It Can be Difficult to Anticipate all Possible Problems or Issues That Could Arise in the Course of Completing a Well or Maintaining Production After Completion
Everyone is familiar with Murphy’s Law, or Sod’s Law as they like to call it in the UK. Usually referred to jokingly, it nevertheless emphasizes a lesson that experienced oilfield hands have learned over the years. Oil and gas wells can be complex, and with complexity comes the potential for problems. As Murphy’s Law says if anything can go wrong, it usually does so at the worst time, in the worst place, and when it can cause the most trouble or damage. Thanks to technology and the ingenuity of oilfield workers, most problems can be solved relatively easily, but preventing problems is better.
Potential problems
Only rarely can a single solution address 10 or more problems, particularly when the problems affect the most fundamental parts of the well – the tubulars. Problems with tubulars are vexing because they affect the well’s hydraulic integrity, which is critical to production. In addition, tubulars are, in most cases, part of the well’s permanent infrastructure and cannot be accessedor repaired with ease. They are subject to corrosion, erosion, separation, leaking connections, and mechanical damage from pressure, impact, or wear. Sometimes there is nothing wrong with the tubulars, but reservoir conditions have changed. Perforations that were providing points of ingress for oil or gas now are producing water, or reservoir pressure has declined to the point that the original tubulars cannot provide enough velocity to naturally lift the production to surface. The implications of these problems go to the operator’s bottomline because they directly affect production, either by reducing it or by cutting it off altogether. The most prevalent problem affecting producing wells is unwanted water ingress. Water can come from natural reservoir depletion in the form of a rising oil/water contact or from other problems such as communication channeling from an aquifer through a bad cement job.
There are several possible solutions available to shut off unwanted water influx. One of the most common solutions is acement squeeze. Squeezes do not always work and cannot prevent potential problems. They typically involve a drilling or workover rig because post-squeeze clean up usually requires a scraper or milling tool run. In addition, when pumped downhole, the cement slurry follows the path of least resistance, which might not be the water source. A variety of casing or tubing patches exists. These offer a potential solution to tubular problems plus the ability to prevent problems in some cases. In most cases, the biggest advantage is that downhole tools can pass through patches after they are set, allowing the well to be worked over, logged, tested and, most importantly, produced. A critical factor is the final ID after they are deployed. Some do a good job at sealing off water influx but place a permanent restriction in the pipe that prevents some tools from passing through. Steel body straddlestyle packers fall into this category.
Solutions
All installed patches have pressure ratings, which can vary widely. For example, the thin-wall fiber and resin patches have very low pressure sealing capability. Operators should carefully check he pressure capability of the proposed solution against the type of problem they are attempting to solve. Retrievability can be a problem. Some patches are very difficult if not impossible to retrieve. They must be completely drilled or milled out from top to bottom, including the zone of original casing damage they were set to mitigate. Trying to mill through such a zone could resultin catastrophic damage if the mill engages a rip or a split in the base pipe.
Executing solutions
Ease of deployment varies greatly. Some patches require a rig; others can be set on wireline only. The distance that can be spanned by a single patch varies greatly as well. Some patches are only available for casing, not for tubing. Tensile strength varies from patch to patch; some cannot support much weight at all, meaning they cannot be used as a hanger system. Cost of mechanical patches varies widely. While many are more economical than cement squeezes, the amount of savings from different designs can be substantial. Some – such as external casing patches, heavy-wall expandables, and fiber-resin varieties – are very expensive. Owen Oil Tools’ X-SPAN system is a highly versatile patch. Available in both fluid and gas models, it addresses a broad range of applications, including shutting off unwanted water influx, zonal protection, or frac-through applications.
All tubular leaks can be repaired, from pin holes to leaking collars, as well as from liner tops to frac ports and auxiliary tools in horizontal wells. Straddling corroded or eroded tubing or casing has the highest long-term potential because it can be a problem prevention application rather than a problem solving one. For example, if a leak is detected due to suspected corrosion or erosion, a corrosion log can be run to identify all portions of the pipe that are affected, not just the joint with the leak. X-SPAN can be deployed to protect 300-ft (100-m) sections of tubing or casing on a single trip, with multitrip stackable patches available to span longer intervals.
Patch work in the field
In Balikpapan, Indonesia, four wells were making anexcessive amount of water from a rising contact. Previously addressed using expensive and time-consuming cement squeezes, the problems were solved by installing 3½-in. X-SPAN patches via electric line at significantly lower cost. In Alberta, Canada, logs indicated a well had a 230-ft(70-m) section of severely corrodedcasing.
After the operator rejected casing retrieval and cement squeeze solutions, a 252-ft (77-m) X-SPAN patch was run effectively, sheathing the entire corroded section. Final costs were 10% of the estimate for the alternate methods. Also in Alberta, a popular multistage frac technique was jeopardized when a shallow frac port was opened prematurely. A 52.5-ft (16-m) X-SPAN patch was run on coiled tubing to straddle and seal off the open frac port.The large ID allowed drop balls to pass so all deeper stages could be fraced successfully. Treatment pressures reached 8,500 psi, but the patch held. In the Bass Strait offshore Australia, misplaced blast joints resulted in high-pressure production eroding tubing near the top of the blast joint. A 10-ft (3-m) 31⁄2-in. diameter X-SPAN patch was run on electric line to isolate the leak. It was successful despite the fact that it had to set and seal in both the tubing and blast joint IDs. The fix eliminated the need for a costly offshore work over and returned the well to full production.
