Processes For Secondarily Recovering Oil

Abstract

A secondary recovery process for oil wet sands using underground combustion to produce a makeup effluent gas containing carbon dioxide. The effluent gas is mixed with a wet casing head gas enriched by ethane plus hydrocarbons and the mixture is injected into the reservoir at relatively low pressures to promote oil flow toward a production well. The enriched injected gas mixture reduces the oil's adhesion to the sand and promotes oil flow. The production well is maintained under a vacuum pressure so as to pull the injected mixture through the formation. The mixture is recovered and reinjected. The production well vacuum pulls ethane plus hydrocarbons from the oil at the formation face to enrich the casinghead gas.

Description

The present invention is directed to improvements in processes for secondary recovery of oil.

A number of secondary recovery processes for the recovery of oil from oil bearing sands are known. In the past water flooding techniques have been utilized in order to drive oil towards a producing well. "Fire flood" processes are also known in which combustion is initiated underground in order to create pressure while reducing viscosity of oil and adhesion of oil to the reservoir sand to thereby promote flow of the oil toward a producing well. In some cases carbon dioxide with or without hydrocarbon gases has been utilized in connection with water flood processes to promote flow of oil towards a recovery well. It has also been known to utilize butane, propane, and equivalent hydrocarbon gases under relatively high pressures, for example, exceeding 2,000 psi in a water or gas mixture for driving oil from the oil bearing sands to a producing well. Air injection processes which produce oxidation without ignition and low pressure gas injection techniques have also been proposed in secondary recovery processes.

Water flooding techniques can be economically effective in the case of water wet sands. However, in the case of oil wet sands the water flooding technique is usually ineffective to free the oil from the formation and drive it to a producing well with satisfactory economy. The term "oil wet sands" as used herein is intended to refer to those sands in which oil is found on the face of the sands and in formations having an absence of formation water. Use of carbon dioxide in water flooding techniques increases equipment corrosion to the extent that the economies of the overall operation may be unsatisfactory. Fire flood techniques are satisfactory in some cases with oil wet sands but in some cases a fire flood operation is not economical, because of the extent and intensity of burning necessary to produce a given amount of oil. The use of injected gas mixtures at high pressures has the disadvantage that the gases so used then become quite dense or may become liquid at the high pressures, with the result that the high pressures utilized with gas injected mixtures usually require plugging of those wells of the field which are not operative in the process in order to maintain the high pressures and to avoid contamination of the atmosphere. Air injection is sometimes satisfactory but this process does not reduce oil adhesion as much as fire flood or carbon dioxide processes. Low pressure gas injection can be satisfactory to promote oil flow in some cases, but the low pressures may not be sufficient to drive oil to a production well in some formations and the gas supply may not be sufficient for production.

With the foregoing in mind, the present invention is directed to a new and improved process for secondary recovery of oil from formations having oil wet sands, and in those instances where a casing head gas which is rich in ethane plus hydrocarbon or the equivalent is present in suitable quantities at the site of the recovery operation.

The major purposes of the invention are to provide a method for secondary recovery of oil from oil wet sands while utilizing relatively low working pressures for gas injection with the result that over a prolonged period of time plugging of the wells not actually involved in the operation and in the field being worked is unnecessary; and in such a way that pollution of the surrounding atmosphere is avoided, all while increasing the recovery of oil at an overall cost less than that which can be obtained with known fire flood, or a water flood, carbon dioxide, air injection or gas injection processes.

These and other purposes will appear from time to time in the course of the ensuing specification and claims when taken in conjunction with the accompanying drawing, in which:

FIG. 1 is a diagram of the process constituting the present invention.

In accordance with the present invention, combustion is initiated underground in accordance with known fire flood techniques. The combustion, however, is not initiated for the main purpose of driving oil towards a recovery well but rather for the purpose of producing an effluent gas containing carbon dioxide and other constituents which are then mixed with a wet casing head gas and reinjected for the purpose of promoting flow of oil towards a producing well. Oil and injected gas are then separately recovered from the producing well, whereupon the recovered part of the injected gas can be recycled.

As shown in FIG. 1, for example, the numeral 10 designates a thermal injection well in which a suitable compressor or the like 11 delivers air to the bottom of the well for the purpose of controlling the combustion. The combustion may be initiated by means of any known system for initiating a fire flood operation. A fire flood as designated generally at 12 produces heat and pressures which are effective in driving the products of combustion and some oil toward an effluent well generally designated at 13. Temperatures at the flame front may be 600.degree. F. or greater. The casing of effluent well 13 is maintained at or near atmospheric pressure and the products of combustion from the fire in the form of effluent gases pass up the casing 14 of the well. Some oil may be driven to the oil inlet of well 13 and this oil may be recovered through the tubing 15 within the well.

Pumping facilities (not shown) may be utilized to withdraw the oil through the tubing 15.

The oxygen in the air pumped underground to the fire is converted to an equivalent volume of CO.sub.2 and this conversion may be as much as 85 percent efficient. Heat from the fire volatilizes light components of the oil in the immediate vicinity and the volatilized components are in the form of rich vapors until they partially condense as they are driven away from the burn area. Some of the partially condensed components then go into solution with other formation oil and others go into the mixture of the combustion gas. The recovered vapors usually include an ethane plus component; thus the effluent gas is a mixture enriched by ethane, heavier hydrocarbons and carbon dioxide for reinjection.

The heavier hydrocarbons are butane, propane, etc. The term "ethane plus" as used herein refers to the heavier hydrocarbons in a gas and designates the ethane and heavier hydrocarbons in the gas.

Since the main purposes of the thermal injection well is not to drive oil towards the well 13 but rather to produce an enriched product of combustion gas, the volume of oxygen or air supplied to the injection well 10 may be considerably lower than that used in normal fire flood processes. In normal fire flood processes the intention is to create an intensity of burning such as to produce temperatures and pressures which cause maximum oil flow. Nonetheless, in the process of this invention, any oil recovered from the effluent well 13 is of value and helps to pay for the cost of operation.

It should be understood that one or more effluent wells 13 may be utilized. They may be advantageously situated in surrounding relation to the thermal injection well 10. It should also be understood that control of the underground combustion in processes of this type is effected through the air supply control. By shutting off the air supply, the combustion may be extinguished eventually. The degree of combustion may also be increased by increasing air supply.

In accordance with the invention, the air supply is controlled so as to produce carbon dioxide in the effluent mixture of gases on the order of 16 to 25 percent by volume of the total effluent gas mixture. The following Table No. I shows typical gaseous mixtures by volume in five effluent gas wells surrounding a thermal injection well:

TABLE I

Comp. 1. 2. 3. 4. 5. Avg. __________________________________________________________________________ Oxygen 3.30 4.00 4.03 1.57 1.38 2.86 Nitrogen 69.88 72.03 67.93 77.20 76.68 72.74 Methane 0.33 0.20 0.56 0.10 0.18 0.27 Carbon 17.98 17.64 20.09 18.23 18.63 18.51 Dioxide Ethane 8.51 6.13 7.39 2.90 3.13 5.62 Plus __________________________________________________________________________

In further accordance with the invention, a wet casing head gas, which is available from producing wells at the field being operated, is utilized for mixture with the effluent gas and for reinjection into the formation. Casing head gas is that gas normally present in the casing of a well and which is sometimes recovered for sale or other use. It normally has little or no carbon dioxide therein. The casing head gas is mixed with the effluent gas from the well 13. Suitable piping connections pass the mixture to a compressor 17. Suitable valves and controls, diagrammatically indicated at 18 and 19, may be used to control the relative volumes of the two gases in the mixture before delivery to the compressor 17. Compressor 17 delivers the mixture to a second injection well 20. Producing wells are diagrammatically represented at 21. The wells 21 are the source of the casing head gas.

The producing wells 21 surround the gas injection well 20. Oil is pumped from the production wells 21 through the tubing of the wells to conveniently located stock tanks. Gas is recovered from these wells by pulling a vacuum on the casing of the wells which causes the gas to be separated from the oil at the formation face and be conducted up the casing and then passed to the compressor 17 for injection. The vacuum on the casing of the production wells 21 is on the order of -5 to -7.5 psi or 10-15 inches mercury vacuum. The vacuum which is maintained on the casing of each production well has the effect of pulling ethane plus hydrocarbons out of the oil at the point of separation, thereby enriching the gas and making it into what may be termed a "wet" casing head gas. The invention contemplates a casing head gas of this type which contains an average of 6 gallons or more, per thousand cubic feet of gas, of 26 lb. Reid vapor pressure at 70.degree. F., gasoline content which is in a vapor phase in the gas.

The mixture injected into the well 20 thus has a beneficial carbon dioxide component which results mostly from the effluent gas as well as a beneficial ethane plus component.

Approximately one quarter of the gas mixture injected into the formation from the injection well 20 is lost from various causes such as a portion of it going into solution with unproduced oil while another portion repressurizes the formation and maintains it under pressure. The remaining part of the injected gas mixture, together with some gas components from the recovered oil as aforementioned, is recovered at the formation face by the casings of the production wells. The effluent gas, in addition to supplying the beneficial effect of CO.sub.2, as well as some ethane plus component to the gas mixture, acts as a source of makeup gas to maintain a total volume of gas mixture injected per day. The carbon dioxide component in the mixture is believed to act in a manner equivalent to the ethane plus hydrocarbons in enriching the gas for oil recovery purposes.

In cold weather some of the gas from the producing wells may condense into liquid drops which may be caught in surface drips or traps in the piping leading to the compressor blank.

The control of the gas mixture is maintained so that there is a greater amount of ethane plus component in the gas by volume than the carbon dioxide.

In a typical example, the casing head gas is mixed with the relatively dry effluent gas in the proportion of three parts of casing head gas and one part of effluent gas by volume, while each injection well receives 50-150 MCF of the gas mixture per day. The actual total volume of gas injected per well per day will depend upon the thickness of the sand layer in the formation. Usually, an injected volume of 50 to 100 MCF of the mixture per well per day is a practical working volume. Preferably the mixture is such that there are on the order of two parts of ethane plus to one part of carbon dioxide in the mixture. The ethane plus component in the mixture is on the order of 20 to 35 percent of the total mixture by volume, while the carbon dioxide is on the order of 10 to 20 percent of the total mixture by volume. The actual percentage of ethane plus gas component in the casing head gas as well as the actual percentage of carbon dioxide in the effluent gas will vary from time to time. The gases are analyzed periodically and the valves controlled to control the relative amounts of carbon dioxide and ethane plus in the mixture supplied to the compressor 17 in the amounts stated.

It may be noted that the casing head gas or the effluent gas is not suitable for injection at high pressures because of the tendency of the ethane plus and carbon dioxide components to liquefy at high pressure. However, the compressor 17 is operated at relatively low pressures. These low pressures are on the order of 125 lbs. psi for delivery into the gas injection well diagrammatically represented at 20 in the drawings. The actual injection pressure may vary somewhat but the pressure developed by the compressor 17 as well as the temperature of the injected gas mixture should be such that the mixture is injected in a gaseous state. Injection well 20 is located with sufficient proximity to the production well or wells 21 so that the injected gas mixture drives the oil in the reservoir toward the production well where it may be withdrawn through the pipe 22 of the well. Suitable pumping facilities (such as rod pumps) may be used to withdraw the oil. The vacuum together with the injection pressure creates a "push-pull" effect and serves to drive and pull the gas through the oil in the reservoir between the second injection well 20 and the production well 21. The vacuum also pulls from the oil hydrocarbons heavier than ethane. The withdrawn gas is then delivered through suitable piping 23 and valve controls 24 for recycling through compressor 17 to the second injection well 20. The withdrawn gas is mixed with the effluent gas as may be necessary to maintain the injection mixture in the volumetric proportion stated and in the total volume per day as stated. A typical gas analysis withdrawn from five production wells is shown in the following table II.

TABLE II.

Comp. Mol % -1 -2 -3 -4 -5 Avg. __________________________________________________________________________ Oxygen .06 .02 .08 .02 .04 .05 Nitrogen 47.67 50.86 52.24 50.14 51.02 50.39 Methane 6.54 9.68 8.38 8.27 9.36 8.45 Carbon 14.11 15.16 16.04 16.25 15.48 15.41 Dioxide Ethane 31.62 24.28 23.26 25.32 24.10 25.72 Plus __________________________________________________________________________

The components shown in Table II illustrate the component parts of the mixture which is pulled through the formation together with some components which are added to the mixture from the oil in the formation from time to time. The carbon dioxide content is due primarily to that which results from the added effluent gas while the ethane plus components are due for the most part to the gas originally within the formation being worked.

The process is relatively inexpensive because the gas materials used are available at the site and because the low pressures require less expensive compressor operation than that required in high pressure techniques. Use of the process enables continuous use of gas native to the formation. The corrosive effect of CO.sub.2 is minimized because the process is intended for oil wet sands rather than water wet sands. The volume of combustion air supplied may be less than that in normal fire flood processes.

The process recovers oil more efficiently than other processes because of the tendency of the enrichers (carbon dioxide and ethane plus hydrocarbons) to partially go into solution with oil in the formation, thereby reducing the oils adhesion to the sand grains and making the oil susceptible to being swept by the low pressure injected gas to a producing well bore.

Claims

I claim:

1. The method of secondary recovery of oil from a reservoir having oil wet sands including the steps of producing a fire flood in a reservoir adjacent a thermal injection well, withdrawing products of combustion from the flood so formed through a second well, mixing the products of combustion with wet casing head gas containing ethane plus gas, with the resultant mixture having on the order of 20 to 35 percent ethane plus gas by volume, injecting the gas mixture thus formed into a second injection well in proximity to one or more production wells in the reservoir, withdrawing the injected gas from the production well, withdrawing oil from the production well, and recycling the withdrawn gas to the second injection well.

2. The method of claim 1 wherein the combustion is controlled and the mixture of casing head gas with the products of combustion is controlled so that the injected gas mixture has on the order of approximately two parts ethane plus to approximately one part of carbon dioxide.

3. The method of claim 2 wherein the gas mixture injected in the second injection well is on the order of 50,000 to 150,000 MCF per day.

4. The method of claim 1 characterized by and including the step of additionally withdrawing oil from the second well.

5. The method of secondary recovery of oil from a reservoir having oil wet sands including the steps of mixing an exhaust gas, containing carbon dioxide and other gases resulting from combustion of a hydrocarbon oil, with a wet casing head gas having an ethane plus gas component, controlling the relative volumes of carbon dioxide and ethane plus in the mixture so that approximately two parts ethane plus to one part carbon dioxide are present in the mixture, injecting the controlled mixture in a reservoir well at pressures and temperatures such as to maintain the mixture during injection as a gaseous phase for driving oil in the reservoir toward a production well, maintaining the production well under vacuum, and separately withdrawing oil and gas from said production well.

6. The method of claim 5 wherein the withdrawn gas is recycled through the injection well at said pressures and temperatures.