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Isolation Barriers With Coiled Tubing in Plug-and-Abandonment Operations

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Plug-and-abandonment (P&A) operations can be expensive, leading to negative net present value. Historically, P&A operations in the North Sea—estimated to hold some 3,000 wells of declining production—were performed with either drilling or workover rigs. In many cases, wells drilled from fixed platforms in the North Sea no longer have operational drilling rigs, requiring recommissioning of existing facilities or mobilization of workover rigs. The complete paper discusses an alternative approach to P&A using coiled-tubing (CT) processes and techniques to create permanent reservoir barriers.

Barrier Requirements

Permanent abandonment of a well can be defined as the activities involved in securing a well that will no longer be used, to ensure containment and no harm to the environment. Standard details of how permanent reservoir barriers are to be created are provided by the Norwegian petroleum industry through NORSOK Standard D-010. Section 9 of this standard details requirements for the creation of permanent reservoir plugs in abandonment activities.

The creation of these reservoir plugs typically is dependent upon the condition of the well, the formation type, the quality of cement behind the casing, and the number of potential inflow sources. Similarly, two cross-sectional barriers must be provided across any inflow source together with a surface well barrier. The permanent plug (typically cement) should have a length of 100 m (50 m in casing with a mechanical plug), be positioned as near the inflow source as possible, extend 50 m above the source or casing shoe, and extend to the full cross section of the well (i.e., rock to rock).

The cement should provide well integrity for the foreseeable future and should be impermeable; materials used should not have shrinking properties. Additionally, the cement must withstand mechanical impact and loads; be resistant to chemicals, such as carbon dioxide, hydrogen sulfide, and hydrocarbons; and be wet, to help ensure bonding to steel casings.

Field P&A

An operator determined that wells in an uneconomic field on the Norwegian Continental Shelf needed to be plugged in preparation for abandonment. The field, located off the west coast of Norway, comprises 22 wells from a 24-slot fixed-jacket production platform. Of these 22 wells, 17 were oil producers (five still producing/12 shut in), one well was an active water-injection well, two were active wastewater-disposal wells, and two wells were previous P&A wells that required removal of the conductor and surface casing. The P&A operation would be split into five phases, the third of which (setting primary reservoir plugs) would be performed with CT.

Well parameters varied, but primary reservoir barriers were generally set in 5½-in. or 6⅝-in. completions at depths of between 2400 and 4400 m with inclinations between 85 and 90°.

CT-Job Design

Step A: Establish Reservoir Access. Drift or wash runs would be performed to establish reservoir access. This would help ensure that the well was cleared of any barriers and that the well had been drifted to ensure that perforating charges and plugs could be run and retrieved. Barriers typically included scale buildup on numerous wells, which could often be treated by milling or spotting acid with CT. In a few other cases, fish left in the well during previous intervention operations would have to be removed first. In some wells where depth control was critical, additional casing-collar-locator (CCL) runs were necessary as part of Step A.

Step B: Establish Reservoir Barriers. Several runs would be performed to enable the placement of the permanent cement reservoir barriers. These typically included tubing punch; perforating runs; wash runs; packer run; cement base placement; and, finally, the cement plug.

Of all the steps, Step B would be the most unconventional and would require testing to demonstrate that the tubing could be perforated, washed, and cemented successfully in field conditions. Testing of the proposed techniques would include testing of the tooling [bottomhole assemblies (BHAs)] at a field facility together with laboratory testing of the cement slurry and placement.

For the plugging operation, a custom-designed blend of abandonment cement was necessary. The blend needed to be suitable for both abandonment and pumping down CT. In addition to the minimum properties necessary per the NORSOK standard, the cement blend provided a low circulating density, high strength, and low permeability. The cement blend also was required to control losses to the formation and successfully establish a fundament on which to place the reservoir plug.

The ability to punch and perforate the production tubing with CT was an established practice; however, the ability to wash and remove debris behind the tubing would require testing, the process of which is detailed in the complete paper. The yard trials were successful in determining that the BHA could successfully wash debris from behind the tubing and that cement could be placed successfully. The testing also confirmed that a slow pump rate and lower viscosity also would benefit cement placement through CT.

Step C: Verify Barriers. The final step in the job design was to perform an additional tubing punch run, dress the cement plug, and validate the cement plug by pressure-testing all of the established procedures.

CT Equipment

Equipment requirements and CT rig-up considerations for the operation only required standard equipment and practices in rigging up with both the pipe deck and drill floor.

The optimal string for the operation was 2⅜-in. outer-diameter Grade-100 CT, selected on the basis of standard design factors including length, crane lift capacity, maximum rates and pressures, maximum set down, and pick-up capacity. During the campaign, a total of four CT strings was used because of the overall footage run and the fatigue accumulation. The placement of the CT reel and string on the turntable base would enable the string to be oriented to the respective well without the need for additional crane lifts.

The drill floor and the tree deck only required standard equipment. The overall stack assembly enabled a maximum BHA length greater than 25 m, well able to accommodate the standard planned BHAs. For safe running of the long perforating guns, operations required a detailed risk assessment and the use of a special drop table (Figs. 1 and 2).

Fig. 1—Rig-up on wellhead.

 

Fig. 2—Making up and running guns in the drop table.

Sequence of Operations

Although individual well parameters varied because of well geometry, well-completion design, and depth, a standard sequence of operations was established for the CT campaign.

Drift Wash.

  • Run 1: Drift wash with rotating nozzle

Perforation.

  • Run 2: First punch run (establish annular circulation)
  • Run 3: Perforating Run 1 (100- to 120-m guns)
  • Run 4: Perforating Run 2 (110- to 130-m guns)+punch

Washing.

  • Run 5: Wash run with fluidic oscillator
  • High-rate annular flush
  • Pump wettability spacer
  • High-rate tubing flush

Cementing.

  • Run 6: Run and set inflatable packer
  • Injectivity test
  • Run 7: Cementing run (base)
  • Run 8: Cement plug

Verification.

  • Run 9: Tubing punch access to test 6⅝- to 9⅝-in. annulus from above
  • Run 10: Tag with nozzle or dress with mill
  • Pressure testing

These runs would be supplemented by additional runs for scale milling, acid spotting, fishing, and CCL runs, as necessary.

Conclusions

From these operations, several best practices were established for placement of permanent reservoir isolation barriers with CT.

  • Effective cleaning of the well before cementing is essential. The fluid-oscillator tool should be stacked with both side jets and down jets. Optimal pump-flow rate was 3 bbl/min for cleaning. A 30° phasing/indexing tool added above the fluid-oscillator tool enhanced cleaning between successive passes.
  • Effective cement-barrier placement was best provided by a cement slurry designed for both abandonment and placement by means of CT. For CT applications, low viscosities combined with low pumping rates were optimal. The use of cement wiper darts above and below the cement, followed by a hesitation squeeze after all the cement was placed, was beneficial.
  • Thorough analysis of potential equipment failure modes combined with spares planning can reduce equipment failure and nonproductive time to a minimum.
  • The use of a regular CT crew together with a mechanic maximizes uptime and improves service quality and safety.
  • Effective CT-string management is important in extended CT campaigns. Real-time data acquisition and analysis and management of fatigue points are vital. The use of hydraulic tubing cutters when cutting long lengths of CT to move fatigue points was necessary for safe and efficient operations. In long campaigns, changing out tool packages is necessary.
  • Plans for contingency operations are vital.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 189956, “Successful Creation of Permanent Reservoir-Isolation Barriers Using Coiled Tubing on the Norwegian Continental Shelf,” by Iain Thomson, Halliburton, prepared for the 2018 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 27–28 March. The paper has not been peer reviewed.

Isolation Barriers With Coiled Tubing in Plug-and-Abandonment Operations

01 June 2018

Volume: 70 | Issue: 6

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