US3376929A - Modified in situ combustion well stimulation - Google Patents

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April 968 A. R. HAGEDORN 3,376,929

MODIFIED IN SITU COMBUSTION WELL STIMULATION Filed Nov. 17, 1965 TEMPERATURE RADIAL DISTANCE FROM WELLBORE INVENTOR. A LTON R. HAGEDORN,

ATTORN EY- United States Patent 3,376,929 MODIFIED 1N SITU COMBUSTION WELL STIMULATION Alton R. Hagedorn, Houston, Tex., assignor to Esso Production Research Company Filed Nov. 17, 1965, Ser. No. 508,337 3 Claims. (Cl. 166-39) ABSTRACT OF THE DISCLOSURE A short-term, cyclic well stimulation process in which an oxidizing gas is injected into a subsurface hydrocarbon-containing formation, and a portion of the resident formation hydrocarbons is burned to raise the temperature of the formation rock remote from the wellbore, thereby reducing the viscosity of the remaining reservoir hydrocarbons. Injection of oxidizing gas is then halted and water is injected into the formation in sutlicient amounts to lower the temperature in the formation to below the cracking temperature of the formation hydrocarbons and to propagate heat further into the formation. Injection of water is halted and formation hydrocarbons are produced through the production well by natural formation energy and/or by pumping a desired period of time, provided only that such production period does not exceed the time in which the formation temperature would fall below the spontaneous ignition temperature of the formation oil upon resumption of the injection of oxidizing gas. The above steps of injecting oxidizing gas, injecting water, and producing hydrocarbons are then repeated.

The present invention concerns an improved method of well stimulation. More particularly, the present invention relates to improvements in oil well stimulation by underground or in situ combustion.

Well stimulation by in situ combustion refers to a wellknown process in which a portion of the underground hydrocarbons in the reservoir or formation, particularly heavy viscous oils, are burned in place to provide high temperatures and heat and thereby cause a reduction in viscosity of the formation hydrocarbon oil which is adjacent the burned-out interval or which enters the burnedout interval. In such a process an oxidizing gas, such as air or a mixture of air and oxygen or other gases capable of sustaining combustion of the formation hydrocarbons, is introduced into the subsurface formation through the production wellbore. The combustible mixture in the formation is ignited in any desired manner, as by electric borehole heaters or chemical catalysts, such as phosphorous, triethylborane, or linseed oil. The oxidizing gas is continuously supplied to the formation to maintain combustion of the subsurface hydrocarbons, The amount of oxidizing gas injected may range from 60 to 180 million cubic feet over a period of one to three months. When the desired quantity of heat has been generated by such combustion, injection of the oxidizing gas is discontinued and burning ceases.

Prior to returning the well to production, a bottom hole choke is preferably installed because of the hazardous combustible gas mixture (20 percent oxygen) initially produced from the formation. Thereafter, the well is immediately returned to production of hydrocarbons through the bottom hole choke. After producing for several weeks or months until the reservoir pressure is no longer capable of sustaining production, a pump and rods are run into the well to initiate artificial lift of the oil production. Then, when production diminishes or ceases and it is desired to again stimulate the well, the a foremcntioned steps are repeated.

Although this conventional process successfully stimulates oil production, it has several limitations, the foremost of which is high operating costs. The principal costs of operation are (1) preparation of the well for air injection; (2) use of a catalytic or other igniter; (3) compressor operation for 30 to days of air injection; (4) bottom hole choke installation prior to flow-back; and (5) running pump and rods into a well several weeks after burning to initiate artificial lift of the oil production.

In order to reduce the high operating costs, modifications in such procedure have been introduced which involve the use of short-term cycles of air injection and production. For example, after injecting about 14 million cubic feet of air into the well and burning the formation hydrocarbons for a relatively short period of time (e.g., seven days at 2.0M c.f./d), the well is shut-in for substantially the same period of time. The shut-in period is known as the soak period. During this time, the hot combustion gases and any unburned oxygen occupying the burned zone migrate up-structure and the burned zone is resaturated with formation oil. Following the seven-day soak period, the well is returned to production and produced for several weeks or months until reservoir energy no longer sustains flowing production. Then, air injection is resumed and the entire cycle is repeated.

A disadvantage of the short-term cycle process results from the thermal cracking of the crude oil hydrocarbons during flow-back through the burned zone which remains considerably hotter immediately adjacent to the wellbore for the short, more frequent burns than for longer, less frequent ones Cracking of the hydrocarbons causes redeposition of coke in the formation as the hydrocarbons flow through the heated region to the well. The process of the present invention overcomes this disadvantage through the injection of suflicient water following the air injection and burning step to lower the temperature of the formation to a value below the cracking temperature of the crude oil or formation hydrocarbons. Cracking temperatures of crude oils are in the range of about 680-700" F. Water injection is continued until the maximum temperature in the formation is about 600 F. The rest of the formation, then, is below 600 F. and no cracking and no coke deposition occurs. Water injection at this stage in the process not only prevents redeposition of coke in the formation as the oil flows through the heated region during the production phase of the cycle, it also eliminates deposition of coke on liners, tubing, etc. Coke deposition in any of these locations would result in reduction of the wells productivity.

A further advantage attained by injection of water at this stage of the process is that heat is propagated farther int-o the formation by means of the steam and hot water generated as the water passes through the region heated in the air injection-combustion step. The larger heated radius results in increased well productivity.

Further, the air which remains in the burned-out region after termination of air injection is displaced through the burning front by the injected water, thus eliminating the hazards of producing a combustible mixture of hot hydrocarbons and oxygen. In addition, suitable reducing agents, such as sodium sulfite, sulfurous acid, water-soluble ferrous salts (e.g., ferrous chlorate or sulfate), water-soluble stannous salts, hydro-gen sulfide, etc., may be added to the injection water to function as oxygen scavengers to remove any oxygen trapped by the invading water front.

Briefly, then, the method of the invention includes the steps of: igniting the hydro-carbons in a subsurface hydrocarbon-containing reservoir by conventional means (heater or catalyst) only if spontaneous ignition is not possible; injecting an oxidizing gas (e.g., air) into the reservoir through a production well and burning a portion of the resident reservoir hydrocarbons to raise the temperature of the reservoir rock remote from the wellbore, thereby reducing the viscosity of the remaining reservoir hydrocarbons; halting injection of said oxidizing gas; then injeoting water into the reservoir in sufiicient amounts to lower the temperature in the reservoir to below the cracking temperature of the reservoir hydrocarbons and to propagate heat farther into the reservoir; halting injection of water into the reservoir; roducing said reservoir hydrocarbons through the production well by natural reservoir energy and/ or by pumping a desired period of time provided only that such production period does not exceed the time in which the reservoir temperature would fall below the spontaneous ignition temperature (e.g., below ZOO-250 F.) of the reservoir hydrocarbons upon resumption of injection of oxidizing gas; and then repeating the above steps of injecting oxidizing gas, injecting water, and producing.

Following the water injection step and prior to the production of hydrocarbons, the well may be shut-in to permit hot combustion gases and any unburned oxygen occupying the burned zone to migrate up-structure and to resaturate the burned zone with formation hydrocarbons.

The sole figure is a graph of temperature versus radial distance from the wellbore.

As shown in the figure, curve 1 depicts qualitatively the temperature distribution which exists in the reservoir following a period of air injection and curve 2 shows the redistribution of the temperature in the reservoir as a result of the water injection. Each formation-burning operation may burn a radius of 20 to 35 feet surrounding the wellbore.

The short period of air injection, which may range from about four to ten days at an injection rate of 2 million cubic feet per day, is used to generate a large quantity of heat in the region near the wellbore. The short shut-in period permits heat to dissipate and steam to condense so that large amounts of energy are not removed in the form of steam when the well is put back on production. Air or oxidizing gas is re-injected into the reservoir while some residual temperature increase is still present in the formation in order to obtain spontaneous ignition of the reservoir hydrocarbons, which eliminates the problems of ignition by conventional techniques.

Having fully described the method, objects, advantages and operation of my method, I claim:

1. A method of short-term, cyclic well stimulation comprising the steps of:

(a) injecting an oxidizing gas into a subsurface hydro- 4 carbon-containing reservoir through a production well and burning a portion of the resident reservoir hydrocarbons to raise the temperature of the reser- 'VOll' rock remote from the wellbore thereby reducing the viscosity of the remaining reservoir hydrocarbons;

( b) halting injection of said oxidizing gas;

(0) injecting a sufiicient amount of water into said reservoir to lower the temperature of the reservoir to a value below the cracking temperature of said reservoir hydrocarbons;

(cl) halting injection of said water;

(e) producing said reservoir hydrocarbons through the production well until reservoir energy no longer sustains flowing production;

('f) halting production of the reservoir hydrocarbons; and then repeating the above recited cycle of steps (a)-(-f) successively, the ambient reservoir temperature prior to injection of said oxidizing gas in each repeated cycle of steps remaining sufficiently high to achieve spontaneous ignition of said reservoir hydrocarbons upon resumption of the injection of said oxidizing gas.

2. A method as recited in claim 1 in which following the step of halting injection of water in each cycle, the well is shut-in for a period of time to permit hot combustion gases and any unburned oxygen occupying the burned zone to migrate tip-structure and to resaturate the burned zone with reservoir hydrocarbons.

3. A method as recited in claim 2 in which said oxidizing gas is air and in each of said cycles said air is injected for a period of from about four to ten days at an injection rate of about 2.0 million cubic feet per day.

References Cited UNITED STATES PATENTS 3,129,757 4/1964 Sharp 166-11 3,171,482 3/1965 Simm 166-39 3,172,472 3/1965 Smith 16638 3,179,167 4/1965 Strange et a1 16611 3,179,169 4/1965 Cline et al 166- 38 3,180,412 4/1965 Bednarski et al 166--l1 3,259,185 7/1966 Gates 166l1 3,259,186 7/ 1966 Dietz 16611 3,266,569 8/1966 Sterrett 166-2 3,285,336 11/1966 Gardner 16611 STEPHEN J. NOVOS'AD, Primary Examiner.

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