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Drilling a Horizontal wellbore between high-pressure water injectors and depleted producers
03 August 2017

Community,

I’d like to pick your brains on a scenario we are looking at drilling and completing for a client.

  • Heavily water-flooded area but showing very low sweep efficiency
  • Overpressured injectors showing potential 1850kg/m3 (15.5+ppg) EMW BHP
  • Vertical Producing wells are on rod pumps with as low as 300kg/m3 (2.5ppg) EMW BHP
  • Very little communication between all these vertical injectors and vertical producers
    • 7-8 week shut in pressures nearly holding at original injection pressures.
  • We need to drill a horizontal leg right in the middle of these and although the injection pressures are not expected to transmit to our well +/-300m (1000ft) away on closest approach we need to be prepared for seeing an increased BHP while drilling.
  • 244.4mm (9-5/8”) Surf csg at 200mMD/TVD (656ft MD/TVD)
    • This is as deep as I can push since a potential low pressure shallow gas zone just below this.
  • 177.8mm (7”) Intermediate top-set above potential pressure formation 1150mMD/971mTVD (3773ftMD/3185ftTVD)
    • To me, this is the highest risk part of the well, drilling my intermediate hole into potential pressure with only surf csg exposed.
    • Plan is to top set the upper-most formation that could transmit the pressure.
  • 159mm (6-1/4”) Production hole to finish the build and go HZ.
    • Max anticipated BHP nearer the heel, max depletion nearer TD
    • Using 4-1/2” DP with DS40 connections
  • Run 4-1/2” prod liner with frac sleeves and Weatherford OH Packers, uncemented.

We just did a well in this area using MPD equipment, light mud with backpressure, didn’t see any noticeable losses throughout, saw 1475kg/m3 (12.3ppg) EMW at TD, was prepared for maximum 1760kg/m3 (14.7ppg) EMW. Mudded up to KWM and got diff stuck. No noticeable losses to speak of.

We then preformed a flow test to see what flow rate potential this tight sand had to feed our wellbore with injection water, initial rate of 19m3/hr (120bbl/hr) but only saw 4m3 (25bbl) total fluid until it petered off to a trickle.

Mud system had been dusted up with BaseBlok to mitigate diff sticking but must have scraped it off. We did manage to get unstuck after displacing to base oil and pipe-free but the whole time we stayed at 1475kg/m3 (12.3ppg) balance to formation pressure.

Cleanout run went well, stripped through MPD kit to inside interm csg, spotted a heavy mud cap inside interm csg, POOH. Ran our liner and got diff stuck again outside interm csg.

Question: What are you experiences in dealing with high pressured heels with depleted toes where the potential pressures can be observed (at least partial pressure) and knowing the risk of diff sticking exists while drilling and running liner?

Thanks.

Keith Simard P.Eng

2 answer(s)
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D&C Project Coordinator / Decommissioning
Society of Petroleum Engineers
Total Posts: 7
Join Date: 25/01/16

A most interesting situation that does evolve in a range of carbonate reservoir situations.  Certainly the managed pressure drilling technologies will make it possible to create reliable two barrier completions. 

I would suggest that all the relevant offset well's ASCII mud log data and mud log daily reports be taken and an analysis of what the operational activity consequences by time and depth are. 

Once the impact of different operations at different depths and over time are understood a best practice to project coordinate the D&C aspects of the well can be determined.  Best to only work in 8 1/2" hole for the completion activities.

One strategy that can be used to optimise well return is to design production to maintain a reservoir pressure above gas dew point pressure. 

My suggestion would be do a vertical and 3 multilateral completions where only the heel and short horizontal is set. Something like to set a 9 5/8 intermediate casing above the multilateral junctions and then drill and complete with 7" the vertical and 3 multilaterals.  This would include the use of SET technology to get full zonal isolation across the multilateral pay zones and at the junction area. Then the completion would be a vertical 2 7/8" tubing string to observe formations, and possibly an injection well that includes CO2 emissions inside a 7" production tubing string.  Incorporating selective perforation strategy, like only 10 to 15 shots over a 20 m pay section, could be used where there isn't a flow path into the well from an adjacent fracture, etc.  The 2 7/8" observation / circulation / injection string would also allow access to the production annulus for the multilateral production monitoring / condition monitoring as well.. 

 During production the reservoir behaviours would be monitored through the vertical well and allow for some intervention based on condition monitoring indicators to where the life of the production could be 50 years for example.  The multilateral completions would allow for a 20 km well location spacing.  .

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Independent Consultant
Olango Consulting
Total Posts: 4
Join Date: 23/03/16

Keith

Would it be an option to run the liner into the open hole by balancing the well?

Once at TD displace the well to a mudweight that balances the toe and puts the heel underbalanced. Apply surface pressure to stop the well (the heel) from flowing, that gives you a good indication of the formation pressures. Need to take the time to determine the pressures accurately and see what the inflow is like.

At that point, you can calculate what it would take to balance the heel of the well with a top kill in the vertical section.

Pull the string back through the RCD holding pressure to balance the well until the bit is in the vertical section. Displace the vertical section to kill mud to kill the heel (12.5 ppg)

Open the RCD, flow check and pull out of the hole, keeping the hole full

Once out of the hole flow check and pick up the liner

Run the liner with the RCD open (no seals installed) down to the bottom of the vertical section.

Once you get the liner down to the top of the build section, install the RCD displace the vertical section of the well back to an underbalanced fluid. Balance the well with surface pressure then run / wash the liner on drillpipe down with underbalanced fluid all the way to TD holding surface pressure

With the liner on pipe and an RCD you should be able to balance the pressure using ECD and some small surface amount of surface pressure to leave the well balanced. If you get differentially stuck lower the surface pressure to balance the well and free the liner. Once you get the liner to TD set packers.

If the stuck point is below the heel you may have to look at bringing the entire horizontal section underbalanced and using surface pressure to balance the well.

You probably also need to look at centralizing the liner in the build section to minimize wall contact.

We have done this successfully in some of the carbonate wells here in Asia where you have the same issues, pressure in the top of the reservoir is higher than pressure at the bottom. We also did the same thing on a High pressure well in Africa (see SPE paper 167985)

I cannot see the well trajectory so not sure if you have enough room to have the liner on drillpipe and still have the liner shoe in the vertical section. Running liners in Managed Pressure Drilling mode has been done successfully even with underbalanced fluid in the well.

You will have to do some calculations based on your well trajectory and formation pressures to see what ECD, Mud weights and pressures you would need or could expect.

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