Research and Development Technical Section

Dear Friends,

I am working on development of stimulation fluid like solvent-surfactant for the wells which have formation damage issues. During the process of development in the lab we do set of experiments in the lab for testing solubility of the collected crude oil or deposit sample, rheology experiments and Interfacial tension etc. We also try to do core flood experiments to see whether the developed formulation is able to remove the formation  plugs and thereby regain the original oil permeability. However, the problem we are facing currently is that we can not create enough damage in the cores by flooding with 3 to 5 PV of crude oil to mimic the phenomenon of deposition of organic deposits near well bore.

Can any body suggest any suitable mean of creating enough damage (by organic deposits) inside the core through core flood experiments.

Dear Friends,

I am working on development of stimulation fluid like solvent-surfactant for the wells which have formation damage issues. During the process of development in the lab we do set of experiments in the lab for testing solubility of the collected crude oil or deposit sample, rheology experiments and Interfacial tension etc. We also try to do core flood experiments to see whether the developed formulation is able to remove the formation  plugs and thereby regain the original oil permeability. However, the problem we are facing currently is that we can not create enough damage in the cores by flooding with 3 to 5 PV of crude oil to mimic the phenomenon of deposition of organic deposits near well bore.

Can any body suggest any suitable mean of creating enough damage (by organic deposits) inside the core through core flood experiments.

I am curious as to whether your damage us caused by condensed paraffins or ashaltenes?  I also am curious to know how many pore volumes of fluid production are needed to cause observed damage in the damaged zone in you well? Is the deposition primarily owing to pressure changes?  Or is there some effect of temperature changes, perhaps owing to injection of cold stimulation fluid?

Dear Friends,

I am working on development of stimulation fluid like solvent-surfactant for the wells which have formation damage issues. During the process of development in the lab we do set of experiments in the lab for testing solubility of the collected crude oil or deposit sample, rheology experiments and Interfacial tension etc. We also try to do core flood experiments to see whether the developed formulation is able to remove the formation  plugs and thereby regain the original oil permeability. However, the problem we are facing currently is that we can not create enough damage in the cores by flooding with 3 to 5 PV of crude oil to mimic the phenomenon of deposition of organic deposits near well bore.

Can any body suggest any suitable mean of creating enough damage (by organic deposits) inside the core through core flood experiments.

I am curious as to whether your damage us caused by condensed paraffins or ashaltenes?  I also am curious to know how many pore volumes of fluid production are needed to cause observed damage in the damaged zone in you well? Is the deposition primarily owing to pressure changes?  Or is there some effect of temperature changes, perhaps owing to injection of cold stimulation fluid?

Dear Friends,

I am working on development of stimulation fluid like solvent-surfactant for the wells which have formation damage issues. During the process of development in the lab we do set of experiments in the lab for testing solubility of the collected crude oil or deposit sample, rheology experiments and Interfacial tension etc. We also try to do core flood experiments to see whether the developed formulation is able to remove the formation  plugs and thereby regain the original oil permeability. However, the problem we are facing currently is that we can not create enough damage in the cores by flooding with 3 to 5 PV of crude oil to mimic the phenomenon of deposition of organic deposits near well bore.

Can any body suggest any suitable mean of creating enough damage (by organic deposits) inside the core through core flood experiments.

Dear Pearson,

The actual cause of formation damage varies on case to case basis. Here I am more concerned about the lab simulation of formation damage i.e. how to create a damage inside a core and establish effectiveness of the formulation through core flood experiment.  We select the formulation after screening a number of solvent combinations through experiments like solubility, rheology, wettability change and Interfacial Tension measurements. The selected formulation we try to validate in core flood experiment, however, in that stage the common problem we encounter is that we can not create enough damage in the core which can mimic actual field scenarios.

Hope I could clarify your queries.

I am curious as to whether your damage us caused by condensed paraffins or ashaltenes?  I also am curious to know how many pore volumes of fluid production are needed to cause observed damage in the damaged zone in you well? Is the deposition primarily owing to pressure changes?  Or is there some effect of temperature changes, perhaps owing to injection of cold stimulation fluid?

Dear Friends,

I am working on development of stimulation fluid like solvent-surfactant for the wells which have formation damage issues. During the process of development in the lab we do set of experiments in the lab for testing solubility of the collected crude oil or deposit sample, rheology experiments and Interfacial tension etc. We also try to do core flood experiments to see whether the developed formulation is able to remove the formation  plugs and thereby regain the original oil permeability. However, the problem we are facing currently is that we can not create enough damage in the cores by flooding with 3 to 5 PV of crude oil to mimic the phenomenon of deposition of organic deposits near well bore.

Can any body suggest any suitable mean of creating enough damage (by organic deposits) inside the core through core flood experiments.

Dear Friends,

I am working on development of stimulation fluid like solvent-surfactant for the wells which have formation damage issues. During the process of development in the lab we do set of experiments in the lab for testing solubility of the collected crude oil or deposit sample, rheology experiments and Interfacial tension etc. We also try to do core flood experiments to see whether the developed formulation is able to remove the formation  plugs and thereby regain the original oil permeability. However, the problem we are facing currently is that we can not create enough damage in the cores by flooding with 3 to 5 PV of crude oil to mimic the phenomenon of deposition of organic deposits near well bore.

Can any body suggest any suitable mean of creating enough damage (by organic deposits) inside the core through core flood experiments.

...some additional thoughts for you:

How well-characterized are your reservoir fluids, especially with respect to pressure-dependent condensation effects?

Are your cores acquired vertically, or, said differently, does your reservoir have strongly anisotropic permeability?

Dear Friends,

I am working on development of stimulation fluid like solvent-surfactant for the wells which have formation damage issues. During the process of development in the lab we do set of experiments in the lab for testing solubility of the collected crude oil or deposit sample, rheology experiments and Interfacial tension etc. We also try to do core flood experiments to see whether the developed formulation is able to remove the formation  plugs and thereby regain the original oil permeability. However, the problem we are facing currently is that we can not create enough damage in the cores by flooding with 3 to 5 PV of crude oil to mimic the phenomenon of deposition of organic deposits near well bore.

Can any body suggest any suitable mean of creating enough damage (by organic deposits) inside the core through core flood experiments.

Sometimes we used actual core for experiments, but mostly we mixed our sand and bitumen and packed the vessels, or we would pack clean sand into pressure vessels and inject warm bitumen to prepare the core for testing.

...some additional thoughts for you:

How well-characterized are your reservoir fluids, especially with respect to pressure-dependent condensation effects?

Are your cores acquired vertically, or, said differently, does your reservoir have strongly anisotropic permeability?

Dear Friends,

I am working on development of stimulation fluid like solvent-surfactant for the wells which have formation damage issues. During the process of development in the lab we do set of experiments in the lab for testing solubility of the collected crude oil or deposit sample, rheology experiments and Interfacial tension etc. We also try to do core flood experiments to see whether the developed formulation is able to remove the formation  plugs and thereby regain the original oil permeability. However, the problem we are facing currently is that we can not create enough damage in the cores by flooding with 3 to 5 PV of crude oil to mimic the phenomenon of deposition of organic deposits near well bore.

Can any body suggest any suitable mean of creating enough damage (by organic deposits) inside the core through core flood experiments.

Dear Friends,

I am working on development of stimulation fluid like solvent-surfactant for the wells which have formation damage issues. During the process of development in the lab we do set of experiments in the lab for testing solubility of the collected crude oil or deposit sample, rheology experiments and Interfacial tension etc. We also try to do core flood experiments to see whether the developed formulation is able to remove the formation  plugs and thereby regain the original oil permeability. However, the problem we are facing currently is that we can not create enough damage in the cores by flooding with 3 to 5 PV of crude oil to mimic the phenomenon of deposition of organic deposits near well bore.

Can any body suggest any suitable mean of creating enough damage (by organic deposits) inside the core through core flood experiments.

Dear Abhishek,

You may use an outcrop rock and saturated saturate it with Bitumen dissolved in Toluene or any other solvent then allow the solvent it evaporate at a suitable temperature, in this way the heavier components (Asphaltene and resins will reside inside the rock, and you can test your stimulation formulation. This would be more representative if you use the same organic deposit in your well in the solvent instead of bitumen.

Thank you

Khaled

Dear Friends,

I am working on development of stimulation fluid like solvent-surfactant for the wells which have formation damage issues. During the process of development in the lab we do set of experiments in the lab for testing solubility of the collected crude oil or deposit sample, rheology experiments and Interfacial tension etc. We also try to do core flood experiments to see whether the developed formulation is able to remove the formation  plugs and thereby regain the original oil permeability. However, the problem we are facing currently is that we can not create enough damage in the cores by flooding with 3 to 5 PV of crude oil to mimic the phenomenon of deposition of organic deposits near well bore.

Can any body suggest any suitable mean of creating enough damage (by organic deposits) inside the core through core flood experiments.