In the oil and gas industry, it is a common practice to install production casing through producing formations, with cement providing the primary inter-zonal isolation in the annulus. However, inadequate displacement efficiencies, fluid contamination, and loss circulation intervals sometimes limit the ability of a cementing operation to provide zonal isolation sufficient to prevent annular communication over the life of the well. Formation damage caused by cementing operations can also adversely affect life-of-the-well production capabilities, thereby adversely affecting the economics of the well. New completion technologies using swellable elastomers can offer an alternative to cementing operations performed over producing formations. However, conventional floating equipment has limited the application of swellable elastomers in some completion operations. For example, in noncemented completions where swellable elastomers provide the only annular barrier, a mechanical seal having a service life equal to the life of the well under downhole conditions is required at the toe of the production casing. This paper describes the benefits of swellable elastomers used to provide life-of-the-well zonal isolation. Additionally, the paper recounts a problem job in which improperly selected check valves were used and new check valves specifically designed for noncemented completions were successfully introduced. Lastly, this paper provides details about equipment designed for a south Texas well that will incorporate SEPs, float equipment, and a combination wiper plug designed specifically for a noncemented completion to be performed in late 2007 or early 2008. Introduction Though the use of swellable elastomers is becoming more and more common, one component of the system that has not received sufficient attention is the float assembly that can be used with swellable element packers (SEP). This paper will review a problem job in which the use of conventional float assemblies resulted in a near-miss incident. A detailed description of the problem and a proposed solution are discussed. Common Completion Methods Numerous completion methods are available for producing oil wells and injection wells. The type of completion method used is governed by the type of reservoir present, the intended production operations, and a host of other factors. Dyson et al. (1999) described several sand control and non-sand control completion methods, focusing mostly on single-string completions. The following are examples of standard industry methods currently being applied.The most simple and cost-effective completion method available is the openhole or "barefoot" completion. This method is used in hard formations where the oil-producing zone is consolidated and not loose. The oil-producing zone is completely open, and no liner or perforated casing is used to case the hole (Fig. 1) (Helmy, et al. 2006).A second completion method involves the use of a slotted liner or gravel pack liner. Typically, the liner is suspended or hung from the bottom of an intermediate string and does not reach surface. These types of liners prevent the entry of sands and solids into the liner ID using either a series of slots or screens, or using gravel (Fig. 2).One of the most common methods of completion is cementing production casing in place through the producing formation, and then perforating the casing. Because the liner or casing must remain in place for the life of the well and its replacement would be very costly, another string of pipe called tubing is run into the well to act as the flow string (Fig. 3).
Drilling operations performed through the shoe-track are generally considered duplicated effort by many operators. Nonetheless, shoe-track drillout is an operation that must be performed on all surface or intermediate casing strings or liners. Slow penetration rates are often experienced, even when drilling through so-called drillable casing equipment. Today's costly drilling operations force operators to attempt to reduce nonproductive operations whenever possible. Therefore, improved shoe-track drillout performance can improve operators' overall drilling cost and schedule. Thus, a better understanding of downhole dynamics is necessary to develop improved drilling procedures. A review of jobs from the North Sea database of cement jobs and shoe-track drillouts revealed that, of the more than 1,200 data points available to the authors, 83% of the drillout times were less than three hours; 70% of the drillout times were less than two hours; and 50% of the drillout times were less than one and one-half hours, with the overall average being 93 minutes. When a single type of cementing casing equipment was drilled in some wells in 30 minutes and other wells in three hours, questions were raised as to what major contributing factors determine actual drillout time. Two case histories are presented with close attention paid to drilling parameters that adversely affect actual weight applied by the bit to the target being drilled. A better understanding of weight on bit (WOB) and weight on target (WOT) is needed to best determine drilling procedures to be used for any given drillout. This paper documents lessons learned from successful drillouts performed with conventional and rotary-steerable drilling assemblies. Software-driven recommendations are provided for improved interpretation of downhole forces applied to the target being drilled. Introduction During the past several years, much progress has been made in fixed-cutter bit designs. Improved technology and manufacturing processes have improved bit performance and reliability to the extent that polycrystalline diamond compact (PDC) bits are successfully encroaching into hard-rock drilling applications. Formations that once were reserved for roller cone bits are successfully being drilled with PDC bits. Additionally, it is becoming more common for PDC bits to be used to drill out cementing plugs and float equipment. These achievements reflect recent improvements in technology and the innovation involved in bit design and manufacture. The aggressive cutting nature of many fixed-cutter bits is designed to maximize bit performance when drilling formations. However, this aggressive nature can cause large debris to be created when drilling through cementing plugs or other cementing casing equipment (Fig. 1). Specifically, the elastomer and phenolic materials commonly used in the construction of cementing plugs and floating equipment tend to tear or fragment into large pieces rather than the typical shearing that occurs when drilling formations. The cuttings created when drilling cementing casing equipment are more significant than cuttings created when drilling formation. In some situations, such debris can become lodged in the junk slot area of the fixed-cutter bit. Therefore, special consideration should be made when determining procedures to be followed when drilling out shoe tracks.
There are a number of challenges associated with setting cement plugs in an openhole well. Most importantly, drillpipe can become differentially stuck across a lost-circulation zone, and the plug may become contaminated with the intermixing of the mud resulting in inadequate isolation or insufficient strength. Cement plugs are used for various reasons including healing losses, abandonment, and directional drilling. It is essential to these operations that a competent cement plug is placed the first time. The value of placing the designed cement plug properly is measured by nonproductive rig time, wasted material, and additional cementing services. An innovative tool and a special process1 were designed to meet the challenges associated with setting cement plugs. The tool connects sacrificial/drillable tubing to the drillpipe and allows an operator to trip into the well and spot the cement plug across the problematic zone. Once cement is placed, the tool is disengaged and the operator trips the drillpipe out of the hole, leaving the cement plug and tubing undisturbed. The sacrificial tubing can be drillable; therefore, the operator can drill through the plug or commence other operations as required. This paper discusses the challenges operators face when setting cement plugs and how the risk and nonproductive time are reduced with this innovative plug-setting process and tool. Well examples are documented from case histories to illustrate the success and lessons learned. Introduction Drilling for natural resources all over the world is not getting easier. To maintain current production levels in a demanding market, operators are forced to either drill into mature fields or into unconventional reservoirs. Production from a mature formation will reduce the pore pressure and this reduced pore pressure can lead to a lower fracture gradient. The chances of lost circulation while drilling into these lower fracture-gradient zones continue to increase. As the reservoir depletes, an operator might drill the next well deeper to capture the resources from a deeper zone. This too exposes the operator to the risk of drilling through this shallower depleted zone. Unique challenges are likely to occur when an operator decides to drill an unconventional reservoir, for example, lost circulation of drilling fluids to a cleated or vugular formation may occur. A properly designed cement slurry is the best choice to heal these lost-circulation events.2,3 Cement can be squeezed into the lost-circulation zones and when set, will strengthen the wellbore. The cement plug is drilled through, leaving the residual cement inside these problem zones. Cement plugs can be placed by bullheading down drillpipe into the loss zone or balanced across the loss zone. There are challenges with both of these operations. When bullheading cement, the zone does not get full coverage. This can lead to cement not deep enough or dehydration of the cement below the plug. When drilling through this plug, losses are usually experienced again. For the greatest chances of success, an operator must place the drillstring down into the lost-circulation zone. This however is a risky operation. The loss of drilling fluid may create a differential pressure across this problem zone and could cause the pipe to stick to the wellbore. Even if the plug is balanced successfully and no pipe sticking occurs, the plug could be compromised as the drillpipe is pulled out. The swabbing effect introduced by pulling out of the thick cement slurry could cause intermixing of the cement and mud. This contamination can lead to an insufficient seal or a soft top. A disconnect assembly (Figs. 1–3), bottomhole kickoff assembly disconnect (BHKA disconnect), was successfully introduced in 1999 in Australia to set a plugback plug using a predrilled appraisal section of the well. A second disconnect assembly Figs. 4–5 was introduced in the fall of 2002 in the Monument field near Hobbs, New Mexico to solve loss circulation problems. A tubing-release tool (TRT) provides a method of placing a sacrificial tubing into the loss circulation zone and balancing the cement plug. The sacrificial tubing is released from the drillstring and remains in the wellbore. Cement covers the full loss zone; pipe sticking is not a concern; and the plug is not disturbed once the cement is placed. A fluid retention mechanism in the TRT prevents energized fluid from the workstring from dumping onto the cement plug.
fax 01-972-952-9435. AbstractThis case history paper describes the use of a bottomhole kickoff assembly (BHKA) tool to place openhole plugs in a high-temperature well. The well was a 6 ½-in. diameter borehole with 52° deviation and 174°C (345°F) bottomhole static temperature (BHST). Depth was 5775 m (18,946 ft). Even though these extreme conditions were anticipated, they were discussed with the operator because two earlier attempts to achieve a kickoff had failed.In this successful kickoff operation, the BHKA was tagged 1 m (3.3 ft) below the calculated top of cement and was tested to 6 tons over the plug, using a 165-mm (6 1/2-in.) roller cone bit. Conditions for both the tool and cement slurry were extreme. Kickoff was successfully accomplished during the first 8 m (26 ft) of the BHKA plug; formation cuttings of 99% were reported.
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