Processes and systems for injection of a liquid and gas mixture into a well
Processes and systems for injecting a liquid and gas mixture into a well are disclosed. The processes and systems include injecting a mixture of a liquid and a gas into a well in order to: increase production of a production fluid in the well, decrease the bottom hole pressure, decrease the density of the production fluid, or a combination thereof.
1. A method for injection of a liquid and a gas mixture into a well that is producing a production fluid at a first production rate, wherein the well comprises a borehole extending into the ground to a formation, the borehole having at least one production tubing extending through at least a portion of the borehole, the method comprising:
measuring fluid properties at a surface level of the at least one production tubing and measuring fluid dynamics occurring within the at least one production tubing while the well is producing fluid at the first production rate;
determining a first mixture of a liquid and gas to be injected into the well based upon the measurements;
injecting the first mixture of a liquid and a gas into the borehole, communicating the first mixture to a portion of the at least one production tubing containing the production fluid, wherein the first mixture is injected at a first flow rate to cause the well to increase production of the production fluid to a second production rate that is greater than the first production rate; and
adjusting gas and liquid mixture compositions and flowrates over time to facilitate downward bubble flow based on the measured fluid properties at the surface level of the at least one production tubing by repeating the measuring, determining, and injecting steps recited above sequentially in an iterative feedback process.
2. The method according to claim 1 , wherein the liquid of the first mixture comprises liquid hydrocarbons.
3. The method according to claim 2 , wherein the hydrocarbons comprise crude oil.
4. The method according to claim 3 , wherein the crude oil was produced from the well.
5. The method according to claim 1 , wherein the gas comprises methane.
6. The method according to claim 1 , wherein the gas is present in the mixture in an amount of from 10% by volume of the mixture to 99% by volume of the mixture.
7. The method according to claim 1 , further comprising, prior to the injecting the first mixture of the liquid and the gas into the well, forming the first mixture at a location proximal to the well.
8. The method according to claim 1 , further comprising, prior to the injecting the first mixture of the liquid and the gas into the well, determining the first flow rate based on one or more of well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters.
9. The method according to claim 8 , wherein the well geometry parameters comprise one or more of: an internal diameter of well tubing, an external diameter of well tubing, an internal diameter of a casing string, a depth of the casing string, an inclination of the casing string, a diameter of the vertical wellbore section, a depth of the vertical section, or a depth of an injection valve; wherein the produced fluids properties comprise one or more of: a density of the well-produced fluids, an API gravity of the produced fluids, such as an API gravity of the oil or condensate, a viscosity of the well-produced fluids, a pressure of the well-produced fluids, a volume of the well-produced fluids, or a temperature of the well-produced fluids; wherein the well productivity parameters comprises one or more of: an average reservoir pressure, a flow potential for the well, production rates from the well, an average oil or condensate rate, an average water rate (barrels per day), an average gas rate, a flowing tubing pressure, a wellhead pressure, a choke setting, a well head flowing temperature; and wherein the surface production parameters comprise one or more of: a gas conduit pressure, a liquid conduit pressure, a liquid and gas mixture conduit pressure, an outlet pressure, a well head shut-in pressure, a well head shut-in temperature, a production line pressure, a separator pressure, a casing head shut-in temperature, a casing head shut-in pressure, the gas volume available or extractable from the gas source, or source gas pressure.
10. The method according to claim 1 , further comprising, subsequent to the injecting the first mixture of the liquid and the gas into the well, identifying one or more of well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters.
11. The method according to claim 10 , further comprising, subsequent to the identifying one or more of well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters, injecting a second mixture of a liquid and a gas into the well, wherein the second mixture is different than the first mixture.
12. The method according to claim 1 , wherein, prior to the injecting the first mixture of the liquid and the gas into the well, the at least one production tubing comprises a first volume of production fluid therein having a first density, and wherein, subsequent to the injecting the first mixture of the liquid and the gas into the well, the at least one production tubing comprises a second volume of production fluid therein having a second density, the second density being less than the first density.
13. A method for injection of a liquid and gas mixture into a producing well, wherein the well comprises a borehole extending into the ground to a formation, the borehole having at least one production tubing extending through at least a portion of the borehole, the method comprising:
measuring fluid properties at a surface level of the at least one production tubing and measuring fluid dynamics occurring within the at least one production tubing while the well is producing fluid at the first production rate;
determining a first mixture of a liquid and gas to be injected into the well based upon the measurements;
injecting the first mixture of a liquid and a gas into the borehole, communicating the first mixture to a portion of the at least one production tubing while the well is producing a first volume of production fluid, the first volume of production fluid having a first density, wherein the first mixture is injected at a first flow rate thereby resulting in the formation of a second volume of production fluid, the second volume of production fluid having a second density that is less than the first density; and
adjusting gas and liquid mixture compositions and flowrates over time to facilitate downward bubble flow based on the measured fluid properties at the surface level of the at least one production by repeating the measuring, determining, and injecting steps recited above sequentially in an iterative feedback process.
14. The method according to claim 13 , wherein the liquid of the first mixture comprises liquid hydrocarbons, wherein the hydrocarbons were produced from the well.
15. The method according to claim 13 , wherein the gas comprises methane.
16. The method according to claim 13 , wherein the gas is present in the mixture in an amount of from 10% by volume of the mixture to 99% by volume of the mixture.
17. The method according to claim 13 , further comprising, prior to the injecting the first mixture of the liquid and the gas into the well, determining the first flow rate based on one or more of well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters.
18. The method according to claim 13 , further comprising, prior to the injecting the first mixture of the liquid and the gas into the well, determining a relative amount of the liquid and a relative amount of the gas in the first mixture, based on one or more of well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters.
19. The method according to claim 18 , wherein the well geometry parameters comprise one or more of: an internal diameter of well tubing, an external diameter of well tubing, an internal diameter of a casing string, a depth of the casing string, an inclination of the casing string, a diameter of the vertical wellbore section, a depth of the vertical section, or a depth of an injection valve; wherein the produced fluids properties comprise one or more of: a density of the well-produced fluids, an API gravity of the produced fluids, such as an API gravity of the oil or condensate, a viscosity of the well-produced fluids, a pressure of the well-produced fluids, a volume of the well-produced fluids, or a temperature of the well-produced fluids; wherein the well productivity parameters comprises one or more of: an average reservoir pressure, a flow potential for the well, production rates from the well, an average oil or condensate rate, an average water rate (barrels per day), an average gas rate, a flowing tubing pressure, a wellhead pressure, a choke setting, a well head flowing temperature; and wherein the surface production parameters comprise one or more of: a gas conduit pressure, a liquid conduit pressure, a liquid and gas mixture conduit pressure, an outlet pressure, a well head shut-in pressure, a well head shut-in temperature, a production line pressure, a separator pressure, a casing head shut-in temperature, a casing head shut-in pressure, the gas volume available or extractable from the gas source, or source gas pressure.