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Innovating together Ours is a culture of purposeful innovation and deep commitment to clients, of defying convention in pursuit of new possibilities and improved project economics. We are a global leader in oil and gas projects, technologies, systems and services. With our clients and partners, we are pushing the limits of technology to ensure the success of today’s most ambitious energy infrastructure projects.
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Content
Features Boston Consulting Group Sylvain Santamarta & Bjรถrn Ewer, How Can Digitalization Impact the Upstream Ecosystem...............................................................................................5 Bentley Systems Are You Overlooking a Significant Source of Savings................................................................................6 DNV GL Energy Transition Outlook- Executive Summary.................................................................................................10 Capgemini Safeguard your Digital Enterprise- Cybersecurity.............................................................................................16 AnTech Coiled Tubing Drilling: Directional and Horizontal Drilling with Larger Hole Sizes . ..............................................20 Sicily and Malta Channels Petroleum Prospectivity...........................................................................................................30
Conferences......................................................................................................................................................................13
Companies in the news: GustoMsc - Chela Further Evolved....................................................................................................................................36 BP plc - Third quarter financial results..............................................................................................................................38
Published by: OYOMEDIA18 Limited, (MED OIL & GAS MAGAZINE is a subsidiary of OYOMEDIA18 Limited), Malta & Dubai Printed & designed by: Rosendahls a/s Denmark Cover photo courtesy of AnTech Limited.
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How Can Digitalization Impact the Upstream Ecosystem?
Despite its long-established use of technology, the upstream oil sector has been slow to embrace the digital solutions that have transformed many other industries. However, the dramatic decline in oil prices since mid-2014 has prompted soul-searching among upstream companies. Digitalization has the potential to substantially improve capital efficiency, lower production costs, and reduce time to first oil. However, digitalization can be complex and difficult to adopt, and companies need to implement a structured approach to examine its impact on business. We recommend using a technology Stack Approach to look at all the elements of the upstream value chain. Each stack is comprised of a discrete ecosystem of companies, with its own business arrangements, a distinct flow of data, and a particular set of technical challenges, and each stack has a different digital maturity.
Exploration stack The application of machine-learning methods to reservoir modeling is based on large data sets and powered by scalable high-performance computers, which will speed up and improve the interpretation of exploration data. Tapping into this opportunity will require substantial investment in the emerging field of machine learning, as well as closer cooperation between oil and gas, seismic-data-processing, and technology companies.
Project stack A new generation of digital modeling and simulation tools will link reservoir data, field
architecture, equipment design, and economics into a single digital framework. This will enable oil companies to quickly narrow down the most economical field designs.
Drilling and well stack Opportunities in drilling and well stack will arise from the development of integrated drilling automation systems, coupled with better coordination and collaboration between rig owners, oil field service companies, and original equipment manufacturers (OEM’s). This will result in closed-loop autonomous drilling, substantially reducing costs and drilling times.
Production stack In production, new digital technologies will allow the capture and real-time processing of larger and more complex data sets. By automatically extracting insight from a combination of data derived from individual machines, system performance, and operator logs, these technologies will improve overall operational performance. However, to fully capture value from digitalization, oil companies need to act on the following three areas: • Understand their current position in the value chain: Map their current position within the digital ecosystem, and better understand the opportunities as well as potential disruptions. For example, the transition to outcome-based models will mean that a hardware manufacturer will need to acquire or develop data analytics capabilities that enable it to assess equipment performance • Identify potential partners: Partner with other companies to develop fresh capa-
Comments from
Sylvain Santamarta Partner & Managing Director Boston Consulting Group; Björn Ewers, Partner & Managing Director Boston Consulting Group Middle East
bilities. For example, operators may need to partner with software companies to access new technological capabilities • Establish in-house development capabilities: The right capabilities will enable companies to achieve a sustainable advantage over competitors, making use of the agile development methods necessary for the adoption of digital solutions. Major GCC (Gulf Cooperation Council) operators have all taken action on digital to exploit its benefits. NOCs (National Oil Companies) have started their digital journey and are already making progress in certain areas. However, considering the breadth of opportunities across the Technology Stacks mentioned above, there is still a long way to go to ensure the current position is properly diagnosed, the right partners are engaged, and internal teams are built to capture the full potential of digital in upstream. This has been the start of a digital transformation journey ahead of the major GCC operators. 5
Are You Overlooking a Significant Source of Savings? Some oil producers are using chemical management and saving up to 10 percent in chemical costs. While oil prices are rising once again after the sharp decline over the last few years, there is still great emphasis on significantly reducing costs across all areas of production, both on and off shore. One area that is often overlooked in terms of applying solutions is the use of chemicals throughout production and processing. The injection of chemicals in a controlled and reliable process across an operation, be it land-based or offshore, is a key factor in the productivity, efficiency, and profitability of oil and gas producers. Applying a chemical management solution to an operation or field affects availability, performance, and maintenance in beneficial ways.
In the past, chemical usage was typically unmonitored. Often, there would be a tendency to add more than necessary to ensure pipes were never under dosed. What was thought of as an acceptable cost and part of the production process is now proven to be a waste of money and resources if not properly monitored and managed. Now, it is critical to inject the prescribed chemical at the recommended dosage rate and use a chemical management system’s analytics to record and report on the exact recommended dosage, which changes based on various parameters and conditions. Inexact dosing can keep the chemical from reacting in the way it is intended, which can lead to hydrate formation (ice-like solids that form when free water and natural gas combine at high pressure and low temperature). Imprecise dosing can also lead to fines for the operator and damaged equip-
Figure 1. Chemicals are widely used throughout the oil and gas industry in both onshore and offshore oil production.
6 | MED OIL & GAS | October 2018
ment, which can lead to costly unplanned process downtime. Due to the wide variety of chemicals used across the operation, the cost of over injecting can quickly mount if left unchecked. A reliable and robust chemical management system should deliver 10 percent savings in chemical costs or more.
Data Challenges and How to Deal with Them One of the main challenges in creating a successful chemical management system concerns data. Chemical injection dosages, tank levels, and chemical inventory should be monitored and produce data from which you can draw insights. If you are monitoring data, it needs to be reliable, not have any gaps, be accessible to those that need it in a timely manner. One of the main challenges for effective chemical management is connecting all relevant data and information sources together for reliable and accurate decision making. The need for a dedicated chemical management system operating within a connected data environment should be high on the “strategic to-do list” for oil producers. While SCADA systems are popular for storing data, you need the right analytics and visibility to gain timely insights and act upon them to get the most out of your data. Many operations have separate applications collecting data for different engineering disciplines, such as chemicals, corrosion, integrity, erosion, production, environmental, and lab analysis to name but a few. The difficulty comes in bringing all data sources together in one system to provide a complete picture of chemical management and production. In today’s digitally connected world, many processes are still manual and isolated, and a lot of time is wasted collating and analyzing data. By the time reports are produced, the information is already out of date. This inefficiency and ineffectiveness can be a result of data that is manually entered, stored
Figure 2. A chemical and corrosion management solution gives you access to key processes that are affected by chemicals, like production, tanks, pump usage, and more.
in multiple or remote locations, in different formats, or is simply hard to access. To address this problem, Bentley’s AssetWise solution is underpinned by a connected data environment and is an illustration of how interoperability is the cornerstone of information accessibility. AssetWise allows the seamless integration of isolated systems and processes that bring the information you need into the Operational Analytics platform for consolidation and analysis. The data is turned into actionable information and viewed within dashboards that are easily tailored to specific needs.
Requirements of a Chemical Management System A dedicated chemical management system will report on measurements like flow rates, levels, and discharge pressures. It will also be committed to providing alerts regarding any upcoming events that affect production, such as notice of potential equipment failure and drops in pressure or flow rates. The system can automatically inform events maintenance, so they can plan and schedule corrective action before the asset fails, as opposed to requiring unplanned site visits after a failure occurs.
With the large and complex set of assets, systems, components, and parts that make up any given operation, there are numerous things that can go wrong that affect process flow rates and pressures, operating temperatures, and the like, such as general wear and tear, equipment fatigue, and human error. It only takes a small change in one of these variables to upset the condition and performance of a finely tuned system, where the consequences of a small error can be large and costly if left unchecked. It’s important to know the day-to-day metrics of production against targets, chemical usage, and discharge, so you can measure performance effectively. However, it’s also crucial to have a system that recognizes these changes (or the results of these changes) and can address them and alert personnel to the problem before it happens. A chemical management solution should have a template and replication feature to create a standard for commonly used systems and structures so that new additions to the registry can be swiftly uploaded. Any changes that need to be done across multiple sites or assets can be replicated across all required points easily by adjusting the template for a specific instance. Figure 3. Never lose track of how much chemicals you are using, how much is left, how much it is costing, when is the next treatment, and how you can optimize chemical usage, with a chemical management solution. 7
Figure 4. A centralized chemical management solution enables up-to-date, timely, and relevant information to help maintain efficient and cost-effective oil production.
Many assets are owned by multiple vendors, so a flexible, yet secure, chemical management system is necessary for tracking who is using what while maintaining the security and privacy of each vendor. Each vendor needs to have their own secure access to the system. This would also include the ability to schedule truck services for manual sampling and injections so that vendors are aware of what chemicals are needed, where they need to be applied, and when they need to be applied, which is crucial, especially when dealing with assets across a large geographic area. This allows each vendor secure monitoring of their own activities and integrity maintenance of confidential information, while the overall operator has access and control of all information. A critical, but often forgotten, requirement of a chemical management system is to create and maintain the chemical list. This is due to the variety and nature of the different chemicals used. As some chemicals become more concentrated, they could have a detrimental effect on the performance of the equipment with which they interact. The viscosity and frequency of chemicals also plays a large role in flow rates, pressure, temperatures, and general wear and tear. Creating and maintaining a chemical list is important within a chemical management solution to not only track chemical levels, but also to track chemical performance, suitability, and risk. 8 | MED OIL & GAS | October 2018
Lastly, the use of chemical injection systems is subjected to extreme conditions. These systems are often placed in remote hostile environments where the elements alone can cause serious equipment failure. Therefore, it is even more important to monitor and manage these assets closely to prevent failures. When operating in these harsh conditions, it is inevitable that these injection systems will eventually fail; it is a question of when, rather than if. Having a reliability strategy in place, such as the AssetWise Asset Reliability solution, that runs alongside the operational chemical management solution, such as the AssetWise Operational Analytics, is a win-win situation that serves the purpose of increasing uptime, reliability, and availability across the operation by driving a proactive approach to managing the maintenance of chemical injection pumps and equipment.
together in one application. With a centralized chemical management system for all associated oilfield data – Production and Process Data, Laboratory, Corrosion, Scale, Wax, Budgets, Monthly reports, as well as chemical treatment scheduling for trucks, it provides an effective, timely, and cost-effective use of oilfield chemical treatments to allow and ensure the best performance of all oilfield assets at all times. The optimization of the assets and processes within the operation will dramatically reduce chemical costs by allowing you to be more efficient and productive in the management of oil production through correct chemical treatments.
Chemical Management: A Step Toward Operational Excellence A reliable chemical management solution is the way forward to managing chemical costs and optimizing usage by ensuring you are applying the correct chemicals at the optimal rate to deliver best and continuous operating performance. Eliminate the nightmare created by spreadsheets, isolated data, unreliable information, and out-of-date information and replace it with a dedicated solution that brings all the important data
Author
Richard Irwin Senior Product Marketer, Asset Performance, Bentley Systems, Inc.
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Global Energy Transition Outlook predicts continuing demand growth for MENA oil and gas The world will need less energy from the 2030s onwards, but it will still require a significant amount of oil and gas in the lead-up to mid-century according to DNV GL’s 2018 Energy Transition Outlook. DNV GL’S ENERGY TRANSITION OUTLOOK – IN BRIEF DNV GL’s recently released Energy Transition Outlook 2018, a global and regional forecast to 2050 is based on their annually updated Independent Model of the World’s Energy System produced by combining the expertise and experience of three of their Business Areas – Oil & Gas, Maritime and Energy. The effort was coordinated by DNV GL’s Group Technology and Research unit and reviewed by a wide range of experts from both industry and academia. Based on the model, DNV GL’s Energy Transition Outlook underpins a unique regional and global forecast covering 10 world regions and the energy trading between them. Its goal is to assist energy supply chain stakeholders in developing their future business strategies and provides essential insights for any company operating internationally.
The Middle East & North Africa (MENA) region will remain the main global supplier of oil and gas for decades to come: • The energy transition will redefine oil and gas exploration and production activity in the lead-up to 2050 • Future production will favour a greater number of smaller reservoirs with shorter lifespans • Increased investment in digitally-enabled technologies is needed now to support faster, more cost-effective production in the coming decades • Gas will overtake oil as the world’s largest energy source by 2026 According to DNV GL’s 2018 Energy Transition Outlook, an independent forecast of the world energy mix in the lead-up to 2050, oil and gas demand will peak in 2023 and 2034, respectively. However, new oil fields will be needed until at least the 2040s, while new gas developments will be required beyond 2050. DNV GL’s Outlook predicts that operators will favor production from a greater number of smaller reservoirs with shorter lifespans, lower break-even costs and reduced social impact compared to those currently in operation. 10 | MED OIL & GAS | October 2018
bon capture and storage (CCS) will need to be implemented at scale for the oil and gas sector to stay relevant in a rapidly decarbonizing energy mix. DNV GL forecasts CCS will capture only 1.5% of emissions related to energy and industrial processes in 2050. Global warming will likely reach 2.6 degrees Celsius (°C) above pre-industrial levels in 2050, according to the Outlook. This is well above the 2°C target set out by the COP 21 Paris Agreement on climate change. By 2050, the Outlook predicts 972 gigatonnes of carbon will be emitted, overshooting the 810 gigatonne budget associated with the target. “Our forecast reaffirms that the oil and gas industry has a vital role to play in the energy transition. It is our sector’s responsibility to maintain a sharp focus on decarbonization, sustainable production, cost management, and the need to embrace innovative technologies to secure long-term supply of sustainable and affordable energy,” adds Hovem.
“Most easy-to-produce, ‘elephant’ oil and gas fields have been found and are already in production. Smaller reservoirs will likely be harder to explore and develop commercially. Digitally-enabled technologies such as directional drilling and steerable drill bits, 4D seismic backed by advanced data analytics and steam flooding, will be crucial to ensure that exploration and production is economic and efficient,” says Liv A. Hovem, CEO, DNV GL – Oil & Gas.
Increasing investment supports gas to fuel the energy transition
Following DNV GL’s Outlook existing technologies for decarbonization, such as car-
DNV GL’s Energy Transition Outlook predicts global upstream gas capital expenditure will grow from USD960 billion (bn) in
Figure 1. World primary energy supply
tripling of electricity demand between now and 2050. Due to low-cost domestic gas reserves, the uptake of renewables starts later than in most other regions. In 2030, onshore wind starts to grow rapidly, followed by solar PV and offshore wind. By 2050, solar PV will be the main source of power, generating 39% of total supply. Onshore wind will then be second, with a share of 28%.
Figure 2. Middle East and North Africa (MENA) primary energy consumption by source
Figure 3. Middle East and North Africa electricity generation by power station type
2015 to a peak of USD1.13 trillion in 2025 to support the transition to the golden age of gas. Upstream gas operating expenditure is also set to rise from USD448bn in 2015 to USD582bn in 2035, when operational spending will be at its highest. This cash injection will enable the 46% increase in the annual rate of additions to gas production capacity that the Outlook forecasts between 2018 and 2030. Conventional onshore and offshore gas production is forecast to decline from about 2030, while unconventional onshore gas is expected to rise to a peak in 2040. Among its forecasts for 10 global regions, DNV GL’s Outlook sees North East Eurasia (including Russia) and the Middle East and North Africa (MENA) accounting for most onshore conventional gas production in the lead-up to 2050, while North America will continue to dominate unconventional gas production. In the offshore sector, the MENA region sees the highest annual rate
of new gas production capacity from now until at least 2050.
The forecast for the Middle East and North Africa (MENA) According to DNV GL’s 2018 Energy Transition Outlook, energy con¬sumption in the Middle East and North Africa will continue to grow moderately and increase 36% by 2050. Growth in energy use is driven by manu¬facturing, buildings, and transport up to 2040, the year when transport energy demand peaks and starts to decline.
The MENA region will remain the main global supplier of oil and gas. However, as the regional population grows, domestic energy demands will change and the use of electricity will grow rapidly. Today, 60% of electricity is gener¬ated from gas. By mid-century, electricity will be primarily generated from variable renewables like wind and solar with increased support from hydropower and nuclear. “Middle East nations are excited by what solar photovoltaic can do for them domestically,” says Jan Zschommler, Area Manager Middle East at DNV GL - Oil & Gas. “This is expanding to reduce oil imports (Egypt, Jordan), allow more oil exports (Iran, Iraq, Oman and UAE) and, to reduce the cost of generation by not having to invest in more expensive hydrocarbon production for domestic power (Saudi Arabia).” Variable renewables alone will provide more than 65% of the electricity in the region by 2050. This means that even though oil and gas production will continue to play a significant role for decades to come, the shift to renewables will change the location of where energy is going to be produced, which in turn impacts on the region’s economies and politics.
Energy consumption is dominated by regional oil and gas resources. Oil is forecast to peak in 2035 at only slightly more than its current level. Natural gas, already the largest energy source, will see a further increase until it peaks in 2035, 30% above its current level. In the mid-2030s, oil for road transport will be increasingly challenged by the uptake of electric vehicles. The growth in natural gas use is driven by a
Figure 4. Middle East and North Africa electricity generation in 2050 11
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Figure 5. Conventional onshore oil production by region
Consequences for oil & gas production in the Middle East and North Africa DNV GL’s ETO forecasting model encompasses the global energy supply and demand and the use and exchange of energy within and between ten world regions, including MENA. “MENA nations are naturally interested in how much decarbonization reduces demand for their exported fossil fuels in the decades to come,” says Zschommler. “Our forecast shows that the region will remain the main global supplier of oil.” As government and public pressure for cleaner energy solutions increases and the price of renewables decreases the production and exploration in challenging environments will shrink and, in some environments like the Arctic, cease altogether. Operators outside the MENA region will choose to develop resources from smaller, more technically challenging reservoirs, with shorter lifespans, lower breakeven costs and reduced social impact. This may lead to a shortfall in world oil & gas supply favoring the MENA region where the cost of production has, historically, been lower and less technically challenging. However, within the region the sector still faces the multifaceted challenges of adjusting production portfolios to favor gas, whilst reducing costs and bringing decarbonization of operations into full focus in order to maintain its social license to operate and help achieve international and national targets for climate change mitigation. Middle East energy companies are already investing heavily in energy efficiency and renewables while raising domestic consumer energy prices, which are widely expected to triple by 2023. The industry’s digital transformation will play a significant role in achieving this. “The industry will need to invest in developing technologies supporting faster and leaner exploration and production. We experience that our customers are seeking more sustainable operations through digitally-enabled solutions, such as predictive emission monitoring for gas turbines and remote technologies to perform targeted inspection, to name just a few examples,’ says Zschommler. “DNV GL is supporting the industry with globally recognized risk-based approaches and domain expertise in combination with leading digital technologies, many of which are developed together with our customers through Joint Industry Projects (JIPs) and other collaborative initiatives.” DNV GL’s suite of 2018 Energy Transition Outlook reports are available to download free of charge. The main ETO report covers the transition of the entire energy mix to 2050. It is accompanied by three supplements forecasting implications for the oil and gas, power supply, and maritime industries.
S C A N D I N A V I A N
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THE NETHERLANDS NIGERIA
Download DNV GL’s 2018 Energy Transition Outlook reports from: https://eto.dnvgl.com
12 | MED OIL & GAS | October 2018
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Safeguard your digital enterpriseCybesecurity Digital transformation and big data are terms that are regularly used to describe the latest digital trends. We need to get more responsive, we need more data to make decisions, we need to be digital and these are all statements that companies are using to help them drive their digital transformation processes. And this is a good thing! Better insight and better data quality will help companies to remain competitive and find new markets.
Companies are starting now to look at their Industrial Control Systems (ICS) and their operational technology (OT) systems to get more information from them so they can take advantage of better monitoring and being able to take advantage of surge pricing for example. These systems have traditionally been protected by strong network protection and air gaps and are now connected to internet facing networks which can make them a new risk and target for attackers. IoT has also been introduced into the landscape to cope where existing systems would be too costly to adapt to the new changes that the business is demanding. Sensors attached to core systems to help with monitoring and maintenance are common sights now on large production systems. These devices are streaming data to large data lakes and other big data stores so that the data can be analysed, used and sold as needed. However, they often are introduced without a full oversight of what information they are sending, how they are sending it or if there are any vulnerabilities in the software or hardware that they use. In times gone by, ICS had the advantage of being a well wrapped present. Until you unwrapped it, 16 | MED OIL & GAS | October 2018
you didn’t know what was under the wrapping, and these gifts were hard to come by and expensive. This high cost and difficulty to obtain the hardware and software made it very difficult for non-nation states and government agencies to develop exploits against them. The new IoT market has changed that. New devices are coming on the market every other day and are affordable and in most cases easy to acquire. Since most of the devices are connected to the internet in some way, it becomes easier to discover them. To make deployment easy and thus increase their uptake in the market, devices use well defined and documented protocols and also may be easily discoverable to allow administrators and solution teams to integrate them into the different technology stacks. This becomes a new attack vector for attacks and a new risk issue for defenders to contend with. Starting with the attacker’s point of view, they can use solutions such as Shodan. Shodan is a search engine for the internet of things and can be found at https://www.shodan.io/. This service scans the internet on a regular basis much in the
same way as Google and catalogues all the different devices it finds such as webservers, databases and IoT devices. Each device that it finds has a fingerprint which can be used to determine what type of services it is running. These services can be then queried to discover what information they are sending out when they are queried, much in the same way an administrator would do to any device on their network. With this information, you can search for any number of devices and services using a simple search interface. Unfortunately, you will find many different misconfigured control systems located around the globe. From fire suppression systems and HVAC solutions to point of sale machines in shops, devices like these can be found easily and quickly with many of them not requiring any username or password to access. In some cases, Shodan can even get a screenshot of the system in question, which can provide better insight into what ICS software systems look like to a potential attacker. When I show people this type of information, the most commonly asked question is “Why does this happen?”. There are many answers to that question, but the most ob-
vious ones are human error, lack of understanding or simple naivety on the part of the person doing the install or administration. People will make mistakes, take shortcuts or most often simply not understand the threats that can happen. The internet is large, but it is still just a lot of computers connected to and talking to each other. The vastness of its scale makes it easy for people to think that it cannot be scanned easily but in truth it can take only thirty minutes to scan the internet to see how many devices are running and to identify what they are when using the correct type of equipment. This doesn’t give you a lot of time to stay hidden and when people are always looking for ways to attack a sudden appearance of a new device will make it easier for them to attack you. Whenever a new vulnerability is discovered in a router for example, attackers will often scan for these devices to exploit the weakness. There are always enemies at the gates and your devices might even be inviting them in. Another aspect that happens is when devices are impacted because of their connection to the business network. We saw this recently with the spread of WannaCry and NotPetya, two similar style virus epidemics that crippled companies worldwide causing companies like Merck, Fedex and MøllerMærsk to have large IT outages. These high-profile attacks targeted unpatched Windows systems and then spread within an organisation quickly, causing OT systems to be affected as their control solutions were hosted on the affected machines. This knock-on effect is a new threat model that needs to be considered when you are connecting your IC systems to an IT network. Industrial control system specific malware is also on the rise. The evolution of this type of malware and the cadence of new discoveries means that more and more devices will soon be at risk. Stuxnet will for many be considered the first that made it in the public consciences. Since then, several different malware variants have been discovered and these have often been dormant or hidden for many years. The latest one to make the news was the malware dubbed Triton due its targeting of the Triconex industrial safety technology and has risen to notoriety as the first ICS malware design to harm humans. While sensational, it was not fully weaponised and defeated by the lack of knowledge on how the Triconex system worked.
Figure 1. Cremation chamber control panel discovered open on the internet in 2012
As mentioned before, industrial control systems have been protected by air-gapped networks, networks which don’t connect to other business or internet facing networks and this has been a largely effective defence mechanism. Now businesses are expecting to get data from these systems and wanting to maintain the air-gap so USB devices are commonly used to transfer data between these separate networks. This is the main delivery agent for the types of malware discussed above. There is no silver bullet solution to this, but simply knowing what your devices are up to may allow to stem the tide in your favour. Solutions like that from Senrio (https:// senr.io) can for example help you discover all the PLCs, HMIS and other networked devices on your control network. Further risk reduction techniques are ensuring that employees and operators understand that their actions will have security consequences. Seemingly innocent actions such as putting the device on a generic Wi-Fi network may lead to issues as these configurations get forgotten and nobody knows how they are configured and assume it was done right. Education is vital factor in reducing your overall risk picture coupled with stringent controls that are enforced correctly. Which leads to the last point, do not try to implement IT (business network) security strategies on Operational Technology (OT) networks. OT which is a common grouping term for ICS, PLC and SCADA technologies,
have a different set of needs when it comes to security requirements and risk assessments. Applying IT policies which are always designed around user access controls and maintaining privacy doesn’t always work on OT systems due to the different needs model. Patching routines may be different and are often in line with factory maintenance schedules. This means that when you apply the wrong policies, people will work around them opening different holes and creating a new and unanticipated threat model for your organisation. Vigilance is the key in maintaining a healthy cyber-defence strategy and working with your people and systems will ensure that you can keep ahead of the latest threats.
Author
Niall Merrigan Team Manger for Cybersecurity, niall.merrigan@capgemini.com
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COILED TUBING DRILLING:
Directional and Horizontal Drilling With Larger Hole Sizes Coiled Tubing Drilling (CTD) is a well-documented technique that has, to date, been used with great success for grassroots vertical wells, where wells have been drilled and cased in a day, along with directional through tubing re-entry work, where it is used to further exploit existing wells, such as the operations carried out in Alaska and the Kingdom of Saudi Arabia. However, in these directional operations the hole sizes drilled with coiled tubing are relatively small (up to 4.5”). There is increasing demand from markets such as shale gas, coal bed methane and underground coal gasification (UCG) for larger hole sizes, but until now there has not been an economically viable option for drilling directional wells with coiled tubing in the 6.25” to 8.5” range. However, the production of a BHA in this size has been made cost-effective through the use of an innovative solid state gyro system for directional measurement at all inclinations. The use of a gyro system whilst drilling, instead of a magnetic steering tool, removes the need for non-magnetic materials and allows the tool to be made much shorter. To demonstrate the capability of this tool, a 5-well drilling program was completed in Kansas, USA between November 2011 and February 2012, using a combination of a hybrid drilling rig and a 5.0” Bottom Hole Assembly (BHA), with a Rotating Orienter. Various directional and horizontal well profiles were drilled with hole sizes from 6.25” to 8.5”. The aim of the program was to demonstrate this new technology with the intention of providing a more economic drilling option and to show that the combination of a hybrid rig and this new BHA can be used to efficiently drill and case directional and horizontal wells with hole sizes from 6.25” to 8.5”. Furthermore, an additional goal of the program was to carry out some initial vibration20 | MED OIL & GAS | October 2018
Figure 1. Benefits of Coiled Tubing Drilling
al analysis into the forces experienced while drilling and investigate how this could inform future equipment testing and operations.
The system used in the drilling program was a combination of a hybrid drilling rig and a new 5.0” BHA with a Rotary Orienter and solid state gyro steering system. Being able to drill and case with the same rig was key to demonstrating how Directional Coiled Tubing Drilling (DCTD) could be an economic option for drilling larger hole sizes and deliver the well-documented benefits of CTD (see Figure 1) to a much wider market.
ed the versatility to drill with coiled tubing (with the wheel raised), whilst also having the ability to run and pull casing (with the wheel lowered). This type of rig configuration had previously been used to drill over 2000 vertical wells, and had demonstrated that CTD could reduce drilling times by up to 60% compared with standard jointed pipe drilling rigs1, equating to an impressive equivalent cost saving of approximately 33% for the operator. The successful completion of the Kansas program would further extend this capability to directional and horizontal drilling with the aim of bringing similar benefits to these types of operations.
The rig selected was a hybrid rig with a “Big Wheel” injector (see Figure 2). This provid-
The CT used was 2-7/8” with a total capacity of 5200’, and had a heptacable wireline
An Innovative System
Figure 2. The “Big Wheel” Injector
Figure 3. Diagram of the 5” BHA
pumped through to allow wireline connection for power and data transfer to the BHA. Using this larger coil size would further enhance CTD capabilities by providing greater stability, better dynamics, less friction loss and the ability to drill deeper and larger wells in harder formations.2
cluding the drilling motor). With its wireline connections the data could be sent in real-time back to the operator for immediate feedback. The size of drilling motor, motor bend angle and choice of bit was altered according to the particular requirements at various stages of the drilling operations.
For directional control the BHA was combined with a motor with a bent sub and drill bit. The BHA used featured a Rotating Orienter that could rotate the entire tool assembly to the required position from below this point, making it possible to point the bit in any direction. A straight hole could also be easily drilled by simply rotating the tool continuously. Positional data was collected through the system’s unique gyro system, which uses a solid state gyro to determine the 3D position of the tool. This was the first time that a gyro system had been used whilst drilling to take measurements in all orientations from vertical, right through to horizontal.
The Well Program
The complete BHA (see Figure 3) consisted of a tubing end connector, a cablehead (incorporating a rope socket and check valves), an electric release system, electric Orienter (with full 360° rotational capabilities), a sensor module (with real-time pressure, temperature and vibration monitoring) and a gyro directional unit. The 5.0” diameter tool had a length of approximately 15’ (ex-
The well program consisted of 5 wells drilled in the Niobrara formation along the Colorado-Kansas border, that required the use of DCTD specifically. The drilling program was completed in two phases and involved drilling through the shale into the limestone formation and following various different well profiles. The first three profiles, one of which was S-shaped and the other two deviated, took advantage of the ability of DCTD to pinpoint a particular spot in the reservoir without having to physically position the rig vertically above it. This enabled easy access to reservoirs that were difficult to access from directly above, and were therefore unsuitable for vertical well operations. The last two wells were horizontal and the primary objective for these was to open up more of the reservoir to the wellbore and keep the formation fractures clean by drilling horizontally and underbalanced (which was also necessary due to the propensity of the for-
mation to take fluid). All of the wells had their surface hole drilled and surface casing set using a water well rig. No pad or access roads were prepared in accordance with the low margin nature of the wells in the particular fields.
Vibrational analysis One of the objectives of the drilling program was to carry out some initial analysis into the vibrations experienced while drilling, with a view to seeing how vibrational data can be used to inform operational procedures in the future and to set appropriate tool qualification procedures in manufacture. The vibrational sensors used in the BHA enabled the operators to monitor the vibrational accelerations in real time in four axes to provide immediate feedback on the tool’s performance. The module also allowed the team to record short 16 second slots of all the data at a particular time for further, more detailed post-drilling analysis. The real time analysis provided continuous reporting of peak and average acceleration levels in average axial, radial and rotational senses. The comparative effects of drilling with mud and air are shown in the Figures 4 and 5, respectively. With the bit off the bottom and using an air mist drilling fluid, shock spikes of up to 250g were recorded by the accelerometers, which is approximately 5x higher than when drilling in mud. 21
face and during orientation in the casing prior to kick-off. This program demonstrated that it is economically and technologically possible to accurately and efficiently drill and case directional wells with larger hole sizes for a variety of well profiles. By building on the technology and lessons learned in the Kansas program, future operations will be able to validate the economic benefits of the solution in comparison to existing techniques. In light of a fast-approaching future where low cost, low impact re-entry operations will become ever-more pertinent, this technology is sure to change the landscape of the industry for the better.
References B. Littleton, S. Nicholson, and C. Blount., “Improved Drilling Performance and Economics Using Hybrid Coiled Tubing Unit on the Chittim Ranch, West Texas,” paper prepared for presentation at the 2010 IADC/ SPE Drilling Conference and Exhibition, 2-4 February 2010, New Orleans, Louisiana, USA
Figure 5. Sample Real Time Vibrational Data when drilling with air Figure 4. Sample Real Time Vibrational Data when drilling with mud
Overview of program performance The successful completion of the program saw all five wells drilled as per the criteria in the job specification, and producing following completion, with no HSE incidents reported. The tools were shown to withstand the harsh vibrational forces associated with drilling with air (which was used for both horizontal sections drilled), demonstrating that this type of set-up is fully capable of directional and horizontal drilling of wells with hole sizes ranging from 6.25” to 8.5”, and with both mud and air as the drilling fluid. Vibrational data was successfully collected and has been subject to further and ongoing investigation. Finally, the operational requirements for the end well position to be within 150’ of the target position were met and the reliability of the gyro was proven during the kick off, build and horizontal sections. Learning points for future DCTD operations As it was the first time that the combination of a hybrid drilling rig and the new 5.0” 22 | MED OIL & GAS | October 2018
BHA with rotary orienter and solid state gyro steering system had been used in the field, the operation offered some valuable lessons. The most notable of which are as follows: • When kicking off, allowances must be made for the kick of the bit which is significant, particularly when in larger casing sizes. • When drilling shallow wells, there is little or no time to correct if the wellbore trajectory deviates from the plan. This highlights the importance of precise planning, accurate tools, and good training. • The tool’s ability to respond depends upon the build rate that can be achieved for a particular motor bend setting in the specific rock formations being drilled. Time to establish this response must be allowed for in the drilling program so that motor bend settings are chosen correctly. • The size of casing must be selected in accordance with the size and bend angle of the motor, otherwise problems may arise during tool make-up at sur-
Drilling Contractor Article - Bigger coil sizes, hybrid rigs and RSS advances pushing CT Drilling to next level – http://www.drillingcontractor.org/bigger-coil-sizes-hybrid-rigsand-rss-advances-pushing-ct-drilling-tonext-level-1572, March/April 2008
Author
Toni Miszewski Managing Director, AnTech Ltd Toni Miszewski is the Founder and Managing Director of AnTech Ltd. With 33 years’ experience in the oil and gas industry, Toni holds 20 patents for oil tools and technologies and has led the company’s drive to enter the Directional Coiled Tubing Drilling (DCTD) service sector. Before founding AnTech in 1992, he worked for Schlumberger Ltd in Europe, Africa and the US in a variety of engineering development roles. He holds a Bachelor of Science Degree (Hons) in Mechanical Engineering from Imperial College, London. Toni is a long-time member of the SPE and is a Chartered Mechanical and Electrical Engineer.
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Sicily and Malta Channels Petroleum Prospectivity INTRODUCTION
Geological evolution
The Sicily and Malta Channels, located between the offshore zones of Sicily (Italy), Malta and Tunisia, are one of the most productive petroleum provinces of the Mediterranean Region.
On a geological stand point, the Sicily and Malta Channel basin is located within the south-central segment of the Apennines-Maghrebides belt developing in the central Western Mediterranean. It represents an important structure of the deformation belt formed by the relative motion of the Europe and Africa during Neogene-Quaternary time.
A total of nearly 800 wells have been drilled in the Sicily and Malta Channel basin, with more than 300 wells considered as wildcats. This exploration activity led to the discovery of 70 fields, with 20 still on production. The first period of O&G exploration years have resulted in some significant oil and gas discoveries in the adjacent onshore areas of Ragusa, in Sicily, during 1953 and El Borma, in Tunisia, in 1964. The offshore exploration also resulted in noteworthy discoveries of the Vega heavy oil field, offshore Sicily, and of the Ashtart and Miskar hydrocarbon discoveries, offshore Tunisia. A further 20-30 discoveries have been made, all of which have been less than 30 MMBOE. In Malta no hydrocarbon discoveries have been made up to now. The presence of several and widespread oil seeps both onshore Sicily and onshore Tunisia has demonstrated since the beginning the presence of a working petroleum system. The most recent exploration activity carried out in the last 15 years has led to some interesting new discoveries that have focused the attention of exploration companies to this part of the Mediterranean basin. The main discoveries of the last decades are: Panda (2002-2003), Baraka South East (2002), Argo (2006), Cassiopea (2008), Dougga (2009), Lambouka (2010-2011).
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The Sicily and Malta Channels regionally belong to the African margin and are crossed by several tectonic lineaments associated mainly to the Mesozoic to Cenozoic rifting and to the more recent strike slip tectonics. This complex tectonic evolution has produced (from Mesozoic to present) a series of basins (Pantelleria, Malta and Linosa Grabens) and structural highs that can still be identified by the irregular bathymetry (see Figure 1). This area represents the bridge between the Neogene Africa-vergent chains of the Tunisian Maghrebides and the Southern Apennines. In mainland Sicily the result of such collision is the E-W trending Northern Range of Sicily, composed of a pile of thrust sheets each representing a former paleogeographic unit (Catalano and D’Argenio, 1982). The foredeep of the system is represented by the Caltanissetta Basin, between the mountain chain and the Hyblean Foreland. Southwards, the Gela Nappe wedges into Plio-Pleistocene sediments in the most external part of the basin, the so called Gela foredeep (Argnani, 1987). To the west, the foredeep is characterized by the complex inverted fault system related to the inverted Messinian foredeep, which developed from the south-western coast of Sicily to the northern offshore Tunisia.
Stratigraphy The Sicily and Malta channels are characterized by a long lasting and complex stratigraphic evolution, characterized by the occurrence of variable depositional environment and changes in sedimentation through time.
The Mesozoic succession of south-eastern Sicily and Malta is characterized by the occurrence of widespread carbonate platform settings with occurrence of intra-platform depressions and lateral euxinic basins. The platforms fragmented and differently drowned from Lower Jurassic onwards, leading to the deposition of pelagic carbonates with variable clay content that persisted locally to Eocene, punctuated by several emersion episodes. From Eocene to Miocene, carbonate ramp geometries developed in some sectors of Hyblean Plateau and Malta, and are locally overlain by evaporites related to the Mediterranean salinity crisis. The Sicily Channel was affected by continental rifting that produced the Pantelleria, Malta and Linosa tectonic depressions during the late Miocene to early Pliocene, filled with turbidites and basinal clays and marls. In Tunisia, carbonates, marls, sandstones, and mixed platform deposits occur between the major fault corridors and are present in different stages of the Mesozoic, from the Triassic to the Upper Cretaceous. Generally, the Tunisia offshore is characterized by strong variability due to variable siliciclastic input from emerged land, and by the occurrence of more frequent evaporite intervals if compared with Sicily. Deeper water deposition, comprising thick shales intervals, passing laterally to shallow water carbonates and evaporites characterized the Cretaceous and Paleogene. The Cenozoic deposits of Tunisia comprise marine and terrestrial siliciclastic facies as well as minor carbonates; Oligocene and early Miocene sequences consist of various facies, from deep sea flysch to continental beds, whereas Middle Miocene to Pleistocene succession consists of a complex succession of syn-orogenic facies with molasses.
Source Rocks and Geochemistry The evolutionary history of the area between Sicily and Tunisia shows the succession of numerous potential source rocks, which are the result of the alternation of
Figure 1. Tectonic units and subunits of the Sicily and Malta channels area, with indication of the localities, fields and wells cited in the text (GEPlan Consulting, 2015).
different depositional environments that have allowed the accumulation of significant thicknesses of organic material. The Sicily and Malta Channels area incorporates different source rock horizons. The most important, as shown in Figure 2, are: the Eocene (Ypresian) Bou Dabbous Formation; the Cenomanian-Turonian Bahloul Formation; the Albian Fahdene Formation; the Jurassic Nara Formation; the Late Triassic-Lower Jurassic Noto and Streppenosa Formations; the Silurian Tannezuft Formation. From geochemical analysis available in literature, it is possible to observe that most of the source rocks are kerogen type II rich organic materials deposited in lacustrine or oceanic anoxic conditions. Other kerogen type III rich in organic matter are of terrestrial origin. Only Bahloul and Bou Dabbous source rocks show the presence of kerogen type I. The Gas in the Sicily channel has a different origin in relation to the different source
rocks, but in general it is characterized by a quite low amount of sulphide. Another peculiarity is the presence of CO2 related to volcanic activity that can be important especially close to Sicily and Pantelleria Island. The Oils in the Sicily Channel can be subdivided in several families, based on the geochemical characteristics. The heaviest oils are located in the Ragusa area, with density reaching 7° API in the Gela Field. The other fields are showing lighter oils, like Mila or Nilde Fields. The source rocks are normally carbonate rocks, except for Nilde and Norma Fields, where the geochemical imprint is linked to an Oligo-Miocene clastic rock (Granath and Casero, 2004; Caldarelli et al., 2011).
Reservoirs In Sicily and the Malta Channel, it is possible to find various good quality reservoir types (Figure 2). The complex and very long sedimentary history allowed the development of multiple depositional environments and it is possible to find: (i) Carbonate reservoirs,
ranging in age from the Mesozoic to Cenozoic, where diagenesis and fracturing are frequently very important. The carbonate reservoirs affected by dolomitization processes are characterised by an enhancement of fractures and vuggy porosity. Furthermore, in some cases, reservoir properties are connected to karst systems. (ii) Clastic reservoirs, within terrigenous sediments deposited during the Mesozoic to Cenozoic. In this clastic reservoirs interesting porosity is associated to the coarser grained textures where intergranular porosity can be well developed. The most important carbonate reservoirs are the Late Triassic to Lower Jurassic intervals (Sciacca, Inici, Streppenosa Fms are reservoir in Vega, Aretusa, Gela and Mila fields, Upper Nara in Ezzaouia field), whereas in Tunisia offshore the carbonate reservoirs are also of Cretaceous to Paleogene age (for instance the Cretaceous Serdj, Orbata, Zebbag, Isis, Miskar, Douleb and Abiod Fms, the Eocene Bou Dabbous, El Garia and Reineche Fms, the Oligocene Ketatna Fm), while Mio31
Figure 2. Schematic stratigraphy of Sicily and Malta channels from Triassic onwards, with indication of the main reservoir and source rock intervals.
cene reservoirs are represented by Nilde and Ain Grab Fms. Among the clastic reservoirs, the most important are the Triassic Kirchaou Fm, the Jurassic-Cretaceous M’Rabtine and Meloussi Fms, the Oligo-Miocene Fortuna Formation, the Miocene Birsa sandstones and the clastics of the Gela Foredeep.
Seals The complex tectonic and sedimentary history of the Sicily Channel comprised the development of several basins with deposition of very fine-grained sediments that could act as effective sealing units. Most of cap rocks are made of shale deposits, other by argil32 | MED OIL & GAS | October 2018
laceous-marly sediments. Buccheri, Lower Fahdene and El Haria Formations are some of the main sealing units, together with Evaporitic intervals, such as Messinian Anhydrites.
Geothermal Gradients and Migration The geothermal regime in the Sicily Channel varies from 1 to 5°C/100 m. The coldest area is localized in the Ragusa Basin and the Malta Plateau with 1.7 to 2.7°C/100 m, while the highest area is the Gulf of Gabes and in the Hammamet region (up to 5°C/100 m; Dhia 1988, 1991). The local geothermal gradient can be modified by the presence of volcanic activity, with shallow intrusions, especially close to the Pantelleria Graben.
A series of 1D basin models have been performed in Petromod 1D Express, with a constant heat flow calibrated on present day temperatures (Figure 3). The regional heat flow is extremely variable and is mainly related to the present day volcanic and tectonic activity. The subsidence curves show the extensional event related to the opening of the Sirte Basin in Libya and this tectonic event is also extremely important for the trap development and the source rock maturation. The basin modelling shows that the present oil window is located between 1300 m and 3900 m of depth, depending on the geothermal gradient. The first phase of generation occurred in Late Upper Cretaceous
Figure 3. Thermal history of Ksar-1, Remo Nord-1 and Egeria-1 wells (see reference map for location; GEPlan Consulting, 2015).
for the Cretaceous source intervals and continuing into the Neogene for the Neogene. The gas charge began from the Cretaceous source rocks in the late Palaeogene and continues to the present day.
(1) The Platform Plays (Streppenosa Basin Play; Gulf of Gabes Mesozoic Play; Cretaceous Carbonate Play; Eocene Play; Miocene Play) are mostly related to fractured carbonate reservoirs of various age.
Plays
(2) Transition Plays: Biogenic Gas Play (localized in the Gela foredeep); Extensional Basins Play (connected to the central Cenozoic grabens).
The main plays of the area can be described and catalogued based upon their geological context. Three main macro-systems were identified: Platform Play, Transition Play and Fold Belt (Granath and Casero, 2004) within which it was possible to classify 8 plays distributed in the Sicily Channel area.
(3) Fold Belt Play: inverted Inner Messinian Foredeep, localized in Nilde Field surroundings.
References Argnani, A. (1987). The Gela Nappe: evidence of accretionary melange in the Maghrebian foredeep of Sicily. Mem. Soc. Geol. It, 38, 419-428. Dhia, H. B. (1988). Tunisian geothermal data from oil wells. Geophysics, 53(11), 1479. Dhia, H. B. (1991). Thermal regime and hydrodynamics in Tunisia and Algeria. Geophysics, 56(7), 1093. Granath, J. W., & Casero, P. (2004). Tectonic setting of the petroleum systems of Sicily. , in R. Swennen, F. Roure, and J. W. Granath, eds., Deformation, fluid flow, and reservoir appraisal in foreland fold and thrust belts: AAPG Hedberg Series, 1, 391–411. Caldarelli, C., Smith, D., Turrini, C. (2011). The link between the onshore and offshore Sicilian fold and thrust belts: tectonostratigraphic evolution and implications for hydrocarbon exploration, New and Emerging Plays in the Eastern Mediterranean Conference, London, 45-46. Catalano, R., & D’Argenio, B. (1982). Schema geologico della Sicilia. In: Catalano R. & D’argenio B. (Eds.), «Guida alla Geologia della Sicilia occidentale», Soc. Geol. It., Guide Geologiche Regionali, Palermo, 9-41.
Conclusions Although the Sicily and Malta Channel is a complex area, it has not been thoroughly explored yet and there are still excellent possibilities for oil and gas discoveries evidenced by the good rates of production in both Sicily and Tunisia. Good opportunities are envisaged for the future exploration, supported by the significant discoveries made in the past and stimulated by the improved seismic surveying technology, which have made remarkable changes in our understanding of the potential exploration prospectivity of this area. If you are interested to know more about the Sicily and Malta Channels please contact angelo.ricciato@geplan.it
Authors GEPlan Consulting, Ferrara, Italy
Enrica Battara Geologist
Alberto Riva Principal Carbonate Geologist/ Geoscientist Consultant
Angelo Ricciato Senior geologist, Project Manager and Quality Assurance Manager
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Chela Further Evolved! With Chela’s inherent safety and efficiency enhancing features as the guiding principle, GustoMSC now introduces an improved design of this multifunctional lifting tool. May this year, GustoMSC announced the first order for Chela, a landmark event that further accelerated its development. Prior to going into the fabrication, installation and commissioning phase, GustoMSC together with its client Maersk Drilling and their client AkerBP, have been closely working together to further improve Chela.
The most significant enhancement introduced into Chela since the order announcement is an increased reach capability under the cantilever, further improving its material handling and safety capabilities over the wellhead area. This has been achieved by introducing an additional “link”, which offers larger flexibility in movement of the lifting tip and thereby increasing reach and control of the supported object. The additional link enhances its crablike motion characteristics. Chela can reach below the cantilever as well as elevate and reach towards the main deck, providing crane access to an area traditionally not accessible due to blocking of the access for the rig cranes by the drilling cantilever. Its safety features allow these operations while simultaneously conducting operations on a well from the drill floor and without the need to shut-in other wells.
Background The Chela lifting and wireline tool has been under development since 2015 to address the need for increased efficiency and cost reduction from the oil companies and service companies. Three key elements were at the basis of the development of this equipment: enhancing the overall efficiency of the drilling jack-up by providing its key features of a large lifting capability and reach and wireline operation capabilities below the cantilever, easing material handling from the drilling jack-up to the production platform and safe lifting over live wells by applying high safety standards.
two key features of lifting and wireline operation capability below the drill floor independently from the drill floor. A key feature is the 25 metric ton hoisting capacity underneath the cantilever at any position below the cantilever, including the possibility to reach to the main deck of the rig for a handshake with the rig’s main cranes. It can transfer containers and other pieces of equipment from the main deck of the rig to underneath the cantilever and vice versa in a single lift operation. This unique feature greatly enhances safety and efficiency of material handling operations from the drilling jack-up to the production platform, as rig crane access to the wellhead deck from the drilling rig is normally blocked by the cantilever.
Enhancing efficiency The Chela lifting and wireline tool significantly enhances efficiency by providing its 36 | MED OIL & GAS | October 2018
The second key feature is Chela’s ability to enable wireline operations independently
from drill floor operations. The Chela lifting and wireline tool is fitted out with a series of wireline guide sheaves to guide the wireline to any position where the tip of Chela can reach. The wireline operations can take place offline, on any other well, while the derrick is engaged with normal drilling operations. This feature of Chela results in significant savings in rig days for plug and abandonment operations that can amount to around 15% compared to the conventional procedure, by providing offline activities such as logging and cementing that normally need to be performed in sequence on the drill floor. The Chela lifting and wireline tool can also be easily retrofitted to the cantilever of various types of existing drilling jack-ups, improving offline drilling efficiencies of both new and existing rigs and increasing the flexibility for
Maximizing safety
dling from the drilling jack-up to the production platform. The high level of control of the load while in the hook, as a result of the short distance from tool tip to hoist, has a substantial positive impact on the overall safety of the material handling operations and personnel involved.
During material handling and drill floor operations the crew does not need to be physically present. This reduced exposure of the crew to risk is, when done correctly, favorable to safety and can also contribute to lower cost. As the Chela lifting and wireline tool separates wireline operations from the drill floor operation, it reduces the need for human presence on the drill floor. By separating operations also less interaction is required between different crews as rigging up for the operation is done offline, this further reduces risk for the crew.
Moreover, Chela’s main hoisting system is fully redundant, a key technical feature needed when working over live wells. This is achieved by executing the lifting system of Chela as a dual-winch system with two times 100% capacity. As a consequence, no single failure, including the failure of a hoisting rope will lead to a high risk situation. Additionally, Chela will keep the load steady after a rope failure. A snag load absorb system further prevents excessive loads on the lifting ropes and structural parts of the crane.
Enabling a single lift from the main deck to the wellhead platform below the cantilever reduces handshakes during material han-
Controlled with a handheld remote allowing the crane operator to be in the optimal position to oversee and control the operations
the operators and contractors. The design of the cantilever interface also allows quick mobilization and de-mobilization, which can also be performed offshore, and allows sharing of Chela between rigs.
at all times, supplied with an anti-collision procedure and electrically driven eliminating the risk of hydraulic spillage, further improve the level of safety. Safety is a prerequisite offshore: it is simply expected to be at the highest level. Continuous improvement of safety at sea is a key driver for GustoMSC to further develop its offshore technology. The evolved Chela lifting and wireline tool is a perfect example of this ambition. Meanwhile the project to deliver the first unit offshore to the Maersk Interceptor is proceeding in full swing and bringing the first operations with the Chela tool continuously closer to reality. With all this, GustoMSC continues to see a high level of interest in the game changing Chela tool, and no doubt this will make its way further into the offshore drilling industry with the increasing level of activities.
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3Q 2018 results from BP p.l.c. “Our focus on safe and reliable operations and delivering our strategy is driving strong earnings and growing cash flow. Operations are running well across BP and we’re bringing new, higher-margin barrels into production faster through efficient project execution. We have made very good progress with our acquisition from BHP and expect to complete the transaction tomorrow. This will transform our position in the US Lower 48 and we expect it to create significant value for BP. This progress all underpins our commitment to growing distributions for our shareholders.” Bob Dudley, Group Chief Executive.
Strong earnings and cash flow: • Underlying replacement cost profit for the third quarter of 2018 was $3.8 billion, more than double a year earlier and the highest quarterly result in more than five years, including significant earnings growth from the Upstream and Rosneft. • Operating cash flow excluding Gulf of Mexico oil spill payments for the quarter was $6.6 billion, including a $0.7 billion working capital build (after adjusting for inventory holding gains). • Gulf of Mexico oil spill payments in the quarter were $0.5 billion on a post-tax basis. • Dividend of 10.25 cents a share for the third quarter, 2.5% higher than a year earlier.
Strong operating performance: • Very good reliability, with the highest quarterly refining availability for 15 years and BP-operated Upstream plant reliability of 95%. • Reported oil and gas production was 3.6 million barrels of oil equivalent a day. Upstream underlying production, which excludes Rosneft and is adjusted for portfolio changes and pricing effects, was 6.8% higher than a year earlier, driven by ramp-up of new projects. Rosneft production of 1.2 million barrels of oil equivalent a day was 2.8% higher than last year.
t us a t i s i V EC A DI P a b i : Dh A b u Pa v i l i o n an Ger m
Strategic delivery: • The Thunder Horse Northwest expansion project in the Gulf of Mexico and the Western Flank B project in Australia began production in October, both ahead of schedule. They are BP’s fourth and fifth Upstream major projects to start up in 2018. • Further expansion in fuels marketing, with now around 1,300 convenience partnership sites worldwide and network growth in Mexico.
BHP transaction: • The acquisition from BHP is expected to complete on 31 October. • Reflecting confidence in cash generation and continued capital discipline, and assuming oil prices remain firm in the recent trading range, BP now expects to fund the entire transaction from available cash, rather than using equity for the deferred consideration. In this case, proceeds from the associated $5-6 billion of divestment s will be used to reduce net debt. 38 | MED OIL & GAS | October 2018
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Butterbrot Kindergarten Heimat Oktoberfest Wunderkind Energiewende
Zuverlässigkeit From Butterbrot to Energiewende, many German words are known round the world. We’ve added one more to the list: Zuverlässigkeit, meaning reliability. That’s what we, Germany’s biggest oil and gas producer, stand for in Europe, North Africa, South America, Russia and the Middle East. www.wintershall.com