Sticking the coiled tubing (CT) is a major operational risk when performing a well intervention with CT. Stuck-pipe incidents often result in considerable production delay or, in the worst case, loss of the well. Mechanisms for dealing with stuck pipe are varied. Over the last decade, the profile of wells in which CT intervention has been used has evolved. The operating environment for today’s intervention can be more challenging, involving difficulties in wellbore trajectory, complexities in the completion, and an array of sophisticated tool assemblies that require conveyance. During this period, the approach to stuck-pipe avoidance or prevention has remained more or less unchanged.
Introduction
During the 10-year period of this study, several developments in the manner in which oil and gas wells are drilled and completed resulted in a change in the complexity of performing CT well interventions. An increase in intervention activity in horizontal or highly deviated extended-reach wells was found across most operating areas. The type of completions in several of these wells required running more-sophisticated bottomhole assemblies (BHAs) to achieve objectives similar to those in a less-aggressive wellbore environment. An example is the need to run tractors or vibrators in tandem with more standard tools to reach bottom and perform fill removal in extended-reach wells.
Also, the great depths and complexity of these completions increased the time required to perform most interventions. Thus, there was a need for improving operational efficiency, which typically took the form of performing fewer runs to achieve the intervention objective, usually through the use of multifunction BHAs to eliminate tripping runs to the surface to change the configuration of the tool string. Unfortunately, additional complexity in the tool string, whether through added components or a more-elaborate design, typically added risk, including greater potential for sticking.
Data collected for the period 2001–2010 showed that sticking incidents during CT interventions increased. Comparing data for the first 3 years (2001–2003) to data for the last 3 years (2008–2010), the number of reported sticking incidents increased more than threefold. Because the activity levels for the periods were not identical (increased by approximately 50% from one period to the next), a more-representative measure was found with a jobs-between-incidents (JBI) comparison. The JBI for the 2001–2003 period was 926, while the JBI for the 2008–2010 period was 524, a 43% deterioration in the JBI metric and an undesirable trend for this type of intervention activity.
During CT-sticking situations, it is critical to have a good understanding of the mechanism causing the sticking. This understanding ensures that an appropriate contingency or remediation method is adopted. Most contingencies are performed without a good understanding of the sticking mechanism; thus, successful retrieval of the string becomes a matter of chance. However, despite a good understanding of the apparent cause(s), the options available to address these situations are often limited. Ultimately, the determining factor for which options become viable in a given situation is the nature of existing conditions of the wellbore itself.
Analysis
Each reported sticking incident that occurred during the 10-year period was classified on the basis of five descriptive aspects to reflect its nature. The classification enabled identifying trends and representative characterization of conditions for sticking the CT. The descriptive aspects were as follows:
- CT application
- Mechanism for sticking (apparent cause)
- Resolution of incident
- Method for successful resolution
- Disconnect activation
Results
The riskiest CT application for sticking during the 10-year period was cleaning out sand/proppant from the wellbore. From a job-count standpoint, this activity comprised at least half of the total interventions performed during the period. Milling was the second-riskiest activity. The incidence of sticking between sand-cleanout and milling applications accounted for approximately 53% of the total during the 10-year period. These two applications were the subject of further scrutiny in this study, focusing on the nature of the incidents from an apparent-cause perspective, resolution of the incidents, and successful contingency methods.
To understand the trend, a comparison between the two 3-year periods was undertaken, as shown in Fig. 1. Although the sticking incidence during sand cleanouts doubled from one period to the next, as a percentage of total incidents, it remained steady—35% during the early period and 34% in the later period. However, during milling, there was a substantial increase for sticking and a clear increase in the percentage of total incidents—9% during the early period to 21% of CT-sticking incidents in the later period. Much of this increase can be attributed to unconventional-resources development—in particular, shale gas. With adoption of the plug-and-perforate completion technique in several North American basins, the number of stages has pushed beyond 20 zones/well. Milling the isolation bridge plugs in these wells is undertaken primarily by use of CT. The complete paper details the trend analysis by mechanism.
Successful CT-String Retrieval. The methods adopted during all sticking incidents that resulted in successful retrieval of the CT string and BHA are summarized in Fig. 2 above. The CT and BHA were recovered from wells successfully in 27% of all sticking incidents during the 10-year study period. In 34% of all sticking incidents, the situation was resolved by working the pipe up and down while continuously circulating the treating fluid. No additional contingency measures were adopted to achieve a desirable incident resolution.
Minimizing Sticking Risk
Overall, the CT string was recovered in approximately 65% of the sticking incidents. However, in more than 70% of those sticking incidents, some sort of remedial work was required to restore the status of the well. This statistic highlights the need for taking a strong proactive approach to preventing CT sticking. This study focused on sticking prevention during sand-cleanout, milling, and tool-conveyance operations, as listed in the following subsections. However, the measures covered may be relevant for avoiding sticking in other types of CT intervention.
Sand Cleanout. Rate of Penetration (ROP). Select an ROP consistent with the solids-removal capability of the overall system. Considered input should include the wellbore-annulus size, well deviation, type of fill, and the circulation rate. A common mistake involves use of only the weight indicator to determine the ROP during execution.
Maintain Circulation. Define a specific plan of action in case the fluid pump fails. Having a backup pump (with a performance specification to maintain the required rate) is desirable. Ensure that the annulus is not overloaded with debris (see Sweeping Runs subsection).
Carrier-Fluid Performance. Select a carrier fluid that is appropriate for transporting the type of sand being cleaned out—consider particle size, density, and wellbore temperature and geometry.
CT Size and Length. Select an appropriate size and length of CT, taking into consideration circulation rates and completion size.
Circulation Rate. Select a circulation rate that can achieve and maintain effective, efficient return of debris to the surface.
BHA Size and Length. Review all BHA profiles and ensure that wellbore tolerances are appropriate. Consider well deviation and the anticipated particle size of the debris. Cleaning compacted fill may result in larger-sized solids being returned (larger than the particle size).
Sweeping Runs/Wiper Trip/Bottoms-Up Circulation. In deviated wells, perform regular sweeping runs to address particle bedding behind the nozzle. Before cleaning out the perforated interval, ensure that the annulus is not loaded with debris should loss to the formation occur.
Well-History Review. Review the well’s history, paying particular attention to all previous well interventions and investigating any possibility of foreign debris or fish left in the wellbore.
Milling. Bit/Mill Type and Selection. Select an appropriate bit for the material to be milled. Target a mill size between 92 and 94% of the component size being milled.
Motor Size and Selection. Select an appropriate motor to provide optimum performance for the available flow rate, and consider the nature of milled material (e.g., appropriate torque and speed). Verify wellbore-temperature compatibility for elastomers (typically used for stator construction) and seals.
Circulating-Fluid Selection. Verify fluid compatibility with the motor and other components in the BHA. Select a fluid that provides adequate transport capability in highly-deviated-wellbore sections.
ROP. Depending on the material to be milled, ROP can vary widely. Ensure ROP is compatible with the entire milling system.
Sweeping Runs/Wiper Trips/Bottoms-Up Circulation. Characteristics of solids returned during milling can vary widely. Metal filings typically will be heavier, while other returns such as rubber materials can be lighter. Undertake regular sweeps, and monitor returns at the surface to ensure proper debris removal, particularly in high-deviation wellbores.
Maintain Circulation. Similar to sand cleanout, define a specific plan of action should the fluid pump fail. Having a backup pump (with a performance specification to maintain the required rate) is desirable. Although the potential for sticking caused by milling debris is low (lower than with sand cleanout), depending on the material being milled, the risk may be significant.
BHA Size and Length. Review all BHA profiles, and ensure that wellbore tolerances are appropriate. This may be critical if the use of articulated-BHA components (e.g., an underreamer) is anticipated.
Motor Stalls. Minimize or avoid (if at all possible) motor stalls. Motor stalls are an inconvenient interruption to the milling process, creating a high-risk situation for sticking.
Tool Conveyance (Logging). Wellbore-Dogleg Severity. Verify the BHA’s ability to pass through all wellbore doglegs and restrictions, considering the length of the logging-tool strings.
BHA-/Completion-Size Compatibility. Verify that the clearance between the BHA and completion is appropriate for the production/injection flow rates during the logging passes.
Sand Production. Determine whether sand production is possible during logging runs—ensure that annular clearance is appropriate to accommodate these situations.
Wellbore Condition. Consider performing a drift run before the logging-tool runs to ensure that no conveyance issues exist. It is recommended that a representative BHA (similar to that of the logging-tool string) be used during the drift run. Also, any debris buildup in the zone(s) of interest can be cleared.
Tool Conveyance (Packers). Tool Operation. Review the operational function of the tools, such as inflation technique (inflatables) and the setting/unsetting technique. Define the operating envelope for monitored parameters during all phases of the operation.
Pressure and Weight. Monitor surface pressures and weight for any abnormalities during the operation. The ability to monitor these parameters downhole provides an advantage.
Wellbore Condition. Consider performing a cleanout run or acid soak before the packer run to ensure debris removal from the completion.
Treating Parameters. If fluid pumping (treatment placement) is required, define the pump-operating envelope to ensure that downhole isolation and proper tool function is not compromised.
Contingency Measures. Define specific contingency plans for every scenario involving tool malfunction.
Tool Conveyance (Completion Manipulation). BHA-Component Performance. Select BHA components appropriate for the task. Verify compatibility of the complete tool system for the entire operating envelope.
BHA Size and Length. Review all BHA profiles, and ensure that wellbore tolerances are appropriate.
Completion Components. Review information regarding the operation or limitations of the completion components to be operated.
Well-History Review. Review the well’s history, paying particular attention to previous interventions, investigating any possibility of foreign debris or fish left in the wellbore.
Although each of these recommendations addresses specific risks for CT sticking, the most important recommendation is to take no shortcuts or deviations from the planned job design without undertaking a proper review of conditions and situations.
Conclusions
- The incidence of CT sticking has increased considerably during 2001–2010.
- Sand cleanout and milling were the two riskiest CT applications involved in pipe sticking. Together, they account for more than 50% of all sticking incidents.
- The most common mechanism for CT sticking in sand-cleanout and milling activities is becoming mechanically stuck because of wellbore debris.
- The top two mechanisms for CT sticking during tool conveyance were mechanical sticking caused by component failure in the completion and higher-than-anticipated wellbore drag.
- The CT string was retrieved successfully (during the same equipment mobilization) in approximately 65% of the sticking incidents; slightly less than one-third of incidents resulted in successful retrieval of the CT string and BHA intact.
- Reciprocation of the CT while circulating fluid was effective in freeing the stuck pipe (and BHA) in more than one-third of the sticking incidents.
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 163914, “Stuck Coiled Tubing: Addressing the Risks in a Complex Operating Environment,” by Rex Burgos, SPE, and Robin Mallalieu, SPE, Schlumberger, prepared for the 2013 SPE/ICoTA Coiled Tubing & Well Intervention Conference & Exhibition, The Woodlands, Texas, 26–27 March. The paper has not been peer reviewed.