Injection Well Injecting at Vacuum 1

[moredrilling]

Hello Gents,
I am implementing a script to monitor injection wells setpoint for automation. From experience we know that some of the wells are injecting at 0 surface pressure or "vacuum" at reservoir condition. I want to catch wells that may be injecting at vacuum regardless of the surface injection pressure, keeping in mind that we are not injecting above the reservoir parting pressure. This is the equation I have. The reservoir frac pressure was determined from step-rate tests made in the previously.

Inj. Surf Pressure = Reservoir Frac Pressure - Hydro static Column + Frictional loss

If the calculated inj surface pressure is less than 0 we know that we are injecting in to a frac'd or high perm zone. Am I in the right track?

T^hank You

 

[zdas04]

It is a lot more complicated than that. Vacuum conditions on the wellhead of liquid injection wells are fairly common. They happen when a slug of water falls into a gas filled column. It is common for the water to fall so fast that it actually compresses the gas below it to values substantially above reservoir pressure (by the way, your "reservoir frac pressure" is normally called "reservoir parting pressure" and has no place in this equation, it is simply "average reservoir pressure"). This very high velocity slug has really high friction losses that are not translated to the injection pressure.

To get an idea of reservoir pressure, you have to stop injection, wait for equilibrium (often several days, but the asymptote of the reservoir pressure can be predicted after about 12 hours. After you get that value, run a pressure bomb to get a fluid level on the static well. Reservoir pressure = Tubing pressure + hydrostatic head of measured water column.

[bold]David Simpson, PE[/bold]
MuleShoe Engineering

In questions of science, the authority of a thousand is not worth the humble reasoning of a single individual. Galileo Galilei, Italian Physicist

 

[moredrilling]

Appreciate your reply David, Great point about gas columns in the well. In a continuously injecting well, I don't presume there would be gas in the wellbore.
To clarify, the wells are in a mature very high watercut >99% field. We are using the parting pressure to determine the maximum injection pressure we should aim for. During previous shut-ins we couldn't get any fluid column in the wellbore. I am thinking this is because of reservoir that has been fractured during injection or high permeability injection zones. The injection well analyst essentially wants to switch the injection controls from rate to pressure controls. While doing that some of the wells were injecting at very high liquid injection rates, and at low well head pressures. I have the injection rate and wellhead pressure from daily measurements while the well is operating. I wanted to calculate the optimal well head pressure without fracing the reservoir. I appreciate your comments.

 

[zdas04]

Parting pressure is a function of the rock mechanics and can only be determined by step rate testes. The tests I've been around have had parting pressures in the thousands of pounds, no well on vacuum will come close to breaking any reservoir rock I've ever seen. If the reservoir can take the gas faster than you can deliver it, then you end up with the liquid flowing faster in the tubing than you are pumping and you get gaps in the stream. Think of it like filling an in-ground tank from a above ground tank through a huge pipe with a small orifice at the head of the pipe.

[bold]David Simpson, PE[/bold]
MuleShoe Engineering

In questions of science, the authority of a thousand is not worth the humble reasoning of a single individual. Galileo Galilei, Italian Physicist