CA1080613A - Well treatment fluid diversion with low density ball sealers - Google Patents
Well treatment fluid diversion with low density ball sealersInfo
- Publication number
- CA1080613A CA1080613A CA299,388A CA299388A CA1080613A CA 1080613 A CA1080613 A CA 1080613A CA 299388 A CA299388 A CA 299388A CA 1080613 A CA1080613 A CA 1080613A
- Authority
- CA
- Canada
- Prior art keywords
- casing
- fluid
- ball
- perforations
- ball sealers
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Expired
Links
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/10—Sealing or packing boreholes or wells in the borehole
- E21B33/13—Methods or devices for cementing, for plugging holes, crevices, or the like
- E21B33/138—Plastering the borehole wall; Injecting into the formation
-
- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y10—TECHNICAL SUBJECTS COVERED BY FORMER USPC
- Y10T—TECHNICAL SUBJECTS COVERED BY FORMER US CLASSIFICATION
- Y10T137/00—Fluid handling
- Y10T137/4891—With holder for solid, flaky or pulverized material to be dissolved or entrained
Abstract
ABSTRACT OF THE DISCLOSURE
A ball sealer for use as a diverting agent when treating a well having a perforated casing. The ball sealer is sized to plug a perforation and has a density less than the treating fluid. The ball sealer is made of a core material, such as syntactic foam or polymethylpentene, and a covering of a thin layer of an elastomeric material. After some of the treating fluid has been injected into the well, the ball sealers are injected and carried by the fluid flow down to the perforations where they seat and divert the further injection of treating fluid through the remaining open perforations.
A ball sealer for use as a diverting agent when treating a well having a perforated casing. The ball sealer is sized to plug a perforation and has a density less than the treating fluid. The ball sealer is made of a core material, such as syntactic foam or polymethylpentene, and a covering of a thin layer of an elastomeric material. After some of the treating fluid has been injected into the well, the ball sealers are injected and carried by the fluid flow down to the perforations where they seat and divert the further injection of treating fluid through the remaining open perforations.
Description
~LV8~613
2 l. Fleld of the Invention. ?his invention pertains to the
3 treating of wells and more in particular to the sequential treatment of
4 formation strata by the temporary closing of perforations in the well casing during the treatment.
6 2. Description of the Prior Art. It is common practice in 7 completing oil and gas wells to set a string of pipe, known as casing, in 8 the well and use cement around the outside of the casing to isolate the 9 various formations penetrated by the well. To establish fluid communication between the hydrocarbon bearing fonmations and the interior of the casing, 11 the casing and cement sheath are perforated.
12 At various times during the life of the well, it may be 13 desirable to increase the production rate of hydrocarbons through acid 14 treatment or hydraulic fracturing. If only a short, single pay zone in the well has been perforated, the treating fluid will flow into the pay zone 16 where it is required. As the length of the perforated pay zone or the 17 number of perforated pay zones increases, the placement of the fluid 18 treatment in the regions of the pay zones where it is required becomes more 19 difficult. For instance, the strata having the highest permeability will most likely consume the major portion of a given stimulation treatment 21 leaving the least permeable strata virtually untreated. Therefore, tech-22 niques have been developed to divert the treating fluid from its path of 23 least resistance so that the low permeability zones are also treated. -~
24 One technique for achieving diversion involves the use of downhole equipment such as packers. Although these devices are effective, 26 they are quite expensive due to the involvement of associated workover 27 equipment required during the tubing-packer manipulations. Additionally, 28 mechanical reliability tends to decrease as the depth of the well increases.
-, - :
~al8Q613 1 As a result, considerable effort has been devoted to the develop-2 ment of alternative diverting methods. One of the most popular and widely 3 used diverting techniques over the past 20 years has been the use of small 4 rubber-coated balls, known as ball sealers, to seal off the perforations inside the casing.
6 These ball sealers are pumped into the wellbore along with the 7 formation treating fluid. The balls are carried down the wellbore and on 8 to the perforations by the flow of the fluid through the perforations into 9 the formation. The balls seat upon the perforations and are held there by the pressure differential across the perforation.
11 The major advantages of utilizing ball sealers as a diverting 12 agent are: easy to use, positive shutoff, independent of the formation, 13 and non-damaging to the well. The ball sealers are simply injected at the 14 surface and transported by the treating fluid. Other than a ball injector, no special or additional treating equipment is required. The ball sealers 16 are designed to have an outer covering sufficiently compliant to seal a jet 17 formed perforation and to have a solid, rigid core which resists extrusion lB into or through the perforation. Therefore, the ball sealers will not 19 penetrate the formation and permanently damage the flow characteristics of the well.
21 Several requirements are repeatedly applied to ball sealers as 22 they are normally utilized today. First, the ball sealers must be chemically 23 inert in the envlronment to which they are exposed. Second, they must seal 24 effectively, yet not extrude into the perforations. Third, the ball sealers must release from the perforations when the pressure differential into the 26 formation is relieved. Fourth, the ball sealers are generally heavier than 27 the wellbore fluid so that they will sink to the bottom of the well, and 28 out of the way, upon completion of the treatment.
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.~ . ~ . .
~0806~3 Although present-day ball sealer diverting techniques have 2 met with considerable usage, there is abundant evidence which indicates 3 that the sealing devices often do not perform effectively because only a 4 fraction of the ball sealers injected actually seat on perforations. The
6 2. Description of the Prior Art. It is common practice in 7 completing oil and gas wells to set a string of pipe, known as casing, in 8 the well and use cement around the outside of the casing to isolate the 9 various formations penetrated by the well. To establish fluid communication between the hydrocarbon bearing fonmations and the interior of the casing, 11 the casing and cement sheath are perforated.
12 At various times during the life of the well, it may be 13 desirable to increase the production rate of hydrocarbons through acid 14 treatment or hydraulic fracturing. If only a short, single pay zone in the well has been perforated, the treating fluid will flow into the pay zone 16 where it is required. As the length of the perforated pay zone or the 17 number of perforated pay zones increases, the placement of the fluid 18 treatment in the regions of the pay zones where it is required becomes more 19 difficult. For instance, the strata having the highest permeability will most likely consume the major portion of a given stimulation treatment 21 leaving the least permeable strata virtually untreated. Therefore, tech-22 niques have been developed to divert the treating fluid from its path of 23 least resistance so that the low permeability zones are also treated. -~
24 One technique for achieving diversion involves the use of downhole equipment such as packers. Although these devices are effective, 26 they are quite expensive due to the involvement of associated workover 27 equipment required during the tubing-packer manipulations. Additionally, 28 mechanical reliability tends to decrease as the depth of the well increases.
-, - :
~al8Q613 1 As a result, considerable effort has been devoted to the develop-2 ment of alternative diverting methods. One of the most popular and widely 3 used diverting techniques over the past 20 years has been the use of small 4 rubber-coated balls, known as ball sealers, to seal off the perforations inside the casing.
6 These ball sealers are pumped into the wellbore along with the 7 formation treating fluid. The balls are carried down the wellbore and on 8 to the perforations by the flow of the fluid through the perforations into 9 the formation. The balls seat upon the perforations and are held there by the pressure differential across the perforation.
11 The major advantages of utilizing ball sealers as a diverting 12 agent are: easy to use, positive shutoff, independent of the formation, 13 and non-damaging to the well. The ball sealers are simply injected at the 14 surface and transported by the treating fluid. Other than a ball injector, no special or additional treating equipment is required. The ball sealers 16 are designed to have an outer covering sufficiently compliant to seal a jet 17 formed perforation and to have a solid, rigid core which resists extrusion lB into or through the perforation. Therefore, the ball sealers will not 19 penetrate the formation and permanently damage the flow characteristics of the well.
21 Several requirements are repeatedly applied to ball sealers as 22 they are normally utilized today. First, the ball sealers must be chemically 23 inert in the envlronment to which they are exposed. Second, they must seal 24 effectively, yet not extrude into the perforations. Third, the ball sealers must release from the perforations when the pressure differential into the 26 formation is relieved. Fourth, the ball sealers are generally heavier than 27 the wellbore fluid so that they will sink to the bottom of the well, and 28 out of the way, upon completion of the treatment.
,, :
.
.~ . ~ . .
~0806~3 Although present-day ball sealer diverting techniques have 2 met with considerable usage, there is abundant evidence which indicates 3 that the sealing devices often do not perform effectively because only a 4 fraction of the ball sealers injected actually seat on perforations. The
5 present-day practice of using ball sealers having a density greater than
6 the treating fluid ylelds a low and unpredictable seating efficiency highly ~ 7 dependent on the difference in density between the ball sealers and the - 8 fluid, the flow rate of the fluid through the perforations, and the number, 9 spacing and orientation of the perforations. The net result is that the 10 plugging of the desired number of perforations at the proper time during 11 the treatment to effect the desired diversion is left completely to chance.
12 When these inefficiencies lead to treatment failures, it is 13 generally believed that these failures result from insufficient flow being 14 carried through the perforations, thereby allowing the balls to fall to the 15 bottom of the well without achieving fluid diversion. Attempts to overcome 16 this problem generally include pumping a quantity of balls which exceeds t 17 the number of perforations. Although this procedure can be helpful, it has 18 not proven to be a satisfactory solution.
20 The method of the present invention overcomes the limitations of ~t 21 present-day ball sealer diversion methods. The present invention utilizes 22 ball sealers having a density less than the treating fluid so that 100%
23 seating efficiency can be achieved.
24 The method of the present invention involves flowing a treating 25 fluid downward within the casing and through the perforations into the ~ 26 formation surrounding the perforated parts of the casing. At the appro- -i 27 priate time during the treatment, spherically-shaped plugging members, 28 i.e., ball sealers, are introduced into the treating fluid at the surface.
.~ .. ~ -, . ~ , ~0~6~3 .
1 These ball sealers will have a size suffiicient to plug the casing perfora-2 tions and a density less than the density of the treating fl~id within the 3 casing. Thereafter, the downward flow of the fluid within the casing will 4 be continued at a rate such that the downward velocity of the fluid in the casing above the perforations is sufficient to impart a downward drag force 6 on the ball sealers greater in magnitude than the upward buoyancy force
12 When these inefficiencies lead to treatment failures, it is 13 generally believed that these failures result from insufficient flow being 14 carried through the perforations, thereby allowing the balls to fall to the 15 bottom of the well without achieving fluid diversion. Attempts to overcome 16 this problem generally include pumping a quantity of balls which exceeds t 17 the number of perforations. Although this procedure can be helpful, it has 18 not proven to be a satisfactory solution.
20 The method of the present invention overcomes the limitations of ~t 21 present-day ball sealer diversion methods. The present invention utilizes 22 ball sealers having a density less than the treating fluid so that 100%
23 seating efficiency can be achieved.
24 The method of the present invention involves flowing a treating 25 fluid downward within the casing and through the perforations into the ~ 26 formation surrounding the perforated parts of the casing. At the appro- -i 27 priate time during the treatment, spherically-shaped plugging members, 28 i.e., ball sealers, are introduced into the treating fluid at the surface.
.~ .. ~ -, . ~ , ~0~6~3 .
1 These ball sealers will have a size suffiicient to plug the casing perfora-2 tions and a density less than the density of the treating fl~id within the 3 casing. Thereafter, the downward flow of the fluid within the casing will 4 be continued at a rate such that the downward velocity of the fluid in the casing above the perforations is sufficient to impart a downward drag force 6 on the ball sealers greater in magnitude than the upward buoyancy force
7 acting on the ball sealers to thereby transport the ball sealers to the
8 perforations. Once the ball sealers have reached the perforations, they
9 will all seat on perforations taking fluid, plug the perforations and cause the treating fluid to be diverted to the remaining open perforations.
11 The ball sealers themselves must have a low density high strength 12 core capable of withstanding the pressures existing within the well. The 13 pressures acting on the ball sealers will be caused by the hydrostatic 14 pressures of the fluid in the wellbore and the pumping pressure. The core material cannot collapse under the pressures in the well or else the ball 16 sealers will decrease in volume and correspondingly have an increased 17 density which can easily exceed the density of the treating fluid. It has 18 been found that core materials that meet the density and strength requirements 19 include syntactic foam and polymethylpentene.
After the treatment of the hydrocarbon-bearing strata has been 21 completed, the pressure on the fluid in the casing will be relieved causing 22 the ball sealers to be released from the perforations where they were 23 seated. The ball sealers will rise within the casing due to their buoyancy 24 and to the upward flow of fluids from the well to the earth's surface. A
ball catcher may be provided to trap all of the ball sealers upstream of 26 any equipment which they might clog or damage.
27 The method of the present invention provides certainty in di-28 version heretofore unknown in well treatment operations.
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;~8(~ 3 2 FIGURE 1 is an elevation view in section of a well illustrating 3 the practice of the present invention.
4 FIGURE 2 is an elevation view partially in section of a typical arrangement of wellhead equipment placed on a production well to control 6 the flow of hydrocarbons from the well including a ball catcher adapted to 7 trap the ball sealers upstream of any equipment which they might clog or 8 damage.
9 FIGURE 3 is a graph of the seating efficiency versus the normalized density contrast between a ball sealer and a treating fluid based on experi-11 ments.
12 FIGURE 4 is a graph of the fluid velocity within the casing i--13 versus the normalized density contrast between a ball sealer and a treating 14 fluid based on experiments.
FIGURE 5 is a view of a ball sealer in section.
16 DESCRIPTION OF THE PREFERRED EMBODI~ENTS
17 Utilization of the present invention according to the preferred 18 embodiment is depicted in FIGURE 1. The well 1 of FIGURE 1 has a casing 2 19 run to the bottom of the wellbore and cemented around the outside to hold casing 2 in place and isolate the penetrated formations or intervals. The 21 cement sheath 3 extends upward from the bottom of the wellbore at least to 22 a point above the producing strata 5. For the hydrocarbons in the producing 23 strata 5 to be produced, it is necessary to establish fluid communication 24 between the producing strata 5 and the interior of the casing 2. This is ;
accomplished by perforations 4 made through the casing 2 and the cement 26 sheath 3.
27 The hydrocarbons flowing out of the producing strata 5 through 28 the perforations 4 and into the interior of the casing 2 are transported -;~, ~ --6--:', :, . . . .
1(1~3()613 1 to the surface through a production tubing 6. A production packer 7 is 2 installed near the lower end of the production tubing 6 and above the 3 highest perforation to achieve a pressure seal between the production 4 tubing 6 and the casing 2. Production tubings are not always used and, in those cases, the entire interior volume of the casing is used to conduct 6 the hydrocarbons to the surface of the earth.
7 When diversion is needed during a well treatment, ball sealers 8 are often used to close off some of the perforations. These ball sealers 9 are preferred to be approximately spherical in shape, but other geometries have been proposed.
11 To use the ball sealers lO to plug some of the perforations 4, 12 the first step is to introduce the ball sealers 10 into the casing 2 at a 13 predetermined time during the treatment. The ball sealers can be mixed 14 with the fluid either before or after the fluid is pumped into the upper 15 end of the casing. Methods of accomplishing these procedures are well ~ -16 known in the art.
17 When the ball sealers lO are introduced into the fluid upstream 18 of the perforated parts of the casing, they are carried down the production 19 tubing 6 or casing 2 by the fluid flow. Once the fluid arrives at the perforated parts of the casing, it moves radially outward, in addition to 21 its downward movement, toward and through the perforations 4. The flow of 22 the treating fluid through the perforations 4 carries the ball sealers 10 23 over to the perforations 4 and seats them on the perforations 4. The ball 24 sealers lO are held there by the fluid pressure differential, thereby effectively closing those perforations 4 until such time as the pressure 26 differential is reversed. Ideally, the ball sealers 10 will first seal the 27 perforations through which the treating fluid is flowing most rapidly.
28 This preferential closing of the perforations allows equal treatment of the 29 producing strata through the entire distance of the perforations.
. . .
1fl)8(~613 1 The prior art teaches that it is preferred for the density of the 2 ball sealers to be greater than the density of the treating fluid. It is 3 worth examining the prior art ball sealer seating mechanism to be able to 4 contrast it to the present invention. The velocity of ball sealers more 5 dense than the fluid in the wellbore is comprised of two components. Each 6 ball sealer has a settling velocity which is due to the difference in the - -7 densities of the ball sealer and the fluid and is always a vertically 8 downward velocity. The second component of the ball sealer's velocity is g attributable to the drag forces imposed upon the ball sealer by the moving
11 The ball sealers themselves must have a low density high strength 12 core capable of withstanding the pressures existing within the well. The 13 pressures acting on the ball sealers will be caused by the hydrostatic 14 pressures of the fluid in the wellbore and the pumping pressure. The core material cannot collapse under the pressures in the well or else the ball 16 sealers will decrease in volume and correspondingly have an increased 17 density which can easily exceed the density of the treating fluid. It has 18 been found that core materials that meet the density and strength requirements 19 include syntactic foam and polymethylpentene.
After the treatment of the hydrocarbon-bearing strata has been 21 completed, the pressure on the fluid in the casing will be relieved causing 22 the ball sealers to be released from the perforations where they were 23 seated. The ball sealers will rise within the casing due to their buoyancy 24 and to the upward flow of fluids from the well to the earth's surface. A
ball catcher may be provided to trap all of the ball sealers upstream of 26 any equipment which they might clog or damage.
27 The method of the present invention provides certainty in di-28 version heretofore unknown in well treatment operations.
~;
;~8(~ 3 2 FIGURE 1 is an elevation view in section of a well illustrating 3 the practice of the present invention.
4 FIGURE 2 is an elevation view partially in section of a typical arrangement of wellhead equipment placed on a production well to control 6 the flow of hydrocarbons from the well including a ball catcher adapted to 7 trap the ball sealers upstream of any equipment which they might clog or 8 damage.
9 FIGURE 3 is a graph of the seating efficiency versus the normalized density contrast between a ball sealer and a treating fluid based on experi-11 ments.
12 FIGURE 4 is a graph of the fluid velocity within the casing i--13 versus the normalized density contrast between a ball sealer and a treating 14 fluid based on experiments.
FIGURE 5 is a view of a ball sealer in section.
16 DESCRIPTION OF THE PREFERRED EMBODI~ENTS
17 Utilization of the present invention according to the preferred 18 embodiment is depicted in FIGURE 1. The well 1 of FIGURE 1 has a casing 2 19 run to the bottom of the wellbore and cemented around the outside to hold casing 2 in place and isolate the penetrated formations or intervals. The 21 cement sheath 3 extends upward from the bottom of the wellbore at least to 22 a point above the producing strata 5. For the hydrocarbons in the producing 23 strata 5 to be produced, it is necessary to establish fluid communication 24 between the producing strata 5 and the interior of the casing 2. This is ;
accomplished by perforations 4 made through the casing 2 and the cement 26 sheath 3.
27 The hydrocarbons flowing out of the producing strata 5 through 28 the perforations 4 and into the interior of the casing 2 are transported -;~, ~ --6--:', :, . . . .
1(1~3()613 1 to the surface through a production tubing 6. A production packer 7 is 2 installed near the lower end of the production tubing 6 and above the 3 highest perforation to achieve a pressure seal between the production 4 tubing 6 and the casing 2. Production tubings are not always used and, in those cases, the entire interior volume of the casing is used to conduct 6 the hydrocarbons to the surface of the earth.
7 When diversion is needed during a well treatment, ball sealers 8 are often used to close off some of the perforations. These ball sealers 9 are preferred to be approximately spherical in shape, but other geometries have been proposed.
11 To use the ball sealers lO to plug some of the perforations 4, 12 the first step is to introduce the ball sealers 10 into the casing 2 at a 13 predetermined time during the treatment. The ball sealers can be mixed 14 with the fluid either before or after the fluid is pumped into the upper 15 end of the casing. Methods of accomplishing these procedures are well ~ -16 known in the art.
17 When the ball sealers lO are introduced into the fluid upstream 18 of the perforated parts of the casing, they are carried down the production 19 tubing 6 or casing 2 by the fluid flow. Once the fluid arrives at the perforated parts of the casing, it moves radially outward, in addition to 21 its downward movement, toward and through the perforations 4. The flow of 22 the treating fluid through the perforations 4 carries the ball sealers 10 23 over to the perforations 4 and seats them on the perforations 4. The ball 24 sealers lO are held there by the fluid pressure differential, thereby effectively closing those perforations 4 until such time as the pressure 26 differential is reversed. Ideally, the ball sealers 10 will first seal the 27 perforations through which the treating fluid is flowing most rapidly.
28 This preferential closing of the perforations allows equal treatment of the 29 producing strata through the entire distance of the perforations.
. . .
1fl)8(~613 1 The prior art teaches that it is preferred for the density of the 2 ball sealers to be greater than the density of the treating fluid. It is 3 worth examining the prior art ball sealer seating mechanism to be able to 4 contrast it to the present invention. The velocity of ball sealers more 5 dense than the fluid in the wellbore is comprised of two components. Each 6 ball sealer has a settling velocity which is due to the difference in the - -7 densities of the ball sealer and the fluid and is always a vertically 8 downward velocity. The second component of the ball sealer's velocity is g attributable to the drag forces imposed upon the ball sealer by the moving
10 fluid shearing around the ball sealer. This velocity component will be in
11 the direction of ~he fluid f'ow. Within the production tubing or within
12 the casing above the perforations, the velocity component due to the fluid
13 will be generally downward.
14 Just above the perforated part of the casing the fluid takes on
15 a horizontal velocity component directed radially outward toward and
16 through the perforations 4. The flow through any perforation must be
17 sufficient to draw the ball sealer 10 to the perforation before the ball
18 sealer sinks past that perforation. If the flow of the treating fluid
19 through the various perforations does not draw the ball sealer to a perfora-
20 tion b~ the t'~e the ball sealer sinks past the lowest pe-;foration, the
21 ball sealer will simply sink into the rathole 8 where it will remain.
22 In contrast, the present invention contemplates the use of ball
23 sealers 10 having a density less than the density of the treating fluid.
24 Within the wellbore, each ball sealer has a velocity comprised of two
25 opposing components. The first velocity component is directed vertically
26 upward due to the buoyancy of the ball sealer in the fluid. The second
27 velocity component is attributable to the drag forces imposed upon the ball
28 sealer by the motion of the fluid shearing past the ball sealer. Above the
29 perforations, this second velocity component will be directed generally ., .
10 !3Q~;13 1 downward. It is essential that the downward fluid velocity in the 2 production tubing 6 and in the casing 2 above the perforations 4 be 3 sufficient to impart a downward drag force on the ball sealers which is 4 greater in magnitude than the upward force of buoyancy acting on the 5 ball sealers. This results in the ball sealers being carried downward 6 to the section of the casing which has been perforated.
7 When ball sealers are utilized in accordance with the present 8 invention, they will never remain in the rathole 8; that is, below the 9 lowest perforation through which the treating fluid is flowing, due to the 10 buoyancy of the ball sealers. ~elow the lowest perforation accepting the 11 treating fluid, the fluid in the wellbore remains sta~na~t. So, there are 12 no downwardly directed drag forces acting on the ball sealers to keep them 13 below the lowest perforation taking the treating fluid. ~ence, the upward 14 buoyancy forces acting on the ball sealers will dominate in this interval.
Therefore, the practice of the present invention results in the 16 vertical velocity of each ball sealer being a function of its vertical 17 position within the casing. At least below the lowest perforation, and 18 possibly higher if little fluid is flowing down to and through the lower 19 perforations, the net vertical velocity of each ball sealer will be upward due to the dominance of the buoyancy force over any downward fluid drag 21 force. At least above the highest perforation, and possibly lower if 22 little fluid is flowing through those higher perforations, the net vertical 23 velocity of each ball sealer will be downward due to the dominance of the 24 downward fluid drag force over the buoyancy force.
The ball sealers having a density less than the density of the 26 treating fluid will remain within, or moving toward, that portion of the 27 casing between the uppermost perforation and the lowermost perforation 28 through which fluid is flowing until the ball sealers seat upon a per-29 foration. While suspended within that portion of the casing, the motion of the fluid radially outward into and through the perforations will exert _g_ :
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~o~u6~3 drag forces on the ball sealers to move them radially outward to the perfora- -2 tions where they will seat and be held there by the pressure differential.
3 The net result of the use of the present invention is that the 4 ball sealers injected into the well and transported to the perforated zone of the casing will always seat upon and plug the perforations through which 6 fluid is flowing with an invariable 100% efficiency. That is, each and 7 every ball sealer will seat and plug a perforation as long as there is a - 8 perforation through which fluid is flowing and the flow of fluid down the - -9 casing above the uppermost perforation is sufficient to impart a downward ~-drag force on each ball sealer greater in magnitude than the buoyancy force 11 acting on that ball sealer.
12 When the treatment has been completed and the pr~ssure differ-13 ential relieved or reversed, the ball sealers will unseat from the perfora-14 tions. With ball sealers having a density less than the treating fluid, in accordance with the present invention, all ball sealers will naturally 16 migrate upward. Therefore, some means should be provided to catch these 17 ball sealers before they pass into equipment which they might clog or 18 damage. A ball catcher 30 which will accomplish this is depicted in 19 FIGURE 2.
FIGURE 2 shows a typical arrangement of wellhead equipment for a 21 producing well. The well casing 2 extends slightiy above the ground level 22 and supports the wellhead 20. The production tubing 6 is contained within 23 the casing 2 and connects with the lower end of the master valve 21. The 24 master valve 21 controls the flow of oil and gas from the well. Above the master valve 21 is a tee 25 which provides communication with the well 26 either through the crown valve 22 or the wing valve 23. Various workover 27 equipment can be attached to the upper end of the crown valve 22 and communi-28 cation between that equipment and the well is accomplished by opening the 29 crown valve 22 and master valve 21. Ordinarily the crown valve 22 is maintained in a closed position. Production from the well flows from the , : :: .. . . - :
... .
1 tee 25 laterally into the wing valve 23. The wing valve 23 directs the 2 flow of fluids from the wellhead to the gathering flowline 26.
3 A ball catcher 30, shown in section, is located downstream of the 4 wing valve and upstream of the flow controlling choke 24. The produced fluid will pass through the ball catcher 30 but the ball sealers will be 6 trapped therein. After the produced fluid passes through the choke 24 it 7 moves into a gathering flowline 26 which will typically transport the fluid 8 to a separation facility and then either to holding tanks or to a pipeline.
9 The ball catcher 30 is basically a tee having a deflector insert 34 containing a deflector grid 35 inserted into the downstream end of the 11 tee. The deflector grid 35 allows fluid to pass through it but it will not 12 allow objects the size of the ball sealers to proceed further downstream.
13 Preferably the deflector grid 35 is angled within the ball catcher 30 so 14 that when the ball sealers strike the deflector grid 35, they will be deflected into the tee's deadleg 32. A deadleg cap 33 is attached to the 16 lower end of the deadleg 32 and can be easily removed, when the wing valve 17 is closed and the pressure bled down, to allow the removal of the trapped 18 ball sealers.
19 Experiments were conducted to test the seating efficiencies of ball sealers utilized according to present practices, i.e., ball sealers 21 having 8 density greater ~han the treacing fluid, and ball sealers utilized 22 according to the present invention, i.e., ball sealers having a density 23 less than the density of the treating fluid.
24 The laboratory experiments were designed to simulate ball sealers seating on perforations in a casing. The experimental equipment included 26 an 8-foot long piece of 3-inch lucite tubing to represent a piece of casing.
27 The lucite tubing was mounted vertically in the laboratory and its lower 28 end sealed closed. Between 3 and 4 feet from the bottom of the tubing, 29 five vertically aligned holes were drilled through the wall of the tubing to represent perforations. The holes were 3/8-inch in diameter and spaced 31 2-inches apart on center.
~. - , ~ -.~V~(,E~;~,3 1 A 90 elbow was placed on the upper end of the lucite tubing and 2 was connected by a flowline to a pump. The pump drew fluid from a reservoir - -3 tank and pumped it at various controlled rates through the flowline and 4 into the upper end of the tubing. The fluid flowed down the lucite tubing, through the perforations and returned by a flowline to the reservoir tank.
6 To inject the ball sealers a suitable hole ~as made in the elbow 7 and a l-inch diameter piece of tubing welded in the hole. The end of the 8 l-inch tubing was centered to be coaxial with the lucite tubing at the 9 upper end of the lucite tubing. The ball sealers were introduced into the lucite tubing through the l-inch tubing.
11 The flow of fluid into the upper end of the lucite tubing was 12 measured. It was assumed that the flow through each perforation was the 13 same and therefore the flow through each perforation was taken to be 1/5 of 14 the measured flow into the upper end of the lucite tubing.
During the experiments, water, having a density of 1.0 grams per 16 cubic centimeter (g/cc), was used as the fluid. Rigid ball sealers were 17 made from four different materials having different densities. The balls 18 were all 3t4" in diameter and were made from polypropylene (0.84-0.86 g/cc 19 density), nylon (1.11 g/cc density), acetal (1.39 g/cc density) and teflon (2.17 g/cc density). These ball sealers did not have an elastomeric cover.
21 In practice, ball sealers are usually covered with an elastomer, such as 22 rubber, so that they effect a better seal, but the purpose of these experi-23 ments was to observe seating characteristics and not sealing characteristics.
24 The experiment generally involved establishing a specific flow ~ -rate of the fluid through the perforations, injecting the ball sealers 26 through the l-inch tubing into the upper end of the 8-foot lucite tubing 27 and observing whether or not the ball sealers seated on the perforations.
28 The experimental program was conducted with ball sealers made of all four 29 materials being injected into the tubing ~-ith the water flowing through it.
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108~613 l A single set of tests involved injecting ten balls of the same 2 material, one at a time, into the top of the 8-foot lucite tubing. An 3 observation was made whether or not the ball sealer seated on one of the 4 perforations. If a ball seated on a perforation, that ball was released from the perforation prior to dropping the next ball, so that there were 6 always five open perforations for each ball to seat upon. During a single 7 set of tests the fluid and its flow rate remained unchanged. After all ten 8 balls had been dropped, the number that seated upon perforations was defined 9 as the seating efficiency under those conditions and expressed as a percen-tage.
11 Six or seven tests were conducted to define a regression curve 12 plotting seating efficiency against flow rate through a peroration for 13 that particular ball sealer and fluid. These regression curves were 14 constructed for each set of equal density ball sealers. The data from those regression curves was then used to make the graph of FIGURE 3.
16 FIGURE 3 is a plot of seating efficiency versus the normalized 17 density contrast. The normalized density contrast is the difference in 18 density between the ball sealer and the fluid divided by the density of the 19 fluid. A positive normalized density contrast means the density of the ball sealer is greater than the density of the fluid and a negative normalized 21 density contrast means the density of the ball sealer is less than the 22 density of the fluid. It follows that a normalized density contrast of 23 zero means that the ball sealer and the fluid have the same density.
24 When the normalized density contrast is greater than zero, the seating efficiency was found to be a function of the flow through the 26 perforations. In FIGURE 3 there are four plots of seating efficiency 27 versus normalized density contrast for four different flow rates through a 28 perforation, 20 gallons per minute (gpm), 15 gpm, lO gpm, and 5 gpm. Also, 29 the seating efficiency was found to increase as the normalized density contrast decreased toward zero.
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1 When the normalized density contrast is less than zero, the 2 seating efficiency is always 100% provided that the flow of fluid downward 3 within the casing above the perforations is sufficient to impart a downward 4 drag force on the ball sealers which is greater in magnitude than the upward buoyancy force acting on the ball sealers. In other words, if the 6 downward flow of fluid within the casing is sufficient to transport the 7 ball sealers downward to the perforations, they will always seat.
8 It is a rather unique situation when the normalized density 9 contrast equals zero. As noted above, the normalized density contrast is zero when the density of the ball sealer is the same as the density of the 11 fluid. There were no tests conducted wherein the ball sealers had the 12 exact same density as the fluid ! but it appears from the rest of the data 13 that the seating efficiency for a normalized density contrast of zero 14 should be close to 100%. The seating efficiency may be slightly less than 100% since there exists the theoretical possibility of a ball sealer not 16 seating. This could occur should the ball sealer be carried downward by 17 the fluid to the level of the lowermost perforation without the ball seating 18 and should the ball subsequently travel below the level of the lowermost 19 perforation due to its inertia. It is conceivable that a ball sealer that overshoots the lowermost perforation due to its inertia will remain suspended 21 in the rathole without seating if the flow of fluid down .he casing and 22 through the perforations does not cause enough turbulence below the lowermost 23 perforation to somehow move that ball sealer upwards. This situation is 24 not possible if the ball sealers are less dense than the fluid since the buoyancy of the ball sealers will cause them to rise at least to the level 26 of the lowermost open perforation taking fluid.
27 When the normalized density contrast is greater than zero, i.e., 28 the density of the ball sealers being greater than the density of the 29 fluid, the seating efficiency of the ball sealers is a function of the flowrate through the perforation and the difference in density between the ball ' ;
~08~;13 sealers and the fluid. The greater the flow rate through the perforationand the less difference in density between the ball sealers and the fluid, the greater the seating efficiency will be. The seating efficiency of ball sealers having a density greater than the density of the fluid is always a statistical phenomenon. A variation in the number, spacing and orientation of~the perforations is highly likely to affect the precise seating efficiency which can be expected in that situation. Therefore, since the seating of ball sealers having a density greater than the density of the fluid is always a statistical phenomenon, there is always the possibility that too few or too many of the ball sealers will seat to get the desired diversion.
Practicing ball sealer diversion according to the present invention i.e., the use of ball sealers having a density less than the density of the fluid, will result in 100% seating efficiency irrespective of the flow rate through the perforations and îrrespective of the magnitude of difference in density between the ball sealers and the fluid. The seating efficiency of the ball sealers having a density less than the density of thQ fluid is only a function of the downward flow of fluid above the uppermost perforation in the casing. If the downward flow within the casing can transport the ball sealers to the level of the perforations, then the ball sealers will seat. A predictable diversion process will occur since the number of perforations plugged by the ball sealers will be equal to the lesser of the number of ball sealers injected into the casing, or the number of perforations accepting fluid.
The relationship between the normalized density contrast and the fluid velocity needed to transport the ball sealers down the casing was investi-gated. FIGURE 4 is a graph of the normalized density contrast between the ball sealers and the fluid plotted against the velocity of the fluid downward within the casing. This graph -ls based on several tests which involved placing a ball ~ealer within a vertical piece of lucite tubing and flowing fluid downward through the tubing. The velocity of the fluid was adjusted until the ball sealer was maintained in a fixed position -': , ., ~
1 at the mid-point of the tubing. In that equilibrium position the drag forces 2 of the fluid shearing past the ball sealer were equal in magnitude to the 3 buoyancy forces acting on the ball sealer. Ball sealers of several densities 4 were used in conjunction with two fluids, water and 1.13 g/cc calcium chloride brine, to give the plot of FIGURE 4.
6 The solid line defines the equilibrium condition wherein the ball 7 sealer will remain stationary within the casing, moving neither upward nor 8 downward. Below the line in FIGURE 4 the velocity of the fluid in the 9 casing would be insufficient to overcome the force of buoyancy and the ball sealers will rise in the casing. Above the line in FIGURE 4 the velocity 11 of the fluid in the casing exerts a drag force on the ball sealers greater 12 in magnitude than the force of buoyancy acting on the ball sealers. There~
13 fore, the ball sealers will be transported down the casing.
14 All points on the line and below it correspond to a certain normalized density contrast and a certain casing velocity which will 16 result in a seating efficiency of zero per cent. Because the ball sealers 17 are not transported down to the perforations, they cannot seat. Whereas,18 if the normalized density contrast and casing velocity define a point above 19 the line plotted in FIGURE 4, the seating efficiency will be lOOæ. If the ball sealers are transported to the perforations, they will seat. Their 21 buoyancy will maintain them at a position at or above the lowermost perfora-22 tion and the downward fluid velocity in the casing above the uppermost 23 perforation will maintain the ball sealers at or below the level of the 24 uppermost perforation. It will take a very small fluid flow through a perforation to draw a ball sealer to the perforation and seat it thereon i 26 when the amount of time the fluid flow through the perforation has to act 27 upon the ball s~aler is limited only by the length of the injection time.
28 To apply the present invention in the field, it is necessary to 29 have a ball sealer which has a density less than the wellbore fluid and at the same time has the strength to withstand the pressures encountered in .
', ~0~13 1 the wellbore. It is not unusual for the bottom hole pressure to exceed 2 10,000 psi and even reach 15,000 psi during a well treatment. If a ball 3 sealer cannot withstand these pressures, they will collapse causing the 4 density of the ball sealer to increase to a density which can easily exceed the fluid density.
6 Since fluids used for treating wells generally have densities 7 ranging from approximately 0.8 grams per cubic centimeter (g/cc) to signi-8 ficantly above 1.1 g/cc, a series of light weight ball sealers are required 9 having densities in the same 0.8 to 1.1 g/cc range.
Suitable materials are currently available for use in conjunction 11 with ball sealers in the 1.1 g/cc range and greater. In the range from 0.8 12 to 1.1 g/cc, techniques at marlufacturing such ball sealers have not been 13 very satisfactory. For example, there is one commercially available BUNA-N
14 covered ball sealer having a phenolic core with considerable void volume which can have a density less than 1.0 g/cc. Since the void volume in the 16 phenolic core is created by partially consolidating a phenolic resin using 17 low pressure molding conditions, control of the density is extremely diffi-18 cult. A representative sample was tested and proved to have an average 19 density of .996 g/cc and a wide distribution (0.908 to 1.085 g/cc). ~loreover, when these ball sealers were hydrostatically pressure tested, it was found 21 that in many of the ball sealers ~he void volumes were unstable and had 22 collapsed when subjected to hydrostatic pressures as low as 6,000 pounds 23 per square inch. Correspondingly, when these void volumes collapsed, the 24 density of the ball sealers increased.
A ball sealer capable of withstanding great pressures and having 26 a density in the 0.8 to 1.1 g/cc range is depicted in FIGURE 5. The spherical -27 ball sealer 10 has a spherical core 101 made of syntactic foam covered with 28 an elastomeric material 201.
29 Syntactic foam is a material system comprised of hollow spherical particles dispersed in some form of binder. The commercially available low .
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. - : . ~, 108~3 1 density syntactic foams which appear to be sufficiently strong to withstand 2 the pressures and temperatures typically encountered by ball sealers, 3 consist of microscopically sm211, hollow glass spheres (averaging approxi-4 mately 50 microns in diameter) dispersed in a resin binder such as epoxy.
It is anticipated that in the future it may become possible in syntactic 6 foam systems to use spheres made from materials other than glass and 7 binders made from materials such as thermoplastics and thermosetting plas-8 tics. In fact, Emerson and Cuming Inc. has recently developed high strength 9 glass microspheres which can withstand high pressures of the magnitude typically encountered during injection molding. If injection molding can llbe used to make ball sealers, it will be possible to use a lightweight ~-12 thermoplastic or thermosetting plastic as the binder resulting in a high 13 strength ball sealer having a very low density.
14Several of the commercially available syntactic foams which appear to be suitable for use as the core material of a low density ball 16 sealer are listed in Table I.
i 19Hydrostatic Compressive Bulk ` 21 Product ManufacturerDensity Strength Modulus 22 (g/cc) (psi) (psi) ; 23 EL 30 Emerson & Cuming 0.48 8,000 250,000 24 EL 36 Emerson & Cuming 0.57 16,000 390,000 EL 39 Emerson & Cuming 0.62 24,000 420,000 26 EF 38 Emerson & Cuming 0.60 7,000 Not Available 27 34-2C6 Lockheet 0.54 18,000 Not Available 28 36-lB4 Lockheed 0.57 13,650 Not Available 29 39-1~5 Lockheed 0.62 15,600 Not Available 1 30 XP-241-36 3M O.57 11,000 325,000 31 XP-241-42H 3M 0.57 20,000 450,000 il .
1~8~6~3 1 The syntactic foams listed in Table I show very good strength 2 when subjected to hydrostatic compression. nany of the materials will 3 easily withstand 15,000 psi. Furthermore, each of the syntactic foams for 4 which the bulk modulus of elasticity was available has a bulk modulus of elasticity comparable to that of water, which is 300,000 psi.
6 The bulk modulus of elasticity is the inverse of material compressi-7 bility. It represents a material's resistance to volumetric change as a 8 function of hydrostatic pressure. For example, if the bulk modulus of a 9 material is greater than that of water, the material will be less compressi-ble than water. Hence, the material's buoyancy will increase with respect 11 to the water when both are being subjected to the same pressure since the 12 water will be compressed more. This qualily of these syntactic foams will 13 .assure that the density of the ball sealers remains less than the density 14 of the treating fluid, thereby, avoiding the problems encountered with the phenolic core ball sealers.
16 Syntactic foam is currently available only in blocks with a 17 standard volume of approximately l cubic foot. Therefore, the first step 18 in the fabrication of syntactic foam ball sealers is to machine the syntactic 19 foam blocks to produce 3/4-inch diameter syntactic foam spheres. The spheres are then surface prepped, coated with a suitable bonding agent and 21 covered with the desired covering. ~ -22 Surface preparation involving some cleaning technique is required ~ -23 to assure the best possible bond between the covering and the syntactic 24 foam. It is most desirable if surface preparation can be limited to a strong air blast which will remove most of the crushed glass and debris 26 created during machining. Sand blasting has been used with very good -27 success but its use should be limited to very brief treatments due to rapid 28 abrasion of the core which leads to increased ball density as well as a 29 highly variable batch density. If the spheres have been handled or are oily, a trichlorylethelene wash has been used satisfactorily. Once the - : ~ : -i13 1 spheres are grease and oil free, they can be dipped in a suitable bonding 2 agent selected according to the covering material to be used.
3 Rubber can be used as the elastomeric covering material. After 4 the uncured rubber cover has been compressed around the foam balls with an arbor press, the balls are ready for molding. The exact temperature, 6 pressure, and cure time will vary with rubber compounds. Curing processes 7 are old and known in the art.
8 The critical parameter in the curing process ~ith respect to 9 syntactic foam ball sealers is the temperature. Since the cure tempera-tures are generally held for about l/2 hour at around 300F for the BUNA-N
11 or epichlorohydrin rubber compounds, it is imperative that the syntactic 12 foam binder is formulated to be heat compatible.
13 All of the manufacturers of the syntactic foam systems listed in ~' 14 Table I have epoxy binder systems using suitable hardeners, such as anhydrite, which do not soften or decompose at these elevated temperatures (around 16 300F). The only polyamide binder system tested was EF 38 (Table I), and 17 it was found to be unsuitable when subjected to temperatures greater than 18 250F.
19 While Table I lists the densities of those selected syntactic foam materials, the overall density of a ball sealer is determined by both 21 the core material and the cover material. Table II sets forth t~e statistics, 22 including the overall ball density, of four groups of rubbercovered syntactic 23 foa= ball sealers which have been manufactDred.
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~: ' 10~(~613 2 MANUFACTURED RUBBER COVERED SYNTACTIC FOA~ BALL SEALERS
3 Average F. H. Maloney Co.
5 Quantity (g/cc) Size Rubber Compound Syntactic Foam 6 275 .879 7/8" 490 FB Lockheed 36-lB4 7 242 .994 7/8" 483 Lockheed 36-lB4 8 237 .898 7/8" 490 FB Lockheed 36-lB4 9 175 .832 1-1/4" 490 FB Lockheed 36-lB4 --Initial screening tests carried out on the manufactured syn-11 tactic foam ball sealers have shown them to be mechanically stable when 12 subjected to a 1500 psi differential pressure across simulated perfora-13 tions and when subjected to temperatures on the order of 170F. Further-14 more, when subjected to hydrostatic pressures, these ball sealers did not begin to fail until pressures of approximately 13,500 psi were 16 reached. At that time they began to fail inelastically due to the 17 collapse of the syntactic foam. Failure at this pressure corresponds 18 extremely well with the manufacturers stated hydrostatic compressive 19 strength of 13,650 psi (see Table I, Lockheed 36-lB4).
Although syntactic foam is one ball sealer core material, 21 certain thermoplastics can be used. Although no unfoamed plastics 22 exhibit sufficiently low densities to make a .8 to .9 g/cc ball sealer, 23 polymethylpentene can be used as a core material for ball sealers in 24 the 1.0 g/cc density range. Polymethylpentene has a density of .83 g/cc and is a high temperature thermoplastic (melting point approxi-26 mately 250C). All other lightweight plastics, which typically include 27 polybutylene, polyethylene, polypropylene, and polyallomer copolymers, 28 are nearly twice as hea~y as is acceptable. Furthermore, since these 29 materials are low temperature thermoplastics, they are probably not ~:
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1 suitable for ball sealer cores from the standpoint that they are likely to 2 extrude through the perforations under the bottom hole temperature and 3 pressure conditions typically encountered.
4 The principle of the invention and the best mode in which it is contemplated to apply that principle have been described. It is to be 6 understood that the foregoing is illustrative only and that other means and 7 techniques can be employed without departing from the true scope of the 8 invention defined in the claims.
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10 !3Q~;13 1 downward. It is essential that the downward fluid velocity in the 2 production tubing 6 and in the casing 2 above the perforations 4 be 3 sufficient to impart a downward drag force on the ball sealers which is 4 greater in magnitude than the upward force of buoyancy acting on the 5 ball sealers. This results in the ball sealers being carried downward 6 to the section of the casing which has been perforated.
7 When ball sealers are utilized in accordance with the present 8 invention, they will never remain in the rathole 8; that is, below the 9 lowest perforation through which the treating fluid is flowing, due to the 10 buoyancy of the ball sealers. ~elow the lowest perforation accepting the 11 treating fluid, the fluid in the wellbore remains sta~na~t. So, there are 12 no downwardly directed drag forces acting on the ball sealers to keep them 13 below the lowest perforation taking the treating fluid. ~ence, the upward 14 buoyancy forces acting on the ball sealers will dominate in this interval.
Therefore, the practice of the present invention results in the 16 vertical velocity of each ball sealer being a function of its vertical 17 position within the casing. At least below the lowest perforation, and 18 possibly higher if little fluid is flowing down to and through the lower 19 perforations, the net vertical velocity of each ball sealer will be upward due to the dominance of the buoyancy force over any downward fluid drag 21 force. At least above the highest perforation, and possibly lower if 22 little fluid is flowing through those higher perforations, the net vertical 23 velocity of each ball sealer will be downward due to the dominance of the 24 downward fluid drag force over the buoyancy force.
The ball sealers having a density less than the density of the 26 treating fluid will remain within, or moving toward, that portion of the 27 casing between the uppermost perforation and the lowermost perforation 28 through which fluid is flowing until the ball sealers seat upon a per-29 foration. While suspended within that portion of the casing, the motion of the fluid radially outward into and through the perforations will exert _g_ :
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~o~u6~3 drag forces on the ball sealers to move them radially outward to the perfora- -2 tions where they will seat and be held there by the pressure differential.
3 The net result of the use of the present invention is that the 4 ball sealers injected into the well and transported to the perforated zone of the casing will always seat upon and plug the perforations through which 6 fluid is flowing with an invariable 100% efficiency. That is, each and 7 every ball sealer will seat and plug a perforation as long as there is a - 8 perforation through which fluid is flowing and the flow of fluid down the - -9 casing above the uppermost perforation is sufficient to impart a downward ~-drag force on each ball sealer greater in magnitude than the buoyancy force 11 acting on that ball sealer.
12 When the treatment has been completed and the pr~ssure differ-13 ential relieved or reversed, the ball sealers will unseat from the perfora-14 tions. With ball sealers having a density less than the treating fluid, in accordance with the present invention, all ball sealers will naturally 16 migrate upward. Therefore, some means should be provided to catch these 17 ball sealers before they pass into equipment which they might clog or 18 damage. A ball catcher 30 which will accomplish this is depicted in 19 FIGURE 2.
FIGURE 2 shows a typical arrangement of wellhead equipment for a 21 producing well. The well casing 2 extends slightiy above the ground level 22 and supports the wellhead 20. The production tubing 6 is contained within 23 the casing 2 and connects with the lower end of the master valve 21. The 24 master valve 21 controls the flow of oil and gas from the well. Above the master valve 21 is a tee 25 which provides communication with the well 26 either through the crown valve 22 or the wing valve 23. Various workover 27 equipment can be attached to the upper end of the crown valve 22 and communi-28 cation between that equipment and the well is accomplished by opening the 29 crown valve 22 and master valve 21. Ordinarily the crown valve 22 is maintained in a closed position. Production from the well flows from the , : :: .. . . - :
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1 tee 25 laterally into the wing valve 23. The wing valve 23 directs the 2 flow of fluids from the wellhead to the gathering flowline 26.
3 A ball catcher 30, shown in section, is located downstream of the 4 wing valve and upstream of the flow controlling choke 24. The produced fluid will pass through the ball catcher 30 but the ball sealers will be 6 trapped therein. After the produced fluid passes through the choke 24 it 7 moves into a gathering flowline 26 which will typically transport the fluid 8 to a separation facility and then either to holding tanks or to a pipeline.
9 The ball catcher 30 is basically a tee having a deflector insert 34 containing a deflector grid 35 inserted into the downstream end of the 11 tee. The deflector grid 35 allows fluid to pass through it but it will not 12 allow objects the size of the ball sealers to proceed further downstream.
13 Preferably the deflector grid 35 is angled within the ball catcher 30 so 14 that when the ball sealers strike the deflector grid 35, they will be deflected into the tee's deadleg 32. A deadleg cap 33 is attached to the 16 lower end of the deadleg 32 and can be easily removed, when the wing valve 17 is closed and the pressure bled down, to allow the removal of the trapped 18 ball sealers.
19 Experiments were conducted to test the seating efficiencies of ball sealers utilized according to present practices, i.e., ball sealers 21 having 8 density greater ~han the treacing fluid, and ball sealers utilized 22 according to the present invention, i.e., ball sealers having a density 23 less than the density of the treating fluid.
24 The laboratory experiments were designed to simulate ball sealers seating on perforations in a casing. The experimental equipment included 26 an 8-foot long piece of 3-inch lucite tubing to represent a piece of casing.
27 The lucite tubing was mounted vertically in the laboratory and its lower 28 end sealed closed. Between 3 and 4 feet from the bottom of the tubing, 29 five vertically aligned holes were drilled through the wall of the tubing to represent perforations. The holes were 3/8-inch in diameter and spaced 31 2-inches apart on center.
~. - , ~ -.~V~(,E~;~,3 1 A 90 elbow was placed on the upper end of the lucite tubing and 2 was connected by a flowline to a pump. The pump drew fluid from a reservoir - -3 tank and pumped it at various controlled rates through the flowline and 4 into the upper end of the tubing. The fluid flowed down the lucite tubing, through the perforations and returned by a flowline to the reservoir tank.
6 To inject the ball sealers a suitable hole ~as made in the elbow 7 and a l-inch diameter piece of tubing welded in the hole. The end of the 8 l-inch tubing was centered to be coaxial with the lucite tubing at the 9 upper end of the lucite tubing. The ball sealers were introduced into the lucite tubing through the l-inch tubing.
11 The flow of fluid into the upper end of the lucite tubing was 12 measured. It was assumed that the flow through each perforation was the 13 same and therefore the flow through each perforation was taken to be 1/5 of 14 the measured flow into the upper end of the lucite tubing.
During the experiments, water, having a density of 1.0 grams per 16 cubic centimeter (g/cc), was used as the fluid. Rigid ball sealers were 17 made from four different materials having different densities. The balls 18 were all 3t4" in diameter and were made from polypropylene (0.84-0.86 g/cc 19 density), nylon (1.11 g/cc density), acetal (1.39 g/cc density) and teflon (2.17 g/cc density). These ball sealers did not have an elastomeric cover.
21 In practice, ball sealers are usually covered with an elastomer, such as 22 rubber, so that they effect a better seal, but the purpose of these experi-23 ments was to observe seating characteristics and not sealing characteristics.
24 The experiment generally involved establishing a specific flow ~ -rate of the fluid through the perforations, injecting the ball sealers 26 through the l-inch tubing into the upper end of the 8-foot lucite tubing 27 and observing whether or not the ball sealers seated on the perforations.
28 The experimental program was conducted with ball sealers made of all four 29 materials being injected into the tubing ~-ith the water flowing through it.
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108~613 l A single set of tests involved injecting ten balls of the same 2 material, one at a time, into the top of the 8-foot lucite tubing. An 3 observation was made whether or not the ball sealer seated on one of the 4 perforations. If a ball seated on a perforation, that ball was released from the perforation prior to dropping the next ball, so that there were 6 always five open perforations for each ball to seat upon. During a single 7 set of tests the fluid and its flow rate remained unchanged. After all ten 8 balls had been dropped, the number that seated upon perforations was defined 9 as the seating efficiency under those conditions and expressed as a percen-tage.
11 Six or seven tests were conducted to define a regression curve 12 plotting seating efficiency against flow rate through a peroration for 13 that particular ball sealer and fluid. These regression curves were 14 constructed for each set of equal density ball sealers. The data from those regression curves was then used to make the graph of FIGURE 3.
16 FIGURE 3 is a plot of seating efficiency versus the normalized 17 density contrast. The normalized density contrast is the difference in 18 density between the ball sealer and the fluid divided by the density of the 19 fluid. A positive normalized density contrast means the density of the ball sealer is greater than the density of the fluid and a negative normalized 21 density contrast means the density of the ball sealer is less than the 22 density of the fluid. It follows that a normalized density contrast of 23 zero means that the ball sealer and the fluid have the same density.
24 When the normalized density contrast is greater than zero, the seating efficiency was found to be a function of the flow through the 26 perforations. In FIGURE 3 there are four plots of seating efficiency 27 versus normalized density contrast for four different flow rates through a 28 perforation, 20 gallons per minute (gpm), 15 gpm, lO gpm, and 5 gpm. Also, 29 the seating efficiency was found to increase as the normalized density contrast decreased toward zero.
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1 When the normalized density contrast is less than zero, the 2 seating efficiency is always 100% provided that the flow of fluid downward 3 within the casing above the perforations is sufficient to impart a downward 4 drag force on the ball sealers which is greater in magnitude than the upward buoyancy force acting on the ball sealers. In other words, if the 6 downward flow of fluid within the casing is sufficient to transport the 7 ball sealers downward to the perforations, they will always seat.
8 It is a rather unique situation when the normalized density 9 contrast equals zero. As noted above, the normalized density contrast is zero when the density of the ball sealer is the same as the density of the 11 fluid. There were no tests conducted wherein the ball sealers had the 12 exact same density as the fluid ! but it appears from the rest of the data 13 that the seating efficiency for a normalized density contrast of zero 14 should be close to 100%. The seating efficiency may be slightly less than 100% since there exists the theoretical possibility of a ball sealer not 16 seating. This could occur should the ball sealer be carried downward by 17 the fluid to the level of the lowermost perforation without the ball seating 18 and should the ball subsequently travel below the level of the lowermost 19 perforation due to its inertia. It is conceivable that a ball sealer that overshoots the lowermost perforation due to its inertia will remain suspended 21 in the rathole without seating if the flow of fluid down .he casing and 22 through the perforations does not cause enough turbulence below the lowermost 23 perforation to somehow move that ball sealer upwards. This situation is 24 not possible if the ball sealers are less dense than the fluid since the buoyancy of the ball sealers will cause them to rise at least to the level 26 of the lowermost open perforation taking fluid.
27 When the normalized density contrast is greater than zero, i.e., 28 the density of the ball sealers being greater than the density of the 29 fluid, the seating efficiency of the ball sealers is a function of the flowrate through the perforation and the difference in density between the ball ' ;
~08~;13 sealers and the fluid. The greater the flow rate through the perforationand the less difference in density between the ball sealers and the fluid, the greater the seating efficiency will be. The seating efficiency of ball sealers having a density greater than the density of the fluid is always a statistical phenomenon. A variation in the number, spacing and orientation of~the perforations is highly likely to affect the precise seating efficiency which can be expected in that situation. Therefore, since the seating of ball sealers having a density greater than the density of the fluid is always a statistical phenomenon, there is always the possibility that too few or too many of the ball sealers will seat to get the desired diversion.
Practicing ball sealer diversion according to the present invention i.e., the use of ball sealers having a density less than the density of the fluid, will result in 100% seating efficiency irrespective of the flow rate through the perforations and îrrespective of the magnitude of difference in density between the ball sealers and the fluid. The seating efficiency of the ball sealers having a density less than the density of thQ fluid is only a function of the downward flow of fluid above the uppermost perforation in the casing. If the downward flow within the casing can transport the ball sealers to the level of the perforations, then the ball sealers will seat. A predictable diversion process will occur since the number of perforations plugged by the ball sealers will be equal to the lesser of the number of ball sealers injected into the casing, or the number of perforations accepting fluid.
The relationship between the normalized density contrast and the fluid velocity needed to transport the ball sealers down the casing was investi-gated. FIGURE 4 is a graph of the normalized density contrast between the ball sealers and the fluid plotted against the velocity of the fluid downward within the casing. This graph -ls based on several tests which involved placing a ball ~ealer within a vertical piece of lucite tubing and flowing fluid downward through the tubing. The velocity of the fluid was adjusted until the ball sealer was maintained in a fixed position -': , ., ~
1 at the mid-point of the tubing. In that equilibrium position the drag forces 2 of the fluid shearing past the ball sealer were equal in magnitude to the 3 buoyancy forces acting on the ball sealer. Ball sealers of several densities 4 were used in conjunction with two fluids, water and 1.13 g/cc calcium chloride brine, to give the plot of FIGURE 4.
6 The solid line defines the equilibrium condition wherein the ball 7 sealer will remain stationary within the casing, moving neither upward nor 8 downward. Below the line in FIGURE 4 the velocity of the fluid in the 9 casing would be insufficient to overcome the force of buoyancy and the ball sealers will rise in the casing. Above the line in FIGURE 4 the velocity 11 of the fluid in the casing exerts a drag force on the ball sealers greater 12 in magnitude than the force of buoyancy acting on the ball sealers. There~
13 fore, the ball sealers will be transported down the casing.
14 All points on the line and below it correspond to a certain normalized density contrast and a certain casing velocity which will 16 result in a seating efficiency of zero per cent. Because the ball sealers 17 are not transported down to the perforations, they cannot seat. Whereas,18 if the normalized density contrast and casing velocity define a point above 19 the line plotted in FIGURE 4, the seating efficiency will be lOOæ. If the ball sealers are transported to the perforations, they will seat. Their 21 buoyancy will maintain them at a position at or above the lowermost perfora-22 tion and the downward fluid velocity in the casing above the uppermost 23 perforation will maintain the ball sealers at or below the level of the 24 uppermost perforation. It will take a very small fluid flow through a perforation to draw a ball sealer to the perforation and seat it thereon i 26 when the amount of time the fluid flow through the perforation has to act 27 upon the ball s~aler is limited only by the length of the injection time.
28 To apply the present invention in the field, it is necessary to 29 have a ball sealer which has a density less than the wellbore fluid and at the same time has the strength to withstand the pressures encountered in .
', ~0~13 1 the wellbore. It is not unusual for the bottom hole pressure to exceed 2 10,000 psi and even reach 15,000 psi during a well treatment. If a ball 3 sealer cannot withstand these pressures, they will collapse causing the 4 density of the ball sealer to increase to a density which can easily exceed the fluid density.
6 Since fluids used for treating wells generally have densities 7 ranging from approximately 0.8 grams per cubic centimeter (g/cc) to signi-8 ficantly above 1.1 g/cc, a series of light weight ball sealers are required 9 having densities in the same 0.8 to 1.1 g/cc range.
Suitable materials are currently available for use in conjunction 11 with ball sealers in the 1.1 g/cc range and greater. In the range from 0.8 12 to 1.1 g/cc, techniques at marlufacturing such ball sealers have not been 13 very satisfactory. For example, there is one commercially available BUNA-N
14 covered ball sealer having a phenolic core with considerable void volume which can have a density less than 1.0 g/cc. Since the void volume in the 16 phenolic core is created by partially consolidating a phenolic resin using 17 low pressure molding conditions, control of the density is extremely diffi-18 cult. A representative sample was tested and proved to have an average 19 density of .996 g/cc and a wide distribution (0.908 to 1.085 g/cc). ~loreover, when these ball sealers were hydrostatically pressure tested, it was found 21 that in many of the ball sealers ~he void volumes were unstable and had 22 collapsed when subjected to hydrostatic pressures as low as 6,000 pounds 23 per square inch. Correspondingly, when these void volumes collapsed, the 24 density of the ball sealers increased.
A ball sealer capable of withstanding great pressures and having 26 a density in the 0.8 to 1.1 g/cc range is depicted in FIGURE 5. The spherical -27 ball sealer 10 has a spherical core 101 made of syntactic foam covered with 28 an elastomeric material 201.
29 Syntactic foam is a material system comprised of hollow spherical particles dispersed in some form of binder. The commercially available low .
' - :
. - : . ~, 108~3 1 density syntactic foams which appear to be sufficiently strong to withstand 2 the pressures and temperatures typically encountered by ball sealers, 3 consist of microscopically sm211, hollow glass spheres (averaging approxi-4 mately 50 microns in diameter) dispersed in a resin binder such as epoxy.
It is anticipated that in the future it may become possible in syntactic 6 foam systems to use spheres made from materials other than glass and 7 binders made from materials such as thermoplastics and thermosetting plas-8 tics. In fact, Emerson and Cuming Inc. has recently developed high strength 9 glass microspheres which can withstand high pressures of the magnitude typically encountered during injection molding. If injection molding can llbe used to make ball sealers, it will be possible to use a lightweight ~-12 thermoplastic or thermosetting plastic as the binder resulting in a high 13 strength ball sealer having a very low density.
14Several of the commercially available syntactic foams which appear to be suitable for use as the core material of a low density ball 16 sealer are listed in Table I.
i 19Hydrostatic Compressive Bulk ` 21 Product ManufacturerDensity Strength Modulus 22 (g/cc) (psi) (psi) ; 23 EL 30 Emerson & Cuming 0.48 8,000 250,000 24 EL 36 Emerson & Cuming 0.57 16,000 390,000 EL 39 Emerson & Cuming 0.62 24,000 420,000 26 EF 38 Emerson & Cuming 0.60 7,000 Not Available 27 34-2C6 Lockheet 0.54 18,000 Not Available 28 36-lB4 Lockheed 0.57 13,650 Not Available 29 39-1~5 Lockheed 0.62 15,600 Not Available 1 30 XP-241-36 3M O.57 11,000 325,000 31 XP-241-42H 3M 0.57 20,000 450,000 il .
1~8~6~3 1 The syntactic foams listed in Table I show very good strength 2 when subjected to hydrostatic compression. nany of the materials will 3 easily withstand 15,000 psi. Furthermore, each of the syntactic foams for 4 which the bulk modulus of elasticity was available has a bulk modulus of elasticity comparable to that of water, which is 300,000 psi.
6 The bulk modulus of elasticity is the inverse of material compressi-7 bility. It represents a material's resistance to volumetric change as a 8 function of hydrostatic pressure. For example, if the bulk modulus of a 9 material is greater than that of water, the material will be less compressi-ble than water. Hence, the material's buoyancy will increase with respect 11 to the water when both are being subjected to the same pressure since the 12 water will be compressed more. This qualily of these syntactic foams will 13 .assure that the density of the ball sealers remains less than the density 14 of the treating fluid, thereby, avoiding the problems encountered with the phenolic core ball sealers.
16 Syntactic foam is currently available only in blocks with a 17 standard volume of approximately l cubic foot. Therefore, the first step 18 in the fabrication of syntactic foam ball sealers is to machine the syntactic 19 foam blocks to produce 3/4-inch diameter syntactic foam spheres. The spheres are then surface prepped, coated with a suitable bonding agent and 21 covered with the desired covering. ~ -22 Surface preparation involving some cleaning technique is required ~ -23 to assure the best possible bond between the covering and the syntactic 24 foam. It is most desirable if surface preparation can be limited to a strong air blast which will remove most of the crushed glass and debris 26 created during machining. Sand blasting has been used with very good -27 success but its use should be limited to very brief treatments due to rapid 28 abrasion of the core which leads to increased ball density as well as a 29 highly variable batch density. If the spheres have been handled or are oily, a trichlorylethelene wash has been used satisfactorily. Once the - : ~ : -i13 1 spheres are grease and oil free, they can be dipped in a suitable bonding 2 agent selected according to the covering material to be used.
3 Rubber can be used as the elastomeric covering material. After 4 the uncured rubber cover has been compressed around the foam balls with an arbor press, the balls are ready for molding. The exact temperature, 6 pressure, and cure time will vary with rubber compounds. Curing processes 7 are old and known in the art.
8 The critical parameter in the curing process ~ith respect to 9 syntactic foam ball sealers is the temperature. Since the cure tempera-tures are generally held for about l/2 hour at around 300F for the BUNA-N
11 or epichlorohydrin rubber compounds, it is imperative that the syntactic 12 foam binder is formulated to be heat compatible.
13 All of the manufacturers of the syntactic foam systems listed in ~' 14 Table I have epoxy binder systems using suitable hardeners, such as anhydrite, which do not soften or decompose at these elevated temperatures (around 16 300F). The only polyamide binder system tested was EF 38 (Table I), and 17 it was found to be unsuitable when subjected to temperatures greater than 18 250F.
19 While Table I lists the densities of those selected syntactic foam materials, the overall density of a ball sealer is determined by both 21 the core material and the cover material. Table II sets forth t~e statistics, 22 including the overall ball density, of four groups of rubbercovered syntactic 23 foa= ball sealers which have been manufactDred.
, :.
;~
~: ' 10~(~613 2 MANUFACTURED RUBBER COVERED SYNTACTIC FOA~ BALL SEALERS
3 Average F. H. Maloney Co.
5 Quantity (g/cc) Size Rubber Compound Syntactic Foam 6 275 .879 7/8" 490 FB Lockheed 36-lB4 7 242 .994 7/8" 483 Lockheed 36-lB4 8 237 .898 7/8" 490 FB Lockheed 36-lB4 9 175 .832 1-1/4" 490 FB Lockheed 36-lB4 --Initial screening tests carried out on the manufactured syn-11 tactic foam ball sealers have shown them to be mechanically stable when 12 subjected to a 1500 psi differential pressure across simulated perfora-13 tions and when subjected to temperatures on the order of 170F. Further-14 more, when subjected to hydrostatic pressures, these ball sealers did not begin to fail until pressures of approximately 13,500 psi were 16 reached. At that time they began to fail inelastically due to the 17 collapse of the syntactic foam. Failure at this pressure corresponds 18 extremely well with the manufacturers stated hydrostatic compressive 19 strength of 13,650 psi (see Table I, Lockheed 36-lB4).
Although syntactic foam is one ball sealer core material, 21 certain thermoplastics can be used. Although no unfoamed plastics 22 exhibit sufficiently low densities to make a .8 to .9 g/cc ball sealer, 23 polymethylpentene can be used as a core material for ball sealers in 24 the 1.0 g/cc density range. Polymethylpentene has a density of .83 g/cc and is a high temperature thermoplastic (melting point approxi-26 mately 250C). All other lightweight plastics, which typically include 27 polybutylene, polyethylene, polypropylene, and polyallomer copolymers, 28 are nearly twice as hea~y as is acceptable. Furthermore, since these 29 materials are low temperature thermoplastics, they are probably not ~:
, - - - . ~ - - : : :
. . : :. , . . - :
- : ~ .
1 suitable for ball sealer cores from the standpoint that they are likely to 2 extrude through the perforations under the bottom hole temperature and 3 pressure conditions typically encountered.
4 The principle of the invention and the best mode in which it is contemplated to apply that principle have been described. It is to be 6 understood that the foregoing is illustrative only and that other means and 7 techniques can be employed without departing from the true scope of the 8 invention defined in the claims.
, , . :
., .
''`1 .
,, .
~ -22-
Claims (8)
OR PRIVILEGE IS CLAIMED ARE DEFINED AS FOLLOWS:
1. A method for treating a subterranean formation surrounding a casing having at least two perforations comprising:
injecting a treating fluid into the casing to cause a flow of fluid through at least one of the perforations and into the formation;
thereafter, injecting into the casing treating fluid carrying a ball sealer having a syntactic foam core and an elastomeric cover, the ball sealer having a size sufficient to plug a perforation and having a density less than the density of the treating fluid being injected into the casing, the injection of the treating fluid into the casing being at a rate sufficient to carry the ball sealer down the casing and substantially sealing one of the perfora-tions; and thereafter, injecting the treating fluid into the casing to cause a flow of fluid through the perforation which the ball sealer did not seat upon.
injecting a treating fluid into the casing to cause a flow of fluid through at least one of the perforations and into the formation;
thereafter, injecting into the casing treating fluid carrying a ball sealer having a syntactic foam core and an elastomeric cover, the ball sealer having a size sufficient to plug a perforation and having a density less than the density of the treating fluid being injected into the casing, the injection of the treating fluid into the casing being at a rate sufficient to carry the ball sealer down the casing and substantially sealing one of the perfora-tions; and thereafter, injecting the treating fluid into the casing to cause a flow of fluid through the perforation which the ball sealer did not seat upon.
2. A method of plugging the perforations in a casing which has been set in a wellbore comprising:
downwardly flowing into said casing a carrier liquid having ball sealers suspended therein, said ball sealers having syntactic foam cores and elastomeric covers, said ball sealers having a density less than the density of the carrier liquid and being of sufficient size to plug the casing perforations; and maintaining the flow velocity of said carrier fluid at a rate sufficient to overcome the buoyancy of said ball sealers and sufficient to transport said ball sealers to the perforations.
downwardly flowing into said casing a carrier liquid having ball sealers suspended therein, said ball sealers having syntactic foam cores and elastomeric covers, said ball sealers having a density less than the density of the carrier liquid and being of sufficient size to plug the casing perforations; and maintaining the flow velocity of said carrier fluid at a rate sufficient to overcome the buoyancy of said ball sealers and sufficient to transport said ball sealers to the perforations.
3. A method for treating a subterranean formation surrounding a perforated casing which has been set in a wellbore comprising:
downwardly flowing a fluid within the casing and through the perforations into the formation surrounding the perforated parts of the casing;
injecting into the casing ball sealers having syntactic foam cores and elastomeric covers, said ball sealers having a size sufficient to plug the casing perforations and having a density less than the density of the downwardly flowing fluid within the casing; and, thereafter, continuing the downward flow of the fluid within the casing but at a rate such that the downward velocity of the fluid in the casing above the perforations is sufficient to impart a downward drag force on the ball sealers greater in magnitude than the upward buoyancy force acting on the ball sealers thereby transporting the ball sealers to the perfora-tions.
downwardly flowing a fluid within the casing and through the perforations into the formation surrounding the perforated parts of the casing;
injecting into the casing ball sealers having syntactic foam cores and elastomeric covers, said ball sealers having a size sufficient to plug the casing perforations and having a density less than the density of the downwardly flowing fluid within the casing; and, thereafter, continuing the downward flow of the fluid within the casing but at a rate such that the downward velocity of the fluid in the casing above the perforations is sufficient to impart a downward drag force on the ball sealers greater in magnitude than the upward buoyancy force acting on the ball sealers thereby transporting the ball sealers to the perfora-tions.
4. A ball sealer for plugging perforations in a casing which has been set in a wellbore comprising:
a. a syntactic foam core, said syntactic foam being a material system comprised of hollow spherical particles dispersed in a binder; and b. an elastomeric covering.
a. a syntactic foam core, said syntactic foam being a material system comprised of hollow spherical particles dispersed in a binder; and b. an elastomeric covering.
5. In a method of sequentially treating two strata of a subter-ranean formation surrounding a well casing having a plurality of perfora-tions formed therein wherein ball sealers suspended in the treating fluid are used to seal part of said perforations, the improvement wherein said ball sealers include a syntactic foam core and an elastomeric cover and have a density less than the treating fluid.
6. A method for treating a subterranean formation surrounding a casing having at least two perforations comprising:
injecting a treating fluid into the casing to cause a flow of fluid through at least one of the perforations and into the formation;
thereafter, injecting into the casing treating fluid carrying a ball sealer having a polymethylpentene core and an elastomeric cover, the ball sealer having a size sufficient to plug a perforation and having a density less than the density of the treating fluid being injected into the casing, the injection of the treating fluid into the casing being at a rate sufficient to carry the ball sealer town the casing and substantially sealing one of the perforations; and thereafter, injecting the treating fluid into the casing to cause a flow of fluid through the perforation which the ball sealer did not seat upon.
injecting a treating fluid into the casing to cause a flow of fluid through at least one of the perforations and into the formation;
thereafter, injecting into the casing treating fluid carrying a ball sealer having a polymethylpentene core and an elastomeric cover, the ball sealer having a size sufficient to plug a perforation and having a density less than the density of the treating fluid being injected into the casing, the injection of the treating fluid into the casing being at a rate sufficient to carry the ball sealer town the casing and substantially sealing one of the perforations; and thereafter, injecting the treating fluid into the casing to cause a flow of fluid through the perforation which the ball sealer did not seat upon.
7. A ball sealer for plugging perforations in a casing which has been set in a wellbore comprising:
a. a core made of polymethylpentene; and b. an elastomeric covering.
a. a core made of polymethylpentene; and b. an elastomeric covering.
8. In a method of sequentially treating two strata of a subterranean formation surrounding a well casing having a plurality of perforations formed therein wherein ball sealers suspended in a fluid are used to seal part of said perforations, the improvement wherein said ball sealers include a polymethylpentene core and an elastomeric cover and have a density less than said fluid.
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US05/830,729 US4102401A (en) | 1977-09-06 | 1977-09-06 | Well treatment fluid diversion with low density ball sealers |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA1080613A true CA1080613A (en) | 1980-07-01 |
Family
ID=25257584
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA299,388A Expired CA1080613A (en) | 1977-09-06 | 1978-03-21 | Well treatment fluid diversion with low density ball sealers |
Country Status (9)
| Country | Link |
|---|---|
| US (1) | US4102401A (en) |
| AU (1) | AU520468B2 (en) |
| CA (1) | CA1080613A (en) |
| DE (1) | DE2838552C2 (en) |
| GB (1) | GB1595366A (en) |
| MX (1) | MX147448A (en) |
| MY (1) | MY8500145A (en) |
| NL (2) | NL7804565A (en) |
| NO (1) | NO151558C (en) |
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| US4287952A (en) * | 1980-05-20 | 1981-09-08 | Exxon Production Research Company | Method of selective diversion in deviated wellbores using ball sealers |
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-
1977
- 1977-09-06 US US05/830,729 patent/US4102401A/en not_active Expired - Lifetime
-
1978
- 1978-03-21 CA CA299,388A patent/CA1080613A/en not_active Expired
- 1978-04-07 GB GB13766/78A patent/GB1595366A/en not_active Expired
- 1978-04-21 MX MX173199A patent/MX147448A/en unknown
- 1978-04-27 NL NL7804565A patent/NL7804565A/en active Search and Examination
- 1978-06-30 AU AU37649/78A patent/AU520468B2/en not_active Expired
- 1978-07-03 NO NO782306A patent/NO151558C/en unknown
- 1978-09-04 DE DE2838552A patent/DE2838552C2/en not_active Expired
-
1984
- 1984-05-28 NL NL8401702A patent/NL8401702A/en not_active Application Discontinuation
-
1985
- 1985-12-30 MY MY145/85A patent/MY8500145A/en unknown
Also Published As
| Publication number | Publication date |
|---|---|
| DE2838552C2 (en) | 1983-07-07 |
| NO151558C (en) | 1985-05-02 |
| GB1595366A (en) | 1981-08-12 |
| US4102401A (en) | 1978-07-25 |
| NL8401702A (en) | 1984-09-03 |
| AU3764978A (en) | 1980-01-03 |
| NO151558B (en) | 1985-01-14 |
| MX147448A (en) | 1982-12-03 |
| AU520468B2 (en) | 1982-02-04 |
| DE2838552A1 (en) | 1979-03-08 |
| MY8500145A (en) | 1985-12-31 |
| NO782306L (en) | 1979-03-07 |
| NL7804565A (en) | 1979-03-08 |
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