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Designing strings of tubulars for oil and gas wells is always challenging. There are a large variety of parameters which must or should be achieved for successful operations. My personal area of greatest expertise applies to the design of coiled tubing work strings, and as a result this discussion will focus on them. Continuous work strings are in some ways the most difficult type of work string to design, but the principals for work string design are generally the same for jointed pipe as they are for continuous tubing strings. Permanent tubulars such as casing strings, liners and production tubing have different criteria for selection; they are run into one particular well, and then left there either permanently or for very long periods of time. This article is not intended to cover everything required for successful work string design. For simple, or common situations, there are many ‘off the shelf’ assemblies which will be robust and successful. However only a careful evaluation by experienced professionals is likely to yield good success for more complex wells, or when attempting to beat industry norms.
Work strings in an ideal world will meet all the following criteria simultaneously:
· Wide tension, compression, and pressure working envelope
· Impossible to collapse in the event of a catastrophic failure
· Impossible to burst in the event of a catastrophic failure
· Impossible to buckle in a catastrophic failure
· High passive resistance to corrosion, abrasion, acid exposure, H2S and CO2 attack.
· High resistance to dimensional deformation
· Sufficient I.D. and torsional strength to operate all types of downhole tools
· A small O.D. for maximum annular space for cuttings
· High dimensional fidelity with design specifications for predictable results
Ease of use requirements
· Cheap to purchase and long lasting
· Readily able to be manufactured
· Easy to inspect for, identify and resolve problems in welds, threads, and pipe body
· compatibility with widely available BOP systems and running tools while fitting inside common permanent wellbore tubulars
Jointed work strings have a couple of additional factors to contend with:
· Minimal or no connection OD and ID versus pipe body OD and ID contrast (internal and external upset)
· Connections as strong as or stronger than the pipe body
· Identical metallurgical properties between joints and pipe body
· No special handling, transportation or running procedures to maintain joint strength and integrity
· Minimal potential for improper joint makeup by accident or inattention which could compromise the string in use
Continuous work strings lack connection issues but have others:
· Total weight and size should be minimized, since the whole work string is transported around as a single item
· The final design needs to be usable on many wells without ANY alterations since most alloys cannot be safely welded on after initial construction
· The entire work string must have only one outer diameter
· High resistance to cracking and low cycle fatigue under plastic bending
The great difficulty is that many of these factors are directly in conflict with one another. For continuous work strings, the pipe is made in a single piece one time only, so there is no opportunity to make changes between wells, or between different trips on a single well. What you constructed initially is what you get until it is worn out, at which point you get an opportunity for a redesign. With only a few tiny exceptions all work strings are made of steel. Not only is it cheaper than many of the potential alternatives, but the thoroughly understood chemistry and homogeneous internal structure mean that it has reasonably predictable reactions under a wide variety of conditions. Attempts, and limited usage of aluminum, carbon fiber, high strength polymers and other materials have been made for certain types of operations, but they are by far the exception to the rule.
String design always starts with the physical strength requirements – if they are not met, then none of the other requirements matter, because there is no hope of achieving any job objectives. An important tool for this portion of the design process is software modelling. The performance of the work string in specific critical wells which are expected to be worked on, or ‘type wells’ of common sorts can be modeled to determine how well the string performs with respect to weight on bit, total expected tensile and compressive loads, and the excess of each. This is an important part of string design, but reliance on software for design leaves out many of factors which can be critical to successful execution of operations. Usually some form of changes/tapers in the steel wall thickness, or properties is desirable so that the string is lightweight in areas where the forces that could be applied to it are low, and strong (albeit heavier) in areas where the forces that might be applied can be large.
Defining a ‘worst case’ varies from one situation to another, but generally speaking, the following rules should be followed: The pipe should support it’s own weight on bottom in a full column of gas, while not collapsing with MASP at surface: The pipe should not be capable of buckling under expecting working geometries, or if it can be buckled, only under conditions which are controlled/created by the operators of the equipment, and not by wellbore conditions: The pipe should be able to withstand the maximum internal pressure which the circulating system can create without bursting or suffering other permanent issues. Tension and compression available at the BHA need to be sufficient to perform expected operations, and, provide a useful excess margin if the work string gets struck, or well conditions are worse than expected. There are two different general ideas behind the amount of tension that the string should be designed for. One possible criterion is to design the string so that it cannot be pulled in two with the expected equipment and operating parameters it will be used with. This prevents potential failure due to operator error. The flip side is represented by designs with lower total strength, where the full working envelope of the pipe can be utilized during operations, but it is up to the operators of the equipment on location to prevent an accidental overpull. Often this is not a primary design criterion, but merely an outcome of other requirements.
The best physical properties are generally obtained with the highest strength materials available. Steel tubing is commonly available in strengths up to 175,000 psi yield strength for oilfield use. As the yield strength rises, the hardness does also, which provides some protection against abrasive wear. All might end with this set of observations except that high strength steel suffers from several disadvantages. High strength and high hardness are the underlying conditions which cause low resistance to fatigue cracking, poor resistance to low cycle fatigue, and poor resistance to corrosion and chemical attack. These issues can be overcome via passive resistance, or active measures.
Active measures are taken to combat damage to the work string in advance of exposure, when there is reason to believe it might take place. They include things like dosing fluid systems with corrosion inhibitors or H2S scavengers, preventing the influx of formation fluids into the wellbore, and thus into contact with the work string, monitoring the system for the presence of potentially damaging chemicals or gasses, special coatings on the tubulars, and more. Active measures when appropriately performed can allow steels which would come apart in a matter of hours to operate safely for indefinite time periods in hostile environments.
The problem with active measures is that they are in fact active. IF they are not continuously measured, applied, and used their effectiveness can rapidly deteriorate. The best example is H2S inhibitors and scavengers. Some of the most popular and useful coiled tubing alloys in widespread use can suffer complete tube parts as a result of sulfide stress corrosion cracking, or hydrogen stress cracking when exposed to as little as 1 ppm of H2S for as little as a few hours. In theory, one can utilize a combination of preventing formation influx, scavengers, and inhibitors to mitigate this. However even a short lapse in coverage can lead to exposure. Worse yet, H2S monitoring and measuring equipment has a lower detection limit, usually somewhere between 2 and 5 ppm. This means that a lapse of protection can take place which is dangerous to the pipe, and yet be totally undetected by even an organized and properly placed wellsite monitoring program.
Passive protection is provided by the inherent properties of the material. Low yield steels have very considerable resistance to damage from H2S – the structure of the steel simply is not damaged by some H2S exposure. Chrome alloys can provide resistance to CO2. If cost is no object, exotic high nickel alloys like Inconel® and Incoloy® can provide incredible protection from a host of chemical and metallurgical hazards without sacrificing desirable physical properties. If cost is no object.
Ease of use Requirements
Cost and ease of manufacturing and repair often, but not always go together. Sometimes there is a trade-off between high initial cost of purchase versus higher ongoing use costs. Continuous work strings wear out and are used up due to low cycle plastic fatigue during their working lives. In general, low yield strength materials are cheaper to purchase, but wear out more quickly, whereas stronger materials are more expensive but last longer. The ‘best’ choice for a particular operation is not always obvious and may require careful tracking of past operations to determine the best choices. Jointed pipe is vastly easier to inspect and repair than continuous work strings. The ID of the pipe is readily accessible for investigation, and a joint which is sufficiently out of specification can simply be pulled from service. By contrast the continuous work string has no direct physical access to the ID and must be treated as a single item – the whole of the pipe must be assessed on a pass/fail basis. Ease of manufacturing is sometimes overlooked but can be critical. If the work string desired can only be made at a limited number of facilities, or by use of proprietary technology or techniques, it must be clear that the potential limitations in availability or deliver-ability are worth accepting.
Continuous Work strings
A special note on continuous work strings: The ability to physically move them around from one place to another is often a critical design criterion. Coiled tubing well servicing units for use on horizontal shale wells are routinely the largest and heaviest vehicles on the road in the countries and states where they operate. Bridge clearances and weight limits, the radius of turns between roads, clearance over railroad crossings, load limits on lease roads, the ability of wellsite soils to support the loads of the units when in use, entry and exit into industrial parks, and numerous other issues all restrict or potentially restrict their movement. For offshore operations, the ability of cranes on wellsite facilities and rigs to pick up a usable work string is often the primary design criteria for a coiled tubing string. Sometimes it is even a primary design criterion for the offshore facility itself.
Ok - maybe not literally, but recently the talented folks at Shell did something new and different - they drilled a horizontal well that went down, then out, then curved back on itself and headed back towards the starting point. They called it a U turn well, and some of the details about it are here in an article by Trent Jacobs a technical journalist with the SPE: https://pubs.spe.org/en/jpt/jpt-article-detail/?art=6595For those with a subscription to the Oil and Gas Journal, the May 4th 2020 print and online editions contain additional information from some of the key people involved with the project for Shell. If you aren't familiar with the project, I encourage you to read his synopsis of the project before continuing with the discussion below.
I had the privilege of being involved in this project during my time as an engineer for Coil Tubing Partners (CTP). CTP was responsible for drilling out the fracturing plugs, and that portion of the job went very successfully. The success of this project overall reminds me of the general guidelines and rules that make any challenging project turn out successfully, There are several, and the guys at Shell discuss a few of them, but since they were talking about this project in particular as opposed to novel projects in general, they didn't aim their attention to these points directly. Any time you attempt to do something which is new and different, either to your team in particular, to your industry, or in general, try to keep in mind and follow these guidelines. They may seem obvious, and sometimes they are, but sometimes they aren't, or or easy to overlook.
Why exactly are you trying to do something novel? Before striking out into the unknown, make sure that it's being done for the right reasons. If there is another way to resolve the problem that is equally valid, and similar in expected cost and effort, but better understood, you are almost certainly better off than going with a method likely to create unexpected risks or expenses with the new methods that you weren't expecting, if only due to lack of familiarity. Make sure that the new idea really does solve a problem. Shell did that here, because the known methods were burning up a lot of cash without producing useful results. There would be considerable value in success, and the potential loss in the event of a failure was no worse than the status quo.
What about the new technique, method or technology is materially different from past practices and experiences. There have been lots of highly deviated and strangely shaped wells made over the years, especially offshore in deepwater and remote areas. By analogue to these wells, the primary distinction of a U turn shaped well is that it is planned and expected to have a major reverse bend in it's well trajectory. Usually drillers and well planners try to avoid these if possible, since they are known to cause issues with workstring sticking, and casing deployment.
What does the new and different thing mean for the operation as a whole? In this case it meant that unplanned and unexpected wellbore deviations had to be kept to a minimum. Normal practice for horizontal shale wells is to drill the well as rapidly as physically possible. The fidelity/accuracy of the final well path to compared to the original directional plan is a compromise between:
For the U turn project, this 3rd criteria became very important, and superseded the other ones. In most highly deviated wells, the primary difficulty is pushing/pumping plugs on E-line, and coiled tubing down to the bottom of the well at the toe. Getting back out is trivially easy. Not so for a U turn. It is entirely possible to accidentally drill a U turn shaped well in such a way that it would be relatively easy to get IN the hole, but relatively hard to get back OUT. For the rig drilling the well and running casing it's not as noticeable, since they can rotate to reduce friction, but it becomes a major problem in the completion phase of the operation.
Another major planning consideration is to ask, what if the novel element doesn't work the way it is intended to? Planning to succeed without having a clear understanding of what to do in the event of failure means that when a failure takes place (any project of sufficient complexity will involve a few less than optimal situations) it will take place without a clear understanding of what the first few steps might be, or who might need to be involved in them, or what if any new and additional people and mechanisms might need to be called upon. In this project, two primary backup plans were created each with several possible paths, in the event that a pumped down plug didn't reach TD, and in the event that coil couldn't drill out all the standard frac plugs and reach the dissolvables for full access to the second leg of the U turn. Not EVERY contingency needs to be reviewed, or can be, and many of them in a 'novel' project will not necessarily be different from those on a better understood one, but a few of the high probability ones need to be pre thought through.
Keep the novel elements to a minimum required for the project to succeed. It's tempting if you are trying to do something new and different to make everything else on the project 'best in class' or 'improved' or to customize 'stock' elements to increase the odds of success. Avoid this if at all possible. Even seemingly minor changes to 'normal' operating procedures, personnel and organizations involved have the effect of making the whole operation longer, more confusing, and difficult to organize, before even taking the new things into account. To the degree that it can be done, try to fit the 'new' thing into the already established types of operations that have been taking place. Remember that no matter how good the plan looks on paper, or autocad, or a conception, it will ultimately be implemented by a small group of people far from home, working 24 hours a day, in lousy weather, while dealing with the underground forces of mother nature, which are unpredictable at best. Try to stack the deck in their favor as much as you can. Shell did this on this project by working with their already existing vendors, and suppliers to keep the ordinary parts of the project ordinary, so that excess attention and oversight effort didn't have to be directed in multiple directions at once.
This brings me to the final element of novel projects: Get the basics right! I can relay a couple of anecdotes where novel projects were stopped dead in their tracks due to basic failures in organization and communication. Once a long time ago as a trainee, I was on one of the first monobore completion jobs offshore in the Gulf of Mexico. Everything was meticulously planned and organized for weeks before the completion was to start. Once on location, the usual bad luck happened - frac boat delayed, equipment difficulties, etc. However the one problem we could not overcome was that no matter what we did, we just couldn't wash the excess proppant out of the hole. Nobody had figured out how much annular velocity, and subsequent hydraulic horsepower was required to get the high density bauxite proppant out of the hole. I had a concern about it (pressure x rate / 40.8 = hydraulic horsepower right?), but as a very junior member of the team, I was assured that I didn't understand why this wasn't going to be a problem. By the time we figured out on location that it really was a major problem, it was too late - a larger pump wasn't readily available, and with the configuration on deck, we couldn't fit one on the platform anyway. The plug was pulled for about a week to regroup and return with quadruple the starting hydraulic horsepower, and everything went as well as you could imagine. I was also involved in a Coiled Tubing Drillout (CTD) project to do a sidetrack offshore. Not the first ever, but the first in our region, and a first for the organizations involved. A torque-up crew had pre-installed the 7 1/16" BOP's on the casing hanger, and left before the CT crew arrived. Only problem was that the stack leaked, and they used a special right angle drive torque tool to make up the BOP bolts, some of which were extremely close to one another. They couldn't be tightened by an ordinary impact wrench, or hand tools, except for a 12" pipe wrench and a sledgehammer. 36 hours later, and that BOP stack was almost in condition to pressure test. The rest of the project went well (a technical success but not a financially viable one) but one single bolt fitting left behind by the torque crew could have saved about $150,000 in project expenses. When trying to do something new or different, make sure the ordinary things are done well. Don't overlook the 'simple' or 'routine' parts of a project while focusing on the new and different. A project that fails or goes overbudget because of a simple issue is worse than one which had issues due to complex or unexpected issues. At least if the issues were unexpected or novel, you have learned something in the process. In this case, Shell got the basics right, and ended up creating a new way to create value from their assets at minimal risk.
That's all for now folks, and I hope you will keep up with us through future articles and updates. Don't forget the ICOTA call for papers that was recently issued. Feel free to get in touch with EPG solutions at https://epgsolutionsco.com/to get assistance on your next project! Remember the questions to ask about your novel and complex projects, and come up with solid answers to them, and you are well on your way to success.
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