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Young Technology Showcase

Disconnect Tools Ease Removal of Upper Completion

Intelligent completion systems have the ability to monitor and optimize reservoir performance in real time without mechanical intervention. Although such systems were introduced more than 15 years ago, the industry has only just begun to recognize and accept the numerous benefits derived from their implementation. Operators and service companies are now looking at new applications for intelligent completion technology including:

  • extended reach horizontal wells 
  • marginally economic assets in which electric submersible pumps (ESPs) are required 
  • regulatory compliance, such as nonfunctional subsurface safety valves replacements

However, these applications bring with them certain challenges. In ESP applications, ESP pumps require periodic retrieval for maintenance. With the high torque and drag in long horizontal wells, deploying intelligent completions on production tubing can become a challenge. When a workover is required to replace a nonfunctional subsurface safety valve, it can become more economical to leave the existing intelligent completion in place, and pull and replace only the upper tubing string including the subsurface safety valve.

How then can one reliably install intelligent completions in these applications? Intelligent completion disconnect tools help address these challenges.

Intelligent Completion Disconnect Tools

Recently introduced disconnect tools for intelligent completion applications by Halliburton facilitate the removal of the upper completion from the lower completion without any destructive or mechanical intervention. This leaves the intelligent completion lower assemblies, such as packers, interval control valves (ICVs), and permanent downhole gauges in the wellbore undisturbed.

Intelligent completions require hydraulic and electrical umbilicals to monitor and control the gauges and ICVs in the wellbore. Besides providing tubing-to-annulus integrity, disconnect tools must also reliably disconnect (demate) and reconnect (wet mate) the umbilicals without affecting the functionality of the downhole intelligent completion equipment. Two variants of the disconnect tool are the hydraulic and the electro-hydraulic. The electro-hydraulic provides the ability to multi­drop gauges on a single I-wire and hydraulically actuate ICVs in the lower intelligent completion.

Design

These disconnect tools are exclusively designed for intelligent completion applications. The tool comprises two halves: the receptacle and the disconnect sub (Fig. 1). When the two halves are wet mated, hydraulic and electrical continuity is achieved from the surface down to the ICVs and gauges.

The tool design provides for six hydraulic channels to run five ICVs using the direct hydraulics (N+1) downhole control system or up to 12 ICVs using an alternative downhole control system. The hydraulic channels on the receptacle have spring-loaded ball checks that prevent any contamination of the hydraulic control line fluids when the disconnect tool is demated. In the hydraulic-only version of the disconnect tool, the hydraulic channels are protected by a sleeve when running in or pulling out of hole. This sleeve moves out of place when the two halves are mated, thus allowing for the respective hydraulic channels to line up and provide the required hydraulic continuity. The hydraulic channels are isolated from each other and annulus or tubing with field replaceable thermoplastic/elastomeric seal stacks. These seal stacks are compatible with oil or water-based control fluids and most types of wellbore fluids.

The electro-hydraulic version, in addition to six hydraulic channels, allows for multidropping downhole pressure/temperature quartz gauges. Electrical continuity is achieved through concentric electrical connectors housed in the receptacle and the disconnect sub. The electrical connectors are protected by a sleeve when demated and slide out of the way to allow for electrical wet mate to take place when the two halves are mated. Seals prevent wellbore fluids from contacting the electrical connector when mated.

The tool design provides for three optional latch mechanisms—snap, shear, and anchor—which are field configurable depending on the application. ­Metal-to-metal seal connectors are used for terminating the hydraulic and electrical umbilicals to the disconnect tool.

Qualification Testing

Robust design validation testing is paramount to help ensure a reliable product. Failure mode effect analysis (FMEA) of the design was conducted and the results used to tailor the qualification test program. Each component was individually qualified before conducting a full scale test. The following is a summary of the qualification testing that was carried out.

Electrical Connector

  • Fit and tolerance stack-up test
  • Electrical performance test: measure voltage and resistance after mating/demating
  • Soak test: short term/long term in completion brine
  • Mate/Demate test: dry mate and wet mate 10 times
  • Debris test: wet mate/demate in sand slurry

Hydraulic Seals

  • Hydraulic unload test: unstab 10 times with 500 psi in hydraulic lines
  • Hydrostatic test: subject tool to 8,000 psi at 140°C
  • Movement test: simulate tool movement due to thermal effects
  • Debris test: wet mate/demate in sand slurry

Full-Scale Test

  • Hydrostatic test: 8,000 psi at temperature/pressure (burst/collapse)
  • Shock and vibration test
  • Integration test: test functionality with ICV and gauge simulator

Completion Design

The disconnect tool is placed directly above the intelligent completion production packer. The packer provides centralization and anchors the receptacle, thus ensuring reliable mates and demates of the upper completion. A shear or anchor latch is required for the initial deployment of the lower intelligent completion assembly. An anchor or suitable shear ring rating needs to be chosen to help ensure the production packer can be set hydraulically without prematurely releasing the disconnect sub. When the upper completion is to be retrieved, rotation or an overpull on the tubing string and/or tubing pressure assist is used to shear the ring and disengage from the lower completion. On recompletion, a snap latch version is used to allow for multiple mates and demates to allow the production tubing to be spaced out and the tubing hanger landed.

Field Trial

A successful field trial of the electro-hydraulic disconnect tool for a major client in Latin America was recently conducted. The objective of the field trial was to reliably disconnect an ESP in the upper completion from the lower intelligent completion that had two ICVs and two dual sensor pressure/temperature gauges. After deploying the lower intelligent completion string and hydraulically setting the production packer, the gauges and ICVs were function tested before disconnection. Subsequently the tubing string was pulled to shear the 70K shear ring. The upper completion was disconnected and pulled out of hole. The subsequent run in hole with the upper completion and ESP reconnected to the lower completion at the same time landing the tubing hanger. The gauges and ICVs were function tested successfully. As of this publication, the well has been producing for the past 7 months with full functionality in the intelligent completion.

Operational Considerations

Wellbore cleanup is critical to the successful mating of the disconnect sub into the receptacle. It is recommended to run junk basket/dirt magnet tools before running the intelligent completion. The disconnect tool is tolerant of wellbore fines, but any large debris can prevent the disconnect sub from engaging the receptacle and damage seals. Circulating down the tubing before engaging the receptacle aids in engaging successfully.

Accurate space-out of the completion string is critical. Unlike floating production seals, the disconnect sub must be latched within the receptacle to ensure electrical/hydraulic channel integrity. Similarly, an adequate tubing movement analysis should be done to determine proper weight down required so that the disconnect sub does not disengage the receptacle during varying well conditions.

As the disconnect tool design evolves, future applications such as deepwater ESP/intelligent completions may become a reality. Safety valve replacements or monitoring of plugged and abandoned appraisal wells in deep water may be other areas in which the disconnect tool finds application.

EC-Drill Eliminates Effect of Equivalent Circulating Density

When drilling offshore wells, the most common method is to drill with a single gradient fluid with the fluid column extending from the bottom of the well back to the drilling rig. Even in shallow water, this sometimes represents a significant challenge if the formation cannot withstand the hydrostatic pressure from the fluid column. An example would be drilling from a jack-up where hydrostatic fluid pressure causes fracture under the shoe of the conductor pipe.

As water depth increases, so do problems associated with having the fluid column all the way back to the rig. The effect of the water depth is particularly significant in the upper part of the well and, consequently, if it can be eliminated, drilling performance can be significantly improved. For this reason, the industry has been working with developing dual gradient drilling technology for decades.

Several methods can be classified as dual gradient drilling. The most common are the seabed pumping and mid-riser pumping methods. For seabed pumping, the drilling riser typically is filled with seawater and the drilling mud is pumped (or lifted) back to the rig from the seafloor. This represents a drilling method in which the effect of the water depth can be eliminated and the well basically drilled as if the drilling rig were sitting on the ocean floor. The same can be achieved with the mid-riser pumping method, but in this case, the riser is typically filled with a gas.

Another significant problem is the effect of dynamic pressure loss (friction) while circulating drilling mud through the wellbore in order to transport drill cuttings back to the rig. In deep water, the margin between pore pressure and fracture pressure is small; hence, there is a narrow drilling window. For static conditions, the mud must have a weight or density great enough to create a wellbore pressure that is above the pore pressure (static overbalance). When the rig mud pumps are started to circulate fluid around the well, the wellbore pressure increases as a function of friction and the pressure may exceed the fracture gradient (typically at the shore above) and result in lost circulation. This may again result in a kick. For low-pressure reservoirs or depleted fields, this problem is significant and may make the wells undrillable with conventional technology.

This dynamic effect, equivalent circulating density (ECD), is a significant drilling challenge in terms of safety and lost time.

The Business Incentive

The business incentive of dual gradient technologies is to improve both safety and drilling performance by eliminating the effect of water depth. In this way, intermediate liners and associated time and cost will be eliminated. Dual gradient technologies enable drilling with a close-to-constant bottomhole pressure and cause little pressure change between static and dynamic conditions.

The pump system not only controls the pressure accurately, but also detects minor changes in flow and fluid density. Well control will thereby be improved and even minor influxes or losses will be detected.

Except for riserless mud recovery top-hole technology, the industry has not been able to develop and deploy dual gradient drilling commercially. The EC-Drill system is a “first out” for post-blowout preventer drilling and is more of a managed pressure drilling (MPD) technology than a full dual gradient technology. The primary purpose of EC-Drill is to eliminate the effect of ECD and enable drilling with close to constant bottomhole pressure.

Technical Details

EC-Drill is an MPD technology that falls within the mid-riser pumping technology of the dual gradient family (Fig. 2). It uses a subsea mud pump that is connected to the conductor pipe or marine drilling riser (Fig. 3).

On a semisubmersible rig, the EC-Drill is attached to the drilling riser in the moonpool and is run together with the riser. The EC-Drill can be run in automatic mode, keeping a desired bottomhole pressure constant, or in manual mode in which the EC-Drill control system maintains a constant riser fluid level set by the driller.

The EC-Drill should not be used to drill underbalanced. A static overbalanced mud weight should be used. For a planned stop in circulation, the riser level should, if necessary, be increased to the point at which static overbalance is obtained. If the rig pumps unexpectedly stop, the annular preventer or a similar device should be closed to prevent static underbalance.

Applications

The target applications are a narrow drilling window, high ECD, and low mud weight environments in which losses are an issue.

The technology has been used nine times. The following are EC-Drill applications to date:

  • One well drilled from a jack-up for BP Egypt
  • One well drilled from a jack-up for BP in the Caspian Sea
  • Four wells drilled from a jack-up for Petrobras in Brazil
  • Three wells drilled from a semisubmersible in deep water, eastern Gulf of Mexico

Case Studies

Three wells have been drilled with EC-Drill from a semisubmersible in a deepwater/low-mud-weight environment offshore Cuba.

Well No. 1

The EC-Drill system was only used in the 12¼-in. hole section. The formation drilled through was predominantly hard-to-very-hard limestone with softer marl (carbonate also) formations embedded. This was experienced through the entire section. Particular drilling challenges included the hard drilling environment and lack of suitable bits and tools. After a failure, the system could not be used for the 8½-in. hole section and losses
were experienced.

Well No. 2

The EC-Drill system was used in the 17½-in. and 12¼-in. hole sections to well total depth. This well was drilled in the same area and with the same rig immediately after Well No. 1. The formation drilled was chalk and moderately hard limestone, sometimes with marl. The main reason for using EC-Drill was the potential for weak zones with the risk of severe losses. An additional effect was improved rate of penetration when reducing riser level and increasing circulation rate. Although the formations drilled through were hard, the 17½-in. hole section was also particularly weak with regard to the planned cementing program. The EC-Drill system was used to manage the bottomhole pressure during the cement displacement and hardening process (Fig. 4).

Successes, Failures, and Lessons Learned

On Well No. 1, there was a problem with the EC-Drill equipment caused by galvanic corrosion on the control system combined with extreme currents—up to 8 knots. A superior galvanic corrosion system was installed and Well No. 2 went smoothly. A significant increase in rate of penetration was experienced when EC-Drill was used. There were no well issues or drilling challenges on Well No. 2.

After Well No. 1, changes to the control system were made for greater robustness in operation. A superior galvanic corrosion system was implemented. Changes were also made to the flexible mud return line and its position in the moonpool. Together, these resulted in the elimination of the associated issues on Well No. 2. On Well No. 2, a significant increase in rate of penetration was seen—up to 30%. No drilling issues or losses were experienced.