Typical coiled tubing procedures

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1 Sand Consolidation

1.1 Introduction

This job outline provides the general considerations to be taken when carrying out a sand consolidation job by coiled tubing. The details will be dependent on the candidate well/formation chosen and thus each programme should be prepared separately. The key parameters are those required to calculate treatment volumes and pumping times (porosity, length and depth of treatment, size of workstring and bottomhole temperature). It is important to realise that when the formation is consolidated, any damage/impairment will also be consolidated in place. Thus, the formation, surface equipment, surface lines, the workstring and downhole equipment should be as clean as possible to minimise impairment. Similarly, all fluids pumped into the well and especially all those that are injected into the formation should be filtered.

1.2 Safety

The chemicals used for a sand consolidation job are safe if handled properly. Thus, a pre-job meeting is essential for this type of operation, especially when the staff concerned are unfamiliar with this technique and/or the chemicals used. The meeting should inform the personnel involved of all health, safety and environmental issues so that they are aware of the potential hazards of not following the agreed procedures. Personal protective equipment should be available for those involved and contingency procedures should be discussed with all relevant parties.

1. Rig-up surface equipment. Ensure all equipment is clean. Preferably use stainless steel calibrated tanks where levels can be monitored. All brine and diesel that is to be used should be filtered if possible.

2. Rig-up coiled tubing. (Pump a plug through the coiled tubing and accurately measure the volume of tubing. It is important that accurate volumes and low rates are recorded during the job.)

3. Make up selective placement tool/bottomhole assembly.

4. Pressure test lines/lubricator/BOPs and function test tool.

Ensure that circulation rates, squeeze pressures and injector loadings are within the operating parameters of the coiled tubing equipment selected for the task.

5. Zero the tool and run in the hole, while circulating with inhibited brine.

6. Correlate tool downhole and move on depth.

7. Set packers across treatment interval and check that a satisfactory seal has been achieved.

8. Carry out injectivity test, with brine, at various rates and record pressures.

The injectivity test should confirm that; the tool has been set in the right position; there is sufficient injectivity to squeeze away the consolidation chemicals and overflush within the allowable pumpable time.

9. If injectivity is high enough, proceed with (10), otherwise acidise and repeat njectivity test. If injectivity is still too low, then:

  • Acidise again, and/or reperforate, and/or
  • Reduce volumes of Sand Mixture to be pumped, or
  • Abort job and pull out of hole

10. Prepare Mixture.

  • Take a sample and carry out viscosity build-up test at bottomhole temperature.

11. Begin pumping at maximum rate (volumes will vary depending on interval length and porosity):

  • Pump 2 vols diesel preflush (optional). (Diesel preflush has been shown to improve performance in some core tests. Thus, prior to including a diesel preflush, core flushing tests should be carried out to determine whether there is any improvement in performance.)
  • Drop 1st plug
  • Pump Sand Mixture
  • Drop 2nd plug
  • Displace entire overflush into formation with displacement fluid
  • Wait on cure. (Surface sample in hot water bath at BHT)

12. Unset the packer and lower toolstring slowly, while circulating displacement fluid, until the top of the toolstring is 10 m below bottom perforation. This will clean/dilute any remaining chemicals in the wellbore across the treated zone.

13. Pull coiled tubing out of hole while circulating displacement fluid out of the coiled tubing by displacing with filtered brine. If losses occur after a sand consolidation job, then a viscous pill should be used to control the losses. If filter cake forming pills are used, then these will be extremely difficult to clean up once they are packed into the perforation tunnels, resulting in high impairment.

  • DO NOT SQUEEZE ANY MORE FLUIDS INTO THE FORMATION AND DO NOT ALLOW THE WELL TO FLOW.

14. Lay down tool and clean residual resin off as soon as possible. After the SPT tool has been laid down, it can be best cleaned by wiping off any resin from surface with dry rags.

15. Rig down all equipment. Report viscosity build-up time of sample in the oven.

16. The well should not be production tested until ±48 hours for maximum strength after the chemicals were injected. Results in the lab have shown that for wells with a bottomhole temperature exceeding 60ºC, there is no significant improvement in return permeability or strength beyond 48 hours curing time.

The pumpable time should be determined beforehand by measuring the viscosity build-up of the chemicals at the bottomhole temperature. This should be done as soon as the chemicals are on site. If the chemicals have been stored for a long time, then a viscosity build-up test should be carried out before dispatching the chemicals to the rig.

The job should be designed so that the chemicals can be mixed, pumped and displaced out of the workstring before the viscosity builds up to 100 cP, at which point the reaction rate increases dramatically and the chemicals gel very soon afterwards. As the mixing occurs at ambient temperature, where the reaction is extremely slow, the mixing time is not included when calculating the minimum pumping time required.

Thus, it is important that an injectivity test be carried out before the job, and the maximum pumping rate be applied during the job. This also encourages even placement.

2 Coiled tubing gas lift

2.1 Introduction

The following procedure details the actions necessary to induce flow in a well which is dead due to the hydrostatic pressure imposed by the fluid column. Nitrogen is introduced such that the hydrostatic column is reduced to a value less than the formation pressure.

To bring on a well irrespective of the deviation profile it should only be necessary to run in to the end of the vertical/build-up section of the completion. Beyond this point the hydrostatic pressure downhole would not significantly increase and so further CT ingress will be unnecessary. Care should be taken in determining the depth to run to and required pump rate since if too deep it is possible to simply inject N2 into the formation and not bring in the well at all.

If too shallow and the rate too slow, an inefficient lift will be performed using large quantities of N2 for little off load of the hydrostatic column. Similarly, if the coiled tubing size is too large the friction losses in the annulus may result in lost returns. If the coiled tubing is too small the low flow rates of N2 and the large annulus may result in liquid slippage and therefore an inefficient gas lift.

Selection of the coiled tubing size is critical in allowing for maximum flowrate yet not creating an annular choke which will cause gas slippage. If N2 volumes are critical and slippage cannot be tolerated, then a foaming agent can be used to improve the efficiency of the lift. Such an approach however, may result in problems in receiving the returns at surface. If possible a computer simulation should be used to plan the operation, from defining optimum depth and pump rate to determining the most effective coiled tubing size.

2.2 Planning

When planning the job with a computer simulator the following information is required:

  • FBHT, SIBHP, expected flow details, produced fluid density, current wellbore fluid density, producing GOR.
  • Completion details showing location of restrictions.
  • Deviation profile showing drift and reach of the well.

Once the above are determined, the following should be conducted using the computer simulator:

  • Optimise flow rates of nitrogen, providing minimum slippage, at safe working pressures and determine the optimum depth for conducting the operation.
  • From the above determine the applicable coiled tubing size and the required volumes of nitrogen allowing for losses e.g. cool down.

2.3 Bottom hole assembly (BHA)

There is no specific requirement for a BHA, the governing factor being to minimise the pressure drop across it. The BHA should consist of the following:

  • Inline connector
  • Double Flapper Check Valve
  • 6 ft of straight bar if required
  • Standard nozzle (single orifice, maximum ID)

2.4 Safety

The main danger in this type of operation is the use of gas (nitrogen) at high pressure, the presence of liquid nitrogen and its associated dangers, and the coiled tubing being in a live well situation.

  • All surface pressure equipment, e.g. coiled tubing and BOPs must be hydro-tested prior to introduction of gas.
  • Conduct the standard precautions necessary for handling of liquid nitrogen requirements will vary depending upon location).
  • All surface lines must be securely tied down prior to commencing operations.

Once the coiled tubing size, flowrates and N2 volumes have been determined, the following should be conducted:

1. Rig up the coiled tubing and pressure test as per standard procedures.

2. Displace the coiled tubing to N2 and perform gas pressure test if required by client.

3. Open well and commence running in hole at 50 ft/min (15 m/min). If the well has a standing fluid level, slow down RIH rate to 10 ft/min (3 m/min) at 100 ft (30 m) above expected fluid level. Once in the fluid resume 50 ft/min (15 m/min) ingress. Circulate N2 at a slow rate to lighten the hydrostatic column prior to reaching the lifting depth. If using a surfactant the pump should be running in order to introduce the correct percentage of foamer for the known volume of fluid within the well.

4. Once at the required depth commence pumping N2 at the specified rate. Monitor the following:

  • Coiled Tubing Pressure
  • Wellhead Pressure
  • Well Flowrate

5. Upon well commencing to flow satisfactorily, commence POOH at 50 ft/min (15 m/min) circulating N2 at a slow rate e.g. 300 scf/min.

6. Once at surface do not rig-down until well has been monitored and is maintaining a stable flow.

2.5 Post job

Upon rigging down thoroughly check the BHA components for any wear due to abrasion. Pay particular attention to the double flapper check valves.

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