US3814187A

US3814187A - Subsurface formation plugging

Info

Publication number: US3814187A
Application number: US00360222A
Authority: US
Inventors: G Holman
Original assignee: BP America Production Co
Current assignee: BP America Production Co
Priority date: 1973-05-14
Filing date: 1973-05-14
Publication date: 1974-06-04
Anticipated expiration: 1991-06-04
Also published as: CA984743A

Abstract

This invention concerns a method of selectively plugging fractures in an underground formation without permanently plugging the ''''secondary porosity,'''' e.g., vugs, etc., which may be in communication with the wellbore. A slurry of finely divided limestone is first pumped through the well to fill the secondary porosity. Then a second slurry of finely divided solids, such as flyash, which is not soluble in most acids, is injected into the well to plug the interwell fracture system. Thereafter, to aid injectivity, the well is given a low pressure acid treatment to remove the limestone from the secondary porosity.

Description

United States Patent 1191 Holman June 4, 1974 [54] SUBSURFACE FORMATION PLUGGING 3,749,174 7/1973 Friedman et al 1. 166/281 x l t Geo e B. Hol an T lsa, Okla. [75] or rg m u Primary Examiner-David H. Brown [73] Ass1gnee: Amoco Produc on Company, Tulsa. Attorney, Agent, or FirmPaul F. Hawley; John D.

Okla- Gassett [22] Filed: May 14, 1973 1 Y 21 Appl. No.: 360,222 [57] ABSTRACT This invention concerns a method of selectively plug-' ging fractures in an underground formation without [52] US. Cl. 166/281, 166/292 permanently plugging the Secondary porosity," fig, [511 lift. Cl E2") 33/138 g etc, which y be in communication with the Fleld of Search 'wienbore. A Slurry f finely limestone is first pumped through the well to fill the secondary poros- [56] References cued ity. Then a second slurry of finely divided solids, such UNITED STATES PATENTS 4 asflyash, which is not soluble in most acids, is injected 2.223.804 12/1940 Kennedy 166/281 into the well to plug the interwell fracture system. 3.280.912 10/1966 Sheffield 166/292 X Thereafter, to aid injectivity, the well is given a low 3-4361559 12/1969 ing el 16'6/292 X pressure acid treatment to remove the limestone from 3,682,245 8/1972 Argabright et al l66/28l X the Secondary porosity 3,701,384 l()/l97 2 Routson et al l66/28l X 3,713,489 1/1973 Fast et al. 166/292 4 Claims, 4 Drawing Figures m LIMESTONE SLURRY M FLYASH SLURRY PATENTED NMHYW 3.814187 SHEEHBFd WW W EMA

PATENTEDJUNYMSMI 3.814187 SHEET2UF4 I E LIMESTONE PATENTEDJUH 4 i974 SHEET 3 0F 4 E LIMESTONE SLURRY l SUBSURFACE ORMATION PLUGGING BACKGROUND OF THE INVENTION 1. Field of Invention This invention relates to improved processes for plugging fissures or fractures in underground penetrated by a wellbore without permanently plugging the secondary porosity. It particularly concerns the use of such plugging processes for use of secondary recovery operations in which fluid is injected into the formation through one well to displace another fluid, usually oil, to a second well.

2. Setting of the Invention The secondary or tertiary recovery operation for which this invention is most suitable is the liquidvdisplacement type, such as waterflood. In waterflood operations, water is injected through an input well into the formation to drive oil toward an output or producing well. In many waterflood projects, the formation has many fractures, either naturally occurring or manmade, existing therein. Too frequently the injected water travels dominantly through such existing fractures. When this occurs, the injected water fails to reach the matrix or rock outside the fractures. Consequently, hydrocarbons in such rock or matrix outside the fissures or fractures are largely bypassed or unswept by the injected water. Thus, poor sweep efficiency and ineffective hydrocarbon recovery are experienced from the waterflood operation.

The water bypass problem in those situations has been at least reduced by plugging-such fissures. Two patents which disclose such processes are U.S. Pat. Nos. 3,486,559 and 3,713,489. Those two patents are also the closest prior art of which I am aware. Both patents relate to method of plugging fractures by injecting a liquid containing finely divided low-density, nonsettling solids into the formation. Those patents suggest several suitable finely divided solids, such as nutshell flour, flyash, limestone dust, blow sand. While those systems have been quite successfully employed in the field, there are nevertheless some areas in which those methods need improvement to improve the efficiency of the overall operations. One such area is in those formations having secondary porosity.

A BRIEF SUMMARY OF INVENTION This is a method of selectively plugging fractures in an interwell-area of an underground formation penetrated by a wellbore without permanently plugging the secondary porosity. A liquid slurry comprised of water and limestone dust is injected into the formation via the wellbore and at a pressure varying up to nearly the fracturing pressure. Pressures of this range are required to stress the dominant fracture and insure filling of secondary porosity." A volume of limestone slurry is pumped into the well to fill the estimated volume of the secondary porosity and enter the dominant fracture. Thereafter, a second slurry is injected through the wellbore at a pressure above that required to open existing fractures but below that required to create a new fracture therein. The second slurry is preferably water and flyash. The second slurry is then pumped into the well until the desired amount has been injected to give adequate inter-well plugging of the opened fracture. After this, steps are taken to remove the plugging material of limestone from the secondary porosity. This is accomplished by a low-pressure acid treatment such as an acid wash or jet washing. This does not affect the flyash plug in the interwell area, but re-establishes injectivity through the secondary porosity.

Secondary porosity includes vugs and small fractures near thewellbore, which extend at most only a few feet in any direction. The common secondary porosity development is found in cores containing crystalline secondary dolomite with inter-crystalline pores connect? ing large vugs. These vugs are irregular but can amount to open space of up to 2 or 3 inches across the opening. Large fossil molds and solution channels are also included in the term secondary porosity. Since many injection wells are converted oil producting wells, prior acid stimulation to increase productivity has resulted in enlarging these channels near the wellbore. The wellbores of injection wells are drilled or extend through these channels or portions of the vuggy porosity. The

walls of these vugs then, insofar as injection considerations are concerned, have the same function as an enlarged wellbore. This secondary porosity aids injection rates but does not cause bypassing of large quantities of matrix or rocks, such as interwell fractures.

BRIEF DESCRIPTION OF THE DRAWINGS A better understanding of the invention and various modifications and objects thereof can be made from the following description taken in conjunction with the drawings in which:

FIG. 1 is a schematic vertical section of an underground formation penetrated by a wellbore, illustrating both an extensive fracture and secondary porosity.

FIG. 2 is the same view as FIG. 1 but after the limestone slurry has been injected.

FIG. 3 is the sequence from FIG. 2 in which flyash has been injected.

FIG. 4 is similar to the other figures, but shows the removal of limestone slurry by acid washing or jetting while the flyash slurry is not affected due to its low solubility in acid.

DETAILED DESCRIPTION OF INVENTION Attention is first directed to FIG. 1 which illustrates an injection well having a borehole 10 which extends through subsurface producing formation 12. Casing 14 is shown set through the top of formation 12; however, the casing can be set through the formation and is in many cases. A tubing string 16 is suspended in the easing and a packer l8 closes the annulus between the lower end of tubing string 16 and the casing. The tubing string 16 ends as shown in this example at just above the lower end of casing 14.

Subsurface formation 12 has two characteristics shown which are important to the application of this invention. One is a large fracture 20 which extends from the wellbore for a very substantial distance, e.g., hundreds of feet or more. If fluid is injected into the wellbore 10, most of the injected fluid will flow through fracture 20; thus, many call this a thief zone. The two patents listed above, U.S. Pat. No. 3,486,559 and U.S. Pat. No. 3,713,489, disclose means of plugging thief zone 20.

Another geological feature of the formation 12, in which I am particularly interested, is the so-called secondary porosity as defined above. This is illustrated by the numerous short vugular spaces 22, which are intercepted by wellbore 10. The permeability in these vugs is many times greater than the matrix permeability of the formation. These vugs would normally extend for a few inches but may, due to prior stimulation, be poorly connected over a radius of a few feet around the wellbore. These channels are closed off or play out or their resistance to flow becomes very great within a few feet of the wellbore. Then, any additional flow or injection into these vugs 22 would have to be to the matrix, itself, which is what is desired in the secondary recovery operations. What then is desired in this situation is to plug the thief zone but have zones 22 open so that they can receive injection water. That is exactly what my disclosed system contains.

Attention is next directed to P10. 2. This figure is the same as FlG. 1 except that it illustrates that a limestone slurry has been injected through the wellbore into the formation, filling the secondary porosity 22, as well as thief zone 20 near the wellbore. 1 preferably inject a slurry of limestone at a pressure level above the fracture opening pressure so that we fill the secondary porosity 22 and open fracture 20 to receive some of the limestone slurry. Under this system, the limestone slurry has extended to a point 26. One can see that the secondary porosity 22 is filled with limestone slurry and will not be able to receive any of the second slurry which is injected, as shown in FIG. 3.

In FIG. 3 it is shown that a flyash slurry 28 now fills thief zone 20, which was first filled with the limestone dust. The limestone slurry is now illustrated as having been driven to point 30, an increased distance from the well. The flyash slurry is continued to be injected into the formation until a sufficient quantity is injected. US. Pat. No. 3,713,489, supra, describes the technique for injecting flyash slurry. The flyash slurry normally comprises water as the carrier fluid, containing about 18 to 26 lbs of flyash per gallon of water. Various additives and flow injection procedures are described in that patent. Those directions for injecting flyash will not be repeated here.

Attention is next directed to FIG. 4. After the desired quantity of flyash slurry is injected, that injection is stopped. This is then followed by an acid treatment. Shown in FIG. 4 is a macaroni string 32, which extends downwardly through the tubing 16 and has jets 34 at the lower end. A jet stream 36 of acid is forced out jets 34 and cleans a good portion of the limestone dust from secondary porosity 22. The initial slurry of limestone dust is percent soluble in acid (such as 15 percent hydrochloric acid) while flyash is only very slightly to not soluble at all in that acid.

While 1 have given limestone slurry as an example of the first slurry to be injected, the important thing is that the small. particles or dust to be carried in the first slurry into the secondary porosity be of such nature that it can be removed by treatment which will not remove the second slurry particles. Limestone dust is really the only practical material which I have found for the first slurry. I prefer to use flyash as the finely divided solids in the second slurry; however, other materials, such as nutshell flour, can be used. The principal criteria is that it be capable of being carried into the thief zone 20 and not be removed by the cleaning process which removes the limestone from the secondary porosity 22. v While the above invention has been disclosed in detail, other embodiments may be made without departing from the spirit and scope of the invention.

1 claim:

1. A method of plugging a fracture in an interwell area of an underground formation having secondary porosity penetrated by a wellbore without permanently plugging said secondary porosity which comprises the steps of:

a. injecting a liquid slurry in which the finely divided solid particles are limestone dust;

b. thereafter injecting a slurry in which the finely divided particles are not soluble in acid, at a pressure in the range from the fracture opening pressure to below the pressure required to create a fracture therein;

c. thereafter acid flushing the wellbore to remove limestone particles from the secondary porosity.

v 2. A method as defined in claim 1 in which the slurry of limestone particles is injected at a pressure in the range of the fracture opening pressure to below the pressure required to create a fracture therein and in which the acid flush is applied at a pressure less than the fracture opening pressure.

3. A method as defined in claim 1 in which the finely divided particles of step b) are flyash.

4. A method as defined in claim 3 in which the flyash slurry includes water as a carrier fluid, containing about 18 to 26 lbs of flyash per gallon of water.

Claims

2. A method as defined in claim 1 in which the slurry of limestone particles is injected at a pressure in the range of the fracture opening pressure to below the pressure required to create a fracture therein and in which the acid flush is applied at a pressure less than the fracture opening pressure.
3. A method as defined in claim 1 in which the finely divided particles of step b) are flyash.
4. A method as defined in claim 3 in which the flyash slurry includes water as a carrier fluid, containing about 18 to 26 lbs of flyash per gallon of water.