The Importance Of Stripping And Splitting Tools For Encapsulated Cables
Stripping and splitting tools are used to remove encapsulation (of varying hardness and dimensions) from a cable or control line quickly and safely. They make stripping and splitting cables much safer because there is no need for knives or hacksaws, preventing the risk of injury. Their unique design ensures that plastic encapsulation is stripped away without damaging the internal metal lines. AnTech’s Air Powered Splitting Tool safely and efficiently splits multiple lines in flatpack, which can then be stripped of encapsulation using AnTech’s stripping tool range. The Air Powered Stripping Tool has proved to be better suited for longer lengths of encapsulation. The Air Powered Splitting Tool can be adapted to different line sizes by changing combinations of guides, wheels and Hand Stripping Tools. The splitting tools are non-adjustable, however, conversion kits for different size flatpacks can be provided. These tools can be used on hydraulic or electrical, single or multiple lines and can remove encapsulation from flatpack ranging from 11 x 11mm to 65 x 65mm. In deciding the correct line size to adapt the tool to, for successful application, it is important to have the flat-pack details or datasheet for the TEC line which will indicate the outer diameter of the line: 1/8”, ¼”, 5/16”, 3/8”, 7/16”, ½” and 5/16” and the dimensions of the flatpack itself. AnTech provides a range of stripping and splitting tools and the team can help you specify what you need for your particular application, so please get in touch if you would like to know more. Author: Alicia Beasley
What is a Downhole Cable Splice?
A control line splice is a means of connecting two separate cables providing a continuous electrical connection. The splice is sealed against the environment in an outer metallic body and is mechanically joined to both ends of the gauge cable providing a metal to metal seal. It is necessary that the connection is reliable, corrosion resistant and suitable to be used for long periods of time. If a splice has metal to metal seals, then the lifespan will tend to be much longer than a splice that uses elastomeric seals. Critically, a splice should have the means to be pressure tested as part of wellsite testing and checks. Splices are commonly used at the wellsite to extend existing cable, to replace sections of damaged cable or to connect to equipment mid line. They are simple to make up and a reliable solution. A control line splice can come in different sizes and materials to suit different cable specifications. It is important that the material of the downhole cable, usually SS316 stainless steel or Inconel 825 is matched with the ferrules in the metal to metal seal to prevent any galvanic effects. It is important that the pressure and temperature ratings are suitable for the wellsite environment. You also need to match the electrical specification of the splice to ensure the equipment you are running is compatible. Splices can be used to connect hydraulic, fibre and electrical cables. Author: Emily Blackman
The Importance of Document Control within Upstream Engineering
What is document control? Document control is the management of certain documents and the ability of engineers (or other members of staff) to make changes to them. This is normally very strictly controlled for documents such as technical drawings or manuals. Each company will have their own procedure for document control however they are generally very similar. At AnTech, drawings are given a simple A, B, C revision initially which is peer reviewed. This means the engineers check one another’s drawings and must sign them off before the drawing can go “live” in the system and be seen by other staff members (for example the production team who will be ordering parts and assembling the designs). When the design has been proven, it is moved from the initial (usually prototype) stage to the released stage. Here, documents start from revision RA, RB, RC etc with the capital “R” standing for “Released”. This means the level of document control for such parts is higher. In addition to peer review, any engineer wanting to make a change to a drawing must submit an Engineering Change Notification (ECN) which is then signed off by the Engineering Manager, the Production Manager and the Quality Manager. This process must be followed before any work can take place, once the ECN has been signed off, the engineer is allowed to make changes to the parts specified on the ECN and these are peer reviewed as before. Finally, once the work has been completed the Engineering Manager must check the work against the ECN before the drawings are released. Why is document control important? It is essential to have document control on engineering drawings, and other technical documentation for a number of reasons. Firstly, document control is a requirement for many different standards to which AnTech conforms. For example, ISO 9001 requires that companies are able to approve documents for adequacy prior to use, identify changes and prevent obsolete documents from unintended use. By following standards like these, document control ensures that drawings and other technical documentations are checked by someone other than the author meaning that errors are captured, for example a drawing error is picked up before the drawing is sent to the machine shop, saving the part from being manufactured incorrectly. Controlling documents also means that historical changes are captured. As each drawing is taken to a new revision the reason behind these changes is documented. This enables engineers to go back through a design and understand when and why things changed. How has document control changed over time? Traditionally draftsmen would produce drawings by hand and these would be stamped and signed. The original (or master) copy of the drawing was stored away safely and physical copies would be created as per requirement. As technology advanced, the introduction of Computer Aided Design (CAD) meant that drawings could be produced on a computer. At AnTech, CAD drawings were initially printed off, stamped and signed and the master copy was filed away, with the CAD documents (saved on the computer) and a pdf copy of each part were stored on the server using data management software. Nowadays we do not use paper copies at all and we fully utilise computer-based data management with electronic pdfs being signed off within the system. This system has streamlined the design and manufacturing process and ensures we provide the correct products, without any non-conformances for our customers’. Author: Sophie Harris
QA & Testing Procedures For API 6A Surface Equipment: Part Two
Quality Assurance and Testing In the oil and gas industry, operators need to have confidence that their equipment will operate as intended. To prevent problems from occurring, they must be identified and eliminated at the design stage, as well as, during production. To help ensure reliability, customers want products to be made to standards that have been proven by industry experience, and meet their own exact requirements for operational, safety and environmental performance. The main standard for surface equipment that relates to our wellhead outlet product range is API 6A, Specification for Wellhead and Christmas Tree Equipment. Key sections that help ensure this reliability are as follows: Design and Performance (PR1 & 2) To help meet the exact requirements of the environment in which we operate, the standard sets out design performance criteria and the methods to be used to verify them. For standard applications, verification by calculation, finite element analysis and hydrostatic pressure testing are sufficient, this is known as PR1. For HTHP applications, higher levels of testing are required which included temperature and pressure cycling testing, known as Annex F PR2. These are one off tests for each design and do not need to be repeated once qualified. Independent Design Review (IDR) To give customers more confidence in a product, an independent design review (IDR) can be carried out upon request. IDR review is a third-party review of mechanical engineering designs. The third party (for example Lloyds) inspector will show up to location and verify designs against API 6A standards. All designs and calculations will be documented in a report. This report will consist of calculations, FEA (Finite element analysis) running a temp/press/torque test, which then highlights the weaker parts of the design. Once the documentation has been reviewed, a certificate will be given validating the report. Quality Control Plan (QCP) ATEX products are used in hazardous environments and it is important that every design and manufacturing process is followed accurately. A Quality Control Plan (QCP) is something that is regularly requested from customers to be provided when placing an order. It is effectively a quality assurance project plan that documents each step of the production of a WHO. A QCP covers the assessment procedures, as well as any specific quality assurance and quality control activities. A quality plan is created by AnTech which is then approved by the service company and the customer. A QCP lists the different stages it takes to design and manufacture the product. A QCP for a WHO would consist of different stages that need to be followed such as the design plans, drawings for manufacture, material test certificates, pressure tests, electrical or optical tests, mechanical assembly, marking and labelling, work instructions, Production and Quality Files. A final inspection and release may be carried out by a Third Party Inspector (TPI) to review and inspect the QCP. Third Party Inspection (TPI) Third party inspection is commonly requested by the end customer for HPHT or operationally critical work. A TPI provides the customer with an independent quality assurance check. The Inspector checks the processes detailed on the QCP such as pressure testing, gas testing and final inspection before the final product is released. Once the QCP is signed off, the customer will be given an inspection release note to confirm that the product is in accordance with the relevant standards and meets the requirements of the QCP. Author: Emily Blackman
An Introduction To API 6A For Surface Equipment: Part One
API 6A Explained ‘ISO (the International Organization for Standardization) is a worldwide federation of national standards bodies’. International Standards are drafted in accordance with the rules stated in the ISO/IEC Directives. API standards are published to facilitate the broad availability of proven, sound engineering and operating practices. Any manufacturer marking equipment or materials in conformance with the marking requirements of an API standard is solely responsible for complying with all the applicable requirements of that standard. As a manufacturer of completion and monitoring products, we have to be fully compliant with API 6A standards. For example, if we take a Wellhead Outlet, API 6A specifies requirements and gives recommendations for the performance, dimensional and functional interchangeability, design, materials, testing, inspection, welding, marking, handling, storing, shipment, purchasing, repair and remanufacture. For every product that needs to comply to API 6A, you will need to first start at section 1.4 of the standards ‘Product Specification Levels - PSL’ which details five product specification levels. Annex A provides guidelines for selecting an acceptable PSL. PSL-1 is the minimum requirement of API Spec 6A for design, specification, qualification, temperature, process, inspection and hydrostatic test. For example, when picking a material’s class rating from what is listed as standard, a wellhead outlet’s commonly used material class would be FF which is Stainless steel. If a nonstandard material is chosen providing an explanation of why you have chosen a different material is necessary, giving reasons such as the material strength and hardness. Traceability is required until all the tests are passed.PSL-2 Equipment meets all the requirements of API 6A PSL-1 and in addition to this, mandatory traceability is required throughout the entire production process and after completion.PSL-3 Equipment meets all the requirements of API 6A PSL-2 with the Hydrostatic Test time extended, all our products are PSL3 qualified as standard. PSL-3G includes all the requirements of PSL 3 plus additional practices described in API 6A and requires an additional gas-testing requirement for assembled equipment. Moving on to section 4.1 of the standards the ‘Design and Performance Requirements’. There are two performance requirement levels PR1 and PR2 with different design validation procedures. PR1 is the basic level of testing and designing in accordance with material/temp/pressure specifications.PR2 is a higher-level validation design procedure which, on occasion, can be requested by customers. This involves carrying out and applying the test procedures specified, such as pressure and temperature cycles. Pressure shall be monitored and controlled during temperature, see Figure 1, which shows the procedure that’s followed, the letters detailed correspond with specific instructions for example ‘d) Apply test pressure, minimum hold period 1 h, then release pressure’. Figure 1. Test Procedure (Source: API 6A Specification 20th Edition) A third-party test house is used for carrying out the pressure and temperature tests, physically testing whether the product withstands the temperature and pressure specifications. Upon completion, a certificate is given to prove that the equipment has passed. Once a PR2 validation is carried out on a product, it does not have to be repeated. Scaling may be used to validate other similar products if they are in accordance with the limitations set, such as the configuration and the design stress levels stay the same. Any manufacturer of API 6A compliant products needs to have a good understanding of the standard. They also need to be able help their clients understand some of the fundamental requirements and how it impacts the design, testing and QA associated with it to ensure they supply compliant products. Author: Sophie Harris
When Design Meets Reality: A DevelopmentEngineer Offshore
I am a development engineer and in March I had my first trip offshore to install equipment which I had designed. This is a record of my experience. My initial task was to design a fibre optic wellhead outlet suitable for 4 fibres. This was a particularly interesting project for me because our customer (READ) wanted the design to be 3rd party and tested to PR2, which involves pressure and temperature cycling. The purpose of a wellhead outlet is to safely terminate electrical or fibre downhole cables into an ATEX (hazardous area) outlet and connect an armoured surface cable to it so that you can have a safe signal running from downhole to surface equipment, usually for downhole sensor applications. Following the successful testing we were asked to provide a training school to demonstrate the correct installation procedure for both the fibre outlet I had designed and an electrical outlet my colleague had designed. This was to be directly proceeded by a Systems Integrations Test (SIT) at AnTech in which the rig operator would be present so the pressure was on to get the installation slick in a few days. We held the training school and SIT over 3-4 days which, except for a few tooling issues and fibre splicing delays, went very smoothly and we had two seamlessly installed outlets. So far, all had gone pretty much to plan. Figure 1 - SIT Installation at AnTech workshop It was towards the end of this week that some of the guys from READ started talking about how useful it would be to have a person from AnTech join them offshore for the installation. Our sales manager asked if I would be prepared to do this and I laughed and said yes I would be more than happy to help with the installation offshore. At that point, however, I really did not think they would take me up on my offer. A few weeks later I found myself in Aberdeen (my first encounter with Scotland) on a Minimum Industry Safety Training (MIST) and Basic Offshore Safety Induction & Emergency Training (BOSIET) course. This was equal parts fun (with practical drills on fire fighting and helicopter ditching) and petrifying (with horror stories and life raft training). I left feeling confident I could cope during an emergency offshore whilst praying I would never have to apply any of this training in real life. Before heading out I was a mixture of nervous and excited. I kept running through situations in my head; what if the helicopter had to ditch? What if I inadvertently broke one of the off-shore rules? Or worse still, what if the outlet I had designed didn’t go together as planned and I became the girl who tried but failed on the rig? Putting these fears aside I donned my survival suit and life jacket, and took a helicopter ride to the platform. I had to wear a green hard hat and arm band to show everyone I was a newbie and people were very friendly and helpful. I was escorted to the jack up rig and inducted with numerous forms to sign, 4 videos, a talk with the OIM (Offshore Installation Manager) and medic and a grand tour of the rig. It was in the galley (canteen) section of the tour that I met Hans, one of the customers I was helping with the installation. This, I believe, was the turning point at which the nervousness subsided and I began to relax a little. I’d managed to land in time for dinner and, the travel sickness subsiding, I sat down with my new team to a meal of steak and chips. I must be fair; the food was good. Although it was not quite the gourmet selection many of my colleagues assured me it would be, what they lacked in quality, blimey did they make up for it in quantity! It was possible to eat 3 cooked meals per day. If, at the morning break, your 6 o’clock fry up hadn’t quite sated your appetite, they bought out trays of hot bacon and sausage baps to the boot shack. In the afternoon, a selection of cakes and biscuits littered the table – needless to say my diet was postponed for this week. My first few days became a blur, after performing an inventory on the parts and phoning our production team to be told that “yes the redress kits are in the bag, if you open it up…” it became a waiting game. I mostly helped READ with their preparations, for instance planning the installation of the server rack that the fibre would terminate into. This took me by surprise as I had not previously thought about where the surface cable would terminate. Once it was attached to the wellhead that was it, surely? In fact, they had a 6ft server rack, including pull out laptop-style screen and keyboard, and an enormous processor and 8 hard drives to store all the data! Finally, we were told the wellhead was ready for the two outlets to be installed (a third AnTech outlet had already been installed by the Downhole Gauge Company on the previous shift). Once the downhole lines had been pulled through, a member of the Wellhead Company installed the Grafoil® plugs on both the fibre and electrical lines to secure them to the wellhead. Following this, the fibre optic line was prepared; this involved READ carefully stripping back over 1m of the 1/4” tubing and leaving the 1/8” tubing (containing the fibre) intact. One thing which shocked me during the first few hours of the installation was discovering that the wellheads move. I had always assumed they were completely fixed in place, but in reality they rock slightly with the motion of the sea below. After lunch, we continued the fibre installation and the flange and autoclave seal assembly were successfully installed. Following this, a pressure test was performed on the first fibre adaptor. Once the fibre unit was ready to be spliced (this is the process of fusing the uphole/downhole fibres together), we split into two teams; working on the electrical and fibre units in unison. With considerably less space for the fibre unit, the first difficulty encountered was that the 1/8” tubing could not be pulled off straight meaning it took longer to prep the fibre line for splicing. The remaining 4 pressure tests (electrical cable head, electrical flange, second fibre adaptor and fibre feedthru) all passed first time. Following the successful pressure tests the electrical unit was completed except for the cable gland installation as this would be completed by the platform maintenance team on the morning shift. The fibre outlet was completed during the night shift. I really enjoyed my time offshore and it gave me a much greater appreciation of some of the difficulties of the equipment installation on a rig. Exposure to the elements and the cramped working spaces accessed via ladders are not what I usually experience when I test outlets in our workshops! It was fantastic for me to be able to see the project through completely from initial design through to offshore completion, and to participate in the offshore installation on the spot problem solving. Author: Sophie Harris
Is High Specification Technology Possible In A Low Cost World?
We read all the time in the O&G journals about the industry’s new-found ability to operate in a low cost, $50/bbl world. But has safety been compromised? Have technical standards been watered down? Have operators given service companies and equipment suppliers reduced specifications to meet this pricing challenge? No, of course not. Without these fundamental building blocks, our industry would not be where it is today. So how have we addressed this issue and what can we offer customers to meet these dual requirements? I have two examples that I would like to share with you. Wellhead outlets for Completions For many years, we have sold wellhead outlets (WHO) for offshore platforms, developing solutions for many specifications, underpinned by API 6A. The principles of anti-corrosion, design integrity, rigorous testing and quality assurance are where we excel. To maintain these high standards, but use them to develop new, more cost-effective products, has meant questioning our in-house design criteria on some of the requirements we receive for quote and tender requests. Many of our WHO design principles are based on the upper pressure and temperature thresholds. Since 2013, we have sold our cost-effective Type CA electrical wellhead outlet which has a glass to metal feedthrough arrangement suitable for a maximum operating temperature of 160°C. However, many applications require a lower temperature ceiling than this. Elastomers are suitable at these lower temperatures and cheaper so the product range has recently been extended to include a Type CB WHO which has an elastomeric feedthrough arrangement. This takes the maximum operating temperature down to 100°C and so opens up the opportunity to supply an integrated WHO that connects downhole control line to the surface cable, with full explosive atmosphere certification, which costs 33% less than our top end Type C. We have taken this approach further and asked ourselves and our customers whether there are wells that are low pressure and low cost, where a wellhead outlet without a cablehead could be used? With the Type CC WHO we have done this and can again provide an integrated unit, designed and built with API 6A principles but for 60% less than our top end Type C. Good value when you get rid of junction boxes, stuffing boxes and crazy pipework! Data Acquisition for Coiled Tubing Applications To support our Directional Coiled Tubing Drilling service, we have developed our own data acquisition system to support the downhole environment as well as the data integration with operators and partners. However, the software allows us to provide separate stripped-down modules for individual applications such as well integrity monitoring which only requires a pressure and temperature sensor and maybe a pump rate. Much narrower specifications strips out the need for the full system and consequently saving costs for you as the customer. This approach has led to the development of our ACQUEST product line which is a fully bespoke data system, modifiable to the customers’ needs, including explosive atmosphere certified wireless options. Importantly it allows the options to be modified around the price the customer wants to pay. At the most cost-effective end of the spectrum, our hard wired DAQ-H option is a power and connections unit, a junction box suitable for up to 10 sensors (digital and analogue) and a standard tablet to run the software. The unit is easily upgraded to zoned options. Getting the Specification Right These two examples demonstrate how we have approached this challenge for our existing and new product lines. By looking at the specifications of our products against the customer requirements, we have identified where we can compromise to provide a more cost-effective solution. We will continue to employ this approach, as will many companies in the oil and gas market who are also facing the same challenge. Author: Tim Mitchell
The Evolution Of PPE In The Oil & Gas Industry
Personal Protective Equipment (PPE). It is the last line of defence between the wearer and the hazards they face. These days, for many industries, the wearing of such protective items during work is mandatory. So, have you ever given much thought to the processes that led to how PPE was developed and how it has been improved over the years, decades or even centuries? You may not be surprised to hear that PPE was inspired by the military. The earliest known protective clothing was recorded in the Fourth Century, when Japanese soldiers would strap iron plates to their bodies to protect themselves during combat. Blacksmiths were then known to wear protective clothing to shield them from the molten metals they worked with on a daily basis. Such practices have led to the development of protective overalls, such as those worn in many industries today. The use of respirators is said to have been invented by Leonardo Da Vinci in the Sixteenth Century, and was further developed during WWI to protect the wearer from inhaling the harmful gases that were developed for use as toxic weapons. In modern days, workers wear and use respirators and breathing apparatus to protect themselves from irrespirable atmospheres they may encounter during their line of work. In addition to military applications, the development of protective headwear stemmed from the ship building yards in the 1800s where workers would cover their hats in tar and leave in the sun to cure and harden, thus protecting them from dropped objects such as hammers and wrenches. This ‘Hard Boiled Hat’ was developed by the owner of a mining equipment company, whose son returned from war with a steel helmet, inspiring him to develop something to improve industrial safety. The modern hard hat, as you will know, is made from lightweight plastics and synthetic fibres. No doubt this made them far more comfortable and effective for the user. Whilst modern PPE can be very effective, we must remember to not rely wholly on it to protect us from the dangers we face, both at work and during our day-to-day activities. Author: Harriet Miller
When Is A Measurement Not A Measurement?
If you're reading this blog then you probably measure stuff every day. As an electronic engineer I find instrumentation and metrology, basically the science behind measuring stuff, very interesting. What was the last thing you measured? (No, seriously). When you think about that question you're probably thinking of when you last got a tape measure out. But it's not just that, with all the technology around us on a daily basis we're constantly seeing measurements of all sorts of things. Even without those modern tools you're measuring things yourself, by eye, all the time. Maybe you had to squeeze your car through a narrow gap this morning. That was a judgement, based on a measurement, of sorts. What was the unit of measure? Well it was a relative one: One car width. How accurate was the instrument? Well when you were 100 yards out it wasn't great, just an educated guess maybe if the gap was tight. But if you've still got the wing mirrors on your car then clearly it was good enough. What did you do if you didn't trust the instrument? Slow down hopefully! You adjusted your behaviour based on the quality of the information. Working for a company that makes measurement instruments we're bound to discuss with you questions of accuracy, resolution and repeatability. But really, that's just to keep the project managers happy, it gives us something to sign off. What do you really want to know? That's the interesting part. An easy to illustrate example is position and speed. Let's say you've got a stopwatch, an accuracy about half a second. And you've got that tape measure, giving an accuracy of about 1mm. Measuring the position of the car to about 1mm is pretty good for an object of that scale. Now, measure the speed of the car. Given a clear mile of track, you can do that pretty accurately too. At around 60mph you're accurate to better than 1%. Now let's say you want to plot a graph of speed over that mile. Right now you know the speed and you know the distance, but you've only got one point for your graph. To increase the resolution on the position axis of the graph, let's say to ten points, instead of taking a position every 1 minute (with an accuracy of 0.5s), you're taking a position every 6 seconds. That's now an accuracy worse than 8%. The more you know about position, the less you know about speed. This similar effect pops up all over the realm of metrology when two combined factors affect the resultant accuracy. Uncertainty is an inherent part of any measurement, as with most information in life. With an understanding of what you are trying to do with the measurement, how we overcome that uncertainty in your instrument can easily be solved. Chasing a really high specification can sometimes be an unnecessary waste if it isn't considered in context. Back with the example above, perhaps you didn't really need an accurate speed after all, perhaps all you wanted to know was where on the track the car accelerated and decelerated. Ah, in which case let's use an accelerometer, and for a fraction of the price we can log a graph with 1000 points over the mile. Author: Benjamin Brooking
An Introduction To ATEX Certification
ATEX is the name used to cover the European Directive for controlling equipment in explosive atmospheres. An explosive atmosphere is a mixture of dangerous substances with air, under atmospheric conditions, in the form of gases, vapours, mist or dust in which, after ignition has occurred, combustion spreads. It is necessary for all products exposed to a potentially hazardous environment to be ATEX certified. To prevent an explosion from occurring you must isolate one side of the fire triangle, methods such as excluding the fuel/oxygen or removing/limiting the heat and lastly stop the explosion from expanding and causing a larger explosion. Figure 1. Fire triangle showing fire elements ATEX covers Europe but with its alignment to IECEx is also gaining applications internationally after the Macondo disaster in the Gulf of Mexico. ATEX allows the free movement of Ex products across the European Union. Under ATEX Directive, Ex certification is a marking shown on products to prove that they have been tested to comply with the explosive atmosphere standards. It is a requirement that where hazardous explosive atmospheres occur they must be classified into zones. Each zone is determined by its size and location and is dependent on the likelihood of an explosive atmosphere occurring and for how long. There are three zones of risk: Zone 0 ‘Gas vapour or mist present continually or for long periods of time’Zone 1 ‘Occasionally in normal operation’Zone 2 ‘Not likely in normal operation or not likely’ The higher the risk, the safer the equipment should be, therefore equipment used in Zone 0 should be designed to be safe even after two faults and Zone 1 should be safe for one fault. All products that are ATEX certified must be marked with the CE mark, the ‘Ex’ mark and the equipment coding. For example, an AnTech Type CA Wellhead Outlet is certified as ‘Ex db T3 Gb’. ‘Ex’ meaning explosion proof, ‘db’ is the type of protection ‘Flameproof enclosure’, ‘T3’ Temperature class, meaning the surface of the equipment won’t exceed 200°C, ‘G’ suitable for atmospheres containing gas and ‘b’ must be safe after one fault. The Type CA outlets are also marked with an extended ambient temperature rating (60°C < Ta < +160°C), for more information on this see here: 'The Temperature Confusion Of The ATEX Marking Scheme Explained'. 'Ex d’ is marked on several AnTech Wellhead Outlets meaning that the equipment that may cause an explosion is contained within an enclosure which can withstand the force of an explosion and cools the venting gas preventing it spreading to the outside hazardous atmosphere. AnTech Type XA is certified as ‘Ex e IIC T3 Gb’ ‘Ex’ meaning explosion proof, ‘e’ type of protection is increased safety, ‘II’ Equipment group is surface above ground industries, ‘C’ Most easily ignited (hydrogen or acetylene), ‘T3’ Temperature class, ‘G’ suitable for atmospheres containing gas and ‘b’ must be safe after one fault. ‘Ex e’ is typically marked on AnTech’ s Type X Wellhead Outlets meaning safety measures are applied to the installation to ensure increased security against the possibility of increasing temperatures and sparks from electrical equipment. AnTech’s products are designed to a standard which are approved and tested by a third party notified body, involving the testing and approval of prototypes. Which leads to the next stage of certification: production quality. AnTech’s products are produced and tested precisely to the work instructions, including full traceability of the people who have carried out the manufacturing task and full traceability of the company's used suppliers. AnTech will have an annual audit to check ATEX products. For AnTech’s customers, the approval is in the declaration of conformance found in the QA packs distributed with its products, which includes third party certifications. AnTech can offer various product options with different certifications to meet the customers’ requirements and welcome any questions regarding our Ex products and are happy to provide any education or clarification. Author: Emily Blackman
Wellhead Outlets - Which Outlet Is Right For You?
At AnTech we have been working on providing a wide range of Wellhead Outlet (WHO) options for our customers. In the past, we have struggled to provide solutions for every application. Frustrating for us and for the customer. Now we have a comprehensive range of options from basic electrical units for low cost operations up to fully integrated hybrid electric and fibre optic outlets where the highest levels of specification and certification are required. The question is how do you, the customer, know what is right for you? The best place to start is with the control line and wellhead connection. This determines the family of outlets that might be suitable. Is the control line fibre optic, electrical or a hybrid combination of both? For example, if it is a single electrical conductor line, options are available in our Type X and Type C product families. The Type X is suited to wellhead connections with bolts or stud and nuts and some sort of seal arrangement, something like a Grayloc or FMC’s SBMS seal. If the wellhead only has a standard connection such as an NPT, the Type C family will be suitable. As the Type C doesn’t have a flange and seal it makes it a much more cost effective option, which could be a deciding factor for you or your customer. Therefore, it may be beneficial for your customer to look for a standard connection rather than a bolted and sealed one, if you need to reduce the costs. Once you have established the basic mechanical specification you can then start to consider the rest of the specification. Quite often this is focussed on the certification required by your rig operator or the oil company. If it is an offshore application, you will need it to be explosive atmosphere certified (Ex). Or you may need the outlet to be suitable for use in acidic downhole fluids (NACE/MR0175), or to be certified as fire tested (API 6FB) for use in the North Sea, for example. The next stage is drilling down into the finer details of the specification, specifying the operating temperatures and pressures for your outlet and lastly, there may be a pricing point that you are aiming for. The various WHO families provide options for most specifications but occasionally the price point determines what specification can be achieved. Seldom are there no options that can be supplied, more often, it's a case of referring back to the end user to show them the alternatives. Detailing the specification for the outlet is no different to detailing any other part of the monitoring equipment package. However, it may include additional specification that end users are not familiar with. We have worked hard to be able to provide the options and the documentation to support the decision. Most importantly, equipment must be fit-for-purpose, so the most expensive kit is not always necessary for every installation. So check your specification, check what we have to offer and find out what’s new. The website provides comprehensive data sheets for each family explaining the various options. And finally, we are always available to provide advice. Author: Tim Mitchell
Getting A Handle On The Big Numbers . . .
Remember the headlines in the summer of 2015? “100 billion barrels of oil found under Gatwick!” Well, it’s oil, so that’s good news. And 100 billion sure sounds like a big number. So we should be excited, right? But what does it actually mean? Where does it fit in? UK crude oil consumption in 2012 was 1,520,000 barrels per day. That’s about 555 million barrels per year. Like interstellar distances, or atomic scales, millions of barrels is not a quantity that most of us are readily able to visualise. I like to think of it in terms I can understand. The town where I live, a typical UK ‘market town’, has a recreational swimming pool. The pool is 25 metres long, 1.5 metres deep, on average, and 10 metres wide, giving a volumetric capacity of 375 cubic metres. 1 cubic metre contains 6.23 barrels, so our pool could hold 2,336.25 barrels of oil. It would keep the UK running for 2 minutes and 13 seconds, or four millionths of a year. That’s not really any more accessible. Let’s apply the same principle to something a little larger. The northern tower of the original World Trade Centre (WTC) had a floor area of 4,020 square metres, and it was 417 meters high. A tank that size would hold 10.4 million barrels. So we can say that the UK’s oil consumption can be visualised as approximately 1 WTC (North) tower per week. For all the wrong reasons, most people are able to visualise the WTC (North) tower, and the number of weeks in a year is something that most of us are comfortable with. Combining those two gives us a manageable handle on what 555 million barrels of oil actually represents. It is interesting to contemplate how that quantity of oil relates to reservoir size. Remember that the oil we can hope to recover from a reservoir using today’s technology is a maximum of 25% of the oil in place. So we need a reservoir containing 2.2 billion barrels of oil in place to keep the UK going for a year. We know, of course, that there are no lakes of oil under the ground. Oil is contained in the inter-granular spaces of reservoir rocks. Let’s say this inter-granular space is 10% of the total material volume – it’s not so unrealistic, it keeps the maths simple and it tells us that we need a reservoir volume of 22 billion barrels, or 3.5 billion cubic meters. To get an idea of the size of that reservoir in real world terms, consider the following. AnTech is headquartered in Exeter, Devon, a smallish UK city covering 18 square miles, or 47 million square metres. Whilst Devon is not renowned for its oil prospectivity, we can hypothesise a reservoir thousands of feet below Exeter’s streets. To provide enough oil to keep the UK supplied for a year, that reservoir would need to be 74.5 metres thick. Of course the picture is never that simple in real life. A reservoir that had ‘just’ 555 million barrels recoverable would be expected to yield that total volume over a number of years, with the initial production declining to a threshold of economic viability as the total recoverable volume is approached. The initial production rate, the shape of the decline cure and the length of the tail are strongly dependent on the reservoir characteristics and the amount of reservoir exposed by the well(s) draining it. Similarly, while initial exploration has determined that there is 100 billion barrels of oil in place below Gatwick, the proportion of that oil that will ever be recovered, and the rate at which it is extracted is strongly dependent on the mobility of the oil in that location, and the technologies that we are allowed to use to get to it. But that is a subject for another blog post. Author: Richard Stevens
Super Duplex - Is It Really That Super?
As the industry moves towards more HPHT wells, and with the rise in stringent HSE legislation following the Macondo’10 disaster, we are seeing increasing demands on our products safety specifications. This move, along with a rise in the exposure levels of H2S gas has led to increasing demands for the use of exotic materials with greater corrosion resistance such as the Duplex stainless range and nickel alloys. Although some of the more expensive materials (e.g. Alloy 718) available do genuinely deserve the accolade ‘super’, many, whilst exhibiting exceptional corrosion resistance, compromise on both strength and hardness when compared to standard materials. This is little understood within the industry, and it is often the case that end users will stipulate the need for specific exotic NACE compliant materials for use in inappropriate scenarios, such as unwetted closure bolting. A320 bolts in the L7 grade are supplied with a minimum yield strength of 105 ksi, whilst Super Duplex is supplied with a minimum yield of only 80 ksi. As such, the use of Super Duplex over A320 L7 in unexposed bolting applications, would significantly reduce the load carrying capacity and hence safety factor of a component used in lethal service, with no advantage gained with regards to NACE compliance. Similarly, care must be taken in applications where flanged components and bodies, formally manufactured from standard materials such as 410 SS (with a yield strength of 80 ksi), are substituted for use in highly corrosive environments by materials such as 6 Mo (with a yield strength of only 45 ksi). In this instance, critical dimensions such as wall and flange thicknesses would need to be reassessed with regards to pressure carrying capability, to ensure adherence to appropriate safety factor limits. In conclusion, although many exotic materials do offer significant performance enhancement with regards to corrosion resistance, blanket application of such materials could needlessly compromise other safety aspects of the design, whilst yielding no advantage. As such, it is essential that any material change in applications of lethal service, be accompanied by a comprehensive mechanical review. Author: Chris Bowmer
The Temperature Confusion Of The ATEX Marking Scheme Explained
Of all the confusion generated by the cryptic ATEX marking scheme, often the worst is caused by the different temperature ratings applied to a unit. The first thing to realise is the difference between ambient temperature and maximum surface temperature. Ambient temperature is the easiest – that’s the highest external temperature touching the unit – be it air temperature, temperature of what it’s attached to or the heat of the sun warming the unit. By default ATEX assumes -20°C to +40°C, but often manufacturers will apply extended ratings which will be written as (-20°C < Ta < +60°C). Surface temperature is harder – not least because of the counterintuitive numbering scheme! Any piece of electrical equipment dissipates power, even if it is just a wire or a connector block. This power creates a temperature rise. Add this temperature rise onto the ambient temperature and you get a maximum surface temperature. Why does this matter? Gases will auto-ignite at different temperatures. Less volatile gases such as hydrogen can come into contact with temperatures up to 536°C before risk of ignition. In the event of a gas such as Carbon Disulphide being present then it only takes temperatures of 90°C to cause ignition. So, onto this numbering scheme – there are a set of surface temperatures split into so-called T-classes, T1 to T6. T6 is the most universally applicable covering surface temperatures lower than 85°C. T1, at 450°C requires that the user knows that the most volatile gases won’t be present on site. Custom T marks are also possible, e.g. T120 would denote a 120°C max surface temperature. As you have now seen, the T-class is a product of the maximum power dissipation in an electrical product, added on to the maximum ambient temperature. If as a user you have a high ambient temperature, such as a 140°C wellhead then you are already limited to the T-classes of the equipment mounted to it. From the other point of view, as a manufacturer, if you make something with a high ambient temperature to suit many applications you will be limited if customers require low temperature T-classes. This is the reason why some products will carry different marking options. Author: Sophie Harris