A downhole electro-mechanical power-unit tool was used to provide anchored power to pull crown plugs in a single run and in reduced time. This setup has the capability to pull subsea crown plugs that often require greater force than is possible with traditional conveyances without requiring time and resources to reduce hydrostatic pressure. In deepwater environments, reducing time can significantly impact costs because of the extra equipment and logistics necessary to properly operate in those conditions. The downhole electrical power generator tool proved to be a viable and cost-effective option. A Gulf of Mexico job for Statoil required the removal of the upper and lower crown plugs just below 8,000 ft with 10.6 lbm/gal fluid in the riser. While on location, the crew ran a conventional pulling tool to attempt pulling the upper crown plug. While latched into the plug, an integrated workover control system (IWOCS) pumped fluid in between the two plugs to decrease the differential across the plug to assist in pulling. The crew was unable pull the plug on two separate attempts. A 3.59-in. extended-stroke downhole electro-mechanical power-unit tool with a crown plug latch tool capable of an effective stroke of 36 in. and a linear pulling force of 60,000 lb was the program's contingency. It was deployed and pulled the crown plug. There were indications that the IWOCS system had failed, and the downhole electro-mechanical power-unit tool pulled the upper crown plug with the full differential of the hydrostatic head. A conventional pulling tool was used to attempt to pull the lower crown plug, again without success. The downhole power tool was then used to retrieve the lower crown plug successfully. In a subsea tree, crown plugs are used to isolate the wellbore from the environment. Often, one of the first required tasks of a subsea well intervention is to pull the subsea crown plugs from the wellhead to gain access to the wellbore. Hydrostatic pressure associated with fluid in the riser creates a large pressure differential across these wellhead plugs that seal the cross-sectional area of the tree. If the plugs cannot be removed from the profile conventionally, the fluid is displaced to lighten the hydrostatic head before the plug can be pulled. This operation requires a minimum of 24 hours of rig time. Slickline and coiled tubing have limited constant pulling force because of the finite-strength limits of the conveyance. Deep water and debris often compound the required pulling force. These forces are well above the tensile-strength limit of slickline wire and even the pulling strength of coiled tubing. A subsea wellhead plug requires a steady pull along the entire length of the sealbore. Conventional slickline methods are limited to creating extremely high, but short-duration, impact loads; however, brief impact loads are not suitable because the seals tend to reseat after each impact and are forced back on seat by hydrostatic pressure from above. Therefore, using mechanical or hydraulic jars to simplify the delivered force does not effectively retrieve the plug from the wellhead.
The rise in unconventional resource exploration relies on strategically placed sensors to record critical information during multiple forms of testing and reservoir enhancement techniques. The accurate data gained during the testing phases are what ultimately lead to the best flow regime design and successful optimization of the resources. New completion design or reservoir stimulation techniques are also effectively evaluated using data acquisition, aiding the development, refinement, and implementation of these techniques. Subsequently, suspension of the sensors in wellbores without decreasing flow can be challenging when introducing new techniques or modifications. Additionally, these flow rate conditions can prevent the determination of production at the most economically advantageous time and rate. This paper examines difficulties associated with acquiring data that can exist because of new completion designs or exploratory methods tested as a means to optimize a resource's economic viability. Solutions offered by a new highexpansion hanger that can be used to meet these difficulties are also discussed. The tool has been proven to be a durable and flexible solution for an increasing array of completion and reservoir enhancement techniques for many styles and types of well testing under varying pressures and conditions. The tool is available in a wide range of pipe sizes and types, enabling positioning inside liner sizes of larger inside diameter (ID) than that of the uphole completion tubing string within the wellbore. The high-expansion design also provides the assembly a generous bypass flow area, which helps increase the accuracy of the data received during flowing events.Case histories are presented to illustrate the varying range of situations where the high-expansion hanger has been proven both a viable and valuable solution for reservoir analysis and optimization.
Anoperatorin Baku, Azerbaijan was planning to create a gas lift configuration and needed to perforate 7-in., 32-lbf, 13% chrome, up to 0.51-in.wall thickness, heavy wall tubingwithout explosives. A nonexplosive mechanical tubing perforator conveyed on electric line avoided damaging the in-situ control lines and the casing. To meet the job parameters, a mechanical tubing perforator capable of generating up to 100,000 lbf necessary to perforate the 7-in. tubing was developed.The 7-in. downhole electrical power generator actuated tubing perforator tool provided a controlled, nonexplosive, cost-effective solution to create a single perforation hole in tubing or casing without damaging in-situ control lines in the annulus. Tubing to annulus communication was established and through-tubing gas lift straddle was installed to allow increased production. When workover requirements necessitate rapid mobilization, the tubing perforator helps lower costs while providing a safe, effective, and dependable solution for perforating the tubing. Offering conveyance flexibility, the perforator can be run on slickline, electric line, or coiled tubing (CT), providing versatility and economy to meet multiple operational requirements.This actuated tubing perforator eliminates logistical challenges associated with using explosives, is health, safety, and environment (HSE) and user friendly, and helps reduce rig time by minimizing missed runs. It is compact and heli-lift compliant for portable, rapid deployment and has no risk of damaging annular tubular or casing. Relying on the dependable performance of the tool to provide power, the actuated tubing perforator has proven to be a safe, reliable, and cost-effective means of punching production tubular for circulating purposes.Acquiring, moving, storing, and handling explosive-based equipment can be very difficult and time-consuming. In many countries where regional security is a concern, the movement of explosives is a controlled activity and can often delay projects. Consequently, when an unplanned event occurs for which pipe severing with explosives is the solution, such as stuck pipe, the drilling rig team might be required to wait several days before performing this job. These types of occurrences are quite common, especially in highly active drilling areas. In some cases, this lost time is conservatively estimated to be more than USD 12 million annually for a land-based operation. It is easily plausible to incur triple these costs for offshore operations, noting that these cost estimates do not account for the revenue losses attributable to a delay in production of hydrocarbons.Wells in the Middle East, both onshore and offshore, often require workover because of the highly corrosive environment to which the downhole equipment is subjected. During these operations, the downhole equipment frequently must be repaired or replaced. To maintain well control during these workovers, a single hole is often necessaryto allow the kill fluids to be circulated. Traditionally, these holes are cr...
The storage of natural gas in underground caverns is a common storage method. However, subsurface performance during injection and production rates differ from what is observed on surface. This paper reviews a unique well intervention solution conducted in The Netherlands that enabled the placement of downhole pressure and temperature gauges, with the successful simultaneous acquisition of accurate data from multiple depths during a 40-day period in a salt dome gas cavern. This intervention was performed to obtain pressure and temperature data during injection and production of gas in and out of the gas cavern. The data was acquired by installing five memory gauges spaced out with 0.160-in. slickline at various intervals over 275 m. This arrangement enabled the customer to gather data from multiple depths while continuing to inject and produce gas at very high rates through the 9⅝-in. production tubing above the gauges. The unique assembly needed to perform such a job while under pressure required a specific rig-up process to install and retrieve long assemblies. The purpose of the test was to verify the accuracy of the model with subsurface data for an extended period to predict gas behavior during injection and production. Although real-time data transmission through a cable to a surface-readout system was the preferred method of data acquisition, this was not possible because the cable would cross the tubing retrievable safety valve, rendering it inoperable during the test period. After 40 days, the memory gauges were successfully retrieved from the cavern. The acquired data was then entered into the production software to validate the model and, ultimately, to optimize gas injection and production rates. The suspension of the memory gauges in this manner provided an accurate pressure profile across the gas cavern that was not affected by the injection and production flow. Equipment was specifically designed and developed to enable memory gauges to be hung below the end of the tubing. This assembly provided minimal restriction to gas flow and a platform to enable the installation of memory gauges suspended more than 275 m below the end of the tubing. Because the rates of injection and production change as the level of gas varies within the facility, collecting relative data at multiple points simultaneously is very desirable.
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