Corrosion control downhole in a borehole

Claim 2

In a wellbore which produces a corrosive fluid through a production tubing, the method of controlling downhole corrosion comprising the steps of: (1) mixing a corrosion inhibitor with recycled water to provide a mixture which remains admixed for a measured length of time; (2) flowing the mixture downhole into the wellbore annulus; (3) recycling at least part of the water by separating the produced comingled oil and water to provide the recycled water of step (1); (4) measuring the time required for the inhibitor of step (1) to be returned from the well as residual inhibitor in the recycled water of step (3); (5) measuring the corrosion rate of the separated water; (6) adjusting the water rate of flow until the time interval of step (4) is less than the time interval found in step (1); (7) adjusting the inhibitor rate of flow until step (5) indicates that the corrosion rate of the well is controlled.

Claim 3

The method of claim 1 wherein the treatment chemical and the water are mixed together sufficiently so that appreciable separation thereof requires 6-8 hours, and the flow rate of the water in the mixture is increased to cause the residual treatment chemical to flow through the borehole is less than 6-8 hours.

Claim 4

The method of claim 1 wherein the inhibitor is selected from the groups comprised of: oil soluble filming inhibitors and water soluble filming inhibitors; and, the treatment chemical and the water are mixed together sufficiently so that appreciable separation thereof requires 6-8 hours, and the flow rate of the water in the mixture is increased to cause the residual treatment chemical to flow through the borehole in less than 6-8 hours.

Claim 5

In an oil well which produces hydrocarbons and water, and wherein the lower borehole annulus has a hydrostatic head comprised of a mixture of water and hydrocarbons adjacent the pay zone and separated hydrocarbons at a location above the water and hydrocarbon mixture, the method of treating the wellbore with treatment chemical comprising the steps of: (1) flowing produced fluid from the well and separating at least part of the water from the produced fluid; (2) admixing treatment chemical with the separated water of step (1) to provide an intimate mixture of produced water and treatment chemical; (3) continuously flowing the mixture of step (2) into the borehole annulus and gravitating the mixture down through the separated hydrocarbon part of the fluid column contained within the annulus at a rate which causes most of the treatment chemical to arrive at the water and hydrocarbon mixture of the lower borehole.

Claim 6

In an oil well which produces hydrocarbons and water, and wherein the lower borehole annulus has a hydrostatic head comprised of a mixture of water and hydrocarbons adjacent the pay zone and separated hydrocarbons at a location above the water and hydrocarbon mixture, the method of treating the wellbore with treatment chemical comprising the steps of: (1) flowing produced fluid from the well and separating at least part of the water from the produced fluid; (2) admixing treatment chemical with the separated water of step (1) to provide an intimate mixture of produced water and treatment chemical; (3) continuously flowing the mixture of step (2) into the borehole annulus and gravitating the mixture down through the separated hydrocarbon part of the fluid column contained within the annulus at a rate which causes most of the treatment chemical to arrive at the water and hydrocarbon mixture of the lower borehole.

Claim 7

The method of claim 4, and further including the steps of: (4) measuring the time interval required for the mixture of treatment chemical and water to separate into water and treatment chemical; (5) measuring the conductivity of the produced fluid; and, (6) adjusting the flow rate of the separated water in step (2) to obtain a mass flow of sufficient value to enable the mixture to gravitate down the annulus and into the production tubing prior to the treatment chemical separating from the water.

Claim 8

The method of claim 4, and further including the step of: (4) measuring the corrosion rate of the separated water; and, (5) adjusting the flow rate of the treatment chemical used in step (2) to provide sufficient treatment chemical to substantially reduce the corrosion occurring downhole in the borehole.

Claim 9

The method of claim 6, and further including the step of: (6) measuring the conductivity of the produced fluid before and after carrying out step (5); and, (7) adjusting the flow rate of the separated water in step (2) to obtain a mass flow of sufficient value to enable the mixture to gravitate down the annulus and into the production tubing prior to the treatment chemical separating from the water.

Claim 10

The method of claim 4 wherein the separated water flow rate and the treatment chemical flow rate is adjusted according to the following additional steps: (4) measuring the conductivity of the produced fluid to determine the time interval required for the mixture to reach the tubing interior; (5) adjusting the flow rate of the separated water in step (2) to obtain a mass flow of the mixture which enables the mixture to gravitate down the annulus and into the production tubing prior to the treatment chemical and water separating from one another; (6) measuring the corrosion rate of the separated water; and, (7) adjusting the flow rate of the treatment chemical used in step (2) to provide sufficient treatment chemical to substantially reduce the corrosion occurring downhole in the borehole.

Claim 11

The method of claim 4 wherein the separated water and treatment chemical are admixed according to the following steps: (4) flowing the water at a rate which translocates the chemical from the top of the annular fluid column down through the separated hydrocarbons within an interval of time which is less than the length of time required for the treatment chemical of the mixture to significantly disperse into the separated hydrocarbons contained within the upper annular area of the wellbore; and, (5) flowing the treatment chemical at a rate which controls the downhole corrosion rate.

Claim 12

Apparatus for treating oil wells with corrosion inhibitor chemical, comprising: a separator, means for measuring the conductivity of produced fluid, means for measuring the corrosion rate of produced water, a mixing means by which water and treatment chemicals are admixed together to provide an intimate mixture of chemical and separated well water; means connecting said separator to the well head for separating produced hydrocarbons from at least part of the produced water; a source of inhibiting chemical; means connecting said separated water to said mixing means; means connecting said source of inhibitor chemical to said mixing means; and means connecting said mixing means to the upper annular area of the oil well; means controlling the rate of chemical flow in proportion to the corrosion measurement of the produced fluid to thereby provide a concentration of inhibitor chemical in the well which effectively controls the corrosion rate downhole in the borehole; and, means controlling the rate of flow of water through the mixing means proportional to the conductivity measurement so that a mass flow rate of mixed chemical and water is supplied to the annulus in an amount to force the mixture down through the hydrostatic head of the wellbore during a time interval which is less than the time interval required for most of the chemical to separate from the water of the mixture.

Claim 13

Apparatus for treating oil wells with corrosion inhibitor chemical, comprising: a separator, means for measuring the conductivity of produced fluid, means for measuring the corrosion rate of produced water, a mixing means by which water and treatment chemicals are admixed together to provide an intimate mixture of chemical and separated well water; means connecting said separator to the well head for separating produced hydrocarbons from at least part of the produced water; a source of inhibiting chemical; means connecting said separated water to said mixing means; means connecting said source of inhibitor chemical to said mixing means; and means connecting said mixing means to the upper annular area of the oil well; means controlling the rate of chemical flow in proportion to the corrosion measurement of the produced fluid to thereby provide a concentration of inhibitor chemical in the well which effectively controls the corrosion rate downhole in the borehole; and, means controlling the rate of flow of water through the mixing means proportional to the conductivity measurement so that a mass flow rate of mixed chemical and water is supplied to the annulus in an amount to force the mixture down through the hydrostatic head of the wellbore during a time interval which is less than the time interval required for most of the chemical to separate from the water of the mixture.

Claim 14

The apparatus of claim 10 wherein said corrosion inhibitor chemical is selected from the group consisting of; oil soluble filming inhibitors and water soluble filming inhibitors.

Claim 15

The apparatus of claim 10 wherein said mixing means and the means for controlling the flow through the mixing means is a motor driven pump apparatus.

Claim 16

In a wellbore which produces hydrocarbons comingled with water up through a tubing string, with there being a lower borehole annulus containing a mixture of water and hydrocarbons, and an upper borehole annulus containing separated hydrocarbons, a process for controlling the corrosion rate of the borehole; comprising the steps of: (1) producing the well and separating at least part of the water from the produced fluid; (2) measuring a parameter of the produced fluid related to the presence of treatment chemical contained therein; (3) measuring a parameter of the produced fluid related to the separated water; (4) intimately admixing a quantity of treatment fluid with a quantity of the separated water and flowing the resultant mixture into the borehole annulus above the column of fluid contained within the wellbore annulus; (5) using the measurement of step (3) to adjust the quantity of treatment fluid in step c4) to a value which controls the corrosion rate of the wellbore; (6) using the measurement of step c2) to determine the length of time required for the mixture to travel through the fluid contained in the annulus; and, (7) adjusting the rate of flow of the quantity of water in step (4) to a value which causes the translocation of the mixture through the hydrocarbon part of the fluid column to occur before the mixture of water and treatment chemical separate to the extent which precludes corrosion control downhole in the borehole.

Claim 17

In a wellbore which produces hydrocarbons comingled with water up through a tubing string, with there being a lower borehole annulus containing a mixture of water and hydrocarbons, and an upper borehole annulus containing separated hydrocarbons, a process for controlling the corrosion rate of the borehole; comprising the steps of: (1) producing the well and separating at least part of the water from the produced fluid; (2) measuring a parameter of the produced fluid related to the presence of treatment chemical contained therein; (3) measuring a parameter of the produced fluid related to the separated water; (4) intimately admixing a quantity of treatment fluid with a quantity of the separated water and flowing the resultant mixture into the borehole annulus above the column of fluid contained within the wellbore annulus; (5) using the measurement of step (3) to adjust the quantity of treatment fluid in step c4) to a value which controls the corrosion rate of the wellbore; (6) using the measurement of step c2) to determine the length of time required for the mixture to travel through the fluid contained in the annulus; and, (7) adjusting the rate of flow of the quantity of water in step (4) to a value which causes the translocation of the mixture through the hydrocarbon part of the fluid column to occur before the mixture of water and treatment chemical separate to the extent which precludes corrosion control downhole in the borehole.

Claim 18

The method of claim 13 wherein the time interval required for the treatment chemical to travel from above the ground, downhole to the lower end of the borehole, and back to the surface of the earth is 4-8 hours.

Claim 19

The method of claim 13 wherein the treatment chemical and the water are mixed together sufficiently so that appreciable separation thereof requires 6-8 hours, and, the flow rate of the water in the mixture is increased to cause the treatment chemical to flow into the borehole, and back up to the surface of the ground in less than 6-8 hours.

Claim 20

The method of claim 13 wherein the residual inhibitor is measured by analyzing the separated water.

Claim 21

The method of claim 10 wherein the inhibitor is selected from the group comprised of: oil soluble filming inhibitors and water soluble filming inhibitors; and, the treatment chemical and the water are mixed together sufficiently so that appreciable separation thereof requires 6-8 hours, and, the flow rate of the water in the mixture is increased to cause the residual treatment chemical to flow through the borehole and back up to the surface of the ground in less than 6-8 hours.