Method of treating oil wells

June 9, 1964 τ. τ. graham 3,136,359

METHOD OF TREATING OIL WELLS

Filed Aug. 11, 1961 ⁴ Sheets-Sheet 1

Producing WetACfi5c

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54· ) Producing Weuu

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June 9, 1964

T. T. GRAHAM

METHOD OF TREATING OIL WELLS

3,136,359

Sheets-Sheet 2

1961

Filed Aug. 11.

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June 9, 1964

T. T. GRAHAM

METHOD OF TREATING OIL WELLS

3,136,359

Filed Aug. 11, 1961

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Sheets-Sheet 3

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IOOO P.S.1.-Va.uje Cvoseo

900

800

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Thomas T. GraLhcun

June 9, 1964

T. T. GRAHAM

METHOD OF TREATING OIL WELLS

3,136,359

Filed Aug. 11, 1961

Sheets-Sheet 4

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Producing Well

Injection Well

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Thomas T. Gra.ha.rn

INVENTOR.

BY

3,136,359

Patented June 9, 1964

United States Patent Office

136,359

METHOD OF TREATING OIL WELLS Thomas T. Graham, Box 8171, Southmore Station, Houston, Tex.

Filed Aug. 11,1961, Ser. No. 131,010

Claims. (Cl. 166—4)

This invention relates to a method of treating wells, and more particularly to a process for extracting difficultly recoverable oil from oil-bearing formations.

This application is a continuation in part of my copending application Serial No. 672,829 filed July 18, 1957, now abandoned which is a continuation-in-part of my prior application Serial No. 404,255 filed January 15, 1954, now abandoned.

The invention finds particular application in connection with abandoned or poorly producing oil fields, such as oil fields wherein much or all of the freely recoverable oil has been removed from the wells by pumping, gas lift, or the like, and additional means must be employed to bring further quantities of oil to the surface.

In practicing this invention it is preferred to provide heat for the formation at the surface, but if desired this invention can employ the in situs combustion principle.

For maximum recovery in secondary recovery operations a driving force should be applied to the formation to drive oil into recovery wells, and the formation should be heated to reduce the viscosity of the oil. The materials selected for providing the drive and heat must be carefully selected and controlled. Preferably, compressed air is used to provide both pressure and heat to the formation. However, if the air is dry, clogging of the formation results, and therefore compressed air is not satisfactory when used alone. Moisture should be added continuously to the formation to prevent clogging, and for the additional reason that better recovery is possible where some water is present in the formation. Water in liquid form is not satisfactory as the permeability of most formations for water is relatively low. Therefore, steam is used to provide moisture.

It is well known when air is injected into a formation at elevated temperatures, an exothermic reaction sometimes occurs, known in the art as “in situ combustion or fire. In the past no method has been known for controlling this combustion, as there is ample air in the formation to support combustion. While combustion generates pressure and heat which are desirable, elevated temperatures are also present which result in coking and otherwise stopping of the pores of the formation. By this invention this exothermic reaction is readily detected shortly after it begins and is either controlled by permitting it to be carried out at a low temperature, or stopped completely by the application of sufficient steam to prevent the reaction from being carried out at a high temperature, or prevent the reaction from occurring at all, as desired. By this invention the injection well and surrounding formation are also kept clear of liquids which impede the movement of moist gas into the formation.

An object of this invention is to provide a method of secondary recovery of oil in which hot air under pressure may be used to drive oil from a formation and any in situs combustion readily detected and controlled.

Another object is to provide a method of secondary recovery in which hot air under pressure may be used to drive oil from a formation and any in situs combustion readily detected and extinguished.

Another object is to provide a method of secondary recovery in which hot air and steam under pressure may be used to drive oil from a formation, condensate periodically removed from the well to prevent its interference with the action of the air and steam, and any in situ combustion readily detected and controlled.

Another object is to provide a method of secondary recovery in which hot gas and steam under pressure may be used to drive oil from a formation, and the well and formation adjacent the well bore kept open.

Another object is to provide a method of secondary recovery in which gas and steam under pressure are used to drive oil from a formation in which the formation is periodically refluxed to prevent the formation from clogging up. ....

Another object is to provide a method of secondary recovery in which hot air under pressure and steam are injected into a formation, the injection well and formation periodically refluxed to remove condensate from the well, the formation refluxed to keep it open, and the tempera15 ture of the effluent determined to detect the presence of fire in the formation, any fire detected controlled or extinguished, if desired, by varying the rate of steam injected in the injection well, and recovering oil from a producing well spaced from the injection well.

Other objects, features and advantages will be apparent from the specification, the drawings and the claims.

In the drawings, wherein an illustration of this invention is shown, and wherein like reference numerals indicate like parts:·

FIGURE 1 is a diagrammatic plan view illustrating the preferred arrangement of injection well and producing wells in accordance with this invention;

FIGURE 2 is a diagrammatic plan view illustrating a preferred arrangement of apparatus for carrying out the 30 methods of this invention.

FIGURE 3 is a fragmentary sectional view through a well showing the portion of the well which penetrates a surrounding oil-bearing formation and illustrating a portion of the manner in which the method of this invention 35 is carried out;

FIGURES 4A, 4B and 4C are schematic views in vertical section through an injection well showing the refluxing action of this method and illustrating the well in FIGURE 4A before refluxing, the well in FIGURE 4B 40 at the beginning of the refluxing action showing the condensate in the lower end of the well being raised, and in FIGURE 4C the end of the refluxing action in which the condensate is being driven from the well;

FIGURE 5A is a schematic view illustrating the pres45 sures present in the well and surrounding formation during injection;

FIGURE 5B is a view similar to FIGURE 5A showing the pressures present in the well during refluxing;

FIGURE 6 is a graph plotting time against pressures ₅₀ showing bottom hole pressure during injection and refluxing; and,

FIGURE 7 is a diagrammatic view in section showing gas being injected into the well and oil being driven toward a producing well from which it is recovered.

In practicing the preferred form of this invention air and steam under pressure and at elevated temperature is injected into an injection well reaching down to a producing formation. Oil is recovered from one or more producing wells spaced from the injection well.

_fin Periodically a tubing in the injection well is opened for a short period of time to permit pressure in the bottom of the well to drive up through the tubing and out at the surface any liquids which have accumulated in the bottom of the well. This feature of the invention has several resulting advantages. If liquids remain in the bottom of the well they interfere with the action of the injected hot gases and steam as the formation will have a much lower permeability for liquids than for vapors. A second advantage is that by opening the tubing to a low, preferably atmospheric, pressure, reverse flow is obtained across the ‘° formation face and the adjacent areas of the formation to open up the formation and maintain the high permeabil8,136,359 . ³ ity for vapors. A third advantage is that the temperature of the effluent material will indicate the presence of fire in the formation. After the system has been in practice for some time the temperature in the bottom of the injection well will be such that little or no liquids will accumulate in the bottom of the well. At this time the refluxing action keeps the formation open and the face of the formation clean, as well as giving an indication of the presence or absence of fire in the formation.

When a fire is indicated in the formation, the percentage of steam is preferably increased and the fire extinguished. As soon as the fire is extinguished the steam volume is preferably cut back to prevent the injection into the well of an unnecessary amount of water which, if continued, might result in channeling in the formation.

Where it is desired to permit combustion in the formation, the method is carried out as broadly outlined, and only such volume of steam injected as necessary to prevent runaway combustion, that is at high temperatures.

From what has been said above, it is apparent that, instead of air, inert gas or a gas which will not support combustion may be injected. Where inert gas is injected in accordance with this invention, it will be found that refluxing of the formation and injection well will keep the well and formation open and receptive to the injected gases. Air is preferred for economic reasons.

In secondary recovery systems the injection system must be periodically shut down for repairs. It will be appreciated that the bottom hole temperature will drop and condensate will accumulate in the injection well. Refluxing will clean out the well and adjacent formation and greatly reduce the time necessary to bring the formation back up to the desired temperature and pressure as the condensate which forms in the bottom of the well at lower temperatures and the oil, etc. which drains from the surrounding formation are removed.

Referring now to the drawings in detail for a detailed explanation of the method of this invention, reference is first made to FIGURE 1. Water from a suitable source is delivered by pump 10 to a heater 11 wherein it is converted to steam. Compressed gas is delivered by a pump 12 to heater 11 wherein it is heated to the desired temperature. . The hot gas and steam pass from the heater to the injection well 13 and are injected into the formation. Periodically the injection well is opened to atmosphere or to a reduced pressure to clean out the well and reflux the formation. The effluent from the well has its temperature sensed by thermometer 14. If the temperature is above a selected value, the rate of water delivery by pump 10 will be varied either automatically or manually, as desired, to inject sufficient water to control fire indicated by the elevated temperature. Oil will be recovered from the producing wells indicated at 15α through 15/, inclusive. Production may be had through natural flow is possible, or, if desired, production from the producing wells may be assisted by gas lift, pumps, or the like.

Reference is now made to FIGURE 2 wherein the apparatus is shown more in detail. Water from a suitable source is first passed through filter 16 to filter out solids. The water is then treated in a water-treater 17 to remove additional solids. The softened water is stored in water tank 18 awaiting use. Water is withdrawn from tank 18 by variable volume pump 10 and delivered to heater 11. En route the water is measured in water meter 19 and its pressure is sensed by pressure gauge 21. A back check valve 22 is provided in the line between the pump and heater to prevent back flow.

In the heater the water passes through the preheat coils 23 wherein it is preferably converted into steam.

A suitable gas for use in the system, such as air, is compressed by air compressor 24 to a desired pressure. The compressed air is stored in surge tank 25 which is of sufficient size to provide a source of air at a substantially constant pressure. The air from the surge tank is metered in air flow meter 26. The temperature of the air is de4 termined by thermometer 27 and the air is delivered to heater 11 through a suitable check valve 28 which prevents back flow of air. The pressure of the air is measured by pressure gauge 29. The air is passed through the preheat coil 31 in heater 11 and then mixes with the preheated steam at the junction 32 of the pre-heat coils 23 and 31. The mixture is then further heated in super-heat coils 33 in the heater.

As the hot steam and air leave heater 11, its temperature is determined by temperature controller 33a which automatically controls fuel inlet valve 34 to provide in the heater the required amount of fuel to obtain the desired temperature at the temperature controller 33. From temperature controller 33a the hot gas passes through check valve 35 and control valve 36 to the casing 37 of injection well 13. When the system is first started up it is desirable to vent the gases from the heater until they come up to the desired temperature. For this purpose, the blow-down valve 38 is provided and remains open during normal startup of the system until the gas-fired heater comes up to temperature.

It will be appreciated that suitable chemicals may be injected at any desired point in the system to aid in the recovery of oil from the formation, to inhibit corrosion, etc.

The steam and air will pass down through casing 37 and into the formation as shown in FIGURE 3. As the formation is cold, the steam will quickly condense in the well bore and in the adjacent formation. At least in the early operation of the system, considerable sand and slag may be expected to accumulate in the bottom of the well. After a selected time interval, the tubing 39 of the injection well is opened, preferably to atmosphere, by a quick-opening valve 40. While valve 40 may be manually operated, it is preferred that it be operated by a timer control 41. The effluent from valve 40 is conducted to a suitable pit, separator, or the like, where any hydrocarbons therein may be recovered.

The condition of the well at the time of beginning the reflux action is indicated in FIGURE 4A, and it will be noted that a body of liquid and slag has accumulated in the bottom of the well. If this accumulation of liquid were permitted to continue, it would rise to a high level in the well and require that the hot gas expend a portion of its energy in passing through the liquid. As the formation face would be covered with liquid, it would bo more difficult for the vapors to penetrate into the formation.

When the quick-opening valve 40 is opened, the pressure in the hole drives the slug of liquid and slag up the tubing, as shown in FIGURE 4B, to remove this slug of liquid and slag from the well. The slug of liquid and slag is shown leaving the well in FIGURE 4C, and it will be noted that due to the wide-open tubing and the air pressure available in the casing and the pressure within the formation, that substantially all of the liquid and slag will be removed from the bottom of the hole. After the slug of liquid and slag has passed through valve 40, the valve is closed and conditions will return to those shown in FIGURE 3.

As noted in FIGURE 3 and FIGURES 4A, 4B and 4C, the tubing extends down at least to the oil-bearing formation, and preferably down close to the bottom of the hole. Thus, when the reflux induced by opening of valve 10 occurs, all of the liquid, sand and accumulated solids in the bottom of the well will be blown up the tubing and removed from the well.

An illustrative pressure diagram is shown in FIGURES 5A and 5B. FIGURE 5A indicates 1,000 p.s.i. gas being introduced into tubing 39 to maintain on the face of the formation a pressure of about 950 p.s.i. Of course, the pressure drops with distance away from the well bore as indicated.in FIGURE 5.

FIGURE 5B indicates the pressure situation when the tubing 39 is open for refluxing. The casing pressure at

3,136,359 its upper end will drop to about 950 p.s.i. and the open hole pressure will drop to about 800 p.s.i. Then, as indicated at 42, there will be an annular area about the well and spaced therefrom having an equilibrium pressure of 900 p.s.i Radially out from the equilibrium area there will be present in the formation progressively less pressure. Thus, it will be seen that refluxing or reverse flow of fluid in the formation adjacent the well will occur. This refluxing will tend to keep the formation open and maintain its high permeability for gas, as well as keep the face of the formation open.

By way of example, a field being placed on steam in accordance with this invention may have its injection well or wells refluxed each hour for a sufficient period to remove the liquids and solids from the bottom of the well, which may be about 14 seconds, as illustrated in FIGURE 6. After normal production is obtained and the injection well and surrounding formation heated to a temperature at which little or no steam will condense in the open hole, and most of the liquids in the surrounding formation have been driven away from the injection well, the refluxing action may be drastically curtailed and, for example, refluxing once a day for about 14 seconds may be all that is required.

After an initial warmup, it will be found that the temperature of the injected gas can be raised to the desired level. For instance, it may be raised to a temperature in excess of 400° F. After the injection temperature reaches about 400° F., care must be exercised to avoid the formation catching on fire. For this reason a temperature gauge and controller 43 determines temperature of the effluent. At this time refluxing is preferably carried out very frequently to keep a constant check on the temperature of the effluent from the injection well. If this temperature is noted to climb unduly, this is an indication that the formation is on fire and, in accordance with this invention, the water pump 10 is speeded up to increase the percentage of steam injected into the formation. This may be done automatically by the temperature controller 43 or manually if desired. This increased steam will extinguish the fire. Probably the steam blankets the fire and thus puts it out. In any event, it has been found that combustion may be controlled by steam. After a fire occurs, it is advisable to lower the input temperatures slightly to prevent reoccurrence of the fire until the hydrocarbons have been driven further away from the injection well. It will be appreciated that after a few days, the hot, moist air will have driven most of the hydrocarbons away from the injection well and back into the formation where a lower temperature prevails. Thus, after a few days, it is safe to begin raising the temperature again until finally the temperature selected as desirable for the particular formation, depending upon its characteristics, is reached.

Even after full temperature is reached, it is desirable to continue refluxing the well to check against the possibility of a fire, to keep the hole clean, and to keep the formation face open.

As an alternative method, the formation can be permitted to burn, if desired. In this instance steam would be injected in an amount to prevent undue rise of temperature due to a runaway fire. High temperature burning results in coking of the formation with attendant reduction in permeability, which is undesirable. Therefore, sufficient steam should be injected to maintain the reaction at a relatively low temperature at which substantial coking will not occur. Refluxing permits a constant check on the temperature of the formation.

This invention has been proven in a Texas field having eight production wells and one injection well. Before practice of this method, the wells were making from Vs to Vi barrel per day. After several months of practicing this method, field production was increased to about 60 barrels per day. When this field was first placed on steam, the temperature of the formation was about 67°

F. Several months later, oil recovered from the wells had reached a temperature of 208 to 240° F. In the beginning steam and air at a temperature of about 250° F. were injected at a pressure of 500 p.s.i. After warm5 ing up for about a day, the temperature was increased to about 350° F. and the injection well was refluxed four times per hour for periods of 2 to 3½ minutes. The well was found to blow water, oil and sand on each reflux. The next day the temperature was raised ₁₀ to 375° F., and the pressure to 550 p.s.i. The well was refluxed for 2 to 3 minutes, four to five times per hour, and blew oil, water and sand at every blow. The next day, the temperature was raised to 450° F. and the pressure to 600 p.s.i. Refluxing was reduced to 22 to 28 15 seconds, four times per hour, and blew some oil, water and sand at each blow. The next day the temperaure was raised to 475° F. and the pressure to 625 p.s.i. The formation was found to be on fire three times, and the temperature of the effluent from the injection well ranged 20 from 420 to 460° F. The next day, the temperature being reduced to 465° F., the well was still on fire several times. In each case the fire was extinguished by increasing the amount of water injected.

The next day the temperature was further reduced to 25 460° F. and the temperature of the effluent from the injection well ranged from 430° F. to 470° F. The formation was on fire at least one time, and took approximately 1½ hours to extinguish. Having an air input of about 90,000 cubic feet per day, the water input varied from 30 % of a gallon per minute when the formation was not on fire, up to 1½ gallons per minute to extinguish the fire. After this short period of time, it was found that the wells began making increased amounts of oil ranging from 1 to 7 barrels per day.

After about two weeks, it was found that casing pressure was beginning to build up on the production wells and an increase in temperature could be noted in some of the wells.

After about two months, refluxing was reduced to one 40 time per hour for a period of about 12 to 18 seconds, to check the formation temperature, and to keep the formation adjacent the injection well open.

After the initial problem with fires, no further difficulty was experienced with fires, and the temperature was grad45 ually raised to about 525° F. and the pressure maintained around 600 to 700 p.s.i. As noted above, production of the field was increased from about 4 barrels per day to about 60' barrels per day.

From the above it will be seen that the objects of this 50 invention have been attained, and it has been proven that a substantially depleted field can have its production greatly increased by the practice of this invention.

The temperature of the input air or gas is not critical except that it should not be so high as to maintain a fire in 55 the formation unless it is desired to permit and maintain a controlled low-temperature fire.

The pressure of the input gas may be such as desired, and normally the greater the pressure imposed on the formation the greater the rate of recovery of oil.

The volume of gas available will also affect the rate of recovery, and normally an increase in volume of gas will result in an increased rate of recovery.

The percentage of water employed may vary greatly, it only being necessary to provide sufficient steam to pre65 vent the formation from drying out and caking up. The volume of water vapor will normally be less than 25%, and usually will vary from about 3% to 15%.

Air need not be used. Where inert gas is used, refluxing will keep the well and surrounding formation open. 70 When “in situ” combustion is planned, hot air may be injected or unheated air injected and combustion initiated in other ways known to those skilled in the art. When cold air is injected, the need for water vapors is not present to a great degree as cold air does not tend to dry out 75 the formation.

3,136,359

The foregoing disclosure and description of the invention is illustrative and explanatory thereof, and various changes in the size, shape and materials, as well as in the details of the illustrated construction, may be made within the scope of the appended claims without departing from the spirit of the invention.