Gravel Pack Cleaning: A New Solution
Abstract: TX 75083-3836 U.S.A., fax 01-972-952-9435. AbstractA large number of fields worldwide have sand production problems and a common solution is a gravel pack (GP) completion. Over time this GP can become plugged with production fines as well as solids that may precipitate out of the produced fluids. As the GP plugs, it creates a larger restriction to flow and the production rate will decline. At some point the operator will decide the production rates are no longer acceptable and intervention is required. As a re… Show more
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Coiled tubing has been used as a well intervention tool since the early 1960's. Since its introduction, the diameter of coiled tubing available has steadily increased, driven by demands for higher flow rates as well as larger push and pull forces. However, bigger coiled tubing sizes require larger equipment and in many cases, the simple physical size of the equipment becomes unworkable, particularly for offshore applications. Some of the most common reasons for not using coiled tubing are:-The platform and/or platform crane is not big enough for coil tubing size thought to be required.The available or manageable coiled tubing size cannot access the bottom of the well.Insufficient pull or push is available using the available or manageable coiled tubing size.The low fluid rates achievable through the available coiled tubing make the job time too great. This paper addresses each of the above arguments put forward against the use of coiled tubing. The paper shows how advances in technology have, to a large extent, removed these perceived barriers, most notably for the most common coiled tubing activities, these being fill cleanouts, gas lifting and acidizing/stimulation. Several technologies have emerged recently that enable small, light coiled tubing units to be used where previously larger units were thought necessary. Introduction The strength of coiled tubing lies in the fact that it is a continuous length of pipe, with no joints and no upsets. Continuous pipe is easy to strip in and out of live wells, even against very high wellhead pressures. It is also fast and safe as no manual operations are required at the wellhead while tripping. At the same time, the fact that coiled tubing is one continuous length can be its own down fall. Two limitations arise from having no such joints: -The coiled tubing generally has to be picked up in one single lift. This can be a very significant lift, in excess of what many offshore cranes can achieve.Pump rates can be limited as the coiled tubing diameter is relatively small and there may be a significant length of coiled tubing remaining on the drum, when the end of the coiled tubing is in the well. This pipe on the drum is a source of significant fluid friction, so limiting pump rates. The advantages of continuous pipe outweigh the disadvantages generally speaking when the size of coiled tubing used is small (11/2" outside diameter or smaller). Even moderately long strings of 11/2" coiled tubing can be picked up by many offshore platform cranes. (e.g. 14,000ft of 11/2", 0.109" wall coiled tubing on a lightweight metal drum weighs about 12 tonnes). The equipment required to run such small sizes is also generally manageable. When the coiled tubing size exceeds 11/2", the weight of the coiled tubing and the associated equipment can become more than can be accommodated, particularly in a marine environment (e.g. 12,000ft of 23/8", 0.156" wall coiled tubing on a steel drum weighs about 24 tonnes). An obvious solution is then to only use small diameter pipe. Historically, this often cannot be done due to the reasons listed above. However, new technologies have greatly extended the capabilities of small coiled tubing. Coiled tubing operations, most notably offshore rigless applications, can now be conducted, where they may not have been possible a short time ago. The following sections examine in further detail why smaller coiled tubing was previously unsuitable, and shows how the new technologies have now enabled its use.
Coiled tubing has been used as a well intervention tool since the early 1960's. Since its introduction, the diameter of coiled tubing available has steadily increased, driven by demands for higher flow rates as well as larger push and pull forces. However, bigger coiled tubing sizes require larger equipment and in many cases, the simple physical size of the equipment becomes unworkable, particularly for offshore applications. Some of the most common reasons for not using coiled tubing are:-The platform and/or platform crane is not big enough for coil tubing size thought to be required.The available or manageable coiled tubing size cannot access the bottom of the well.Insufficient pull or push is available using the available or manageable coiled tubing size.The low fluid rates achievable through the available coiled tubing make the job time too great. This paper addresses each of the above arguments put forward against the use of coiled tubing. The paper shows how advances in technology have, to a large extent, removed these perceived barriers, most notably for the most common coiled tubing activities, these being fill cleanouts, gas lifting and acidizing/stimulation. Several technologies have emerged recently that enable small, light coiled tubing units to be used where previously larger units were thought necessary. Introduction The strength of coiled tubing lies in the fact that it is a continuous length of pipe, with no joints and no upsets. Continuous pipe is easy to strip in and out of live wells, even against very high wellhead pressures. It is also fast and safe as no manual operations are required at the wellhead while tripping. At the same time, the fact that coiled tubing is one continuous length can be its own down fall. Two limitations arise from having no such joints: -The coiled tubing generally has to be picked up in one single lift. This can be a very significant lift, in excess of what many offshore cranes can achieve.Pump rates can be limited as the coiled tubing diameter is relatively small and there may be a significant length of coiled tubing remaining on the drum, when the end of the coiled tubing is in the well. This pipe on the drum is a source of significant fluid friction, so limiting pump rates. The advantages of continuous pipe outweigh the disadvantages generally speaking when the size of coiled tubing used is small (11/2" outside diameter or smaller). Even moderately long strings of 11/2" coiled tubing can be picked up by many offshore platform cranes. (e.g. 14,000ft of 11/2", 0.109" wall coiled tubing on a lightweight metal drum weighs about 12 tonnes). The equipment required to run such small sizes is also generally manageable. When the coiled tubing size exceeds 11/2", the weight of the coiled tubing and the associated equipment can become more than can be accommodated, particularly in a marine environment (e.g. 12,000ft of 23/8", 0.156" wall coiled tubing on a steel drum weighs about 24 tonnes). An obvious solution is then to only use small diameter pipe. Historically, this often cannot be done due to the reasons listed above. However, new technologies have greatly extended the capabilities of small coiled tubing. Coiled tubing operations, most notably offshore rigless applications, can now be conducted, where they may not have been possible a short time ago. The following sections examine in further detail why smaller coiled tubing was previously unsuitable, and shows how the new technologies have now enabled its use.
Effective placement of stimulation fluids on horizontal, long interval and/or gravel-packed wells is critical for cost-efficient production enhancement. Successful case history work in 19991, using precision rotary jetting technology (R-Jet) on the end of coiled tubing (CT), demonstrated to the oil and gas industry that fluid placement is a key factor in removing near-wellbore damage and optimizing well stimulation treatments. This paper will review continued efforts relating to precision rotary jet technology including extensive laboratory tests using a full-scale gravel pack (GP) model. Tests were videotaped for further visual study. Established guidelines applying lab results, computer modeling, and field validation provide a well-engineered, non-damaging (low nozzle pressure) treatment for optimum stimulation performance. Proper damage identification coupled with skillful stimulation fluid design are important steps to a successful job and will be highlighted in the global R-Jet case histories. The data clearly shows that a highly effective method of placing stimulation fluids into a completion, such as sand control screens or slotted liners, is to use CT-conveyed, rotary speed-controlled, forward-angled radial jets. This technique yields 360° coverage of the treatment area, is more efficient than traditional bullheading and CT methods and allows reduced treatment volumes to be considered. It applies to a wide selection of completions including horizontal wells which can now be successfully stimulated at reasonable costs. Introduction Around the world there are tens of thousands of completions with screens and liners2 which could benefit from a reliable and cost-effective method for removing near-wellbore damage caused by drilling fluids, poor completion practices, fines migration and produced fluids. Very often a well begins producing with some form of damage (skin) caused by drilling (drill-in fluid filter cake) or completion damage (lost circulation material, perforating, dirty fluids). This skin will gradually increase over time as the screen/liner continue to collect migrating particulates (fines). Even if a sand control completion begins with no skin, there is an increased chance, due to the down-hole filter mechanism of a screen or liner, that fines, scale, organic deposits and/or drill-in fluid (DIF) filter cake will begin to plug the completion or GP proppant. There are inherent difficulties associated with trying to remove damage from the screen or liner, from the matrix of a GP or from perforation tunnels. Damage related to migrating fines is typically composed of either quartz particles (silica), silicates and alumino-silicates (clays and feldspars) or, more commonly, a combination of these. Scale, although most commonly deposited in up-hole tubulars, can also be found in the near-wellbore or screen area in the form of calcium carbonate, calcium sulphate or iron bearing scales (to name a few). Since downhole screens or liners often filter some of the described particles, these particulates tend to be much more concentrated in the near-wellbore or screen/liner area than in the formation. Damage associated with DIF (mostly on horizontal wells) is generally related to water-based, oil-based or synthetic oil-based mud comprised of polymers and particulates. These systems are extremely efficient in forming a thin DIF filter cake barrier to control mud losses to the formation and aid in drilling the well. Although efforts are made to minimize remaining DIF damage during the completion process, they often fall short, leaving damage that can be difficult to remove with conventional fluids or pumping techniques. The chemical formulations used to react with the various damage mechanisms have been previously reported in numerous papers1,3–7 and will be further investigated in this paper. Much of a well's damage acts as a downhole choke. Identifying the damage and properly designing the stimulation system to remove it is a painstaking process. However, even the best of fluids, improperly placed, are destined to fail. Major laboratory research on treatment fluid delivery methods and the use of controlled hydraulic energy to remove damage will be a central focus in this paper.
A study on past water injector well performance indicated that soaking the OH with DIF breaker was not effective at removing filtercake, especially when compared with wells that had a post-completion stimulation. Analysis of the data suggested that long term injectivity/productivity could be improved at lower cost if a stimulation could be performed during the lower completion operational step. A new technology to precisely inject and divert acid, through the screens, towards the filtercake during the lower completion installation was developed, thoroughly tested and finally trialed in a well, to verify the results and validate the theory. A jetting tool assembly was developed, with the goal to improve clean-up by impelling acid through the screens and against the filtercake, adding agitation (previously unavailable through soaking placement) leading to a more thorough filtercake clean-up during lower completion installation. The assembly ran in hole includes a high-pressure jetting tool designed to divert the acid to every inch of formation for a very thorough filtercake removal, and it is powerful enough to jet through the screens and reach the formation face. The development process included the expansion of the jetting tool's capability to pump at higher rates, and the addition of two flow control tools to assist the jetting tool to function at will, while maintaining all typical lower completion service tool functionalities prior to its activation. Once the tool was developed, a series of successful tests were carried out, culminating with a full-scale SIT on a rig, to fully test all the capabilities of the tool assembly. Finally, the technology was successfully trialed in an deepwater injector well in the Gulf of Mexico (GoM) to acid jet the filtercake, achieving very positive initial results, which support expansion of the technology's use to other assets and well types. High pressure jetting tools have been used before with coiled tubing deployment, but never during a lower completion run. Through the development of the new tools, and the expansion of the jetting tool capabilities, this new approach allows the operator to save significant post-completion intervention costs by adding the stimulation capability to the completion phase of the well, obtaining a significantly better well performance at a reduced cost. This is especially significant in deepwater wells.
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