US3442331A - Cyclic secondary oil recovery process - Google Patents

Description

May 6, 1969 w. B. FULTON ET AL 1 3,442,331

CYCLIC SECONDARY OIL RECOVERY PROCESS Original Filed May 27, 1964 PRODUC T/ON REsERvolR RATE /0 PREssuRE -P5/ FIG. 20 F|G.2b 60 FlG.2c 60 FlG. 2d 60 i FIG.30 G0 FlGQ3b F|G.3c e0 Flasd WALTER B. FULTON LEONARD J. W/cKE/vHAL/sg INVENTO A TTORNE Y United States Patent 3,442,331 CYCLIC SECONDARY OIL RECOVERY PROCESS Walter B. Fulton and Leonard J. Wickenhauser, Laurel, Miss., assignors to Central Oil Company, Laurel, Miss., a corporation of Mississippi Continuation of application Ser. No. 370,526, May 27, 1964. ,This application May 22, 1967, Ser. No. 640,427

- Int. Cl. E21b 43/16, 43/20 US. Cl. 166-263 9 Claims ABSTRACT OF THE DISCLOSURE The above identified application is a continuation of application No. 370,526, filed May 27, 1964, now abandoned. This invention relates to the production of petroleum' by secondary recovery methods, and in particular concerns an improved water flooding process wherein oil recovery is enhanced by maintenance of reservoir pressure. Among the various methods presently employed for recovering petroleum from oil bearing formations which have become depleted to the point where petroleum no longer flows naturally into wells penetrating such formations, the secondary recovery method commonly known as water flooding probably enjoys widest exploitation. In brief, water flooding as usually practiced consists essentially in pumping water into one or more injection wells under a pressure suflicient to cause the water to flow out through the oil bearing formation toward one or more other wells which serve as producing wells. Theoretically, as the water flows through the oil bearing formation the mobile oil contained therein is forced ahead of the advancing water front into the producing wells from which it may be pumped to the earths surface. In many instances, however, this method proves ineffective by reason of'the occurrence of strata of high permeability extending-between the injection and producing wells. The water. chooses the path of least resistance, i.e., the strata of highest permeability, and hence travels from the injection wells to the producing wells in more or less well defined channels and fails to sweep the oil from the formation as a whole.

Various means have heretofore vbeen suggested for preventing or stopping such channeling of the water through the formation, as shown for example in Patent No. 2,988,142 to Maly and in Patent No. 3,032,101 to Woertz et al. Such methods, however, usually contemplate some sort of plugging or partial plugging of the more permeable strata of the formation so that the water is less likely to channel through such strata.

Many other methods have heretofore been proposed for increasing the proportion of oil in place which is recoverable from petroleum reservoirs by secondary recovery methods. Note for example the methods described in US. Patents 1,099,170, Dunn; 1,242,557, Dunn; 2,135,- 319, Bays; 2,724,438, Whorton et al.; 3,036,631, Holbrook; 3,084,743, West et al., and in the August 1963 issue of Journal of Petroleum Technology, pp. 877-884. None of the methods heretofore used, however, has been found to be consistently effective for the recovery of more than about fifty to sixty percent of the mobile oil in place.

-It is an object of this invention to provide a secondary 3,442,331 Patented May 6, 1969 recovery process which is effective for the recovery of extremely high proportions of the oil in place in a reservolr.

Another object of this invention is to provide a secondary recovery process wherein channeling of water or other liquid through more permeable strata of the formation is substantially reduced.

Still another object of this invention is to provide a water injection process wherein both the more permeable and the less permeable pore spaces of the rock are pressurized under stabilized conditions so as to cause production of oil therefrom.

Yet another object of the invention is to provide a process whereby gravity segregation of the gas, oil and water in the formation is improved by liquid injection.

Another object of the invention is to provide a process wherein water may be injected into a series of interbedded lenticular sands within a single well bore even though each sand may have different rock characteristics.

A further and most important object of the invention is to provide a secondary recovery process wherein maximum recovery of oil from a formation may be obtained without having to pump the production wells at any stage of the production.

These and other objects of the invention are attained by a water injection process wherein production from a partially depleted reservoir is substantially completely shut off before any injection is begun. The pressures at the bottoms of all of the wells in the formation are then monitored until they are stabilized. A pressurizing fluid, usually water, is then injected into one or more injection wells until the pressure reaches a desired point which preferably is approximately the original virgin reservoir pressure. When the desired pressure has been reached injection is stopped and pressures at bottoms of all wells in the reservoir are again monitored until the pressures are stabilized. Then, without any further injection, the producing wells are opened and allowed to flow. Production is continued until flowing production rates are reduced to a value where economics dictate that further pressurizing of the reservoir would be advantageous, at which time the production wells are again shut in and the injection cycle' is repeated.

For a better understanding of the invention reference is now made to the accompanying drawings wherein FIGURE 1 is a graph showing typical variation in reservoir pressure and production rates during practice of one embodiment of the present invention;

FIGURES 2(a) through 2(d) are schematic representations of the progression of a direct line drive fluid injection system as taken from FIGURE 7.26 of Applied Petroleum Reservoir Engineering, by Kraft and Hawkins (Prentiss Hall, 1959); and

FIGURES 3(a) through 3 (d) are schematic representations similar to FIGURES 2(a) through 2(d) showing the progression of a water injection system carried out according to the present invention.

The process of this invention may be readily understood by reference to FIGURE 1, wherein the point 10 signifies the initial virgin pressure of a reservoir before any production therefrom. As oil is produced from the reservoir, the reservoir pressure is reduced as indicated by the line 12. At the same time the rate of production in barrels per day is reduced as indicated by line 16 from a maximum at point 14. Thus after a period of time, as reservoir pressure is depleted the amount of oil which flows from the well decreases until the rate of production is' very low, as indicated at point 18, or flowing production ceases entirely. At this point the pressure in the well is as indicated at point 20 in the upper curve in FIGURE 1. Preferably in the performance of this process this pressure is still above the bubble point of the reservoir. In other words it is preferred that the initial production from the reservoir be stopped before the reservoir pressure is reduced below that required to maintain the reservoir in an undersaturated condition.

In some instances the production well or wells may be put on pump during this initial production period, but in most cases it will be most desirable to cease the initial production prior to the time that it is necessary to pump.

Following this first cessation of production all outlets from the reservoir are preferably shut in for a period of time suflicient to allow reservoir pressures to become stabilized. It will be understood that during production from a well the reservoir pressure immediately adjacent the production well will be substantially less than the pressure within the reservoir some distance away from the production well. However, when production ceases and the production well is shut in, any disparity in pressures at the same level within the reservoir is substantially eliminated, since the reservoir acts as any other tank containing a fluid under pressure. Due to the small passageways in the sand of the reservoir it may in some cases take a considerable time, up to several days, before the pressures within the reservoir become stabilized. During this time the pressure at the bottom of a production well will gradually increase, and the pressure elsewhere in the reservoir will gradually decrease. Stabilization can be determined by pressure measuring instruments at the bottom of various wells which encounter the reservoir. When these pressure measuring instruments indicate that pressure changes in the reservoir have ceased, then it may be assumed that pressures within the reservoir have stabilized.

Following the stabilization of pressures in the reservoir, which stabilization period is indicated on the pressure curve in FIGURE 1 at 22, water injection into the formation is begun. This initial injection period is indicated in FIGURE 1 by the curve 24, showing increase in reservoir pressure, and by the period between point 18 and point 26 on the production curve wherein there is no production from the well. The usual water flooding equipment may be utilized to inject water into the formation as rapidly as possible or as desired. In many cases injection pressures at the injection well will be low, since the weight of the column of water in the injection well will be sufiicient to cause the injection water to flow into the reservoir at a high rate. Where high injection rates are required, and where formations otfer resistance to the injection of water at desired rates, it will be necessary to inject water by means of conventional water injection pumps. Injection pressures should normally be maintained at a level below which rupturing of the formation can occur.

As indicated on the pressure curve in FIGURE 1, when sufiicient liquid has been injected to bring the reservoir pressure up to approximately the original virgin pressure of the reservoir, injection is stopped, as indicated by the point 28. Pressures somewhat higher than virgin pressure may be used, but pressures should normally be maintained at a level below which rupturing of the formations can occur.

After the desired pressure has been reached preferably, a period of time is provided during which there is no injection and no production from the reservoir, and during this period pressures within the reservoir are allowed to stabilize until pressure changes cease. Such stabilization period is indicated by the time interval 30 marked on the pressure curve in FIGURE 1.

As soon as stabilization of the reservoir pressures has been reached, the production wells may again be opened and production continued until such time as the reservoir pressure has been reached a substantial amount to whatever level is considered by the operator to be a proper time for ceasing production and again initiating injection to increase the reservoir pressure. As shown in FIGURE 1, production periods after the initial production period may be substantially shorter and may be at high average production rates. Thus, as shown in this figure, the lines 32, 34 and 36 on the pressure curve indicate production periods which correspond to the periods of lines 38, 40 and 42 on the production rate curve, and lines 44 and 46 indicate intermediate injection periods during which there is no production. The small steady pressure periods 48, 50, 52, 54 and 56 on the pressure curve indicate the pressure stabilization periods provided before and after each injection period.

In a conventional water injection operation, injection and production take place at the same time. Thus there is created within the reservoir an area of lowest pressure, i.e., at the production well; and an area of highest pressure, i.e., at the injection well. Thus, as in any hydraulic system, there is a tendency for the injection water to flow from the high pressure point to the low pressure point. Such flow will naturally follow the path of least resistance, which in a reservoir is the strata of the highest permeability with flow along the shortest paths to the producing outlets. Thus conventional fluid injection will displace oil primarily from the more permeable strata of sand, leaving substantial quantities of oil in less permeable strata.

Thus in the usual fluid injection system the path taken by the injection fluid in substantially homogeneous sand reservoirs is most likely approximately that shown in the four drawings, FIGURE 2(a) through 2(d), wherein 60 represents the injection well, 62 represents a production well, and the hatched area 64 represents the advancing fluid which is injected through the injection well While oil is being produced from the production well. As seen in FIGURE 2(a), the fluid may initially start out with a substantially cylindrical front, but tends to flow most readily toward the lower pressure area at production well 62, so that, as shown in FIGURES 2(b) and 2(0), the injection fluid front is moved much more rapidly in the direction of the production well than in other directions from the injection well. Thus eventually, as shown in FIGURE 2(d), the injection fluid is flowing directly to the production well without sweeping out any of the area on either side of its path of flow.

The advance of the injection water through the formation when injected according to the process of this invention is illustrated in FIGURES 3(a) through 3(d). When the process of this invention is practiced, there is no point of lower pressure at the production well, or elsewhere in the formation, during the time water is being injected. Thus there is no tendency for the injection water to flow in any particular horizontal direction so that it will flow substantially uniformly in all directions from the injection well. It is therefore thought that a substantially cylindrical front will be obtained which will gradually, as shown in FIGURES 3(a), 3(b) and 3(a), move in all directions from the injection well to sweep a high proportion of the reservoir as the water moves outwardly from the injection well. It will be apparent from a comparison of FIGURES 2(d) and 3(d) that the area swept by the injection water in the process of this invention is substantially greater than that in the area swept by the prior art processes.

The stabilization of pressure gradients provides further benefit in that gravity segregation of fluids in the reservoir is facilitated. Since pressure gradients are at a minimum, the tendency is for water, because of its greater density, to move downwardly by gravity through the reservoir rock and seek a level below the oil in the reservoir.

In the practice of this process to date the production wells have been completely shut down during water injection periods. However, the advantageous results of this invention may be obtained by producing at very low rates during the injection period, if the production rates are kept low enough that the pressure reduction in the reservoir resulting therefrom is more or less localized around the production well, being low enough that no noticeable pressure gradient extends to the area into which water is being injected.

It is apparent that the process of this invention may be used as it has in the past with a single injection well and a single production well intersecting the reservoir, and that it also may be used where there are any number of production wells together with one or more injectionwells, as required for an eflicient flooding operation. It is of course essential for the pressure stabilization steps that all wells encountering the reservoir be controlled and made a part of the process.

Preferably the injection wells used for the practice of this invention will be spaced farther away from the production wells than in the conventional water flood. There is no need for them to be close to the production wells, since the entire reservoir is pressurized. If the injection wells are farther away, the period of time required for the injection water to reach the production well is delayed. One or more water input wells are preferably located along the flanks of the reservoir to allow more beneficial effects from gravity segregation. However, in other instances, since water does nothave the tendency to flow through oil saturated rocks, injection wells may be located in other portions of the rservoir without appreciable damage due to channeling;

The process of this invention may most advantageously be practiced by repressuring the reservoir after each production period to a pressure substantially equal to virgin reservoir pressure. However it may in some instances be found advisable to raise the pressure slightly higher than initial reservoir pressure to some point less than formation breakdown pressure. Also in other instances it may be found most advisable to stop injection before the initial reservoir pressure has been reached and start produc tion then at a lower pressure. Such procedures will produce satisfactory results so long as the process of this invention is followed wherein stabilization of pressures within the reservoir is allowed both before any injection is begun and after all injection has been completed.

Since no production takes place while injection is going on, it is most advantageous economically to inject as rapidly as possible. This has been found to be no problem, however, since injection rates may normally be six to nine times as high as rates of production, so that a period of one month provided for injection will raise the reservoir pressure high enough to allow six to nine months of flowing production. Oil production rates after an injection by the process of this invention are often substantially as high as original production rates from the reservoir and therefore substantial increases in annual production are still obtained by the process of this invention even though the reservoir is shut in for one or two months per year.

It will be apparent that the process of this invention may be carried out in a plurality of sands encountered by a well merely by pressurizing each sand to a desired pressure with suitable plugs between sands.

The process of this invention greatly increases the ability to produce oil without high proportions of water, because under the pressure stabilized conditions that exist during production according to this invention, oil will flow through the oil-saturated rock, in preference to water, toward the oil-producing outlets.

One of the major advantages obtained by the process of this invention is the elimination of any necessity to pump in most reservoirs, since the reservoir pressure is most advantageously maintained high enough at all times to cause the wells to flow. Thus the need for expensive artificial lifting equipment and consequent high operating cost is greatly reduced if not entirely eliminated. Other savings may be realized because of the fact that injection pumps and facilities are required only occasionally, so that the same equipment may be moved from reservoir to reservoir as injection is required.

The process of this invention was performed in a closed reservoir having an areal extent of approximately 200 acres. A single production well was completed with perforations from 11,661 to 11,681 feet. Original bottom hole pressure was 5750 p.s.i. and the bubble point was 1262 p.s.i. The well originally flowed, on inch choke, 422 barrels per day with a flowing surface pressure of 1350 p.s.i. After flowing 90,000 barrels of oil, the well died and was placed on hydraulic pump. After some three years on pump, the well was still capable of pumping 50 barrels of oil per day. However, the well was closed in at a bottom hole pressure of 1320 p.s.i. after cumulative production of 230,000 barrels of oil, and a total reservoir withdrawal of 270,000 barrels.

Prior to closing in the production well, pipe had been set in another well 1200 feet west. When the production well was closed in the pressures in both wells were monitored until reservoir pressure was stabilized, and then water injection was started through the second well and continued until 200,000 barrels of water had been injected and bottom hole pressure was raised to 5300 p.s.i. Injection was terminated and the bottom hole pressures were allowed to stabilize again. Bottom hole pressure surveys indicated slightly less than six days were required for stabilization. The production well was then opened and flowed on inch choke at the rate of 230 barrels per day with 5S0# tubing pressure. After approximately 50,000 barrels of reservoir fluids were produced, yielding 39,000 barrels of oil, the production well was again closed in. Bottom hole pressure stabilized at 4050 p.s.i. Water injection was then again initiated at a rate of 1500 barrels per day with a surface injection pressure of 700 p.s.i.

It will be noted that in this particular case the well had been pumped until it was only marginal economically and probably would have had to be abandoned in a relatively short time. However, by means of the process of this invention additional recovery amounting to nearly twenty percent of the primary production has already been ob tained and it is anticipated that upon continuation of utilization of the process of this invention the total recovery from this reservoir, without any additional pumping of the well, will far exceed the primary recovery, and should amount to -90% of the total mobile oil in the reservoir.

Although specific embodiments of this invention have been shown and described herein the invention is not limited to these embodiments but only as set forth by the following claims.

We claim:

1. A secondary recovery process comprising:

substantially shutting off all outlets from a partially depleted reservoir, allowing pressure come stabilized, injecting liquid into said reservoir sufficient to restore reservoir pressure to near virgin conditions,

allowing pressure gradients within the reservoir to become stabilized, and

producing from said reservoir while substantially no liquid is being injected.

2. A petroleum production process comprising:

producing from a reservoir until the reservoir pressure has reduced substantially "below virgin conditions, substantially shutting 01f all outlets from said reservoir, allowing pressure gradients within the reservoir to become stabilized,

injecting liquid into said reservoir sufficient to restore reservoir pressure to near virgin conditions,

allowing pressure gradients within the reservoir to become stabilized, and

producing from said reservoir while substantially no fluid is being injected.

3. A petroleum production 2 wherein initial production ment of a mobile gas phase.

4. A petroleum production process comprising:

producing oil from a reservoir until the reservoir gradients within the reservoir to be process as defined by claim is stopped prior to developpressure has been reduced substantially below virigin conditions,

reducing the production rate to such a level that pressure gradients within the reservoir may become substantially stabilized, maintaining said reduced production rate after said substantially stabilized condition is reached,

beginning and continuing water injection into said reservoir, without any increase in production rate, until the reservoir pressure has been increased substantially but to a pressure below breakdown pressure,

substantially terminating said injection,

allowing pressure gradients within the reservoir to again become stabilized, and

resuming oil production at increased rates while substantially no liquid is being injected.

5. A secondary recovery process comprising:

substantially shutting ofl? all outlets from a partially depleted reservoir,

allowing pressure gradients within the reservoir to become stabilized, injecting water into said reservoir at approximately the maximum feasible rate until the reservoir pressure is restored to approximately vigin conditions,

allowing pressure gradients within the reservoir to become stabilized, and

producing oil from said reservoir without further injection.

6. A secondary production process for use with a reservoir having a production well and an injection well comprising:

shutting down said production well,

allowing pressure gradients within the reservoir to become stabilized,

repressuring said reservoir by injecting water through said injection well while said production well is shut down,

stopping water injection,

allowing pressure gradients within the reservoir to become stabilized, and

resuming production from said production well while no water is being injected,

7. A secondary recovery process wherein the steps set forth in claim 6 are repeated until the reservoir is substantially depleted of recoverable petroleum.

8. A secondary recovery process wherein the steps set forth in claim 6 are performed before the reservoir pressure has ever been reduced enough to cause an under saturated condition.

9. A secondary recovery process as defined by claim 6 wherein the said water injection is carried out at substantially the maximum rate at which the formation can take water.

References Cited UNITED STATES PATENTS 5/1966 Cooke et al 166-9 OTHER REFERENCES STEPHEN J. NOVOSAD, Primary Examiner.

US. Cl. X.R. l66-268

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