Well Integrity Technical Section

Greetings all,
We have a bit of a brain-teaser and I'm hoping this community can help.
We're planning a deepwater development that will include subsea water injectors.  These will operate at matrix rates to start but as reservoir pressure depletes (production rates >> matrix injection rates), we expect the injection pressure will exceed parting pressure, ie, the sand will fracture and we'll be able to place more water.  The reservoir is a relatively soft (low UCS) sandstone.  
We've done numerous sanding studies (applicable when the well is shut-in and cross-flow is expected between heterogeneous sand packages) and have developed criteria under which we can complete the injectors as "cased and perforated" completions and avoid the cost and operational complications of sand control, which would likely be a frac-pack (before we go there, we've looked at long horizontals and the geology makes this extremely difficult, if not impossible).
The sanding studies are based on stresses acting on a cylindrical perforation.  This model is valid until we frac.  When we open the frac, I expect this geometry and all the associated stresses to change: I expect the perf tunnel will erode and cease to be a cylinder.  The stresses on a frac face differ from those on a cylinder, etc. 
Has anyone assessed this on past projects, and if so, how?
My thanks in advance,
R

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Ron Nelson
Subsea Completion Consultant
ron@deep-blue.ca
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Hi Ron,

I don't know if the still offer it, but Tendeka had the Cascade3 screen technology specifically designed to manage this problem in water injectors.  Was co-developed with Shell for GOM wells.

Ron, 

Many water injectors are taking water via hydraulic fracture w/o operators realizing it. This happens because of stress reduction due to cooling by the injected water. If the water has solids in it - the frac face will get clogged up and the frac will propagate. There was an online simulator for this somewhere. 
You are right to be concerned about sanding; I've seen reports of it being an issue on injectors. I'm also with you on avoiding screens. Not only will it be expensive, but it will also be prone to plugging by any water impurities. 
I'd look at two options to avoid sanding - indirect vertically inverted fractures, or a completion w/ flow regulators and check valves to prevent crossflow. Both have their disadvantages. 
I'd reach out to DuneFront folks. 

regards,
daniel
CASE Solutions Pty Ltd
Brisbane, Australia
dkalinin@casesols.com

Ron,

I was thinking why don't you look at the fracture geometry issue itself.  In a low UCS high perm reservoir it is going to be difficult to grow a fracture of any width or length. Here I think width is the key thing to calculate as the fracture may only be a few grains wide.  I teach a little on this in my classes at Petroskills and here is a simple way to calculate the frac geometry using a PKN model.  I know there are more sophisticated models but this allows you to play with the key variable and get a reasonable understanding. 

There is also a simple leakoff calculator that will allow you, again, to get an idea of the key factors. 

I also think you need to consider fracture contact with the wellbore if there is any deviation.  I have done frac studies on GOM deepwater wells where it is expected there will be multiple fractures along the wellbore with limited contact to the perforations.  Once the matrix starts to plug the fractures will start at the weakest zone and spread out over time. If you have a long interval it is likely the injection will be spread out over a number of spots limiting the rate per fracture and again limiting it's width and growth.  Call me if you have any question about this.

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Dan Gibson
aka The Well Doctor
Completion & Well Integrity Advisor
Houston, Texas
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