly water would invade the wellbore and this translates into very high water cuts at surface along with the decrease on hydrocarbon production. AICDs are self-adjusting or active inflow control devices that act as traditional/ passive ICDs during oil production. However when low viscosity fluids break through, the AICD chokes them slowing down the flow from the zone producing unwanted fluids. This action occurs autonomously, using dynamic fluid technology to discern from desired and undesired fluids. The well installation of AICDs is a simple operation and no control lines are needed. AICDs are run with the completion bottomhole assembly and installed in front of the reservoir. Therefore, reservoir fluid must pass through the AICD before entering the production tubing, and consequently reservoir zones can be controlled by AICDs. AICDs can also be run with swellable packers to create zonal isolation and prevent crossflow of fluids between zones at the wellbore.
Figure 1: A comparison of completions in a homogenous reservoir prior to water breakthrough. ICD and AICD balance influx, delaying water breakthrough.
Offshore World | 22 | December 2014 - January 2015
Features Inflow control devices (ICDs) integrated with a sand screen or debris filter have become a common technology to balance the influx and delaying water and/or gas breakthrough; while at the same time reducing operating costs, increasing the longevity and enhancing the oil recovery of the wells. The fluid mechanics behind the AICD must accomplish the following: a) determine if the reservoir fluid flowing through it is mostly oil or mostly water and/or gas; b) restrict the production when the fluid is mostly water and/or gas. The fluid identification and the fluid restriction capabilities are accomplished with the properties of the fluid and the geometry of the flow channels. Thus, directing the fluids (desired or unwanted) through different passages. The two main constituent elements of the AICD are: 1) a viscosity selector that identifies the fluid; and 2) a flow restrictor that chokes the flow of undesired fluids. These functions are accomplished by specially designed channels. These flow channels inside an AICD are optimized for different specific range of fluid viscosities.
Higher viscosity fluids flow more easily through the AICD than lower viscosity fluids. With low viscosity fluids, the high velocity of the fluid creates a vortex and a pressure drop that restricts the production of those fluids. With higher viscosity fluids, the amount of rotation decreases and the pressure drop through the AICD decreases. Testing Long-term production reliability and robustness are important characteristics for downhole equipment. Furthermore, fluid flow performance of the AICD is what truly distinguishes it from other ICDs. Therefore, extensive testing on flow performance, plugging and erosion has been made on EquiFlow AICDs.
The method used to generate the desired pressure drop depends on the fluid properties: density and viscosity, and a desired flow rate.
Flow performance of the AICDs can be characterised by measuring the pressure drop vs the flow rate at different viscosities. The flow through the device has been validated by flowing test oil, water and gas as single phase, as well as by a mixed multi-phase flow.
The restriction of the fluid in the AICD is accomplished by spinning the fluid around the exit. The amount of restriction on the device, DP (Pressure Drop), is related to the local velocity change in the fluid, i.e. the fluid near the exit will flow faster than at the entrance. The high rotational velocity near the exit hole creates a larger pressure differential. The AICD is designed so that the spinning velocity changes with the properties of the fluid, thus especially designed for causing a greater restriction for unwanted fluids.
As shown in the graph below (Figure 2, below), at a similar flow rate, the AICD shows in average 50% more restriction (pressure drop) for water than that of oil compared to a nozzle ICD. When comparing AICD vs nozzle with gas flow, the AICD shows a reduction of 54% less. Similarly at equivalent pressure drops, the AICD has at least 1.4 times more oil flow than water. The reduction of flow of gas and water represents significant savings in OPEX to operators, while at the same time more revenue from the oil production of the other zones.
Figure 2: Fluidic diode Autonomous ICD Range 3B vs .085� nozzle flow performance comparison. Offshore World | 23 | December 2014 - January 2015
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Features AICDs have proven to be a reliable technology to increase ultimate recovery and optimise reservoir sweep by equalizing influx along the wellbore.
In order to ensure that AICDs are able to withstand real well conditions, to which they can be exposed at downhole environments, they have undergone several plugging and erosion tests, circulated sand-water slurry through the AICD without any failure to the tool which simulated a 20-year lifetime. Modeling NETool™ software is Halliburton Landmark’s industry leading near-wellbore reservoir modeler and is used with reservoir input from the operator to determine the number of AICD inserts per joint, number of joints in a well, and quantity and location of swellable packers. Characteristic equations, dependent on fluid properties, have been created based on testing flow data in order to describe flow performance. Those equations have been integrated into NETool simulation software for accurate well performance prediction of the designed completion. NETool software is a steady-state, network-based simulator for quick calculation of multiphase fluid flow through a well completion and the near-wellbore region. The well completion and the near-wellbore region are represented by a distribution of nodes that may be interconnected by flow channels. Specification of the completion details leads to an appropriate pressure drop correlation for each flow channel, whether that is the formation, annulus or a range of completion paths.
Conclusion AICDs have proven to be a reliable technology to increase ultimate recovery and optimise reservoir sweep by equalizing influx along the wellbore. Operating under the combination of fluid mechanics, computer modeling, and measured performance data, the AICD is able to restrict the production of undesirable fluids, promoting the production of hydrocarbons. AICD provides a robust, reliable solution without any control lines, moving parts, or electronics and relies on no intervention of any sort. It has predictable flow performance and has been proven through extensive testing and field installation success. References • SPE 167415. The Theory of a Fluidic Diode Autonomous Inflow Control Device. Michael Fripp, Liang Zhao, Brandon Least. Halliburton • SPE166495. AICD Installation Success, Ecuador Heavy Oil: A Case Study. Brandon Least, Aaron James Bonner, Rhandy Espinosa Regulacion (Halliburton), Robert Penaranda, Tito Fernando Sampedro, Francisco Coloma (Repsol Exploracion S.A.) • SPE 170282. Plugging Testing Confirms Reliability the Fluidic Diode-Type Autonomous Inflow Control Device. Stephen Greci, Brandon Least, Liam Aitken. Halliburton. Addam Ufford (SWRi) • SPE 172077 – Erosion Testing Confirms Reliability of the Fluidic Diode Type Autonomous Inflow Control Device. Stephen Greci, Brandon Least, Halliburton. Gordon Tayloe, Stress Engineering.
Through interactive well placement and easy selection of completion components with built-in pressure drop correlations, the effects of well position, length, and completion configuration on production response are easily modelled. The effects of using an EquiFlow AICD completion can be seen by setting up the basic well parameters in the NETool software and running different completion designs with varying inflow parameters such as water cut, permeability, skin models, among others. Case Study An example of a successful installation was performed at the Ginta Field in Ecuador. The Ginta Field is a mature field, in production since 1996. Its location within the Amazonas jungle makes water handling process a delicate and expensive process. Water has to be treated and re-injected into the reservoir to minimize the impact to the environment. It has a very high mobility ratio and a strong aquifer which leads to very high water cuts, above 90% at surface. A big concern from this field was that much of the oil could be unrecoverable due to water breakthrough. With the installation of EquiFlow AICDs in the Ginta field, the operator recovered 21,000 additional barrels of oil and reduced water production as much as 34%. www.oswindia.com
Georgina Corona Cortes Product Champion – Sand Screens and ICDs Halliburton Email: gina.corona@halliburton.com John Fitzpatrick Product Manager – Sand Screens and ICDs Halliburton Email: john.fitzpatrick@halliburton.com
Offshore World | 24 | December 2014 - January 2015
Features New LNG Frontier
New LNG Supplies and Price – Oil or Hub Indexed? Insight into Asian LNG Business The advent of new LNG supplies represents a golden opportunity for Asia. The new LNG supplies are coming from US, Canada, Australia and East African projects. While most of the supplies will be oil-linked, there is still scope for the hublinked supplies that is majorly coming from US. This article highlights the new LNG supplies and at what price the LNG will flow to Asia and the nature of its linking to oil or hub indexation.
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LNG at present contributes 2.3 per cent to the world’s fuel mix. Asia is the largest consumer of LNG, with strong traditional consumers in Japan, South Korea, and Taiwan and emerging powerhouses in China and India. The two mature natural gas markets in the Asia region are Japan and South Korea; coincidentally, both markets are nearly exclusively supplied by LNG, as local production is practically non-existent. A marked shift in demand for LNG is expected, as mature markets such as Japan have limited potential for an increase in LNG consumption, while China and India are expected to be the biggest sources of additional LNG demand. Always Change a Losing Game There has been a significant progress towards the Asian gas market and its demand to increase further – need for additional imports will rise. The share of flexible LNG will grow significantly; enhanced intra-regional connectivity will also support flexible volume flows. The growth of unconventional gas in the US
will substantially increase the import portfolio of the Asian countries. Nine US projects, with a total of about 83.0 mtpa of export capacity have received full export approvals. Approved export project capacity is likely to top 90.0 mtpa in the early 2015. The National Energy Board of Canada has approved eleven LNG export projects covering 100.0 mtpa of potential capacity - out of which nine are Asia-focused. The proximity of Canada’s west coast ports to Japan, China, and South Korea is an extra advantage. Certainly Japan, South Korea, and China are expected to secure a decent amount of the gas supplies from the North America region. With the discoveries of natural gas in the Rovuma Basin, East Africa is evolving as a new LNG frontier. The location of East Africa is well suited for supplying LNG to multiple markets. It is particularly well situated with respect to India’s west coast and the emerging markets of Southeast Asia. Mozambique is expected to
Offshore World | 25 | December 2014 - January 2015
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Features A marked shift in demand for LNG in the Asia region is expected, as mature markets such as Japan have limited potential for an increase in LNG consumption, while China and India are expected to be the biggest sources of additional LNG demand.
export its first LNG cargo by 2019, while Tanzania will need to wait until 2021. The delay is on account of the different political and regulatory environment of these countries. However, East Africa has to avoid these delays in LNG supply to compete with rivals. At present, Australia is the 4th largest gas supplier to Asia, with 22.8 mtpa. With three existing LNG projects already providing over 24.0 mtpa of LNG export capacity, and with a further seven schemes under construction, Australia’s LNG export capacity is expected to exceed 85.0 mtpa by 2018. Riding the New Wave of LNG The existing LNG contracts and the latest tranches of Australian LNG are secured against long-term oil-indexed supply contracts. However, large regional differences in gas prices have driven buyers to seek a shift away from traditional oil-linked LNG pricing, and towards one with more transparent prices based on gas-on-gas economics similar to other commodities. Many Asian buyers looking to trim costs have secured attractive long-term contracts that are linked to the US domestic gas prices (Henry Hub), and are being offered by planned US export projects. Many buyers believe that the gas indexation-based LNG deliveries will provide lower LNG prices in the long term.
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The marketing proposal for Sabine Pass suggests that a fee of USD 1.75/mmbtu and a 10 per cent fuel surcharge would be sufficient to cover the cost of turning gas into LNG. At current spot freight rates, transport costs would add about USD 3.75/mmbtu to deliver Sabine Pass gas to Asia. This suggests that at USD 4.0/ mmbtu cost of the feed gas, Gulf Coast LNG would cost about USD 10.0/mmbtu delivered to Asia. At Henry hub gas price USD 6.0/mmbtu, the delivered cost would be around USD 12.1/mmbtu. The cost to produce natural gas in the US plus the cost to transport LNG to international markets is significantly below crude prices on an energy equivalent basis and oil indexed gas market prices that present a substantial value arbitrage opportunity with an increase in oil prices. However, the possible Hub indexation will still be relatively small, and there is no assurance that all US exports will be sold on a Hub basis. US exports could be equivalent to 15 per cent of Asian demand in 2025; it is by no means certain that all the volumes will go to Asia. South America and Europe are likely to be an attractive destination for US exports, and these regions are likely to account for more than 50 per cent of US export. In other words, Asian buyers may want LNG at Henry hub-linked prices, but such volumes are
Offshore World | 26 | December 2014 - January 2015
Features The higher cost structure of projects in Canada and new frontiers such as East Africa ensure that oil-linked pricing will remain a mainstay or possibly a mix – 80% oil-indexed and 20% hub-indexed, given that these projects need this type of linkage to justify multi-billion dollar investments.
limited. Therefore demand will need to be satisfied by other projects, which may be priced higher. Moreover, the cost advantage has diminished following the oil price glut resulting in a fall of oil prices. LNG prices from oil-linked contracts are now appearing more cost-competitive against US projects. At USD 70.0/barrel, LNG would cost around USD 10.5/mmbtu to Asia, which is quite close to Henry Hub gas price at USD 4.0/mmbtu when other associated costs are added to it. The irony is that, given the huge cost structure of LNG exporting facilities, it is very likely that a large proportion of Asian-sourced LNG will have to be mainly, if not fully, linked to oil to secure project financing. Therefore, safeguarding returns on large liquefaction plant projects, coupled with long-term oil-indexed LNG contracts currently in force, means that Asian LNG pricing will remain predominantly linked to oil, certainly to the end of this decade. The impact of future US LNG export volumes on Asian prices is likely to be marginal. Finally, the higher cost structure of projects in Canada and new frontiers such as East Africa ensure that oil-linked pricing will remain a mainstay or possibly a mix – 80% oil-indexed and 20% hub-indexed, given that these projects need this type of linkage to justify multi-billion dollar investments. Solving the LNG Equation The future of LNG is positive with steady demand growth in its traditional markets for gas to power generation and the opening up of new markets and players in a whole new batch of countries. There is a growing momentum in Asia LNG prices predominantly based on a prices of oil = USD 10 – USD 17/mmbtu LNG Contract Price Indexation%
11%
15%
at USD 90/bbl
USD 9.90
USD 13.50
at USD 110/bbl
USD 12.10
USD 16.60
the multi-segment small-scale LNG and the opportunities for using LNG as a transportation fuel substitute, driven by the divergence of oil and gas pricing, and the environmental benefits of LNG as a cleaner burning fuel. High LNG prices are the only factor posed to dampen the enthusiasm for gas demand, as many countries are increasingly unwilling or unable to afford highpriced supplies. Delivered LNG pricing is the key for opening new markets and increasing the growth in demand. The days of the traditional oil-indexed LNG supply contracts are not under threat till 2020 and the future is looking for more transparent prices based on gas-on-gas economics. Asian buyers have recently looked to secure planned US LNG exports linked to the low Henry hub gas price that are priced competitively when compared with oil-indexed LNG contracts, especially with high oil prices. However, with the falling crude oil prices, the LNG price equation is getting more complex. The pricing linked to the US domestic gas is probably not the best solution for Asian buyers, but it will take a while before LNG price based on LNG/ gas market fundamentals emerge in a market dominated by oil-linked pricing. Upcoming LNG export projects are not free from their own set of challenges and are capital intensive, and hence, securing finance will require LNG export prices that recognise acceptable risks. Based on upcoming projects planned or in construction, a delivered LNG price to JKM (Japan Korea Marker) in the range USD 9.5 – 14.0/mmbtu is necessary to cover the costs of project development, which effectively provide a minimum Asian market price for these new projects. To no surprise, US, Canada, Australia, and East African countries such as Mozambique and Tanzania will be some of the largest natural gas exporters by the end of this decade. Aforementioned countries will definitely take the market share of LNG export from large LNG exporters such as Qatar and Malaysia. The way forward for the LNG trade however might not be smooth due to continued unexpected demand and supply shortfall.
Cost to deliver gas from Sabine Pass to Asia = USD 10 – USD 12/mmbtu USD/mmbtu
Low
High
Henry Hub
USD 4.00
USD 6.00
Capacity
USD 1.75
USD 1.75
Shipping
USD 3.75
USD 3.75
Fuel
USD 0.40
USD 0.60
Delivered Cost
USD 9.90
Source: MarketsandMarkets Analysis
USD 12.10
Priyank Srivastava Analyst - C&M MarketsandMarkets Email: priyank.srivastav@marketsandmarkets.com
Offshore World | 27 | December 2014 - January 2015
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Features Automation Technology
Smart Refinery: Enhance the Productivity of Plant in Manifold While advance in sensors, wireless, predictive technologies and automation have significantly changed the way refineries operate today, the complexity in refinery operations continues to increase with refiners adding units to provide flexibility in processing opportunity crudes, and relying on crude blending to give the right feedstock properties to best utilise the refinery design coupled with complying with new and existing government regulations. The article explains on smart refinery solutions that could enhance improvements to energy efficiency, safety, health and environmental issues, value addition, cost control, mass and energy balance and overall energy conservation of a refinery.
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When managing a complex and dynamic operation like an oil refinery, having the predictability to minimise unplanned shutdowns and slowdowns is critical to safe, reliable and profitable operations. Having the visibility and insight to ‘be alerted and take timely corrective action’ is the characteristic of a worldclass operation. It means being more informed and smarter about each decision made and action taken. In reality, ‘smart’ technologies have been around the refining industry for a couple of decades. In fact, process automation, control and monitoring technologies get smarter every year. But are they actually improving refinery business? Are they helping address the impending skilled workforce crisis all industries are facing? Are they helping provide flexibility to change production strategies to profit from opportunity crude oils? Are they giving confidence to operate the refinery at rated capacities while ensuring safe operating conditions? Access to subject matter experts whether onsite or remotely? Technology enables your staff the ability to operate reliably, safely, and profitably. What is referred to as the ‘Smart Refinery’. The complexity in refinery operations continues to increase with refiners adding units to provide flexibility in processing opportunity crudes, and relying on crude blending to give the right feedstock properties to best utilise the refinery design. Product specifications have simultaneously become more geographically complicated and restrictive. Regional and local fuel specifications including the use of biofuels often lead to multiple product blending steps and transport restrictions. In addition, refiners require special processing for their unique needs in asphalts and lubricating oils. Complying with new and existing government regulations is demanding on resources. Now, more than ever, efficiency and consistent productivity are required to stay viable in a commodity based market with far-reaching boundaries for competitors. Advances in automation are enabling refiners to achieve these efficiencies and improve the overall performance of their plants - decreasing costs and increasing profits. The cost and size of computing elements, the continuing increase in communication bandwidths, advances in software and mathematical analyses and better modeling capabilities have provided new optimising tools for increasingly reliable refining operations. This is not just a vision of the future; it is today’s
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reality for top quartile performers. Many new developments such as improved process sensors and measurement devices are being applied. The era of the ‘smart refinery’ is today. How is the smart refinery different? In a very important way, it isn’t. The operating objectives for the refinery still include: • Maintaining safe operations • Enhancing environmental stewardship • Sustaining high equipment availability and reliability • Maximising plant and product value through efficient and optimised operation • Ensuring refinery staff maintain required skills and stay current with changing technology Advances in automation technology including the implementation of pervasive sensing to bring process and asset condition data to both operations and maintenance enable new and better ways to integrate work processes and improve the timeliness and accuracy of decisions. Significant improvements in plant performance are possible when the right expertise is applied at the right time; when personnel have the information they need to make quality decisions quickly, and when they have access to specialised supplemental expertise when they need it. Most processing facilities are balancing the needs for safety, quality, profit, environmental compliance, and reliability against the challenge of applying the right knowledge across organisational and geographic boundaries while simultaneously reducing costs. Therefore, many companies are taking advantage of technologies such as virtualisation, remote monitoring, enhanced KPIs and dashboards, co-location of personnel, control room consolidation, etc. For example, a US West Coast refiner implemented wireless vibration sensors on essential pumps to monitor asset health (to improve production availability) where a wired solution was not cost effective. Similarly, a US Gulf Coast refiner showed sustained 50 per cent reduction in reliability risk (increased availability) by incorporating a smart refinery technology enabling refining staff the ability to
Offshore World | 28 | December 2014 - January 2015
Features Advances in automation technology including the implementation of pervasive sensing to bring process and asset condition data to both operations and maintenance enable new and better ways to integrate work processes and improve the timeliness and accuracy of decisions. effectively use additional information. It should be stated that technology alone is not the solution – staff need to be trained on how to use the new information. The new smart refinery will complement the console operator, control engineer and maintenance technician, improving their efficiency and decision-making with timely, actionable information. With any new technology, ease of use and ease of integration with existing operations are key factors. For example, Emerson Process Management carefully considers the effects of smart refinery technologies, not only on present staff, but also on successfully transferring critical knowledge to younger operators as a significant number of older, experienced operators retire. The continuing evolution in digital computing and communication capabilities – and the application of these technologies – has led to fundamental differences in the way refineries operate and will continue to change the way they operate in the future. However, staff needs to be trained to use the technology effectively to capture the benefits of new information. Improvements in information and processes in place to utilise the information can be worth millions of dollars a year, and competitive cost advantage. In today’s economic environment, management demands that new investments provide low risk and expected rate of return on both new and existing assets, particularly automation assets. Investments in smart refinery technology often provide some of the highest economic paybacks of any possible investments, and these expected returns can be determined in advance and demonstrated after implementation. Both new and existing plants can get quick return on investment and sustainable value by investing in smart refinery technology. New plants can easily take advantage of state-of-the-art technology and processes right from initial startup, but existing plants can also benefit. Existing refiners can start small and gain experience by implementing upgrade programmes at a measured pace that can be self-funding with benefits from early installations paying for the later stages. Smart refinery operators now have the opportunity to leverage these investments to enhance the safety, reliability, productivity and profitability. Increasing regulatory requirements, refinery complexity and demands for higher quality continue to place higher economic demands on refineries while reducing operational margins. The new smart refinery can offset these barriers. Technology enables and enhances this smart refinery. For example, wireless technology extends sensor reach, enabling smart refinery operators to monitor areas of the plant that were previously inaccessible due to location or significant wiring installation costs. Because of automation, the smart refinery has the ability to predict maintenance issues, alert and take timely action to prevent failures and greatly improve plant and process reliability. Not only does this translate into more efficient operation, higher product quality and reduced maintenance costs, it also means that the smart refinery has improved and increased uptime, which adds dollars to both the top and bottom lines.
Smart refining offers more than just leveraging state-of-the-art technology. Evolving developments are leading to new methods and procedures for plant operation; increased monitoring capabilities that continually check the pulse of the refinery; advanced modeling and analytics that compare refinery production against expectations; earlier detection of abnormal conditions or imminent failure; and tools that can plan future operation with increased confidence. These technology developments enable significant changes in the way refineries operate. Most refineries were originally constructed with the minimal amount of instrumentation required to operate the plant. What we see in the future is more use of collaborative software tools, and standards-based software and hardware to reduce ongoing support costs. The operating systems of the future will process, store and analyse much more data and information, including many more sensors in primary and secondary locations and a wider range of live video and spectral data. This data will be analysed and displayed as information to be acted on in a timely manner. The technologies that are being put into the marketplace today are only the stepping stones to that future. Another smart refinery trend is toward increasing levels of remote operation. Individual refineries can be geographically dispersed. Control rooms can be many miles from the physical units. Complete information on the state of the plant can be communicated to the remote control room. Fully reliable automated plant startup and shutdown systems enable safe remote operations. Today, major sites operate across hundreds of miles. In the future, smart refineries will continue this trend, placing greater demands on reliable automation and communication. Fortunately, the automation developments that support these remote operations have kept pace. While smart sensors, wireless, predictive technologies and automation continue to make the smart refinery even smarter, these enablers do not replace the power of the human decision-making process, nor the accompanying responsibilities. Technology must be used, not only to make the smart refinery more productive and more profitable, but to make it safer as well. Smart refinery operators have the opportunity to deploy these technologies to ensure the safety of their personnel, communities and the environment, while enhancing the productivity and prosperity of the enterprise. It takes a dedicated and deliberate level of commitment and vision on the part of refinery owners and operators to leverage this smart enabling technology to allow it to transform their facilities into safe and profitable smart refineries. Emerson has taken a leading role in providing smart refinery solutions, including improvements to energy efficiency, safety, health and environmental issues, value addition, cost control, mass and energy balance and overall energy conservation. Tim Olsen Refining Consultant Emerson Process Management Email: Tim.Olsen@Emerson.com
Offshore World | 29 | December 2014 - January 2015
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Features Energy Watch
Energy Commodity Prices Continues to Move Down Price Review: November - December 2014 Prices of most energy commodities continued to move down in the month of November and December 2014. During this period, NYMEX crude oil (light sweet) futures prices declined by 33.9 pe rcent, the most amongst major energy commodities under review (without considering very lowly priced (Certified Emission Reduction) CER futures). Interestingly, European Union allowances (EUA) futures prices (traded on ICE) was the only energy commodity to move up i.e. by 14.5 per cent.
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Continuing on past few months’ momentum, NYMEX (CME) crude oil (light sweet) futures started the month of November at USD 78.78 per barrel, down by 2.2 per cent from previous month’s close. Oil prices continued trade under pressure from a stronger US dollar and fears Saudi Arabia could announce another price cut. Further with oil prices going down right through the two-month period, the opening day’s high of USD 80.98, eventually emerged as two-month’s high. After the support from surprise Bank of Japan’s expansion of its bond-buying program, US dollar was further by the release of higher than expected Institute for Supply Management’s US October manufacturing index. Apart strengthening dollar, China’s official manufacturing PMI dropping to a five-month low of 50.8 in October from 51.1 in September, added to the weak oil demand sentiments. Additionally, Saudi Arabia, the world’s biggest oil exporter, altered oil prices sold to US and Asian buyers – viewed as a way to keep itself competitive amid tanking oil prices and a threat to US domestic producers - aided the fall in oil prices. Later, falling oil prices witnessed few intermittent sessions of respite helped by a US supply report that a smaller-than-expected increase in crude
inventories as well as data release showing US jobless rate hitting a six-year low. But overall, oil prices maintained a down-trend. Helping the downtrend, in addition to downward momentum, was the cut in demand forecast by OPEC (Organization of the Petroleum Exporting Countries) for its oil in coming years as well as sustained concerns over the health of the Eurozone’s economy. Later, signals from OPEC as Kuwait’s oil minister said he doesn’t expect the OPEC to cut oil output, when it meets in Vienna on November 27, kept the downward pressure on oil prices. Data showing Japan unexpectedly fell back into recession in the third quarter, highlighting concerns about demand, also added the bearish sentiments to oil prices. By mid-October, oil prices steadied albeit with downward bias as market participants awaited for the upcoming OPEC meeting. Oil prices then got some brief boost after the People’s Bank of China announced a surprising swath of interest-rate cuts intended on boosting its economy. Later, however with OPEC eventually deciding to keep its production levels unchanged, oil prices stooped down to more than a four year low. The fall in oil prices continued in the month of December as well encompassing a brief period of some short covering.
Futures price movement (November - December 2014)
280
80
250
74
220
68
190
62 NYMEX Heating oil (USd/gal) - LHS
160
NYMEX Gasoline (USd/gal) - LHS NYMEX WTI crude oil (USD/barrel)
56
ICE Rotterdam Monthly Coal (USD/MT)
130
50
Source: Bloomberg
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Offshore World | 30 | December 2014 - January 2015
Features
Futures price movement (November - December 2014) 0.13
7.50
0.10
6.50 ICE-ECX CERs (Euro/tonne) - LHS
0.08
NYMEX Natural gas (USD/mmBtu)
5.50
ICE-ECX EUAs (Euro/tonne)
0.05
4.50
0.03
3.50
0.00
2.50
Source: Bloomberg
On December 4, Saudi Arabian Oil Co reduced its official selling prices for all oil grades bound for Asia in January by between USD 1.50 and USD 1.90 a barrel, compared with December. It also cut prices for all crude grades to the US. by between 10 cents and 90 cents a barrel. Oil markets have recently been interpreting Saudi Arabia’s monthly price adjustments as signs of the oil producer’s intent to retain market share through a price war rather than adjusting export volumes – in turn adding to the bearish sentiments in oil prices. Later the bearish rally in oil prices was also supported by forecasts that a global glut of oil will persist into the first half of next year. Additionally, the reports on US drilling (an uptick in the rig count, despite the falling price) and Japan’s economy (a downward revision to Japanese GDP) aided the decline in oil prices. Barring short sessions of respite from falling oil prices largely on hopes for stimulus from global central banks, the bearish rally sustained unabated. Increase in US oil inventory levels along with cut in oil demand expectations for 2015 by OPEC and IEA, ensured the slide in oil price continued. News of a dramatic interest-rate hike in Russia (17% from 10.5%) in a bid to support its currency and a further slowdown in China’s manufacturing sector kept the downward pressure on oil prices. Though oil prices again intermittently received support from strong US economic growth numbers and later on reports of a fire at oil storage terminals at a Libyan oil terminal, by large oil prices continued to be down-trended. Hints by several OPEC ministers to maintain their oil production and may even increase it if a new client emerges, ensured the sell-off in oil prices right till the end of the month. As a result, NYMEX crude oil futures registered their month-low of USD 52.44 on the last trading session of the month. Finally, NYMEX crude oil futures closed the month at USD 53.27, registering a fall of about 33.9 per cent in two-month period of November and December 2014. Futures prices of oil derivate i.e. heating oil and gasoline (both traded on NYMEX-CME platform) also traversed movement similar to crude oil prices in the two-month period of November-December. While heating oil futures prices declined by about 26.6 per cent, gasoline futures prices moved down by about 33.9 per cent amidst rising US oil production. On similar lines, the other
major energy commodity natural gas futures traded on NYMEX (CME) platform registered a price fall of 25.4 per cent in past two months. Though in early stage of this two-month period, cold snap in US prompting gas demand as well as on forecasts of cooler-than-normal temperatures in key heating markets, supported gas demand sentiments. However, later, warmer winter and less-than-expected decline in US natural gas stockpiles took a toll on natural gas prices. Additionally, weak global economic data and a sharp drop in crude oil prices also contributed to downward pressure on gas prices. Another energy commodity, ICE Rotterdam monthly coal futures prices too moved down i.e. 8.4 per cent in the two-month period. Drop in the cost of mining and shipping the fuel (with fall in oil prices), as well as weaker demand from the power-plants helped the fall in coal prices. Additionally, forecasts for decline in coal demand from China, the world’s largest consumer of the fuel also added to bearish sentiments in coal prices. Finally in emission segment, as mentioned before EUA futures prices traded on ICE platform jumped by 14.5 per cent in the two-month period. Nations in the European bloc considering reforming the carbon market to reduce a surplus sooner than proposed by its regulator, was a major factor in helping the jump in EUA prices. (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 | 31 | December 2014 - January 2015
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news features
Southern Africa’s Oil and Gas: An Energy Game Changer The authors elucidate the economics of oil and gas of the Southern Africa region and share their views in successfully using the vast hydrocarbon resources for beneficiary of the local rather than simple export.
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Recent discoveries of major gas and oil deposits in southern Africa could dramatically improve the prospects for Southern African countries— reducing imports, driving economic growth, and lowering CO 2 levels in power generation.
New Discoveries The highest-profile recent discoveries are in Mozambique, where estimates of offshore gas reserves range from 50 to 100 trillion cubic feet (tcf ) in depths of 1,000 to 3,000 meters (about 3,200 to 9,800 feet).
Scattered pockets of natural gas off the coasts of South Africa and Mozambique were all that southern African countries seemed to offer in terms of oil and gas resources. That changed in 2010 and 2011, when a potential 500 trillion cubic feet of gas was identified across Mozambique and South Africa, along with 11 billion barrels of oil in Namibia. Together, these countries’ gas reserves equal those of Canada or Venezuela.
The largest potential reserves are in South Africa’s shale beds beneath the Karoo region, estimated by the US Energy Information Administration to exceed 400 tcf. These reserves may now be extracted in an economically viable manner, thanks to hydraulic fracturing techniques.
These discoveries could transform the southern Africa region. In this paper, we examine some of the economics of oil and gas in the region, consider their possible impact, and offer recommendations for handling these resources. The scope of our study is South Africa and its neighboring countries, since they form a large, connected economy with the potential for significant local use and beneficiation of hydrocarbon resources rather than simple export. 1
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In addition to gas, oil deposits amounting to an estimated 11 billion barrels were found off the coast of Namibia in mid-2012. This discovery has spurred further exploration along the west coast of South Africa in the Orange River basin, an extension of the Namibian fields (see Figure 1). Yet the full potential of oil and gas in the region remains uncertain for three reasons. First, most fields are in the early-exploration phase; the estimated volumes are technically recover-able resources, not proven reserves. Second, gas and oil sources have relatively high extraction costs: They’re either
Offshore World | 32 | December 2014 - January 2015
news features deepwater sources, such as those off Mozambique, or unconventional gas sources, such as Karoo’s shale gas and Botswana’s coal-based methane. Third, new areas are opening for exploration promising even greater volumes, for instance the southern extensions of the fields off the coast of Namibia and the coal bed methane deposits in Botswana. Southern Africa’s Energy Outlook Southern Africa’s economy is based on coal, and is short of liquid fuels. In 2011, South Africa imported 130 million barrels of crude oil. 2 This high import volume exposes South Africa to both political and supply risk. The country’s primary source of crude oil is Iran, followed by Saudi Arabia, Nigeria, and Angola. In June 2012 sanctions against Iran led to the cancellation of all imports from the country and a rapid search for alternative sources. South Africa’s total refining capacity is 250 million barrels per year, or about 700,000 barrels per day. Of the daily total refining capacity, 500,000 barrels is crude oil and 195,000 barrels coal-to-liquid synthetic fuel. So with total consumption at about 24.5 billion liters (6.5 billion gallons) of fuel annually— mainly petrol and kerosene—there is a 7 per cent shortfall of 1.5 billion liters (nearly 400 million gallons) of fuel per year, accounting for South Africa’s need to import refined products. Against this backdrop there have been a series of fuel shortages due to refinery-maintenance issues. The most significant event was in January 2012 when several planned and unplanned refinery shutdowns combined with problems at the Single Buoy Mooring facility off Durban to cause widespread fuel shortages. Also, South Africa’s refineries are old, an average of 43
years old, and need increasing levels of maintenance—and in some cases, significant upgrades—to keep them operational, efficient, and in line with environmental standards. With fuel prices regulated, funds for making those upgrades are limited. Further, South Africa’s general energy environment is constrained. Electricity utility Eskom operates with a very narrow reserve margin—about 17 per cent, and much lower when affected by maintenance—and depends on diesel generation to cover peak demand. 3 Two open cycle gas turbines (OCGTs) running on gasified diesel started on 11 August 2012. They consume an estimated 220 million liters (nearly 60 million gallons) annually—about 2.5 per cent of South Africa’s total diesel consumption. 4 Southern Africa has abundant and cheap sources of coal, making it still the primary energy source; it provides 85 per cent of Eskom’s total generation. The region’s coal-fired power fleet is the cheapest option for producing power and at current coal production, reserves could last at least a century. However, coal dependency for generating electricity and for conversion to liquid fuels makes South Africa one of the most CO 2-intensive countries in the world. Were South Africa part of the European Emissions Trading Scheme (ETS), the Sasol Secunda plant would be the single largest CO 2-emitting site. The Potential: Generation Gas is a low-cost, flexible power source. It can provide generation primarily above the base load in peak-demand periods. Replacing expensive diesel generation during these hours would also contribute to reducing the cost
Offshore World | 33 | December 2014 - January 2015
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news features of electricity generation for Eskom and mitigate price rises for consumers (see Figure 2).
refineries. The proximity will also reduce freight costs and provide more flexibility in scheduling supplies and managing stocks.
Coal is expected to maintain a high position in the southern African energy mix. The South African Department of Energy’s Integrated Resource Plan expects a coal share of 46 per cent in 2030, with OCGTs expected to contribute about 8 per cent of the mix. If gas were increased to 25 per cent and based on combined cycle turbines, the coal share could be reduced to a third of total generation capacity.
Gas is a more complex source, requiring conversion from gas to liquid. With PetroSA’s Mossel Bay gas-to-liquids (GTL) plant operating at 60 per cent of capacity, according to the company’s annual report, there is immediate potential to increase the utilisation of existing assets. PetroSA’s plan to extend its operations to the F-O gas field should bring capacity back up to 100 per cent. 5
Gas generation also plays a role in enabling the build-up of renewable energy sources. Wind and solar units experience down periods when they cannot generate due to intermittent loss of wind or when clouds block the sun. Since these periods are unpredictable, there is a need for short-term generation sources to cover loss of output; gas turbines with start-up times of between 10 and 30 minutes are ideal to meet this need. The more southern African countries develop renewable energies, the greater will be their need.
The large gas sources in and around southern Africa offer the possibility of increasing GTL refining capacities to further address South Africa’s short position. An additional GTL plant would enable South Africa to close the shortage of liquid fuels. We will consider the full feasibility of this option below.
Finally, since gas generates only about half the CO 2 emissions of coal and two-thirds those of oil-fired power facilities, increasing the gas share would significantly lower South Africa’s overall CO 2 emissions.
The chemicals industry is a critical part of South Africa’s economy. The industry’s USD 23 billion in annual revenues contribute more than 5 per cent to the gross domestic product (GDP), accounting for approximately 25 per cent of all manufacturing activity. 6 Despite its local importance, the industry’s poor access to local feedstock and remoteness from major developed markets are fundamental weaknesses.
The Potential: Liquid Fuels Namibian oil is the simplest source of newly discovered liquid fuels. When in production it will provide a local, relatively secure additional source of crude oil for the region. Reduced reliance upon the Middle East and Angola would substantially improve the security of crude-oil supply to South African
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The Potential: Chemicals
South Africa’s current feedstock sources are Sasol’s coal-to-liquids Secunda plant and imports from the Middle East and Far East. Chemicals margins are
Offshore World | 34 | December 2014 - January 2015
news features declining and Sasol in particular is suffering as a result of cheaper imports. Its competitive position was weakened further with the removal of import duties on polymers in January 2012. This has deepened a strategic shift in the South African chemicals industry to one that focuses more on higher-value chemicals products, greater customer service, and innovation. The new hydrocarbon sources have the potential to transform this landscape. Local sources would secure low-cost supplies of feedstock for southern African chemicals companies, reducing their reliance on imports and improving profitability. This would open up new possibilities for manufacturing further down the value chain. This leads to a fundamental question: Where should the chemicals feedstock come from? Today the major production operations are around the Secunda plant in Sasolburg and the six other refineries. The new feedstock sources are off the western and eastern coasts and in the Karoo.
energy basis, achievable margins are significantly greater (see Figure 4). This means that southern Africa’s energy infrastructure would have to be developed to use gas rather than oil. The way to do this is to add GTL refining capacity in South Africa. One option would be for PetroSA, the country’s national oil company, to convert its planned Mthombo refinery project from a conventional refinery to a GTL plant. Rather than adding more conventional capacity in an unattractive refining market, this would give PetroSA a leading position in a market where margins are potentially more attractive. However, this would leave PetroSA exposed to changes in the energy landscape and ‘unhedged’ should the oil-gas gap narrow. It would also constrain competition. Another option could be for a local player or group of players already active in southern Africa to construct a plant. This would result in downstream integration, foster competition, and provide balance across a number of suppliers and sources.
There are a number of possible answers. While using Namibian oil could allow expansion of the existing refineries, potentially building new capacity, Namibian oil is a relatively small source and offers few cost advantages over existing crude oil sources. Further, due to overcapacity in Europe and the United States, refining margins are falling worldwide (see Figure 3). Adding southern African conventional refining capacity would expose the market even more to the dynamics that are making refining unattractive in most regions.
Constraints and Solutions The development of southern African oil-and-gas solutions is subject to several constraints, one of which is location. Mozambique gas is several hundred miles from the major consuming regions in South Africa. Either more pipelines would have to be built down to Natal, the Eastern Cape, and Gauteng, or gas could be brought into South Africa using a liquefied natural gas (LNG) terminal.
The opportunity, then, is first to take advantage of offshore gas and, ultimately, shale gas. With gas trading at about half the price of oil on a recoverable-
An LNG terminal solution would give flexibility to address the related constraint of supply stability. In the event that supply is interrupted from a principal
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news features source, a pipeline leaves no room for alternatives. LNG, by contrast, would allow South Africa to import from whatever low-cost supplier it could find. This also reduces the need for South Africa to become politically dependent on its neighbors. There is a time factor involved in the location constraint. Immediate supplies of gas are available on the coasts of South Africa, either from Mozambique or from PetroSA’s Mossel Bay fields. The largest supply, however, is unconventional shale gas from Karoo in the west. The best solution would be to build capacity to offer maximum flexibility around the two sources—and Mossel Bay looks ideal. Implications The South African government has the opportunity to use oil and gas discoveries to boost its economic and social development. Low-cost energy and feedstock sources have the potential to give South Africa the same cost advantages in manufacturing enjoyed by other hydrocarbon-rich nations. In the short term, such sources also could alleviate the shortfall in electricity generation and facilitate development of renewable energy sources. To capitalise on these opportunities, South Africa must support the development of gas as a low-cost energy source and a feedstock source for chemicals beneficiation. It should work with Eskom and other potential electricity providers to explore options for gas generation around the Southern Africa Power Pool. Finally, as owner of PetroSA and sponsor of the Mthombo refinery project, the government should consider redesigning the plant as a GTL facility. Mozambique’s government has more direct opportunities to capitalize on the gas found off its shores. Supplies are already set for export, with Anadarko and ENI preparing two LNG liquefaction facilities. However, the real development opportunity for Mozambique is the potential for bringing gas onshore—first for energy generation and second, for liquid fuels and chemicals manufacturing. The imperative for the government is to make sure it explores all possible opportunities and puts in place policy and investment frameworks needed to promote that development. With their aging assets, refiners and retailers are at some risk from new developments. They will find it difficult to compete with new large-scale, efficient refining facilities, whether GTL or crude oil-based. They should first explore options for partnerships in emerging projects to exploit gas supplies. Secondly, they should concentrate on maximizing the performance of their legacy assets. Thirdly, they should focus on commercial positioning around sources of potential cost advantage, crude oil from Namibia, new-build refineries, or a GTL plant. Chemical companies have the most to win from the exploitation of gas in the region. With a looming worldwide oversupply of chemical capacity, only regions with a source of local, low-cost feedstock will stay competitive. Southern African gas offers that opportunity. Chemical firms must advocate the immediate exploitation of offshore natural gas and opportunities to www.oswindia.com
access it as feedstock, whether in ethane from pipelines, LNG deliveries, or a GTL plant. Over the longer term, the Karoo shale-gas basin offers the greatest, albeit least well-defined, opportunity. Chemical companies must treat this undeveloped area as an option that has the potential to increase greatly in value over time. Right now they must ensure that the opportunity is fully recognized and developed. As the chemical composition and economics become clearer, chemical firms must take increasingly concrete steps to work with the companies developing the basin to access its gas as feedstock. Finally, they must work with governments and their customers to identify manufacturing opportunities and assist in investing to realise them. A Range of Options and Opportunities The discoveries around the coast of Southern Africa present major opportunities for South Africa, Mozambique, and Namibia—from reducing the cost and carbon intensity of power generation, to creating a supply of chemical feedstock to drive manufacturing development. The challenge is for those involved to find the best way to take advantage of these opportunities. There are no simple paths to combining the locations, production timing, logistics, and market opportunities. However, those governments and companies that create and develop a range of options will most likely benefit from long-term development—the kind that can transform the southern African economy. References • Beneficiation is local processing to add value to raw materials in the country or region where they are extracted. • Source: South African Petroleum Industry Association • Source: Eskom annual reports • Source: Malusi Gigaba, Minister of Public Enterprises, in a report to parliament • The F-O gas field is 4 0 kilometers southeast of PetroSA’s F-A production platform and will be developed as an extension of the existing infrastructure. • Monetary figure is in U.S. dollars. Source: Statistics South Africa.
David Richard Partner ATKearney Email: david.richard@atkearney.com Wim Plaizier Patner ATKearney Email: willem.plaizier@atkearney.com
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SCANNING FOR OPPORTUNITIES IN WEST AFRICA How AVEVA PDMS, AVEVA E3D and laser scanning gave Ariosh real competitive advantage in challenging revamp projects.
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As Owner Operators increasingly turn to laser scanning to extend the life of their assets, Nigerian leading EPC contractor, Ariosh has secured a valuable competitive advantage by pioneering laser scanning competence in Nigeria. Supported by AVEVA PDMS™, and now AVEVA Everything3D™ (AVEVA E3D™), Ariosh can generate accurate as-built 3D models and drawings, perform virtual installations and generate job cards. This capability has helped them to deliver several brownfield projects with the accuracy needed to achieve right-first-time installation. Their most recent success was the laser scanning of several platforms in Nigeria, after a major international OO had been forced to halt modification work due to unforeseen design clashes. Recovering flare gas In 2012 Ariosh was awarded the contract to provide follow-on engineering services during a revamp of the OO’s seven offshore platforms. Production needed to be stepped up in order to provide approximately 300 million cubic feet per day of natural gas feedstock for a refinery which will convert natural gas currently being flared into high-value, clean transportation fuels. Serious problems The challenges of executing brownfield projects became apparent following the completion of detailed engineering and fabrication drawings by an international EPC. The OO experienced significant clashes during installation of the first modifications on the first platform. They suspended work on the first platform and proceeded to the next one, only to encounter the same problems. Worried that history would repeat itself with the remaining five platforms, the upgrade programme was put on hold. Ariosh was contracted to help recover the situation.
fabrication and fabrication assurance, and installation on the first three platforms was completed in only 18 months. Design verification should obviously be performed prior to fabrication. However, on this project, fabrication of the spools and structures had progressed to over 70% before Ariosh’s involvement. These spools and structures were then scanned in the fabrication yard to allow Ariosh to conduct virtual installations of the asfabricated spools to make recommendations for correcting installation issues in advance. Rework was also minimised. Modifications performed at Idmon, the fabrication yard based in Warri, Nigeria, were also verified by laser scanning. Scans of the modified spools and structures were superimposed on the design models within AVEVA E3D to ensure compliance with Ariosh-issued construction drawings. Although it took Idmon about a year to implement all Ariosh’s recommended corrections, the resulting 98% first-time fit achieved a substantial reductionin overall installation time and provided the OO with a cost saving of around 40%. Clash checking and reporting could all be efficiently performed within AVEVA’s single 3D model environment, thus saving Ariosh’s OO client considerable time and cost during project execution. Implementation of AVEVA solutions Serving a wide client base, Ariosh operates a range of engineering and design solutions. From AVEVA’s solution offerings, it currently uses AVEVA PDMS with AVEVA Laser Model Interface™ (AVEVA LMI™) and AVEVA E3D. Ariosh had adopted AVEVA PDMS in 2010, having used many different 3D design software tools and finding that none compared to AVEVA products in terms of versatility and efficiency, especially when handling large and complex 3D models. It has more recently also
Heavy cost impact The problems needed to be resolved quickly to avoid the serious impact of increased costs, schedule delays and lost production, as well as safety and reliability concerns. The direct costs alone were heavy; the barge used for installation cost over 100,000 USD per day. Modification work during installation offshore can take at least twice as long as modifications in the fabrication yard. Solving the problems Ariosh started by laser scanning all seven platforms and then modelling the new design, using AVEVA PDMS for the first two and AVEVA E3D for the remainder. These 3D models were superimposed on the laser data and clash checked using the built-in clash management capabilities. Design verification, completion of Offshore World | 37 | December 2014 - January 2015
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adopted AVEVA E3D, which adds more value with its improved Access Platforms, Stairs & Ladders (SLH) modelling and its built-in capacity to read and work with the full laser dataset. ‘AVEVA PDMS has been our first choice of 3D modelling package,’ explained Yusuf Alege, Technical Manager, Ariosh. ‘Its seamless integration with laser data (thanks to the add-on of AVEVA LMI) is a particular advantage, and many of our clients specify PDMS for their design. Our designers are highly competent in PDMS and preferred working with it over any other 3D package, until we migrated to AVEVA E3D and found it to be even better. AVEVA PDMS and AVEVA E3D, which automatically integrates laser scan data into its system, were critical to the success of this project.’ When AVEVA E3D was released in 2013, Ariosh immediately saw value in its new capabilities, especially those related to laser scanning. As a result it chose to migrate from AVEVA PDMS to AVEVA E3D, a decision made even easier by the two-way database compatibility. All potential installation issues, including clashes, can now be more easily identified and resolved, while fabrication issues are avoided through the ability to automatically produce fabrication drawings directly from the AVEVA E3D design model. We started off using AVEVA PDMS on the first two platforms and then, once AVEVA E3D was released, we switched to using AVEVA E3D on the remaining five. We required seamless integration of 3D model and laser data for clarity and consistency, and AVEVA products achieve this for us,’ Yusuf continued. ‘AVEVA E3D’s handling of laser data proved superior to any other package we had used, or even heard of. Our objective in selecting AVEVA E3D was to ensure error-free design and first-time-fit installation. It more than met our expectations. ‘Ariosh and AVEVA worked very well together during the implementation and we were very impressed with the prompt responses of AVEVA’s support team. We were also provided with an AVEVA E3D migration licence that enabled us to toggle effortlessly between AVEVA PDMS and AVEVA E3D,’ Yusuf added. Ariosh’s laser scanning offering is now powered by AVEVA E3D. The Ariosh team’s significant experience with other laser data handling software made it very easy for them to learn AVEVA’s laser scanning solution. While the team took a little while to get used to AVEVA’s laser model interface, the self-explanatory AVEVA laser scan data manual allowed engineers to be operational very quickly. Outcomes for Ariosh Ariosh was very impressed with the outcome of the project. ‘AVEVA E3D’s BubbleView™ technology removed the import/export bottleneck between the 3D design package and the laser data software to obtain a realistic view of laser data within the design model,’ Yusuf said. ‘The BubbleView feature improved our www.oswindia.com
productivity by 20% and the quality of our deliverables was also higher. AVEVA E3D was a game-changer on the project. We recorded a 20% increase in productivity relative to PDMS immediately upon deployment, and we expect still further increases as our designers become fully familiar with the AVEVA E3D interface.’ Ariosh intends to be the partner of choice in West Africa for the delivery of EPCI projects, and underpinning this drive is a commitment to cutting-edge tools. Ariosh has built its work processes around AVEVA E3D, which has significantly increased efficiency in its design verification process and has inspired improvements to the company’s PipeFit™ Assurance work process. Furthermore, the BubbleView feature of AVEVA E3D enables superb synchronisation between 3D model and laser data, which significantly improved the team’s design efficiency. AVEVA solutions have added significant value to Ariosh’s business processes, through features such as the automation of pipe fabrication drawings. The company is currently evaluating the use of AVEVA Bocad Steel™ for structural steel detailing. Future opportunities Ariosh has invested in the development of its laser scanning capabilities at an opportune time. First, there is significant demand for laser scanning services in Nigeria due to the hundreds of aging onshore and offshore facilities requiring extensive revamp projects, and which generally lack accurate as-built documentation. Many companies planning revamp projects have little or no reliable as-built information and must rely heavily on laser scanning to create this, and for design verification. Second, the Nigerian government’s ‘Stop Routine Gas Flaring’ campaign is driving demand for laser scanning services as operators seek to phase out gas flaring. Ariosh is well placed to capitalise on its laser scanning capability, with its experience of using AVEVA PDMS and AVEVA E3D, and its track record of success. After significant problems, the revamp project in Nigeria is classified as a significant success, with Ariosh having been able to complete the previously suspended programme in a timely and cost-effective manner. Ariosh expects to work with this OO, among other clients, on similar projects in the region in the future. Above Images Caption: AVEVA E3D BubbleViews™ showing the virtual installation of brownfield modifications (deck extension, pig launcher and piping hookup) on one of the seven production platforms. [Colours: grey – laser model of the as-built platform; other colours – 3D design model]. Images courtesy of Ariosh.
Tracey Nabe Regional Marketing Lead - North America AVEVA
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Tekla Improves Offshore Efficiency at NPCC Engineering Limited The leading offshore company NPCC Engineering Limited (NEL) is a joint venture of NPCC, Abu Dhabi and Arcadia Shipping, Mumbai, carrying out design and engineering activities for oil and gas upstream industry. NEL’s Quality management system (ISO 9001:2008) is certified by BUREAU VERITAS and it has carried out several design and engineering projects of new well head platforms, subsea pipelines and topsides modifications on well head/process platform.
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NEL had a task to create well head platforms at WO-16 and SB-14 cluster field located at South East of SH process complex of Mumbai High Field in water depth of 75 to 80m. The project scope consists of 5 new well head platforms and 2 major deck extension on process complexes. NEL was already equipped with high end softwares needed for oil and gas upstream projects such as PDS, PDMS, STAAD, Sacs and Caesar. There was need to have 3D software to handle their all structural needs start from concepts to engineering/detailing/ fabrication to erection. After extensive evaluation and anticipating upcoming challenges NEL decided to switch from traditional 2D based platform to 3D BIM based process & technology. Their obvious choice was Tekla and they decided to implement the software in this fast track green field well head platform project. WO-16 Cluster & SB-14 Wellhead Platforms Project This project is a new well head platform which is supported on four legged fixed jacket structure with two legs having single batter and other two legs have double batter. Jacket is made of tubular sections, welded together, and it is anchored in seabed with main/skirt piles. Jackets have spider deck at top level and have diagonal bracing in all faces connecting horizontal framing levels. It also includes boat landing, buoyancy tank, anodes, riser, skirt pile guide and lifting/ upending trunnion etc. Maximum jacket weight is 2100MT. The platform top side consists of sub-cellar deck, cellar deck, main deck and aluminium helideck. Top side also includes building module, vent boom, crane pedestal, solar panel supporting platform, well head access platform, walkways, stairways, ladders and railings. Maximum topside weight is 1900MT. Interoperability Contributed Towards Success: The design and modeling of the structure was done with the Tekla Software right from the early stage. Modeling began with the main steel & secondary steel structure as soon as the calculations were completed with SACS. The model is completed later with all the tertiary elements such as the connecting plates, equipment supports, access platforms, padeyes, stiffeners, node plates, cut outs and penetrations as the vendor information was made available. The robustness of the software in dealing with the changes was benefcial in the overall smooth execution of the project.
Complexity Handled with Ease: NEL structural design team worked based on the requirements of client and came up with relevant technical and design issues to be developed and incorporated in the Tekla model. Tekla technical support team and NEL design team worked together during development and customized few tools as per the project requirement. Although the project had time constraint, NEL managed to achieve defined results in relatively short period with the help of versatile Tekla software and the excellent implementation support provided by the Tekla team. In the process of project execution Tekla local support team got valuable feedback on a few small requirements of offshore industry incorporation. This can further fine tune Tekla offerings to all offshore players. Other Salient Features of Tekla That can Help on a Fasttrack Project: • Easy to learn and implement.
• Tekla Structures allows simultaneous access by multiple users to the same model. • Web-link facility allows engineers to review the model simultaneously as it is getting developed. • Tekla Structures users can streamline the design and fabrication processes, ultimately ensuring the highest level of quality in project deliverable. • Free tools Tekla BIMsight for every NEL team member involved in projects to communicate collaborate with others. NEL Received the Following Benefits: • Generating detailed structural material take off list very quickly and accurately during design phase of job. • Monitoring weight of the structure and the position of the deck structures center of gravity during the design phase. • Direct output of 2D drawings to present to the end user or client and the relevant authorities for approval or certification purposes thus reducing human errors and checking time drastically. • The software allows user friendly interface with Piping or E&I models in PDS for reviews and complete clash free structural model. • Import of main steel frame directly from analysis software SACS. • Using Tekla 3D structural model for regular design review kept it fully coordinated from any conflicts with the equipment, piping, cable trays and access routes. Our Ambition is to Multiply Your Potential to Think and Achieve Big: • With an ambition to multiply its customers’ potential to think and achieve big, Tekla provides a BIM (Building Information Modeling) software environment that can be shared by contractors, structural engineers and detailers and fabricators of all materials. • Tekla software is made for creating, combining and distributing highly detailed, constructable 3D models. Information-rich models lead the way for production control and more collaborative and integrated project management and delivery. This translates into increased productivity and elimination of waste, thus making construction and buildings more sustainable. • Tekla Corporation drives the evolution of digital information models and provides competitive advantage to the construction industry. Tekla software is used worldwide to model all types of structures. Tekla and Trimble: • Tekla was established in 1966, and today it has customers in 100 countries, offices in 15 countries, and a global partner network. Since 2011, Tekla has been a part of the Trimble Buildings Group. • Trimble group’s solutions tightly link office-based process and information with the field crew. Trimble Design-Build- Operate platform responses to the needs of owners and the AEC industry by increasing productivity and reducing rework. Tekla Bimsight: Tekla BIMsight is a free professional tool for construction project collaboration. Anyone can combine models, check for clashes, markup and share information using the same easy-touse 3D environment. With Tekla BIMsight project participants can identify and solve issues already in the design phase.
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Inspectahire relies on the FLIR GF320 OpticalGas Imaging camera for maintenance inspections and hydrocarbon leak detection in the offshore oil and gas industry Established in 1981, Inspectahire is a leading international supplier of specialist remote isual inspection technology and solutions to companies in many industries around the orld. Supported by the most advanced technologies around, Inspectahire helps its customers manage their safety, pro¬tability and environmental impact of their assets. When the company is tasked with the detection of fugitive hydrocarbon emissions, FLIR’s GF320 Optical Gas Imaging (OGI) camera is their preferred technology to use.
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Inspectahire offers equipment rental, contracting and project engineering services supported by a team of skilled engineers who have a wealth of inspection knowledge and experience. Their expertise extends to a wide range of equipment and assets, both onshore and offshore, and in all environments – including harsh and hazardous. All Inspectahire’s advanced inspection solutions are carried out in accordance with the requirements of ISO 9001 best practice. Oil & gas industry Having worked for three decades in the Oil & Gas industry, both in the North Sea and worldwide, Inspectahire has built up a strong expertise in this sector. Safety and cost are two of the biggest concerns in the offshore oil and gas industry today. Inspectahire realizes this as no other and therefore aims to tackle those challenges by using the best technologies available.
Director of Inspectahire. “At Inspectahire we strive to identify and offer the best available technological solutions for all remote inspection scenarios.” Safety & economy Dangerous gas leaks are a concern to every oil and gas production plant. Not only do some of the gases harm the environment, but the leaks also cost companies substantial amounts of money. “The company has been using thermal imaging cameras for a very long time to detect dangerous gas leaks,” comments Cailean Forrester “Thanks to thermal imaging cameras, we can easily detect gases in difficult to reach or hazardous locations. And we can help companies prevent costly downtime of their production plant.”
“The offshore oil and gas industry are proactive in their search for the best technologies for detecting emissions that may affect the safety, profitability and environmental impact of their assets,” comments Cailean Forrester, Managing
Contact measurement technologies vs. thermal imaging “We have been using certain contact measurement tools like laser detectors or leaks sniffers,” says Cailean Forrester. “But the problem is that you have to go right up to the object, which is not always safe or even possible. In other words, this approach is limited and not very precise. With a thermal imaging camera like
Inspectahire has been using thermal imaging cameras for a long time to detect dangerous gas leaks.
Inspectahire has been using thermal imaging cameras for a long time to detect dangerous gas leaks.
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Small leaks can become big ones, that is why it is important to be able to detect them in an early stage.
the GF320 however, you can keep a safe distance and still detect gas leaks with great precision.” Accurate and ergonomic The Inspectahire team is using the GF320 optical gas imaging camera for maintenance inspections and for all its hydrocarbon detection jobs, in hydrocarbon production plants or for the inspection of any material that uses hydrocarbon as a fuel. The GF320 camera offers a range of tangible benefits compared to traditional hydrocarbon leak sniffers, because it can scan a broader area much more rapidly and monitor areas that are difficult to reach with contact measurement tools. The portable camera also greatly improves operator safety, by detecting emission at safe distance. “The camera is very ergonomic and very sensitive,” comments Cailean Forrester. “If a hydrocarbon leak is there, you will certainly see it with the GF320 camera, even if it is a small one. Small leaks can become big ones, that is why it is important to be able to detect them in an early stage. With the GF320, we are sure of an accurate and reliable detection.”
GF320 Optical Gas Imaging (OGI) camera The FLIR GF320 is an optical gas imaging camera designed to help the oil and gas industries better control hydrocarbon emissions, thereby preserving the environment, improving operational safety and minimizing revenue loss. The thermal imaging camera is designed for use in harsh industrial environments. It takes advantage of a state-of-the-art focal plane array detector and optical systems tuned to very narrow spectral infrared ranges. This enables the camera to image infrared energy absorbed by hydrocarbon gas leaks. Images are processed and enhanced by the FLIR High Sensitivity Mode feature to clearly show the presence of gases against stationary backgrounds. Gases detectable by the camera appear on-screen as smoke plumes. In the offshore oil and gas industry, the camera offers operators a preventive maintenance tool to help spot hydrocarbon leaks in tanks, pipelines and facilities. The FLIR GF320 can be used both for finding gas leaks and maintenance inspections. For more information about thermal imaging cameras or about this application, please contact: FLIR Systems India Pvt. Ltd. 1111, D Mall, Netaji Subhash Place, Pitampura, New Delhi – 110034 Tel: +9111-4560 3555 Fax: +91-11-4721 2006 E mail: flirindia@flir.com.hk Website: www.flir.com
With the GF320 camera, you can keep a safe distance and still detect gas leaks with great precision.
Imagery used for illustrative purposes only
Offshore World | 41 | December 2014 - January 2015
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india news ONGC Bags Exploration Block Offshore New Zealand Right Time to Build and Raise Strategic Crude Oil New Delhi: ONGC Videsh Ltd, the overseas Reserves: ASSOCHAM
N K Verma, Managing Director & CEO, OVL
investment arm of the State-owned Oil and Natural Gas Corp (ONGC), has won an offshore oil and gas exploration block in New Zealand, the first by an Indian firm in that country. The exploration Block – 14TAR-R1 – is in New Zealand’s Taranaki basin, in the same region which has several commercially successful oil and gas fields. New Zealand launched the bidding round in April, offering five offshore and three onshore release areas. OVL has taken a 12-year permit in the Taranaki Basin.
OMV New Zealand, a subsidiary of Austrian oil major OMV and already producing oil and gas offshore Taranaki, was awarded another offshore Taranaki and one Pegasus permit. Narendra K Verma, Managing Director & CEO, OVL, said that the fim’s ‘maiden entry into the hydrocarbon province of Taranaki offshore basin in New Zealand shall provide an opportunity to explore interesting hydrocarbon potential in the region and act as a foothold for greater participation in the far-east region.”
New Oil & Gas Contracts may be Tough on Investors New Delhi: The petroleum ministry is looking to rework several of the contentious clauses in the proposed model revenue sharing contract, including those related to the escrow account, production targets and monetisation of petroleum in the reservoir, which private players argue is an attempt to take a share of the profit from sale of rights in the blocks. Sources said that the review of the proposals circulated in the draft model sharing contract is based on feedback received from stakeholders. A key concern, industry players said, relates to monetisation. The draft contract under which the next round of oil and gas blocks will be auctioned seeks to close all the loopholes in the earlier production sharing agreement for which the government was criticised by the CAG. In the new contract, the government has proposed to have complete control of cash flows, operators cannot profit from block sales and are subjected to an environment damage liability that is more stringent than under the Nuclear Liability Act. According to the draft, released for comments, the tough conditions will cause private companies to review their plans. In effect, it seeks to put a lid on selling of stakes in oil blocks by companies without sharing the gains with the government.
Oil India Shale Drill in Northeast Mumbai: Oil India has sought permission from the government to hunt for shale oil and gas in several of its blocks in Arunachal and Assam. At least two of the PSU’s blocks in Arunachal Pradesh - Deomali and Jairampur - and three in Assam - Chabua, Dibrugarh and Dumduma - hold potential. The Union cabinet has already approved the ministry of petroleum and natural gas’s proposal to allow state-run oil and gas firms to hunt for shale oil and gas in their existing acreages. Top officials said Oil India believed Dishang Shales in the 120-sq-km Deomali tract alone could prove to be a major find for the company. www.oswindia.com
Mumbai: It would take just about half in building strategic crude oil reserves throwing a tempting opportunity for India to increase the storage capacity by raising investment multi-fold in physical infrastructure besides signing forward contract with the exporting countries. “It is once in several decade opportunity for India to scale up its strategic oil reserves at much higher level than even three months’ consumption, which itself is a long way to go for us at this point of time,” a paper by industry body ASSOCHAM has pointed out. In the backdrop of falling global crude price, India’s crude oil import bill has been drastically decreased in the last six months. It will cost India 40 per cent less to build strategic energy reserves at the present prices. But to take the advantages, the government has to take speedy initiatives on underway projects because who knows by the time our storage capacity for the reserves is ready the crude would not have bounced back. The government should quickly get the viable projects examined and take quick decisions while those in the private sector should be given the support in terms faster RBI clearances and easier tax administration. Presently, there are three strategic reserves - one in Andhra Pradesh and two in Karnataka and four more facilities are proposed at Bikaner in Rajasthan, Rajkot in Gujarat, Padur in Karnataka and Chandikhole in Odisha. The government may be planning to spend about ` 50-60 billion on building these capacities. Given the opportunity, the government must commit and increase this investment at least three-four times to ` 150-200 billion and let the oil marketing companies invest in the same along with the special purpose vehicle- Indian Strategic Petroleum Reserves Ltd (ISPL), the report suggested.
Gas Pricing Regime should be Remunerative for Producers: Panel New Delhi: A Parliamentary committee has said that the domestic gas pricing regime should be remunerative so as to ensure fresh investment in the sector even as it stated that a hike gas price will heighten the subsidy burden. The Standing Committee on Finance, headed by former Oil Minister M Veerappa Moily, said that all actions of the government should be dictated by ‘public interest’ and also fair to all stakeholders. “The Committee is of the firm opinion that it is also important to have a policy regime that ensures remunerative price to gas producers as well in order to stimulate fresh investments in the sector,” the report tabled in Parliament said. Simultaneously, it added the government should devise an optimum pricing formula, which is fair to all stakeholders and also safeguards the long term interest of economy. The Committee also said that the increase in price of gas will heighten the subsidy burden on the exchequer, as the MRP of urea is statutorily controlled. Among others the Committee also include former Prime Minister Manmohan Singh.
Offshore World | 42 | December 2014 - January 2015
india news Allocation of 116 NELP Blocks Gets Delay in Statutory Clearances: OilMin
Parl Panel Pitches for Bold Initiatives to Contain CAD
New Delhi: As many as 116 exploration blocks under the New Exploration and Licensing Policy have been affected due to delay in grant of statutory clearances. “Exploration operations have suffered in NELP exploration blocks due to delay in grant of various statutory clearances required from Ministry of Defence and other central government or state government Dharmendra Pradhan, regulatory authorities,” Minister of Petroleum Oil Minister and Natural Gas Dharmendra Pradhan said in a written reply to the Lok Sabha. Exploration operations have suffered in 116 NELP exploration blocks due to delays in grant of Petroleum Exploration Licence by state governments including 76 blocks affected due to delay in Defence Ministry approval.
New Delhi: A Parliamentary Panel has called for ‘bold policy initiatives’ including steps to contain the current rupee depreciation so as to get complete handle over the current account deficit (CAD) situation. With petroleum prices having shown a southward trend, the situation is ripe for ‘bold policy initiatives’ by the government to maintain the trend of easing of CAD, Standing Committee on Finance headed by Veerappa Moily said in a action taken report tabled in Lok Sabha. Noting that the unrelenting situation of CAD of the past few years has eased a bit alongside fiscal deficit, the Committee expected the Government will not let this opportunity go a begging.
On the progress of revival of sick oil and gas wells, Pradhan said, it is a continuous process. “Revival of sick oil and gas wells is a continuous process and all the contractors under PSC (production sharing contract) regime, undertake several measures on regular basis to revive the sick wells to increase production,” he said. The revival process includes measures such as periodical well intervention through work-over jobs, well stimulation, installation of suitable artificial lift systems and side tracking of wells etc. Sick wells are also abandoned by the contractors either on completion of their economic life or due to fact that they could not be economically revived. He added that the revival of sick wells of fields of ONGC and Oil India under nomination regime is monitored on continuous basis by Directorate General of Hydrocarbons (DGH).
This Panel has said that rupee depreciation needs to be contained to bridge the CAD-Gross Domestic Product (GDP) divide. Simultaneously, competitive domestic production needs to be reinforced along with opportune policies to maintain the growth in exports. This would go a long way towards maintaining sustainable CAD at an acceptable level of GDP. “The CAD is a serious malaise gnawing at the vitals of the Indian economy and needs to be treated as an overriding priority”, the report said. India’s CAD in the first half (April-September) of this fiscal was USD 17.9 billion (1.9 per cent of GDP) as against USD 26.9 billion (3.1 per cent of GDP) in same period last year, data released by Reserve Bank of India (RBI) recently showed. CAD remains within RBI’s comfort zone of 2.5 per cent of GDP.
Refining Giants on Expansion Mode in Gujarat
IOCL to Upgrade Nigerian Refineries
Ahmedabad: Gujarat, which is already hailed as the refining hub of the world, is likely to be increased refining capacity.
New Delhi: India’s biggest refining and oil marketing company, Indian Oil Corporation (IOC), may consider taking up modernisation of existing refineries in Nigeria subject to allocation of equivalent oil equity in producing blocks with substantial recoverable reserves in its favour. As Nigeria is a major oil producer and India’s oil security is on priority, it would be a win-win for both the nations.
Over the next few weeks, petroleum giants Reliance Industries Ltd (RIL), Indian Oil Corporation (IOC) and Essar group will ink agreements pledging ` 1,12,000 crore to build and expand refineries. All three companies may sign memoranda of understanding during the upcoming Vibrant Gujarat summit in January 2015.
Nigerian National Petroleum Corporation (NNPC) has four refineries, two in Port Harcourt (PHRC) and one each in Kaduna (KRPC) and Warri (WRPC). The refineries have a combined installed capacity of 445,000 barrels-per-day (bpd). As a result of poor maintenance, theft and fire, none of these refineries have ever been fully operational. In recent years, these refineries have often operated at their lowest levels of just 30 per cent of capacity. New refineries have been planned for several years now, but lack of financing has caused several delays. Currently, the PSU refiner buys crude from Nigeria. Although IOC seeks larger supplies of Nigerian crude on term contracts, nearly 90 per cent imports are spot market deals. Nigerian crude is preferred under the low-sulphur category for IOC refineries. In 2013-14, the company imported about 8.5 million ton of Nigerian crudes.
This will consolidate Gujarat’s position as the world’s leading supplier of fuel almost doubling the total refining capacity from the existing 66.7 MT per annum. While IOC plans to invest Rs 40,000 crore to build a greenfield refinery in Mundra - the fourth in Gujarat - RIL will set up a new ` 42,000 crore facility next to its existing refinery in Jamnagar. Essar too plans to pump in ` 30,000 crore on expanding capacity in Jamnagar. With its Mundra refinery, IOC will raise processing capacity to 100 million tonnes. The capacity of its 13.7 MT refinery in Koyali near Vadodara is being raised to 18 million tonnes at a cost of about ` 5,000 crore. Already, two single buoy moorings (SBM) at Mundra are being operated by IOC and HPCL. This facilitates transport of crude to the refineries. RIL, on the other hand, wants to build a 400,000 barrels per day refinery at its Jamnagar complex to process cheap, heavy crudes. RIL’s existing refining complex - world’s biggest - at Jamnagar Reliance can process 1.4 million barrels per day of oil.
Offshore World | 45 | December 2014 - January 2015
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india news Petroleum Pipeline from Siliguri to Parvatipur Kolkata: Oil Minister Dharmendra Pradhan has pushed for laying of a petroleum product pipeline from Siliguri to Parvatipur in Bangladesh for supply of fuel. Pradhan met Dr Tawfiq-e-Elahi Chowdhury, Energy Advisor to the Prime Minister of Bangladesh, to discuss the pipeline.
Former Indian Oil Chairman Appointed Gulf Petrochem Advisor New Delhi: UAE-based oil manufacturing group Gulf Petrochem has appointed former Indian Oil chairman as its Strategic Advisor and member of Board of Directors.
“Both sides discussed the need to greatly enhance cooperation in the oil and gas sector to the mutual benefit of people of the two countries,” an official statement said. Pradhan requested cooperation from Bangladesh government for materialisation of Indo-Bangla product pipeline from Siliguri to Parvatipur, which is a part of Prime Minister Narendra Modi’s view that North-East is our Natural Economic Zone (NEZ). India, he said, is keen on setting up of marketing infrastructure in Bangladesh, including infrastructure development projects on a case-to-case basis. “The two sides agreed to have frequent interactions to further (this) cooperation,” it added.
Essar Group Pacts with Rosneft Mumbai: Essar Group has signed a USD 10 billion contract to import crude oil from Russia over a 10-year period. Essar signed a deal with Russia’s top crude oil producer Rosneft to buy 10 million tons a year of oil for 10 years beginning 2015. The deal was among a host of agreements being signed during Russian President Vladimir Putin’s visit to the country for talks with Prime Minister Narendra Modi. Moscow-based OAO Rosneft Chairman Igor Ivanovich Sechin said the agreement was to ship by sea as much as 10 million tons of oil per year to Essar Group. The oil deal, Sechin said, could be extended beyond 10 years.
ONGC Awards Contract to Technip New Delhi: State-owned Oil and Natural Gas Corp (ONGC) has awarded a EUR 100 million contract to French firm Technip to build an oil and gas terminal at Odalarevu in Andhra Pradesh. Technip’s scope of work for this contract includes basic design, detailed engineering, procurement, fabrication, inspection and testing, installation, precommissioning and commissioning of the new onshore terminal facilities which will be integrated to the existing terminal. The terminal, which will have a capacity of 6 million standard cubic meters per day, will receive gas from ONGC’s Vashistha and S1 fields in Bay of Bengal, Technip said in a statement here. The Vashistha and S1 fields are located 30-35 km off the Amalapuram coast in the KG Basin, off the East Coast at water depths of 250 to 700 meters. www.oswindia.com
Brij Mohan Bansal, Strategic Advisor, Gulf Petrochem
Brij Mohan Bansal, with over 40 years of experience in the energy sector, will oversee Gulf Petrochem Group’s strategic expansion plans especially within the mergers and acquisitions space as well as managing the process of integration and diversification.
Bansal has overseen and assumed strategic responsibility for the growth of Indian Oil and Kenya Petroleum Refineries besides identifying and initiating foreign and domestic strategic partners. As an IMD Certified Project Director bestowed from the International Projects Management Association, Bansal will lead the group’s project formulation, implementation and operations ensuring that quality, safety and cost efficiencies are maximised.
Gas Discovers in Tamil Nadu Chennai: Bharat Petroleum Corporation Ltd (BPCL) ha announced that its partner Oil and Natural Gas Corporation (ONGC) has discovered gas in one of its oil blocks in Tamil Nadu’s Nagapattinam district. The block is held jointly by ONGC and Bharat Petroresources Ltd (BPRL), a subsidiary of BPCL. ONGC had previously entered into an exploration partnership agreement with BPCL for the Cauvery basin. According to BPCL’s note to National Stock Exchange, the exploration well in the block - MD 5 - was drilled down to a target depth of 2,175 metres and trapped natural gas in the block flowed at a rate of 61,800 cubic meters per day. It also showed the presence of condensate (a form of volatile light oil) at the rate of 9.6 cubic meters per day. The discovery has been termed Thirunagari Gas Discovery after the name of the nearby village where the gas was found. This is the second hydrocarbon discovery made by ONGC in the NELP-IV block. The first discovery in this block was made in October 2012, which established the presence of crude oil. However, these sets of discoveries are exploratory in nature and the two companies will be starting the appraisal to find out the exact amount of reserves in the block. If found commercially viable, production may start from Mid 2015. BPRL has a 40 per cent interest in the block and the rest is held by ONGC.
Offshore World | 46 | December 2014 - January 2015
india news Unviability of Production of Natural Gas by GSPC
OPEC’s Face off against Shale will Gain for India: CRISIL
Ahmedabad: Petroleum & Natural Gas Minister, Dharmendra Pradhan, has informed the Rajya Sabha in a written reply that Gujarat State Petroleum Corporation (GSPC) has not intimated about the start of commercial production of gas from its discoveries in the Block (KG-OSN-2001/3) in KG basin. As per the approved Field Development Plan, initial production of 1.0 MMSCMD (Miliion Standard Cubic Meters per Day) and peak production of 5.0 MMSCMD is envisaged.
Mumbai: Excess global supply, weak demand growth and OPEC’s unwillingness to cut production despite glut is expected to result in sharp fall of 25-30 per cent y-o-y in crude oil prices in 2015. This along with recent deregulation of diesel prices is likely to benefit India in multiple ways, according to the latest report by CRISIL. CRISIL says on account of the above two factors, underrecoveries (loss on sale of regulated fuels below cost price) on petroleum products would plummet by over 60 per cent to ` 500-550 billion in 2015-16 from ` 1,400 billion in 2013-14.
GSPC had requested this Ministry to nominate Gujarat Narmada Valley Fertilizers & Chemicals Ltd (GNFC) for supply of DDW field gas at price and delivery terms actually negotiated between GSPC and GNFC based on arm’s length principles. GSPC has also informed that GNFC agreed to purchase gas produced from DDW field at USD 8.5/MMBTU. In this regard, on 14th November, 2014, this Ministry has decided that the matter of pricing of DDW gas would be as per the New Domestic Natural Gas Pricing Guidelines, 2014 notified on 25th October, 2014. PPAC has notified the gas price of US $5.05(GCV) based on above mentioned guidelines to be applicable from 1st November, 2014. For development of discoveries made in Ultra Deepwater & Deepwater Areas, (well head shut-in pressure > 690 bars, bottom hole temperature > 150 degree centigrade), it has been decided to give a premium for all such discoveries after the issuance of these guidelines, on the price determined as per the abovementioned
OVL Eyes Stake in Israel’s Leviathan Gas Project Mumbai: ONGC Videsh (OVL) is eyeing to mark a entry in Western Asian nation oil & gas industry by strike a deal in Israel’s prolific Leviathan gas project. The state-run oil firm sought guidance from the petroleum ministry to pursue exploration and production (E&P) investments in Israel. Leviathan, discovered in 2010 off Israel’s Mediterranean coast, is poised to be the world’s largest gas find in recent times and production is slated to commence in 2017. In July, according to reports by consultant Netherland Sewall & Associates (NSAI), the reserve estimate was revised to 21.93 trillion cubic feet from 18.91 tcf earlier.
The sharp drop in petroleum product under-recoveries will significantly reduce the government’s contribution to ` 250-275 billion in 2015-16 from Rs 707 billion in 2013-14. Upstream oil companies will also benefit as their share of under-recovery burden (PSU upstream companies sell crude produced from their fields at discounted prices to OMCs) will reduce to ` 250-275 billion in 2015- 16 from ` 670 billion in 2013-14
Revenue-share Model to Debut with Marginal Fields New Delhi: The ministry of petroleum and natural gas (MoPNG) is likely to usher in the much-anticipated revenue-share model for the nearly 60 small and marginal fields surrendered by PSUs ONGC and Oil India and are being auctioned. The ministry is currently preparing the policy guidelines for the auction, and if the Cabinet Committee on Economic Affairs (CCEA) approves the proposals, it would mark the launch of the new bidding mechanism for hydrocarbon explorers, as recommended by the C Rangarajan Committee. The move comes at a time when it is widely believed that auction of hydrocarbon acreages under the next (10th) round of the New Exploration and Licensing Policy (NELP) regime will be based on the revenue-share model. The MoPNG also intends to offer an attractive fiscal regime for those who bid for the marginal fields. This is in keeping with the government’s strategy of plucking the low-hanging fruit first when it comes to augmenting the country’s oil and gas output.
India Refiners Surge amid Oil Bust New Delhi: Oil’s slump has almost doubled the value of India’s big, state-owned refiners, outpacing the rest of the industry from China to the US. The companies had been forced to make a large proportion of sales at below cost for over a decade. Now, they can profit from fuels after India’s new government saw its opportunity in falling oil prices to deregulate the market without bothering its inflation targets. OPEC’s decision to sit on its hands in the face of an oil glut has only accelerated share gains. India’s big three state refiners - IOCL, BPCL and HPCL - are up 53 per cent, 84 per cent and 131 per cent respectively over the year to Dec. Hindustan Petroleum is the best performing oil stock in the world, outpaced Asia’s biggest refiner - China Petroleum & Chemical Corp, and even the largest US processor - Phillips 66. Whether India’s refiners can maintain their tear will depend on the constancy of politicians and markets. In the meantime, there’s a new-found freedom to make money.
Videocon-BPCL Discover Oil in Brazil Mumbai: A consortium of Videocon Industries, Bharat Petroleum Corporation Ltd (BPCL) and Brazilian state-owned company Petroleo Brasileiro SA (Petrobras) has announced ‘significant’ discovery of oil, off the coast of Brazil. “The well 3-SES-186 was drilled 103 km from the city of Aracaju, Brazil, and 10 km from the discovery well in 2,467 meter of water. The well will be drilled to 6,060 meters. This accumulation is part of the exploratory project in the deepwater Sergipe-Alagoas basin,” Videocon said. Petrobras operates the consortium with 60 per cent interest in partnership with IBV-Brazil (an equal joint venture of Videocon Industries and BPCL), which holds the remaining 40 per cent. “The result obtained in this well confirms the extension of the light oil reservoirs previously discovered by the ‘Farfan’ discovery well.
Offshore World | 47 | December 2014 - January 2015
www.oswindia.com
india news M Ravindran takes over as Chairman of Indraprastha ONGC, OIL Ink Pact for Crude Oil Transport to Northeast Gas Ltd Mumbai: M Ravindran, Director (Human Resources) of state-owned gas utility GAIL (India) Ltd, has taken over as the Chairman of Indraprastha Gas Ltd, the firm that sells CNG in the National Capital. He replaces K K Gupta, Director (Marketing), Bharat Petroleum Corporation Ltd (BPCL), who has relinquished the charge upon completion of his two-year tenure, M Ravindran, Chairman, IGL said in a statement here. IGL is a joint venture Indraprastha Gas Ltd of GAIL, BPCL and government of Delhi. The post of chairman is rotated among GAIL and BPCL every two years. The firm is the sole supplier of Compressed Natural Gas (CNG) and Piped Natural Gas (PNG) in the National Capital Territory of Delhi, Noida, Greater Noida and Ghaziabad. It has around 9500 km of pipeline network and meets fuel requirements of over 0.77 million vehicles running on CNG in NCR.
Shell Gears up for Bigger Market Share Mumbai: The market for lubricants in India is set to get exciting as Shell, one of the largest private players in the industry, is set to embark on a major branding exercise. Among one of its new marketing initiatives is an industry first: The first engine warranty by a lubricant maker. India is the third largest market for lubricants in the world after the US and China. And the growth prospects here have made major lubricant makers sit up and take notice. “We are not just focused on earning a higher volume share but we are aiming for higher brand awareness and equity,” says Mansi Madan Tripathy, CMO with Shell Lubricants India. Rival brands such as, Castrol has managed to push ahead of Shell in certain categories like two wheelers. Tripathy wants to make up for the lost ground, fast. Shell has tied up with around 55,000 mechanics across the country for its loyalty programme in addition to working on increasing its distribution points. “Product availability is a big driver in the purchase decision of heavy duty engine oil segment (truckers),” says Tripathy.
Elango Joins HOEC as MD Mumbai: Former Cairn India CEO P Elango has joined smaller oil exploration firm Hindustan Oil Exploration Company Limited (HOEC) as Managing Director. Elango quit Cairn in May last year.
P Elango, Managing Director, HOEC
He was named CEO of the company in August 2012 when Cairn India’s first chief executive officer Rahul Dhir resigned.
“These are challenging times for both the oil and gas industry and the company itself. My long term vision is to build a world class, independent oil and gas company strongly rooted in india, providing a robust platform to talented professionals to add value and make a difference,” said Elango. www.oswindia.com
Mumbai: State explorers Oil and Natural Gas Corp (ONGC) and Oil India Ltd (OIL) have signed an agreement for transportation of crude oil in North Eastern states. The two firms have signed the Crude Oil Transportation Agreement (COTA), OIL said in a statement here. The agreement formalised the long standing arrangement between these two companies to transport ONGC crude to the refineries in the North East through OIL’s pipeline facility. The pact was signed by OIL Director (Operations) S Rath and ONGC Director (Offshore) T K Sengupta on January 28, it added.
Oil Ministry Seeks More Share in Extended Production Contract New Delhi: The oil ministry proposes to raise the government’s share by 5 per cent and insist on explorers accepting Delhi as the seat of any future arbitration, irrespective of any other provision in the agreement, for granting extension to production sharing contracts for small and marginal fields. Government sources said the extension policy being worked out in the ministry does not envisage any concession on royalty and cess to explorers but lays down time limits for the ministry and its technical arm, Directorate General of Hydrocarbons, to process and decide applications for extensions.
Cairn India to Invest in KG Basin Mumbai: Cairn India may spend Rs 130 billion in developing an oil and gas block in Krishna-Godavari Basin over a period of time even as it geared up to undertake drilling of 64 exploratory and appraisal wells in that block. The oil and gas major has sought permission to prepare Terms of Reference for undertaking drilling of the wells in the block- KG-OSN-2009/3 in the Bay of Bengal, according to minutes of meeting of Expert Appraisal Committee under the Ministry of Environment. Cairn India had earlier said it declared force majeure of two of its oil and gas blocks including KG-OSN-2009/3 due to the objections raised by the Ministry of Defence for taking up exploratory works.
Petronet Shortlisted for Bangladesh LNG terminal New Delhi: Petronet LNG Ltd, India’s biggest importer of liquefied natural gas (LNG), is among five global energy firms that have been shortlisted for setting up an LNG import terminal in Bangladesh. Bangladesh is looking at setting up a 3.5 million tons a year LNG import facility at Matar Bari in Moheshkhali Island of Cox’s Bazar district or Anwara, Chittagong. The terminal, which is to be set up on the build-own-operate basis, will supply gas to power plants. Of these, five -- Petronet LNG, Anglo-Dutch super-major Shell, China’s Huanqiu Contracting & Engineering, Tractebel Engineering of Belgium and Japan’s Mitsui have been shortlisted, industry sources said.
Offshore World | 48 | December 2014 - January 2015
international news West Warns Libya Risks Bankruptcy
Offshore Drilling Rig Count Declines
UK: The United States and five of its European allies have warned that Libya could face bankruptcy if its oil output and prices on international markets continue to fall.
USA: The international offshore rig count for January 2015 was 314, down 24 from the 338 counted in December 2014, and up 12 from the 302 counted in January 2014, reports Baker Hughes.
In a statement voicing alarm at the deteriorating security situation in the conflict-wracked North African state, the allies also warned that Libya was on the brink of economic implosion because of a collapse in its production and the sliding value of crude.
The worldwide count for both offshore and onshore rigs for the period declined from 3,570 to 3,309. The largest drop, 199 rigs, came in the United States.
“We remain deeply concerned about the economic impact of the political and security crisis on Libya’s future prosperity,” the joint statement read. “In light of low oil production and prices, Libya faces a budget deficit that has the potential to consume all of its financial assets if the situation does not stabilise,” it says. The joint statement was issued by Britain, France, Germany, Italy, Spain and the United States.
In Oil Price War, Gulf Producers Grab Market Share in Asia UAE: Saudi Arabia’s move to slash the price it charges in Asia to the lowest in more than a decade is the latest aggressive action by Gulf States to defend market share in the world’s top oil consuming region. A price war between producers has raged since Saudi Arabia and its Gulf allies at the Organisation of Petroleum Exporting Countries (Opec) last November chose to keep their taps open in a bid for market share over price, sending oil prices down more than a third to under USD 50 a barrel in just two months. Since then, Gulf producers — including Saudi Arabia and the UAE — have steadily increased shipments to Asia, helped by low production costs that allow aggressive discounts, at the expense of West African and Latin American supplies.
More Oil Resource at Krafla Offshore Norway Norway: Statoil has completed a two-well appraisal program in the Krafla area of the Norwegian North Sea. The semisubmersible Transocean Leader drilled well 30/11-10 A, the ninth in production license 035, in 105 m (344 ft) of water. This was designed to appraise Statoil’s 2011 30/11-8 S discovery, 25 km (15.5 mi) southwest of the Oseberg Sør platform. According to the Norwegian Petroleum Directorate, the aims included delineation of the discovery and reducing the range of uncertainty of recoverable resources in Mid-Jurassic reservoir rocks (the Tarbert formation). The well encountered an oil column totaling around 260 m (853 ft) in the Tarbert formation, divided between the upper and middle Tarbert, with good-quality reservoir rocks.
Heavy Oil Found at Basilisco in Campos Basin Brazil: Petrobras has discovered heavy-oil accumulations in the BM-C-35 concession in the postsalt Campos basin. Well 1-BRSA-1289-RJS was drilled on the Basilisco structure in 2,214 m (7,264 ft) of water, 143 km (89 mi) from Armação dos Búzios on the Rio de Janeiro state coast. The well encountered oil at reservoir depths of 3,190 and 3,521 m (10,466 and 11,552 ft). Petrobras and partner BP will take action to assess the extension of the discoveries, and the concession’s exploratory potential.
Nasr Oil Field Sees First Production UAE: Japan Oil Development Co Ltd (JODCO) has started oil production from the Nasr oil field offshore Abu Dhabi, the United Arab Emirates. In the first development phase, the INPEX subsidiary is producing through the existing facilities of the Abu Al Bukoosh (ABK) and Umm Shaif oil fields, located adjacent to Nasr. Full field development of Nasr is in progress, and after completion, the field is expected to produce oil at a peak rate of 65,000 b/d. The oil produced from Nasr in the first development phase is transported via an existing subsea pipeline to Das Island. Nasr is approximately 130 km (81 mi) northwest of Abu Dhabi City. INPEX has jointly developed the Nasr oil field with Abu Dhabi National Oil Co., BP, and TOTAL.
First Oil from Brynhild Field UK: Lundin Petroleum AB, an independent international petroleum company formed in 2001 and based in Sweden, has reported the discovery of first oil from the Brynhild field. The field, located on PL148 in the Norwegian sector of the North Sea, is a subseatieback to the Pierce field, operated by Enterprise Oil Ltd (a subsidiary of Shell UK Ltd), in the UK sector. The Brynhild field is estimated to contain gross reserves of 23.1 MMboe, and production is in excess of the forecast gross plateau rate of 12,000 bopd. Drilling of the third development well is ongoing, and the fourth and final development well will be completed in 2015.
Offshore World | 49 | December 2014 - January 2015
www.oswindia.com
international news UH to Lead Offshore Energy Research Center
FMC Nets Deepwater Angola Production Order
USA: The University of Houston will lead a national research center for subsea engineering and other offshore energy development issues, including research and technology to improve the sustainable and safe development of oil and gas resources in the Gulf of Mexico.
Angola: Eni Angola has commissioned FMC Technologies to supply subsea production systems for the deepwater block 15/06 East Hub development. Value of the order is $393 million.
The work is intended to reduce the risk of offshore accidents, oil spills, and other deepwater disasters. The Subsea Systems Institute, announced by the Texas Commission on Environmental Quality, will be funded by the RESTORE Act (Resources and Ecosystems Sustainability, Tourist Opportunities and Revived Economies of the Gulf Coast States), resulting from the 2010 Deepwater Horizon oil spill. Outgoing Texas Gov. Rick Perry said that $4 million in funds given to Texas by BP after the 2010 oil spill will be distributed to fund the center launched by the university, as well as a second center to be led by Texas A&M University-Corpus Christi. The Institute will be led by UH, working in collaboration with Rice University, the Johnson Space Center, Texas Southern University, Houston Community College, and Lone Star College.
Eni operates the block in partnership with Sonangol Pesquisa e Produção, SSI Fifteen, and Falcon Oil Holding Angola.
Ennsub Unveils New Deepwater Deployment Systems UK: Ennsub has completed the design and manufacture of two workclass ROV deployment systems, which have been designed and manufactured for ROVOP and are due to be installed into a new build, Tier 1 pipelay vessel early in 2015. Ennsub’s DEEP 4000 system includes a unique cable handling solution designed to maximize umbilical lifespan, particularly in ultra-deepwater and other highfatigue applications such as active heave compensation. The system also has a high-speed electric winch with full active-heave compensation, semi-dipping extendable A-frame, and a transfer skidding system for large tool packages. A new control system and human machine interface (HMI) provide clients with a fully integrated and centralized operating station.
Lucius enters production in the ultra-deepwater GoM Dolphin Gets 3D Project Offshore Africa Mexico: Petrobras has started production at the Lucius field in the ultradeepwater Gulf of Mexico. The field, which includes portions of the Keathley Canyon blocks 874, 875, 918, and 919, is around 236 mi (380 km) southwest of Port Fourchon, Louisiana, in water depths of 7,086 ft (2,160 m). Lucius was developed with six subsea wells tied back to a truss spar floating production unit (FPU), a cylindrical-shaped vertical platform connected to the shore via dedicated oil and gas pipelines. The FPU has the capacity to process up to 80,000 b/d and 450 MMcf/d (12.7 MMcm/d) of natural gas.
Africa: : Dolphin Group ASA has won a 3D seismic contract including fasttrack data processing by an undisclosed major oil company for a project offshore Africa. A Dolphin high-capacity 3D vessel will commence operation on the three- to four-month project during 2Q 2015.
TGS begins Australasia frontier seismic surveys
The operator is Anadarko Petroleum Corp Petrobras is one of seven partners in Lucius, with 11.5 per cent interest.
New Zealand: TGS has started a 17,500-km (10,874-mi) 2D seismic survey offshore northeast New Zealand, which it expects to completed during early 2Q. Additionally, the contractor has begun acquiring the second phase of its Nerites survey in the Great Australian Bight off South Australia. This 13,000-sq km (5,019-sq mi) survey should also be complete during 2Q. Last year’s highlights for TGS included completion of 5,400 km (3,355 mi) of a multi-year 2D program offshore northeast Greenland, 10% more than planned for the season.
2D Seismic Survey Starts in Offshore Brazil
Plan for Seismic Survey in offshore Western Australia
Brazil: Spectrum is performing a 12,000-km (7,456-mi) multi-client 2D seismic survey in the Pelotas basin offshore Brazil. The new acquisition program will infill both of Spectrum’s 7,500-km (4,660-mi) survey acquired in 2013 and 12,000 km of data reprocessed in 2014, covering open acreage in the Pelotas basin and providing more than 31,000 km (19,263 mi) of new data over the area that may be included in the next licensing round, expected in late 2015.
New Zealand: Searcher Seismic and project partner BGP have announced a 2015 GroupSeis campaign over the North West Shelf offshore Western Australia. The 2015 GroupSeis campaign currently includes the acquisition of three individual broadband seismic surveys with further additions being negotiated for the final 2015 time slots.
The data is being collected by the vessel BGP Challenger and will be processed in the company’s processing center in Houston. PreSTM and PreSDM data will be available in early 3Q 2015, says Spectrum. www.oswindia.com
The current surveys include the 437-sq km (169-sq mi) Quoll 3D seismic survey in the Bonaparte basin, the 500-km (311-mi) Dunnart 2D seismic survey (which includes coverage of the Jansz gas discovery), and the 146-sq km (56-sq mi) Numbat 3D seismic survey, both in the Carnarvon basin.
Offshore World | 50 | December 2014 - January 2015
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Modularization can be realized in all the following parts of the drilling rig: rig floor, draw works, mast, basement, mud pump system, solid control system and auxiliary system with a high level of modularization. The draw works uses single drum draw works and the main brake is a disc brake mechanism (single disc or double disc). The derrick is tower-type or has a multi-section telescoping structure, which can be hydraulically rigged up and rigged down. This rig has high reliability, strong wind-resistant ability and excellent seawater corrosion resistant performance. In addition, its explosion-proof capability also meets offshore drilling requirements. The correlative ACS certificate, such as CCS, DNV, can be obtained according to the client’s requirements For details contact: Gruppe Littlesilver Sterling Center, 4th Flr Dr Annie Besant Road, Worli, Mumbai 400 018 Tel: 022-24976868
ELECTROMAGNETIC FLOW METER Jaycee Technologies Pvt Ltd offers range of electromagnetic flow meter. The provided meter is precisely manufactured using quality grade raw material and modern technology. This meter is available in different technical specifications. For details contact: Jaycee Technologies Pvt Ltd Shed No: 7, Nanekar Industries Building Survey No: 79/2, Dangat Indl Estate, Shivane, Pune, Maharashtra 411 023 Tel: 020-64703186, 25290744 Fax: 91-020-25290744
It also uses algorithms confirming to International Standards like ISO 5167 to compute flow from orifice plates, venturi, flow nozzles, pitot tubes, etc, and corrects for factors like Reynolds number when the flow is computed. It can be connected to any of these standard flow measuring systems such as vortex flowmeter, orifice plate, DPT; and Pitot Tube, Venturi , Verabar, etc. The flow computer can easily be interfaced to SCADA or DCS systems as various options like analogue retransmission and RS485-Modbus outputs are available. For details contact: Cosmic Technologies Plot No: 87, Indl Area, Phase-9 Mohali, Punjab 160 062 Tel: 0172-5096230 E-mail: vikram@cosmictechNo:com / info@cosmictechNo:com
FLAMMABLE GAS DETECTORS A flameproof (Ex d) pellistor-based flammable gas detector with local display and 4-20 mA output, suitable for gases including hydrocarbons, hydrogen and petrol vapours. Flamgard Plus is a flameproof (Exd) flammable gas detector, which uses poisonresistant pellistors to detect explosive levels of hydrocarbons, hydrogen and other flammable gases and vapours, including aviation fuel and leaded petrol vapours. Non-intrusive calibration can be performed locally without the need for hot work permits. Local display and magnetic key enable calibration without opening the junction box. Flexible output options a 4-20 mA signal is provided and optional alarm and fault relays are available to drive local alarm devices. If required the sensor can be mounted remotely from the display/transmitter enclosure. It is rugged and reliable in construction using highly durable marinegrade alloy with a tough polyester coating. Ingress protection to IP65 as standard. Uses long-life poison-resistant pellistors. For details contact: Enviro Safety Solutions 106 Sindhuratnya Complex, Retibunder Road Kalher Village, Bhiwandi Thane, Maharashtra 421 302
Offshore World | 51 | December 2014 - January 2015
www.oswindia.com
products
ELECTRO MAGNETIC FLOW METER Charun Instruments offers electromagnetic flow meter which is fully automatic and digitally designed by their expert professionals. This flow meter is simply structured, reliable, no movable parts and long operation life. These range of products have no mechanical inertia, quick response and good stability, application in automatic examination, and regulation and controlling. Measuring accuracy is not influenced by the physical parameters such as type, temperature, viscosity, density and pressure. This range of product posses operation data for safe and firm protection of memory. Our product is made from fine quality basic components, the products meet the need of different mediums. Charun Instruments offer many types of flow meter such as sandwich type and insertion type. The company also provides client’s specifications according to their requirement. For details contact: Charun Instruments 210-C-D, 2nd Flr, Kalrav Comml Complex Opp: Maninagar Railway Station, Maninagar (W) Ahmedabad, Gujarat 380 008 Tel: 079-25471190
For details contact: Pon Engineers Pvt Ltd 81 Kalyani Indl Estate, Vanagaram Road Athipet, Ambattur Indl Estate, Chennai 600 058 Tel: 044-26880660, 26880460
Accurate Oil Care offers premium quality electrostatic oil purifier. These electrostatic oil purifiers are highly demanded in the market owing to their good functionality and cost-effectiveness.
Jaycee Technologies Pvt Ltd offers qualitative range of ultrasonic flow meter. In synchronization with the set industry standards, these meters are manufactured under using the latest technology. Owing to their excellent measurement and user friendly features, their provided meters are highly demanded among. Furthermore, our quality controllers check these meters on various quality parameters to avoid any flaws.
These electrostatic oil purifiers find application in oil refineries, food industries, power transmission plants, etc. For details contact: Accurate Oil Care 1300/2 Warje Malwadi, Mahatma Phule Chowk Nr Water Tank, Pune, Maharashtra 411 058 Tel: 020-20250038
FIXED GAS & FLAME DETECTION MSA
For details contact: Jaycee Technologies Pvt Ltd Shed No: 7, Nanekar Industries Building Survey No: 79/2, Dangat Indl Estate, Shivane Pune, Maharashtra 411 023 Tel: 020-64703186, 25290744 Fax: 91-020-25290744
OIL PURIFIERS M Harakhji & Sons offers high performance sturdily built oil purifiers that purifies oil with perfection at industry leading prices.
www.oswindia.com
Pon Engineers Pvt Ltd offers comprehensive range of electrostatic oil purifier. In this purifier, chemical breakdown of oil molecules takes place and additives degrade with time pressure and temperature owing to their oxidizing and polar nature. To form an insoluble sediment / contaminant, these chemicals effectively combine together. This sediment/contaminant is commonly termed as varnish and tar.
ELECTROSTATIC OIL PURIFIER
ULTRASONIC FLOW METER
For details contact: M Harakhji & Sons 255 Madhavdarshan Waghawadi Road Bhavnagar, Gujarat 364 002
ELECTROSTATIC OIL PURIFIER
UltraSonic EX-5 gas leak detector instantly detects pressurized gas leaks with this high-precision, omnidirection device. Features advanced acoustic detection technology. Works even when traditional methods of detection are unsuitable or dependent on ventilation. The patented self-test system provides fail-safe operation. Functions in extreme weather conditions, making it ideal for use in complex pipeline systems, both onshore and off. LED display provides actual sound pressure level and alarm indication. Easily integrates with a broad range of applications. For details contact: Secure Plus Allied Pvt Ltd B-3 Devendra Apartment Basement, Sahyog Mandir Road Ghantali, Naupada, Thane (W) Thane, Maharashtra 400 602 Tel: 022-65554479
Offshore World | 52 | December 2014 - January 2015
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
Sitra Refinery Expansion Project
Bahrain
6,500,000,000
Execution
Yateem Oxygen - Carbon Dioxide Extraction Plant
Bahrain
-
Execution
Baiji Oil Refinery
Iraq
-
Execution
Bazian Refinery Expansion Phase 3
Iraq
-
Bidding
Miran and Bina Bawi Development Project
Iraq
-
Study
Nassiriyah Grassroots Refinery
Iraq
8,000,000,000
Bidding
Al Zour Refinery
Kuwait
15,000,000,000
Bidding
Olefins III
Kuwait
5,000,000,000
Study
Duqm Refinery and Petrochemical Complex
Oman
6,000,000,000
Bidding
Liwa Plastics Project (LPP)
Oman
3,600,000,000
Bidding
Sohar Refinery Expansion
Oman
2,100,000,000
Execution
Ras Laffan Condensate Refinery - Phase 2
Qatar
1,200,000,000
Execution
Halul Island Master Plan
Qatar
-
Bidding
QP/Shell - Al Karaana Petrochemicals
Qatar
6,400,000,000
Bidding
Jizan Export Refinery
Saudi Arabia
7,000,000,000
Execution
Jizan Export Refinery - IGCC Project
Saudi Arabia
8,500,000,000
Execution
Jubail Acrylonitrile Plant
Saudi Arabia
1,000,000,000
Bidding
Yanbu Export Refinery
Saudi Arabia
12,000,000,000
Execution
Chemaweyaat - Petrochemicals Complex Phase 1
UAE
10,000,000,000
Bidding
Emarat - Fujairah Terminal Third Phase Expansion
UAE
-
Bidding
IPIC - New Fujairah Oil Refinery
UAE
3,500,000,000
Bidding
Ruwais Refinery Expansion (RRE)
UAE
10,000,000,000
Execution
Africa
Country
Value ($)
Status
Sonatrach - Paraxylene Crystallization Plant
Algeria
-
Study
Tiaret Oil Refinery
Algeria
6,000,000,000
Execution
Lobito (SonaRef ) Refinery
Angola
8,000,000,000
Execution
Soyo Refinery
Angola
-
Planning
Cameroon Ammonia Urea Fertilizer Plant
Cameroon
1,400,000
Study
Middle East
Offshore World | 53 | December 2014 - January 2015
www.oswindia.com
project update
Ain Sokhna Petrochemical Complex - Ammonium Nitrate
Egypt
600,000,000
Execution
Alexandria Petrochemicals Complex - Ethylene Plant
Egypt
600,000,000
Execution
Alexandria Petrochemicals Complex - Polyethylene Plant
Egypt
-
Execution
Egypt / South Korea Petrochemical Plant
Egypt
4,800,000,000
Study
Tahrir Petrochemicals Complex
Egypt
5,000,000,000
Execution
Sogara Refinery
Gabon
-
Completed
Atwereboanda LPG Storage Facility
Ghana
200,000,000
Study
Equatorial Guinea Fertilizer
Guinea
-
Study
Kenya Petroleum Refineries Limited (KPRL) Mombasa Refinery
Kenya
17,000,000
Execution
Mellitah Complex
Libya
-
Execution
Mohammedia Refinery Rehabilitation & Expansion
Morocco
816,000,000
Execution
Zinder Refinery (Soraz)
Niger
980,000,000
Execution
Dangote Oil Refinery
Nigeria
-
Execution
Ibeno Petrochemical Complex
Nigeria
1,500,000,000
Execution
Coega (Mthombo) Refinery
South Africa
10,000,000,000
FEED
Mnazi Ammonia/Urea/Methanol Project
Tanzania
-
Study
Hoima Oil Refinery
Uganda
2,500,000,000
Bidding
Caspian Region
Country
Value ($)
Status
Baku Heydar Aliyev (Azerneftyanajag) Refinery Upgrade
Azerbaijan
-
Execution
Oil, Gas Processing & Petrochemical Complex (OGPC) Project
Azerbaijan
15,000,000,000
Study
Sumgayit Nitrogen Fertilizer-Urea Complex
Azerbaijan
-
Execution
Abadan Refinery Upgrade
Iran
3,000,000,000
Completed
Abadan Second Refinery
Iran
3,500,000,000
Execution
Anahita Oil Refinery
Iran
3,130,000,000
Bidding
Bandar Abbas Refinery Upgrade
Iran
300,000,000
Execution
Esfahan (Isfahan) Refinery Expansion
Iran
2,500,000,000
Execution
Fajr-e-Jam (Kangan) Gas Refinery
Iran
-
Completed
Hormoz Urea Ammonia Plant
Iran
526,000,000
Planning
Kermanshah Ammonia/Urea Complex
Iran
260,000,000
Execution
Persian Gulf Star Gas Condensate Refinery (PGSCR)
Iran
2,600,000,000
Execution
Tabriz - Gasoil Hydro-Treating Plant (GHP)
Iran
-
Bidding
Atyrau Refinery Upgrade
Kazakhstan
1,040,000,000
Execution
Kazakh GTL Plant
Kazakhstan
50,000,000
Planning
Pavlodar Refinery
Kazakhstan
40,000,000
Execution
Komsomolsk Refinery Upgrade
Russia
700,000,000
Execution
Novokuibyshevsk Refinery Upgrade
Russia
-
Execution
Omsk Refinery Upgrade
Russia
5,000,000,000
Execution
Saratov Refinery Upgrade
Russia
300,000,000
Execution
Syzran Refinery Upgrade
Russia
-
Execution
Tobolsk-Polymer Complex
Russia
-
Completed
www.oswindia.com
Offshore World | 54 | December 2014 - January 2015
EWEA OFFSHORE 2015 Date: 10-12 March, 2015 Venue: Bella Center Copenhagan, Denmark Event: EWEA OFFSHORE, the world’s largest offshore wind energy conference and exhibition, is a biennial event that unites the whole of the wind energy value chain under one roof. And, what better place to hold the next event than Denmark – home to the world’s first ever commercial offshore wind farm and the second largest offshore wind market. Year after year, EWEA OFFSHORE attracts thousands of offshore wind energy professionals from Europe and beyond from manufacturers, developers, operations and maintenance, and logistics and installation – come to EWEA OFFSHORE 2015 to meet your industry. The EWEA OFFSHORE conference is the leading-edge, international conference for the offshore wind industry. Get advanced learning, hear about important industry trends and network with your peers, potential clients and collaborators. The 2015 conference offers in-depth sessions on a wide range of topics, with a special focus on cost reduction. 24 sessions will address how cost reductions can be achieved. For details contact: Anne Lannoy T: +32 2 213 18 66 E: registration@eweaevents.org
ADIPEC 2015 Date: 9-12 November, 2015 Venue: Abu Dhabi, UAE Event: The Abu Dhabi International Petroleum Exhibition and Conference (ADIPEC) is the world’s new meeting point for Oil & Gas professionals. The 30th Anniversary edition closed on the 13 th November 2014 having attracted 1,868 exhibitors and 76,240 attendees from 112 countries during the 4 days of the event. ADIPEC provides an unrivalled global platform for Oil & Gas professionals to do business. The world-renowned conference programme within ADIPEC further educates and provides knowledge transfer and unparalleled network working opportunities. Located in the capital city of the United Arab Emirates, Abu Dhabi acts as a natural cross-roads between the east and the west and is fast becoming one of the world’s most influential energy hubs for the 21 st century.ADIPEC is supported by industry through its unique Executive Committee that convenes to shape the conference content of the event and is supported by many of the world’s leading National Oil Companies, International Oil Companies and key service providers. For details contact: dmg events Jhoanna Kilat T: 02 6970 529 E: JhoannaKilat@dmgeventsme.com
3 rd Annual Pipeline Integrity Management, 2015 Date: 8-9 April, 2015 Venue: The Royale Chulan Hotel, Kuala Lumpur, Malaysia Event: Following the success of the past events, Fleming Gulf is proud to present the 3rd Annual Pipeline Integrity Management, 2015. The event will provide a sound understanding of Pipeline Integrity Management strategies. The event has been carefully designed based on the current market needs and will focus on the challenges related to design, inspection & maintenance, integrity and rehabilitation in pipelines. Focusing on existing technologies, as well as those in research and development, the program will include information on advances and best practices in aboveground remote assessments, Structural Integrity, Emergency Response, PIMS, Data Management, NDT, In-Line Inspection, Cathodic Protection in Pipelines, Top of Line Corrosion, Rehabilitation of Aging Pipelines, Pipeline Life Extension studies and other issues which are important for this sector. For details contact: Fleming Gulf Rina Jamesr T: +603 2027 4767 F: +603 2272 5350 E: rina.james@fleminggulf.com W: www.fleminggulf.com
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 | 55 | December 2014 - January 2015
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 | 56 | December 2014 - January 2015