CA1139217A - Low density ball sealers for use in well treatment fluid diversions - Google Patents
Low density ball sealers for use in well treatment fluid diversionsInfo
- Publication number
- CA1139217A CA1139217A CA000349664A CA349664A CA1139217A CA 1139217 A CA1139217 A CA 1139217A CA 000349664 A CA000349664 A CA 000349664A CA 349664 A CA349664 A CA 349664A CA 1139217 A CA1139217 A CA 1139217A
- Authority
- CA
- Canada
- Prior art keywords
- ball
- casing
- fluid
- perforations
- ball sealer
- 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
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/25—Methods for stimulating production
- E21B43/26—Methods for stimulating production by forming crevices or fractures
- E21B43/261—Separate steps of (1) cementing, plugging or consolidating and (2) fracturing or attacking the formation
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 comprises a material, such as syntactic foam or polymethylpentene. The ball sealer is also preferably provided with B protective covering 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 comprises a material, such as syntactic foam or polymethylpentene. The ball sealer is also preferably provided with B protective covering 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
~392~7
2 1. Field of the Invention. This invention pertains to the
3 treating of wells and more particularly to an improved perforation plugging L4 elem~nt and the utilization of 6uch elements for temporary closing of ~uch ~ ~rn p~O~
~e~e -o~c in the casing.
6 2. Description of the Prior Art. It is common practice in 7 completing oil and gas wells to ~et a string of pipe, ~nown as ca~ing, in 8 the well and use cement around the out6ide bf the casing to i~olate the 9 various formations penetrated by the well. To establish fluid communi-cation between the hydrocarbon bearing formations and the interior of the 11 casing, the casing and cement sheath are perforated.
12 At various times during the life of the well, it may be desirable13 to increase the production rate of hydrocarbons through treatment such as 14 scidizing or hydraulic fracturing. If only a short, single pay zone in thewell 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 more19 difficult. For instance, the strata having the highest permeability will most li~ely 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 resi~tance so that the low permeability zones are slso treated.
24 One technique for achieving diver6ion involves the use of downhole equipment such as packers. Although these devices are effective, they are 26 quite e~pensive due to the involvement of associated workover equipment 27 required during the tubing-packer manipulations. Additionally, mechanical 28 reliability tends to decrease as the depth of the well incresses.
29 As a result, considerable effort has been devoted to the develop-ment of alternative diverting methods. One of the most popular and widely 31 used diverting techniques over the past 20 years has been the use of small 32 rubber-coated balls, known as ball sealers, to seal off the perforations 33 inside the casing.
34 These ball sealers are pumped into the wellbore along with the formation treating fluid. The balls are carried down the wellbore and on 36 to the perforations by the flow of the fluid through the perforations into 37 the formation. The balls seat upon the perforations and are held there by 38 the pressure differential across the perforation.
11~9~1~
1 The major advantages of utilizing ball sealers as a diverting 2 agent are: easy to use, positive shutoff, independent of the formation, 3 and non-damaging to the well. The ball sealers are simply injected at the
~e~e -o~c in the casing.
6 2. Description of the Prior Art. It is common practice in 7 completing oil and gas wells to ~et a string of pipe, ~nown as ca~ing, in 8 the well and use cement around the out6ide bf the casing to i~olate the 9 various formations penetrated by the well. To establish fluid communi-cation between the hydrocarbon bearing formations and the interior of the 11 casing, the casing and cement sheath are perforated.
12 At various times during the life of the well, it may be desirable13 to increase the production rate of hydrocarbons through treatment such as 14 scidizing or hydraulic fracturing. If only a short, single pay zone in thewell 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 more19 difficult. For instance, the strata having the highest permeability will most li~ely 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 resi~tance so that the low permeability zones are slso treated.
24 One technique for achieving diver6ion involves the use of downhole equipment such as packers. Although these devices are effective, they are 26 quite e~pensive due to the involvement of associated workover equipment 27 required during the tubing-packer manipulations. Additionally, mechanical 28 reliability tends to decrease as the depth of the well incresses.
29 As a result, considerable effort has been devoted to the develop-ment of alternative diverting methods. One of the most popular and widely 31 used diverting techniques over the past 20 years has been the use of small 32 rubber-coated balls, known as ball sealers, to seal off the perforations 33 inside the casing.
34 These ball sealers are pumped into the wellbore along with the formation treating fluid. The balls are carried down the wellbore and on 36 to the perforations by the flow of the fluid through the perforations into 37 the formation. The balls seat upon the perforations and are held there by 38 the pressure differential across the perforation.
11~9~1~
1 The major advantages of utilizing ball sealers as a diverting 2 agent are: easy to use, positive shutoff, independent of the formation, 3 and non-damaging to the well. The ball sealers are simply injected at the
4 surface and transported by the treating fluid. Other than a ball injector, no special or additional treating equipment is required. The ball sealers 6 are designed to have a solid core which resists extrusion into or through 7 the perforation. Therefore, the ball sealers will not penetrate the forma-8 tion and permanently damage the flow charactexistics of the well.
9 Several requirements are repeatedly applied to ball sealers as they are normally utilized today. First, the ball sealers must be chemically 11 inert in the environment to which they are exposed. Second, they must seal12 effectively, yet not extrude into the perforations. Third, the ball sealer13 must release from the perforations when the pressure differential into the 14 formation is relieved. Fourth, the ball sealers are generally heavier thanthe wellbore fluid so that they will sink to the bottom of the well, and 16 out of the way, upon completion of the treatment.
17 Although present-day ball sealer diverting techniques have met 18 with considerable usage, there is abundant evidence which indicates that 19 the ball sealers often do not perform effectively because only a fraction of the ball sealers injected actually seat on perforations. The present-21 day practice of using ball sealers having a density greater than the treating 22 fluid yields a low and unpredictable seating efficiency highly dependent on23 the difference in density between the ball sealers and the fluid, the flow 24 rate of the fluid through the perforations, and the number, spacing and orientation of the perforations. The net result is that the plugging of 26 the desired number of perforations at the proper time during the treatment 27 to effect the desired diversion is left completely to chance.
28 When these inefficiencies lead to treatment failures, it is 29 generally believed that these failures result from insufficient flow being carried through the perforations, thereby allowing the balls to fall to the 31 bottom of the well without achieving fluid diversion. Attempts to overcome32 this problem generally include pumping a quantity of balls which exceeds 33 the number of perforations. Although this procedure can be helpful, it has34 not proven to be a satisfactory solution.
SUMMARY OF THE INVENTION
36 The method of the present invention overcomes the limitations of 37 present-day ball sealer diversion methods. The present invention utilizes 38 ball sealers having a density less than the treating fluid. These ball 39 sealers exhibit substantially 100% seating efficiency in laboratory tests.
11392~7 1 The method of the present invention involves flowing a treating 2 fluid downward in the casing, through the perforations and into the formation 3 surrounding the perforated parts of the casing. At the appropriate time 4 during the treatment, plugging members, i.e., ball sealers, are introduced into the treating fluid at the surface. These ball sealers will have a 6 size sufficient to plug the casing perforations and a density less than the 7 density of the treating fluid within the casing. Thereafter, the downward 8 flow of the fluid within the casing will be continued at a rate such that 9 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 11 magnitude than the upward buoyancy force acting on the ball sealers to 12 thereby transport the ball sealers to the perforations. Once the ball 13 sealers have reached the perforations, they will sea~ on perforations 14 taking fluid, plug the perforations and cause the treating fluid to be diverted to the remaining open perforations.
16 The ball sealers themselves must comprise a low density high 17 strength material capable of withstanding the pressures existing within the18 well. The pressures acting on the ball sealers in the well are the hydro-19 static pressure of the fluid in the wellbore and the pumping pressure. The20 material cannot collapse under the pressures in the well because the 21 decrease in volume of the ball sealer upon collapse will result in a corres-22 ponding increase in the density of the ball sealer which can then easily 23 exceed the density of the treating fluid. It has been found that materials24 that meet the density and compressive strength requirement include syntactic foam and polymethylpentene. Thus, ball sealers comprising syntatic foam or 26 polymethylpentene exhibit both a low density and a high compressive strength.
27 The ball sealers of the present invention are preferably provided with a 28 protective covering. The protective covering may comprise a nonelastomeric~
29 plastic material capable of plastic deformation. However, it will be obvious to one skilled in the art that other types of nonplastic protective 31 covering materials such as aluminum may also be utilized in the practice of32 the present invention.
33 After the treatment of the hydrocarbon-bearing strata has been 34 completed, the pressure on the fluid in the casing will be relieved causingthe ball sealers to be released from the perforations where they were ~6 seated. The ball sealers will rise within the casing due to their buoyancy37 and to the upward flow of fluids from the well to the earth's surface. A
113~Z~7 1 ball catcher may be provided to trap all of the ball sealers upstream of 2 any equipment which they might clog or damage.
3 The method of the present invention provides certainty in diversion 4 heretofore unknown in well treatment operations.
_IEF DESCRIPTION OF T~E DRAWINGS
6 ~IGURE 1 is an elevation view in section of a well illustrating 7 the practice of the present invention.
8 FlGURE 2 is an elevation view partially in section of a typical 9 arrangement of wellhead equipment placed on a production well to control the flow of hydrocarbons from the well including a ball catcher adapted to 11 trap the ball sealers upstream of any equipment which they might clog or 12 damage.
13 ~IGURE 3 is a graph of the seating efficiency versus the normalized 14 density contrast between a ball sealer and a treating fluid based on experi-ments.
16 ~IGURE 4 is a graph of the fluid velocity within the casing 17 versus the normalized density contrast between a ball sealer and a treating18 fluid based on experiments.
19 FIGURE 5 is a view in section of one embodiment of a ball sealer suitable for use in the method of the present invention.
22 Utilization of the present invention according to the preferred 23 embodiment is depicted in EIGURE 1. The well 1 of FIGURE 1 has a casing 2 24 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 26 cement sheath 3 extends upward from the bottom of the wellbore at least to 27 a point above the producing strata 5. For the hydrocarbons in the producing 28 strata 5 to be produced, it is necessary to establish fluid communication 29 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 31 sheath 3.
32 The hydrocarbons flowing out of the producing strata 5 through 33 the perforations 4 and into the interior of the casing 2 are transported to34 the surface through a production tubing 6. A production packer 7 is installed near the lower end of the production tubing 6 and above the 36 highest perforation to achieve a pressure seal between the production 37 tubing 6 and the casing 2. Production tubings are not always used and, 1~392~L7 1 in those cases, the entire interior volume of the casing is used to conduct 2 the hydrocarbons to the surface of the earth.
3 When diversion is needed during a well treatment, ball sealers 4 are often used to close off some of the perforations. These ball sealers are preferred to be approximately spherical in shape, but other geometries 6 may also be utilized.
7 To use the ball sealers l0 to plug some of the perforations 4, 8 the first step is to introduce the ball sealers l0 into the casing 2 at a 9 predetermined time during the treatment. The ball sealers can be introducedinto the fluid either before or after the fluid is pumped into the ~pper 11 end of the casing. Methods of accomplishing these procedures are well 12 known in the art.
13 When the ball sealers l0 are introduced into the fluid upstream 14 of the perforated parts of the casing, they are carried down the productiontubing 6 or casing 2 by the fluid flow. Once the fluid arrives at the 16 perforated parts of the casing, it moves radially outward, in addition to 17 its downward movement, toward and through the perforations 4. The flow of 18 the treating fluid through the perforations 4 carries the ball sealers lO
19 over to the perforations 4 and seats them on the perforations 4. The ball sealers l0 are held there by the fluid pressure differential, thereby 21 effectively closing those perforations 4 until such time as the pressure 22 differential is relieved or reversed. Ideally, the ball sealers 10 will 23 first seal the perforations through which the treating fluid is flowing 24 most rapidly. This preferential closing of the perforations promotes distribution of the treatment over the entire distance of the perforations.
26 The prior art teaches that it is preferred for the density of the27 ball sealers to be equal to or greater than the density of the treating 28 fluid. ~t is worth examining the prior art ball sealer seating mechanism 29 to be able to contrast it to the present invention. The velocity of ball sealers more dense than the fluid in the wellbore is comprised of two 31 components. Each ball sealer has a settling velocity always directed 32 vertically downward due to the difference in the densities of the ball 33 sealer and the fluid. The second component of the ball sealer's velocity 34 is attributable to the drag forces imposed upon the ball sealer by the moving fluid shearing around the ball sealer. This velocity component will 36 be in the direction of the fluid flow. Within the production tubing or 37 within the casing above the perforations, the velocity component due to the38 fluids will be generally downward.
1~39217 Just above the perforated part of the casing the fluid takes on 2 a horizontal velocity component directed radially outward toward and 3 through the perforations 4. The flow through any perforation must be 4 sufficient to draw the ball sealer lO to the perforation before the ball sealer sinks past that perforation. If the flow of the treating fluid 6 through the various perforations does not draw the ball sealer to a per-7 foration by the time the ball sealer sinks past the lowest perforation, the 8 ball sealer will simply sink into the rathole 8 where it will remain.
9 In contrast, the present invention contemplates the use of ball sealers 10 having a density less than the density of the treating fluid.
11 Within the wellbore, each ball sealer has a velocity comprised of two 12 opposing components. The first velocity component is directed vertically 13 upward due to the buoyancy of the ball sealer in the fluid. The second 14 velocity component is attributable to the drag forces imposed upon the ballsealer by the motion of the fluid shearing past the ball sealer. Above the 16 perforations, this second velocity component will be directed generally 17 downward. It is essential that the downward fluid velocity in the production 18 tubing 6 and in the casing 2 above the perforations 4 be sufficient to l~ -mpart a downward drag force on the ball sealers which is greater in magni-tude than the upward force of buoyancy acting on the ball sealers. This 2~ results in the ball sealers being carried downward to the section of the 2 casing which has been perforated.
23 When ball sealers are utilized in accordance with the present 24 invention, they will never remain in the rathole 8; that is, below the lowest perforation through which the treating fluid is flowing, due to the 26 buoyancy of the ball sealers. Below the lowest perforation accepting the 27 treating fluid, the fluid in the wellbore remains stagnant and there are no28 downwardly directed drag forces acting on the ball sealers to keep them 29 below the lowest perforation taking the treating fluid. Ilence, the upwardbuoyancy forces acting on the ball sealers will dominate in this interval.
31 Therefore, the practice of the present invention results in the 32 vertical velocity of each ball sealer being a function of its vertical 33 positicn within the casing. At least below the lowest perforation, and 34 possibly higher if little fluid is flowing down to and through the lower perforations, the net vertical velocity of each ball sealer will be upward 36 due to the dominance of the buoyancy force over any downward fluid drag 37 force. At least above the highest perforation, and possibly lower if 38 little fluid is flowing through those higher perforations, the net vertical39 velocity of each ball sealer will be downward due to the dominance of the downward fluid drag force over the buoyancy force.
~39Z17 The ball sealers having a density less than the density of the treating fluid will remain within, or moving toward, that portion of the casing between the uppermost perforation and the lowermost perforation through which fluid is flowing until the ball sealers seat upon a per-foration. W~ile suspended within that portion of the casing, the motion of the fluid radially outward into and through the perforations will exert drag forces on the hall sealers to move them radially outward to the perforations where they will seat and be held there by the pressure differential.
The net result of the use of the present invention is that the ball sealers injected into the well and transported to the perforated zone of the casing will generally experience substantially 100% seating efficiency as demonstrated in laboratory tests.
When the treatment has been completed and the pressure differen-tial relieved or reversed, the ball sealers will unseat from the perfor-ations. With ball sealers having a density less than the wellbore fluid, the ball sealers will naturally migrate upward. Therefore, some means should be provided to catch these ball sealers before they pass into equipment which they might clog or damage. A ball catcher 30 which will accomplish this is depicted in FIGURE 2.
FIGURE 2 shows a typical arrangement of wellhead equipment for a producing well. The well casing 2 extends slightly above the ground level and supports the wellhead 20. The production tubing 6 is contained within the casing 2 and connects with the lower end of the master valve 21. The 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 either through the crown valve 22 or the wing valve 23.
Various workover equipment can be attached to the upper end of the crown valve 22 and communication between that equipment and the well is accom-plished by opening the crown valve 22 and master valve 21. Ordinarilythe crown valve ~2 is maintained in a closed position. Production from the well flows from the tee 25 laterally into the wing valve 23. The wing valve 23 directs the flow of fluids from the wellhead to the gather-ing flowline 26.
A ball catcher 30, shown in section, is located downstream of the wing valve and upstream of the flow controlling choke 24. The pro-duced fluid will pass through the ball catcher 30 but the ball sealers will be trapped therein. After the produced fluid passes through the choke 24 it moves into a gathering flowline 26 which will typically transport the fluid to a separation facility and then either to holding tanks or to a pipeline.
i~39217 The ball catcher 30 is basically a tee haYing a deflector insert 34 containing a deflector grid 35 inserted into the downstream end of the tee. The deflector grid 35 allows fluid to pass through it but it will not allow objects the size of the ball sealers to proceed further downstream. Preferably the deflector grid 35 is angled within the ball catcher 30 so 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 lower ~nd of the deadleg 32 and can be easily removed when the wing valve is closed and the pressure bled down, to allow the removal of the trapped ball sealers.
Experiments were conducted to test the seating efficiencies of ball sealers utilizedaccording to present practices, i.e., ball sealers having a density greater than the treating fluid and ball sealers utilized according to the present invention, i.e., ball sealers having a density less than the density of the treating fluid.
The laboratory experiments were designed to simulate ball sealers seating on perforations in a casing. The experimental equipment included an 8-foot long piece of 3-inch lucite tubing to represent a piece of casing. The lucite tubing was mounted vertically in the labor-atory and its lower end sealed closed. Between 3 and 4 feet from the bottom of the tubing, 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 2-inches apart on center.
A 90 elbow was placed on the upper end of the lucite tubing and was connected by a flowline to a pump. The pump drew fluid from a reservoir tank and pumped it at various controlled rates through the flowline and into the upper end of the tubing. The fluid flowed down the lucite tubing, through the perforations and returned by a flowline to the reserYoir tank.
To inject thè ball sealers a suitable hole was made in the elbow and a l-inch diameter piece of tubing welded in the hole. The end oE
the l-~inch tubi~ng was centered to be coaxial with the lucite tubing at the upper end of the lucite tubing. The ball sealers were introduced into the lucite tubing through the l-inch tubing.
~139217 The flow of fluid into the upper end of the lucite tubing was ? measured. It was assumed that the flow through each perforation was the 3 same and therefore the flow through each perforation was ta~en to be 1/5 of the measured flow into the upper end of the lucite tubing.
During the experiments, water, having a den6ity of 1.0 grams per ~ ic centimeter (g/cc), was used as the fluid. Rigid ball sealer6 were 7 made from four different materials having diffe nt densities. The balls c wnre sll 3/4" in diameter and were made from ~ C(0.84-0.86 g/cc 9 density), nylon (1.11 g/cc density), àcetal (1.39 g/cc density) and teflon (2.17 g/cc density). These ball sealer6 did not have a protective covering.
ll The experiment generally involved establishing a specific flow 1~ rate of the fluid through the perforations, injecting the ball sealer~
13 through the l-inch tubing into the upper end of the 8-foot lucite tubing 14 and observing whether or not the ball sealer6 seated on the perforations.
The experimental program was conducted with ball 6ealers made of all four 16 material~ being injected into the tubing with the water flowing through it.17 A single set of test6 involved injecting ten balls of the same 18 material, one st 8 time, into the top of the 8-foot lucite tubing. An 1~ observation was made whether or ~ot the ball sealer seated on one of the 2~ perforations. If a ball seated on a perforation, that ball was released ~1 ILom the perforation prior to dropping the next ball, so that there were 22 always five open perforations for each ball to ~eat upon. During a ~ingle ~ t ^f ~ ts the fluid and it6 flow rate remained unchanged. After all ten24 balls had been dropped, the number that seated upon perforations was defined 8S the seating efficiency under those conditions and expressed as a per-26 centage.
27 Six or seven te6ts were conducted to define a regression curve 28 plotting seating efficiency against flow rate through a perforation for 29 that particular ball 6ealer and fluid. These regression curve6 were con-structed for each set of equal density ball sealers. The data from those 31 regression curves was then used to make the graph of FIGURE 3.
32 FIGURE 3 is a plot of ceating efficiency ve,sus the normalized 33 density contra6t. The normalized density contrast is the difference in 34 aenSlty between the ball sealer and the fluid divided by the density of thefluid. A positive normalized density contrast means the density of the 3C bdl, ~ealRr is greater than the density of the fluid and a negative normal-37 i 7~ density contrast means the density of the ball sealer is less than the 38 density of the fluid. It follows that a normalized density contrast of 39 zero means that the ball sealer and the fluid have the ~ame density.
-11~9~7 ] When the normali~ed density contrast is greater than zero, the 2 seating efficiency was found to be a function of the flow through the 3 perforations. In FIGURE 3 there are four plots of seating efficiency 4 versus normalized density contrast for four different flow rates through a perforation, 20 gallons per minute (gpm), 15 gpm, 10 gpm, and 5 gpm. Also, 6 the seating efficiency was found to increase as the normalized density 7 contrast decreased toward zero.
8 When the normalized density contrast is less than zero, the 9 seating efficiency was always observed to be 100% provided that the flow of fluid downward within the casing above the perforations is sufficient to 11 impart a downward drag force on the ball sealers which is greater in magni-12 tude than the upward buoyancy force acting on the ball sealers. In other 13 words, if the downward flow of fluid within the casing is sufficient to 14 transport the ball sealers downward to the perforations, they exhibit substantially 100% seating efficiency as demonstrated in laboratory tests.
16 When the normalized density contrast is greater than zero, i.e., 17 the density of the ball sealers being greater than the density of the 18 fluid, the seating efficiency of the ball sealers is a function of the flow19 rate through the perforation and the difference in density between the ballsealers and the fluid. The greater the flow rate through the perforation 21 and the less difference in density between the ball sealers and the fluid, 22 the greater the seating efficiency will be. The seating efficiency of ball23 sealers having a density greater than the density of the fluid is always a 24 statistical phenomenon. A variation in the number, spacing and orientationof the perforations is highly likely to affect the precise seating efficiency 26 which can be expected in that situation. Therefore, since the seating of 27 ball sealers having a density greater than the density of the fluid is 28 always a statistical phenomenon, there is always the possibility that too 29 few or too many of the ball sealers will seat to get the desired diversion.Practicing ball sealer diversion according to the present in-31 vention i.e~, the use of ball sealers having a density less than the density 32 of the fluid, will generally result in substantially lOODID seating efficiency 33 irrespec~ive of the flow rate through the perforations and irrespective of 34 the magnitude of difference in density between the ball sealers and the fluid. The seating efficiency of the ball sealers having a density less 36 than the density of the fluid is only a function of the downward flow of 37 fluid above the uppermost perforation in the casing. If the downward flow 38 within the casing can transport the ball sealers to the level of the per-39 forations, then the ball sealers will seat. A predictable diversion process 113~Z17 1 will occur since the number of perforations plugged by the ball sealers 2 will be equal to the lesser of the number of ball sealers injected into the 3 casing, or the number of perforation~ accepting fluid.
4 The relationship between the normalized density contrast and the fluid velocity needed to transport the ball sealers down the casing was 6 investigated. FIGURE 4 is a graph of the normalized density contrast 7 between the ball sealers and the fluid plotted against the velocity of the 8 fluid downward within the casing. This graph is based on several tests 9 which involved placing a ball sealer within a vertical piece of lucite tubing and flowing fluid downward through the tubing. The velocity of the 11 fluid was adjusted until the ball sealer was maintained in a fixed position12 at the mid-poi~t of the tubing. In that equilibrium position the drag 13 forces of the fluid shearing past the ball sealer were equal in magnitude 14 to the buoyancy forces acting on the ball sealer. Ball sealers of several densities were used in conjunction with two fluids, water and 1.13 g/cc 16 calcium chloride brine, to give the plot of FIGURE 4.
17 The solid line defines the equilibrium condition wherein the ball18 sealer will remain stationary within the casing, moving neither upward nor 19 downward. Below the line in FIGURE 4 the velocity of the fluid in the casing would be insufficient to overcome the force of buoyancy and the ball 21 sealers will rise in the casing. Above the line in FIGURE 4 the velocity 22 of the fluid in the casing exerts a drag force on the ball sealers greater 23 in magnitude than the force of buoyancy acting on the ball sealers. There-24 fore, the ball sealers will be transported down the casing.
All points on the line and below it correspond to a certain 26 normalized density contrast and a certain casing velocity which will result27 in a seating efficiency of 2ero per cent. Because the ball sealers are not28 transported down to the perforations, they cannot seat. Whereas, if the 29 normalized density contrast and casing velocity define a point above the line plotted in FIGUR~ 4, the seating efficiency will generally be substan-31 tially 100%. The buoyancy of the ball sealers will maintain them at a 32 position at or above the lowermost perforation and the downward fluid 33 velocity in the casing above the uppermost perforation will maintain the 34 ball sealers at or below the level of the uppermost perforation. It will take a very small fluid flow through a perforation to draw a ball sealer to 36 the perforation and seat it thereon when the amount of time the fluid flow 37 through the perforation has to act upon the ball sealer is limited only by 38 the length of the injection time.
1~39217 l To apply the present invention in the field, it is necessary to 2 have a ball sealer which has a density less than the wellbore fluid and at 3 the same time has the strength to withstand the pressures encountered in 4 the wellbore. It is not unusual for the bottom hole pressure to exceed 10,000 psi and even reach 15,000 psi during a well treatment. If D ball 6 sealer cannot withstand these pressures, they will collapse causing the 7 density of the ball sealer to increase to a density which can easily exceed 8 the fluid density.
9 Since fluids used for treating wells generally have densities ranging from approximately 0.8 grams per cubic centimeter (g/cc) to signi-11 ficantly above l.l g/cc, a series of light weight ball sealers are required12 having densities in the same 0.8 to l.l g/cc range.
13 Suitable materials are currently available for use in conjunction14 with ball sealers in the l.l g/cc range and greater. In the range from 0.8to l.l g/cc, techniques at manufacturing such ball sealers have not been 16 very satisfactory. For example, there is one commercially available BUNA-N17 cover~d ball sealer having a phenolic core with considerable void volume 18 which can have a density less than l.0 g/cc. Since the void volume in the l9 phenolic core is created by partially consolidating a phenolic resin using low pressure molding conditions, control of the density is extremely diffi-21 cult. A representative sample was tested and proved to have an average 22 density of .996 ~/cc and a wide distribution (0.908 to 1.085 g/cc). Moreover, 23 when these ball sealers were hydrostatically pressure tested, it was found 24 that in many of the ball sealers the void volumes were unstable and had collapsed when subjected to hydrostatic pressures as low as 6,000 pounds 26 per square inch. Correspondingly, when these void volumes collapsed, the 27 density of the ball sealers increased.
28 It has been found that a ball sealer comprising syntactic foam 29 has a high compressive strength and has a density in the range from 0.8 to 1.1 g/cc. Referring to FIGURE 5, there is shown a suitable syntactic foam 31 ball sealer lOl for use in the present invention. Syntactic foam is a 32 material system comprised of hollow spherical particles dispersed in some 33 form of binder. The commercially available low density syntactic foams 34 which appear to be sufficiently strong to withstand the pressures and tem-peratures typically encountered by ball sealers, consist of microscopic-36 ally small, hollow glass spheres (averaging approximately 50 microns in 37 diameter) dispersed in a resin binder such as epoxy. It is anticipated 38 that in the future it may become possible in syntactic foam systems to use ~ ~ 392~
] spheres made from materials other than glass and binders made from materials 2 such as thermoplastics and thermosetting plastics. In fact, Emerson and 3 Cuming Inc. has recently developed high strength glass microspheres which 4 can withstand high pressures of the magnitude typically encountered during injection molding. If injection molding can be used to make ball sealers, 6 it will be possible to use a lightweight thermoplastic or thermosetting 7 plastic as the binder resulting in a high strength ball sealer having a 8 very low density.
9 Several of the commercially available syntactic foams which appear to be suitable for use as the material of a low density ball sealer 11 are listed in Table I.
14 Hydrostatic Compressive Bulk 16 Product Manufacturer Density Strength Modulus 17 r/cc) (psi) (psi) 18 EL 30 Emerson & Cuming 0.48 8,000 250,000 19 EL 36 Emerson & Cuming 0.57 16,000 390,000 20 EL 39 Emerson & Cuming 0.62 24,000 420,000 21 EF 38 Emerson & Cuming 0.60 7,000 Not Available 22 34-~C6 Lockheed 0.54 18,000 Not Available 23 36-lB4 Lockheed 0.57 13,650 Not Available 24 39-lB5 Lockheed 0.62 15,600 Not Available 25 XP-241-36 3M 0.57 11,000 325,000 26 XP-241-42H 3M 0.67 20,000 450,000 27 The syntactic foams listed in Table I demonstrate very good 28 compressive strength when subjected to hydrostatic pressure. Many of the 29 materials will easily withstand 15,000 psi. Tests on a ball sealer having a syntactic foam core (Lockheed 36 lB4) and a rubber covering demonstrated 31 that the ball sealers were capable of withstanding hydrostatic pressures up 32 to approximately 13,500 psi before they began to fail due to the collapse ~392~7 1 of the syntactic foam. ~urthermore, each of the syntactic foams for which 2 the bulk modulus of elasticity was available has a bulk modulus of elasticity 3 comparable to that of water, which is 300,000 psi.
4 The bulk modulus of elasticity is the inverse of material com-pressibility. It represents a mate~ial's resistance to volumetric ~hange 6 as a function of hydrostatic pressure. For example, if the bulk modulus of 7 a material is greater than that of water, the material will be less compress-8 ible than water. Hence, the material's buoyancy will increase with respect 9 to the water when both are being subjected to the same pressure since the water will be compressed more. This quality of these syntactic foams will 11 assure that the density of the ball sealers remains less than the density 12 of the treating fluid, thereby, avoiding the problems encountered with the 13 phenolic core ball sealers.
14 Syntactic foam is currently available in blocks with a standard volume of approximately l cubic foot. Therefore, in order to fabricate the 16 syntactic foam ball sealers, it is necessary to machine the syntactic foam 17 blocks to preferably produce foam spheres having an appropriate diameter.
18 To fabricate the syntactic foam balls, the blocks of syntactic foam material 19 are machined in a standard manner to form syntactic foam spheres.
Syntactic foam balls may be suitably utilized in the practice of 21 the present invention without a protective covering. However, because the 22 syntactic foam material is fairly rigid and brittle, it is preferred that 23 the balls be provided with a protective covering. The protective cove~ing 24 functions to prevent damage to the surfaces of the balls while they are being transported down the wellbore. The covering may comprise a nonelasto-206 meric plastic material capable of plastic deformation to enable the ball 27 sealers to conform to the perforation and form a better seal on the perfor-28 ation. A suitable nonelastomeric plastic material for the practice of the 29 present invention is a synthetic resin such as nylon or phenolic resins.
The phenolic resins are commonly marketed as "Bakelite", snd are manufactured 31 by condensing phenol, cresol, or xylenol with formaldehyde using either 32 acid or base catalysis. However, it will be obvious to one skilled in the 33 art that other types of nonelastomeric plastic materials and nonplastic 34 materials such as aluminum will also be suitable in the practice of the present invention.
36 In order to coat the ball sealers, the surface of the ball is 37 first prepped, coated with a suitable bonding agent and then covered with 38 the desired covering. Surface preparation involving some cleaning technique 39 is important to assure the best possible bond between the covering and the -~4-i~39217 1 syntactic foam. It is most desirable if surface preparation can be limited 2 to a strong air blast which will remove most of the crushed glass and 3 debris created during machining. Sand blasting has been used with very ~ good success but its use should be limited to very brief treatments due to rapid abrasion of the core which leads to increased ball density as well as 6 a highly variable batch density. If the spheres have been handled or are 7 oily, a trichlorylethelene wash has been used satisfactorily. Once the ~ spheres are grease and oil free, they can be dipped in a suitable bonding 9 agent selected according to the covering material to be used.
Although syntactic foam is one ball sealer material, certain 11 thermoplastics can also be used. Although no unfoamed plastics exhibit 12 su~ficiently low densities to make a .8 to .9 g/cc ball sealer, polymethyl-13 pentene can be used as a material for ball sealers in the 1.0 g/cc density 14 range. Polymethylpentene has a density of .83 g/cc and is a high temperature thermoplastic (melting point approximately 250C). Ball scalers made of 16 polymethylpentene may also be provided with a suitable protective covering.17 Suitable protective coverings are nonelastomeric plastic materials and 18 nonplastic materials. All other lightweight plastics, which typically 1~ lnclude polybutylene, polyethylene, polypropylene, and polyallomer copolymers, 2~ are nearly twice as heavy as is acceptable. ~urthermore, since these 21 materials are low temperature thermoplastics, they are probably not suitable 22 for ball sealer materials from the standpoint that they are likely to 23 extnlde through the perforations under the bottom hole temperature and 24 pressure conditions typically encountered.
The principle of the invention and the best mode in which it is 26 contemplated to apply that principle have been described. It is to be 27 understood that the foregoing is illustrative only and that other means and28 techniques can be employed without departing from the true scope of the 29 invention defined in the claims.
9 Several requirements are repeatedly applied to ball sealers as they are normally utilized today. First, the ball sealers must be chemically 11 inert in the environment to which they are exposed. Second, they must seal12 effectively, yet not extrude into the perforations. Third, the ball sealer13 must release from the perforations when the pressure differential into the 14 formation is relieved. Fourth, the ball sealers are generally heavier thanthe wellbore fluid so that they will sink to the bottom of the well, and 16 out of the way, upon completion of the treatment.
17 Although present-day ball sealer diverting techniques have met 18 with considerable usage, there is abundant evidence which indicates that 19 the ball sealers often do not perform effectively because only a fraction of the ball sealers injected actually seat on perforations. The present-21 day practice of using ball sealers having a density greater than the treating 22 fluid yields a low and unpredictable seating efficiency highly dependent on23 the difference in density between the ball sealers and the fluid, the flow 24 rate of the fluid through the perforations, and the number, spacing and orientation of the perforations. The net result is that the plugging of 26 the desired number of perforations at the proper time during the treatment 27 to effect the desired diversion is left completely to chance.
28 When these inefficiencies lead to treatment failures, it is 29 generally believed that these failures result from insufficient flow being carried through the perforations, thereby allowing the balls to fall to the 31 bottom of the well without achieving fluid diversion. Attempts to overcome32 this problem generally include pumping a quantity of balls which exceeds 33 the number of perforations. Although this procedure can be helpful, it has34 not proven to be a satisfactory solution.
SUMMARY OF THE INVENTION
36 The method of the present invention overcomes the limitations of 37 present-day ball sealer diversion methods. The present invention utilizes 38 ball sealers having a density less than the treating fluid. These ball 39 sealers exhibit substantially 100% seating efficiency in laboratory tests.
11392~7 1 The method of the present invention involves flowing a treating 2 fluid downward in the casing, through the perforations and into the formation 3 surrounding the perforated parts of the casing. At the appropriate time 4 during the treatment, plugging members, i.e., ball sealers, are introduced into the treating fluid at the surface. These ball sealers will have a 6 size sufficient to plug the casing perforations and a density less than the 7 density of the treating fluid within the casing. Thereafter, the downward 8 flow of the fluid within the casing will be continued at a rate such that 9 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 11 magnitude than the upward buoyancy force acting on the ball sealers to 12 thereby transport the ball sealers to the perforations. Once the ball 13 sealers have reached the perforations, they will sea~ on perforations 14 taking fluid, plug the perforations and cause the treating fluid to be diverted to the remaining open perforations.
16 The ball sealers themselves must comprise a low density high 17 strength material capable of withstanding the pressures existing within the18 well. The pressures acting on the ball sealers in the well are the hydro-19 static pressure of the fluid in the wellbore and the pumping pressure. The20 material cannot collapse under the pressures in the well because the 21 decrease in volume of the ball sealer upon collapse will result in a corres-22 ponding increase in the density of the ball sealer which can then easily 23 exceed the density of the treating fluid. It has been found that materials24 that meet the density and compressive strength requirement include syntactic foam and polymethylpentene. Thus, ball sealers comprising syntatic foam or 26 polymethylpentene exhibit both a low density and a high compressive strength.
27 The ball sealers of the present invention are preferably provided with a 28 protective covering. The protective covering may comprise a nonelastomeric~
29 plastic material capable of plastic deformation. However, it will be obvious to one skilled in the art that other types of nonplastic protective 31 covering materials such as aluminum may also be utilized in the practice of32 the present invention.
33 After the treatment of the hydrocarbon-bearing strata has been 34 completed, the pressure on the fluid in the casing will be relieved causingthe ball sealers to be released from the perforations where they were ~6 seated. The ball sealers will rise within the casing due to their buoyancy37 and to the upward flow of fluids from the well to the earth's surface. A
113~Z~7 1 ball catcher may be provided to trap all of the ball sealers upstream of 2 any equipment which they might clog or damage.
3 The method of the present invention provides certainty in diversion 4 heretofore unknown in well treatment operations.
_IEF DESCRIPTION OF T~E DRAWINGS
6 ~IGURE 1 is an elevation view in section of a well illustrating 7 the practice of the present invention.
8 FlGURE 2 is an elevation view partially in section of a typical 9 arrangement of wellhead equipment placed on a production well to control the flow of hydrocarbons from the well including a ball catcher adapted to 11 trap the ball sealers upstream of any equipment which they might clog or 12 damage.
13 ~IGURE 3 is a graph of the seating efficiency versus the normalized 14 density contrast between a ball sealer and a treating fluid based on experi-ments.
16 ~IGURE 4 is a graph of the fluid velocity within the casing 17 versus the normalized density contrast between a ball sealer and a treating18 fluid based on experiments.
19 FIGURE 5 is a view in section of one embodiment of a ball sealer suitable for use in the method of the present invention.
22 Utilization of the present invention according to the preferred 23 embodiment is depicted in EIGURE 1. The well 1 of FIGURE 1 has a casing 2 24 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 26 cement sheath 3 extends upward from the bottom of the wellbore at least to 27 a point above the producing strata 5. For the hydrocarbons in the producing 28 strata 5 to be produced, it is necessary to establish fluid communication 29 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 31 sheath 3.
32 The hydrocarbons flowing out of the producing strata 5 through 33 the perforations 4 and into the interior of the casing 2 are transported to34 the surface through a production tubing 6. A production packer 7 is installed near the lower end of the production tubing 6 and above the 36 highest perforation to achieve a pressure seal between the production 37 tubing 6 and the casing 2. Production tubings are not always used and, 1~392~L7 1 in those cases, the entire interior volume of the casing is used to conduct 2 the hydrocarbons to the surface of the earth.
3 When diversion is needed during a well treatment, ball sealers 4 are often used to close off some of the perforations. These ball sealers are preferred to be approximately spherical in shape, but other geometries 6 may also be utilized.
7 To use the ball sealers l0 to plug some of the perforations 4, 8 the first step is to introduce the ball sealers l0 into the casing 2 at a 9 predetermined time during the treatment. The ball sealers can be introducedinto the fluid either before or after the fluid is pumped into the ~pper 11 end of the casing. Methods of accomplishing these procedures are well 12 known in the art.
13 When the ball sealers l0 are introduced into the fluid upstream 14 of the perforated parts of the casing, they are carried down the productiontubing 6 or casing 2 by the fluid flow. Once the fluid arrives at the 16 perforated parts of the casing, it moves radially outward, in addition to 17 its downward movement, toward and through the perforations 4. The flow of 18 the treating fluid through the perforations 4 carries the ball sealers lO
19 over to the perforations 4 and seats them on the perforations 4. The ball sealers l0 are held there by the fluid pressure differential, thereby 21 effectively closing those perforations 4 until such time as the pressure 22 differential is relieved or reversed. Ideally, the ball sealers 10 will 23 first seal the perforations through which the treating fluid is flowing 24 most rapidly. This preferential closing of the perforations promotes distribution of the treatment over the entire distance of the perforations.
26 The prior art teaches that it is preferred for the density of the27 ball sealers to be equal to or greater than the density of the treating 28 fluid. ~t is worth examining the prior art ball sealer seating mechanism 29 to be able to contrast it to the present invention. The velocity of ball sealers more dense than the fluid in the wellbore is comprised of two 31 components. Each ball sealer has a settling velocity always directed 32 vertically downward due to the difference in the densities of the ball 33 sealer and the fluid. The second component of the ball sealer's velocity 34 is attributable to the drag forces imposed upon the ball sealer by the moving fluid shearing around the ball sealer. This velocity component will 36 be in the direction of the fluid flow. Within the production tubing or 37 within the casing above the perforations, the velocity component due to the38 fluids will be generally downward.
1~39217 Just above the perforated part of the casing the fluid takes on 2 a horizontal velocity component directed radially outward toward and 3 through the perforations 4. The flow through any perforation must be 4 sufficient to draw the ball sealer lO to the perforation before the ball sealer sinks past that perforation. If the flow of the treating fluid 6 through the various perforations does not draw the ball sealer to a per-7 foration by the time the ball sealer sinks past the lowest perforation, the 8 ball sealer will simply sink into the rathole 8 where it will remain.
9 In contrast, the present invention contemplates the use of ball sealers 10 having a density less than the density of the treating fluid.
11 Within the wellbore, each ball sealer has a velocity comprised of two 12 opposing components. The first velocity component is directed vertically 13 upward due to the buoyancy of the ball sealer in the fluid. The second 14 velocity component is attributable to the drag forces imposed upon the ballsealer by the motion of the fluid shearing past the ball sealer. Above the 16 perforations, this second velocity component will be directed generally 17 downward. It is essential that the downward fluid velocity in the production 18 tubing 6 and in the casing 2 above the perforations 4 be sufficient to l~ -mpart a downward drag force on the ball sealers which is greater in magni-tude than the upward force of buoyancy acting on the ball sealers. This 2~ results in the ball sealers being carried downward to the section of the 2 casing which has been perforated.
23 When ball sealers are utilized in accordance with the present 24 invention, they will never remain in the rathole 8; that is, below the lowest perforation through which the treating fluid is flowing, due to the 26 buoyancy of the ball sealers. Below the lowest perforation accepting the 27 treating fluid, the fluid in the wellbore remains stagnant and there are no28 downwardly directed drag forces acting on the ball sealers to keep them 29 below the lowest perforation taking the treating fluid. Ilence, the upwardbuoyancy forces acting on the ball sealers will dominate in this interval.
31 Therefore, the practice of the present invention results in the 32 vertical velocity of each ball sealer being a function of its vertical 33 positicn within the casing. At least below the lowest perforation, and 34 possibly higher if little fluid is flowing down to and through the lower perforations, the net vertical velocity of each ball sealer will be upward 36 due to the dominance of the buoyancy force over any downward fluid drag 37 force. At least above the highest perforation, and possibly lower if 38 little fluid is flowing through those higher perforations, the net vertical39 velocity of each ball sealer will be downward due to the dominance of the downward fluid drag force over the buoyancy force.
~39Z17 The ball sealers having a density less than the density of the treating fluid will remain within, or moving toward, that portion of the casing between the uppermost perforation and the lowermost perforation through which fluid is flowing until the ball sealers seat upon a per-foration. W~ile suspended within that portion of the casing, the motion of the fluid radially outward into and through the perforations will exert drag forces on the hall sealers to move them radially outward to the perforations where they will seat and be held there by the pressure differential.
The net result of the use of the present invention is that the ball sealers injected into the well and transported to the perforated zone of the casing will generally experience substantially 100% seating efficiency as demonstrated in laboratory tests.
When the treatment has been completed and the pressure differen-tial relieved or reversed, the ball sealers will unseat from the perfor-ations. With ball sealers having a density less than the wellbore fluid, the ball sealers will naturally migrate upward. Therefore, some means should be provided to catch these ball sealers before they pass into equipment which they might clog or damage. A ball catcher 30 which will accomplish this is depicted in FIGURE 2.
FIGURE 2 shows a typical arrangement of wellhead equipment for a producing well. The well casing 2 extends slightly above the ground level and supports the wellhead 20. The production tubing 6 is contained within the casing 2 and connects with the lower end of the master valve 21. The 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 either through the crown valve 22 or the wing valve 23.
Various workover equipment can be attached to the upper end of the crown valve 22 and communication between that equipment and the well is accom-plished by opening the crown valve 22 and master valve 21. Ordinarilythe crown valve ~2 is maintained in a closed position. Production from the well flows from the tee 25 laterally into the wing valve 23. The wing valve 23 directs the flow of fluids from the wellhead to the gather-ing flowline 26.
A ball catcher 30, shown in section, is located downstream of the wing valve and upstream of the flow controlling choke 24. The pro-duced fluid will pass through the ball catcher 30 but the ball sealers will be trapped therein. After the produced fluid passes through the choke 24 it moves into a gathering flowline 26 which will typically transport the fluid to a separation facility and then either to holding tanks or to a pipeline.
i~39217 The ball catcher 30 is basically a tee haYing a deflector insert 34 containing a deflector grid 35 inserted into the downstream end of the tee. The deflector grid 35 allows fluid to pass through it but it will not allow objects the size of the ball sealers to proceed further downstream. Preferably the deflector grid 35 is angled within the ball catcher 30 so 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 lower ~nd of the deadleg 32 and can be easily removed when the wing valve is closed and the pressure bled down, to allow the removal of the trapped ball sealers.
Experiments were conducted to test the seating efficiencies of ball sealers utilizedaccording to present practices, i.e., ball sealers having a density greater than the treating fluid and ball sealers utilized according to the present invention, i.e., ball sealers having a density less than the density of the treating fluid.
The laboratory experiments were designed to simulate ball sealers seating on perforations in a casing. The experimental equipment included an 8-foot long piece of 3-inch lucite tubing to represent a piece of casing. The lucite tubing was mounted vertically in the labor-atory and its lower end sealed closed. Between 3 and 4 feet from the bottom of the tubing, 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 2-inches apart on center.
A 90 elbow was placed on the upper end of the lucite tubing and was connected by a flowline to a pump. The pump drew fluid from a reservoir tank and pumped it at various controlled rates through the flowline and into the upper end of the tubing. The fluid flowed down the lucite tubing, through the perforations and returned by a flowline to the reserYoir tank.
To inject thè ball sealers a suitable hole was made in the elbow and a l-inch diameter piece of tubing welded in the hole. The end oE
the l-~inch tubi~ng was centered to be coaxial with the lucite tubing at the upper end of the lucite tubing. The ball sealers were introduced into the lucite tubing through the l-inch tubing.
~139217 The flow of fluid into the upper end of the lucite tubing was ? measured. It was assumed that the flow through each perforation was the 3 same and therefore the flow through each perforation was ta~en to be 1/5 of the measured flow into the upper end of the lucite tubing.
During the experiments, water, having a den6ity of 1.0 grams per ~ ic centimeter (g/cc), was used as the fluid. Rigid ball sealer6 were 7 made from four different materials having diffe nt densities. The balls c wnre sll 3/4" in diameter and were made from ~ C(0.84-0.86 g/cc 9 density), nylon (1.11 g/cc density), àcetal (1.39 g/cc density) and teflon (2.17 g/cc density). These ball sealer6 did not have a protective covering.
ll The experiment generally involved establishing a specific flow 1~ rate of the fluid through the perforations, injecting the ball sealer~
13 through the l-inch tubing into the upper end of the 8-foot lucite tubing 14 and observing whether or not the ball sealer6 seated on the perforations.
The experimental program was conducted with ball 6ealers made of all four 16 material~ being injected into the tubing with the water flowing through it.17 A single set of test6 involved injecting ten balls of the same 18 material, one st 8 time, into the top of the 8-foot lucite tubing. An 1~ observation was made whether or ~ot the ball sealer seated on one of the 2~ perforations. If a ball seated on a perforation, that ball was released ~1 ILom the perforation prior to dropping the next ball, so that there were 22 always five open perforations for each ball to ~eat upon. During a ~ingle ~ t ^f ~ ts the fluid and it6 flow rate remained unchanged. After all ten24 balls had been dropped, the number that seated upon perforations was defined 8S the seating efficiency under those conditions and expressed as a per-26 centage.
27 Six or seven te6ts were conducted to define a regression curve 28 plotting seating efficiency against flow rate through a perforation for 29 that particular ball 6ealer and fluid. These regression curve6 were con-structed for each set of equal density ball sealers. The data from those 31 regression curves was then used to make the graph of FIGURE 3.
32 FIGURE 3 is a plot of ceating efficiency ve,sus the normalized 33 density contra6t. The normalized density contrast is the difference in 34 aenSlty between the ball sealer and the fluid divided by the density of thefluid. A positive normalized density contrast means the density of the 3C bdl, ~ealRr is greater than the density of the fluid and a negative normal-37 i 7~ density contrast means the density of the ball sealer is less than the 38 density of the fluid. It follows that a normalized density contrast of 39 zero means that the ball sealer and the fluid have the ~ame density.
-11~9~7 ] When the normali~ed density contrast is greater than zero, the 2 seating efficiency was found to be a function of the flow through the 3 perforations. In FIGURE 3 there are four plots of seating efficiency 4 versus normalized density contrast for four different flow rates through a perforation, 20 gallons per minute (gpm), 15 gpm, 10 gpm, and 5 gpm. Also, 6 the seating efficiency was found to increase as the normalized density 7 contrast decreased toward zero.
8 When the normalized density contrast is less than zero, the 9 seating efficiency was always observed to be 100% provided that the flow of fluid downward within the casing above the perforations is sufficient to 11 impart a downward drag force on the ball sealers which is greater in magni-12 tude than the upward buoyancy force acting on the ball sealers. In other 13 words, if the downward flow of fluid within the casing is sufficient to 14 transport the ball sealers downward to the perforations, they exhibit substantially 100% seating efficiency as demonstrated in laboratory tests.
16 When the normalized density contrast is greater than zero, i.e., 17 the density of the ball sealers being greater than the density of the 18 fluid, the seating efficiency of the ball sealers is a function of the flow19 rate through the perforation and the difference in density between the ballsealers and the fluid. The greater the flow rate through the perforation 21 and the less difference in density between the ball sealers and the fluid, 22 the greater the seating efficiency will be. The seating efficiency of ball23 sealers having a density greater than the density of the fluid is always a 24 statistical phenomenon. A variation in the number, spacing and orientationof the perforations is highly likely to affect the precise seating efficiency 26 which can be expected in that situation. Therefore, since the seating of 27 ball sealers having a density greater than the density of the fluid is 28 always a statistical phenomenon, there is always the possibility that too 29 few or too many of the ball sealers will seat to get the desired diversion.Practicing ball sealer diversion according to the present in-31 vention i.e~, the use of ball sealers having a density less than the density 32 of the fluid, will generally result in substantially lOODID seating efficiency 33 irrespec~ive of the flow rate through the perforations and irrespective of 34 the magnitude of difference in density between the ball sealers and the fluid. The seating efficiency of the ball sealers having a density less 36 than the density of the fluid is only a function of the downward flow of 37 fluid above the uppermost perforation in the casing. If the downward flow 38 within the casing can transport the ball sealers to the level of the per-39 forations, then the ball sealers will seat. A predictable diversion process 113~Z17 1 will occur since the number of perforations plugged by the ball sealers 2 will be equal to the lesser of the number of ball sealers injected into the 3 casing, or the number of perforation~ accepting fluid.
4 The relationship between the normalized density contrast and the fluid velocity needed to transport the ball sealers down the casing was 6 investigated. FIGURE 4 is a graph of the normalized density contrast 7 between the ball sealers and the fluid plotted against the velocity of the 8 fluid downward within the casing. This graph is based on several tests 9 which involved placing a ball sealer within a vertical piece of lucite tubing and flowing fluid downward through the tubing. The velocity of the 11 fluid was adjusted until the ball sealer was maintained in a fixed position12 at the mid-poi~t of the tubing. In that equilibrium position the drag 13 forces of the fluid shearing past the ball sealer were equal in magnitude 14 to the buoyancy forces acting on the ball sealer. Ball sealers of several densities were used in conjunction with two fluids, water and 1.13 g/cc 16 calcium chloride brine, to give the plot of FIGURE 4.
17 The solid line defines the equilibrium condition wherein the ball18 sealer will remain stationary within the casing, moving neither upward nor 19 downward. Below the line in FIGURE 4 the velocity of the fluid in the casing would be insufficient to overcome the force of buoyancy and the ball 21 sealers will rise in the casing. Above the line in FIGURE 4 the velocity 22 of the fluid in the casing exerts a drag force on the ball sealers greater 23 in magnitude than the force of buoyancy acting on the ball sealers. There-24 fore, the ball sealers will be transported down the casing.
All points on the line and below it correspond to a certain 26 normalized density contrast and a certain casing velocity which will result27 in a seating efficiency of 2ero per cent. Because the ball sealers are not28 transported down to the perforations, they cannot seat. Whereas, if the 29 normalized density contrast and casing velocity define a point above the line plotted in FIGUR~ 4, the seating efficiency will generally be substan-31 tially 100%. The buoyancy of the ball sealers will maintain them at a 32 position at or above the lowermost perforation and the downward fluid 33 velocity in the casing above the uppermost perforation will maintain the 34 ball sealers at or below the level of the uppermost perforation. It will take a very small fluid flow through a perforation to draw a ball sealer to 36 the perforation and seat it thereon when the amount of time the fluid flow 37 through the perforation has to act upon the ball sealer is limited only by 38 the length of the injection time.
1~39217 l To apply the present invention in the field, it is necessary to 2 have a ball sealer which has a density less than the wellbore fluid and at 3 the same time has the strength to withstand the pressures encountered in 4 the wellbore. It is not unusual for the bottom hole pressure to exceed 10,000 psi and even reach 15,000 psi during a well treatment. If D ball 6 sealer cannot withstand these pressures, they will collapse causing the 7 density of the ball sealer to increase to a density which can easily exceed 8 the fluid density.
9 Since fluids used for treating wells generally have densities ranging from approximately 0.8 grams per cubic centimeter (g/cc) to signi-11 ficantly above l.l g/cc, a series of light weight ball sealers are required12 having densities in the same 0.8 to l.l g/cc range.
13 Suitable materials are currently available for use in conjunction14 with ball sealers in the l.l g/cc range and greater. In the range from 0.8to l.l g/cc, techniques at manufacturing such ball sealers have not been 16 very satisfactory. For example, there is one commercially available BUNA-N17 cover~d ball sealer having a phenolic core with considerable void volume 18 which can have a density less than l.0 g/cc. Since the void volume in the l9 phenolic core is created by partially consolidating a phenolic resin using low pressure molding conditions, control of the density is extremely diffi-21 cult. A representative sample was tested and proved to have an average 22 density of .996 ~/cc and a wide distribution (0.908 to 1.085 g/cc). Moreover, 23 when these ball sealers were hydrostatically pressure tested, it was found 24 that in many of the ball sealers the void volumes were unstable and had collapsed when subjected to hydrostatic pressures as low as 6,000 pounds 26 per square inch. Correspondingly, when these void volumes collapsed, the 27 density of the ball sealers increased.
28 It has been found that a ball sealer comprising syntactic foam 29 has a high compressive strength and has a density in the range from 0.8 to 1.1 g/cc. Referring to FIGURE 5, there is shown a suitable syntactic foam 31 ball sealer lOl for use in the present invention. Syntactic foam is a 32 material system comprised of hollow spherical particles dispersed in some 33 form of binder. The commercially available low density syntactic foams 34 which appear to be sufficiently strong to withstand the pressures and tem-peratures typically encountered by ball sealers, consist of microscopic-36 ally small, hollow glass spheres (averaging approximately 50 microns in 37 diameter) dispersed in a resin binder such as epoxy. It is anticipated 38 that in the future it may become possible in syntactic foam systems to use ~ ~ 392~
] spheres made from materials other than glass and binders made from materials 2 such as thermoplastics and thermosetting plastics. In fact, Emerson and 3 Cuming Inc. has recently developed high strength glass microspheres which 4 can withstand high pressures of the magnitude typically encountered during injection molding. If injection molding can be used to make ball sealers, 6 it will be possible to use a lightweight thermoplastic or thermosetting 7 plastic as the binder resulting in a high strength ball sealer having a 8 very low density.
9 Several of the commercially available syntactic foams which appear to be suitable for use as the material of a low density ball sealer 11 are listed in Table I.
14 Hydrostatic Compressive Bulk 16 Product Manufacturer Density Strength Modulus 17 r/cc) (psi) (psi) 18 EL 30 Emerson & Cuming 0.48 8,000 250,000 19 EL 36 Emerson & Cuming 0.57 16,000 390,000 20 EL 39 Emerson & Cuming 0.62 24,000 420,000 21 EF 38 Emerson & Cuming 0.60 7,000 Not Available 22 34-~C6 Lockheed 0.54 18,000 Not Available 23 36-lB4 Lockheed 0.57 13,650 Not Available 24 39-lB5 Lockheed 0.62 15,600 Not Available 25 XP-241-36 3M 0.57 11,000 325,000 26 XP-241-42H 3M 0.67 20,000 450,000 27 The syntactic foams listed in Table I demonstrate very good 28 compressive strength when subjected to hydrostatic pressure. Many of the 29 materials will easily withstand 15,000 psi. Tests on a ball sealer having a syntactic foam core (Lockheed 36 lB4) and a rubber covering demonstrated 31 that the ball sealers were capable of withstanding hydrostatic pressures up 32 to approximately 13,500 psi before they began to fail due to the collapse ~392~7 1 of the syntactic foam. ~urthermore, each of the syntactic foams for which 2 the bulk modulus of elasticity was available has a bulk modulus of elasticity 3 comparable to that of water, which is 300,000 psi.
4 The bulk modulus of elasticity is the inverse of material com-pressibility. It represents a mate~ial's resistance to volumetric ~hange 6 as a function of hydrostatic pressure. For example, if the bulk modulus of 7 a material is greater than that of water, the material will be less compress-8 ible than water. Hence, the material's buoyancy will increase with respect 9 to the water when both are being subjected to the same pressure since the water will be compressed more. This quality of these syntactic foams will 11 assure that the density of the ball sealers remains less than the density 12 of the treating fluid, thereby, avoiding the problems encountered with the 13 phenolic core ball sealers.
14 Syntactic foam is currently available in blocks with a standard volume of approximately l cubic foot. Therefore, in order to fabricate the 16 syntactic foam ball sealers, it is necessary to machine the syntactic foam 17 blocks to preferably produce foam spheres having an appropriate diameter.
18 To fabricate the syntactic foam balls, the blocks of syntactic foam material 19 are machined in a standard manner to form syntactic foam spheres.
Syntactic foam balls may be suitably utilized in the practice of 21 the present invention without a protective covering. However, because the 22 syntactic foam material is fairly rigid and brittle, it is preferred that 23 the balls be provided with a protective covering. The protective cove~ing 24 functions to prevent damage to the surfaces of the balls while they are being transported down the wellbore. The covering may comprise a nonelasto-206 meric plastic material capable of plastic deformation to enable the ball 27 sealers to conform to the perforation and form a better seal on the perfor-28 ation. A suitable nonelastomeric plastic material for the practice of the 29 present invention is a synthetic resin such as nylon or phenolic resins.
The phenolic resins are commonly marketed as "Bakelite", snd are manufactured 31 by condensing phenol, cresol, or xylenol with formaldehyde using either 32 acid or base catalysis. However, it will be obvious to one skilled in the 33 art that other types of nonelastomeric plastic materials and nonplastic 34 materials such as aluminum will also be suitable in the practice of the present invention.
36 In order to coat the ball sealers, the surface of the ball is 37 first prepped, coated with a suitable bonding agent and then covered with 38 the desired covering. Surface preparation involving some cleaning technique 39 is important to assure the best possible bond between the covering and the -~4-i~39217 1 syntactic foam. It is most desirable if surface preparation can be limited 2 to a strong air blast which will remove most of the crushed glass and 3 debris created during machining. Sand blasting has been used with very ~ good success but its use should be limited to very brief treatments due to rapid abrasion of the core which leads to increased ball density as well as 6 a highly variable batch density. If the spheres have been handled or are 7 oily, a trichlorylethelene wash has been used satisfactorily. Once the ~ spheres are grease and oil free, they can be dipped in a suitable bonding 9 agent selected according to the covering material to be used.
Although syntactic foam is one ball sealer material, certain 11 thermoplastics can also be used. Although no unfoamed plastics exhibit 12 su~ficiently low densities to make a .8 to .9 g/cc ball sealer, polymethyl-13 pentene can be used as a material for ball sealers in the 1.0 g/cc density 14 range. Polymethylpentene has a density of .83 g/cc and is a high temperature thermoplastic (melting point approximately 250C). Ball scalers made of 16 polymethylpentene may also be provided with a suitable protective covering.17 Suitable protective coverings are nonelastomeric plastic materials and 18 nonplastic materials. All other lightweight plastics, which typically 1~ lnclude polybutylene, polyethylene, polypropylene, and polyallomer copolymers, 2~ are nearly twice as heavy as is acceptable. ~urthermore, since these 21 materials are low temperature thermoplastics, they are probably not suitable 22 for ball sealer materials from the standpoint that they are likely to 23 extnlde through the perforations under the bottom hole temperature and 24 pressure conditions typically encountered.
The principle of the invention and the best mode in which it is 26 contemplated to apply that principle have been described. It is to be 27 understood that the foregoing is illustrative only and that other means and28 techniques can be employed without departing from the true scope of the 29 invention defined in the claims.
Claims (21)
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 comprising syntactic foam, said syntactic foam being a material system comprised of hollow spherical particles dispersed in a binder, the ball sealer having a size sufficient to plug a perforation, the injection of the treating fluid into the casing being at a rate sufficient to carry the ball sealer down the casing and onto one of the perforations to substantially seal the perforation; 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 comprising syntactic foam, said syntactic foam being a material system comprised of hollow spherical particles dispersed in a binder, the ball sealer having a size sufficient to plug a perforation, the injection of the treating fluid into the casing being at a rate sufficient to carry the ball sealer down the casing and onto one of the perforations to substantially seal the perforation; 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. The method of claim 1 wherein said ball sealer is provided with a protective covering comprising a nonelastomeric plastic material.
3. The method of claim 2 wherein said nonelastomeric plastic material is a synthetic resin.
4. The method of claim 1 wherein said ball sealer is provided with a protective covering comprising a nonplastic material.
5. The method of claim 4 wherein said synthetic resin is selected from the group consisting of nylon and phenolic resins.
6. 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 comprising syntactic foam, said syntactic foam being a material system comprised of hollow spherical particles dispersed in a binder, said ball sealers having a density less than the density of the carrier liquid, said ball sealers 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 comprising syntactic foam, said syntactic foam being a material system comprised of hollow spherical particles dispersed in a binder, said ball sealers having a density less than the density of the carrier liquid, said ball sealers 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.
7. The method of claim 6 wherein said ball sealer is provided with a protective covering comprising a nonelastomeric plastic material.
8. The method of claim 6 wherein said ball sealer is provided with a protective covering comprising a nonplastic material.
9. A ball sealer for plugging perforations in a casing which has been set in a wellbore comprising syntactic foam, said syntactic foam being a material system comprised of hollow spherical particles dispersed in a binder.
10. The ball sealer of claim 9 wherein said ball sealer is provided with a nonelastomeric plastic protective covering.
11. The ball sealer of claim 9 wherein said ball sealer is provided with a nonplastic protective covering.
12. 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 comprising polymethylpentene, the ball sealer having a size sufficient to plug a perforation, 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 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 comprising polymethylpentene, the ball sealer having a size sufficient to plug a perforation, 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 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.
13. The method of claim 12 wherein said ball sealer is provided with a nonelastomeric plastic protective covering.
14. The method of claim 13 wherein said nonelastomeric plastic material is a synthetic resin.
15. The method of claim 14 wherein said synthetic resin is selected from the group consisting of nylon and phenolic resins.
16. The method of claim 12 wherein said ball sealer is provided with a nonplastic protective covering.
17. A ball sealer for plugging perforations in a casing which has been set in a wellbore comprising polymethylpentene.
18. The ball sealer of claim 17 wherein said ball sealer is provided with a nonelastomeric plastic protective covering.
19. The ball sealer of claim 17 wherein said ball sealer is provided with a nonplastic protective covering.
20. 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 the treating fluid are used to seal part of said perforations, the improvement wherein said ball sealers comprise a syntactic foam core, said syntactic foam being a material system comprised of hollow spherical particles dispersed in a binder, and a nonelastomeric plastic cover and have a density less than the treating fluid.
21. 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 comprise a polymethylpentene core and a nonelastomeric plastic cover and have a density less than said fluid.
Applications Claiming Priority (2)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US06/035,564 US4244425A (en) | 1979-05-03 | 1979-05-03 | Low density ball sealers for use in well treatment fluid diversions |
| US035,564 | 1979-05-03 |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA1139217A true CA1139217A (en) | 1983-01-11 |
Family
ID=21883472
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA000349664A Expired CA1139217A (en) | 1979-05-03 | 1980-04-11 | Low density ball sealers for use in well treatment fluid diversions |
Country Status (2)
| Country | Link |
|---|---|
| US (1) | US4244425A (en) |
| CA (1) | CA1139217A (en) |
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| US4505334A (en) * | 1983-09-06 | 1985-03-19 | Oil States Industries, Inc. | Ball sealer |
| US4679629A (en) * | 1985-03-01 | 1987-07-14 | Mobil Oil Corporation | Method for modifying injectivity profile with ball sealers and chemical blocking agents |
| US4648453A (en) * | 1985-11-18 | 1987-03-10 | Exxon Production Research Co. | Process for remedial cementing |
| US4702316A (en) * | 1986-01-03 | 1987-10-27 | Mobil Oil Corporation | Injectivity profile in steam injection wells via ball sealers |
| US4702318A (en) * | 1986-04-09 | 1987-10-27 | Mobil Oil Corporation | Injectivity profile in CO2 injection wells via ball sealers |
| BR8604808A (en) * | 1986-10-03 | 1988-05-17 | Petroleo Brasileiro S.A. - Petrobras | MECHANICAL SYSTEM AND PROCESS FOR DIVERSIFICATION IN ACIDIFICATION OPERATION OF OIL PRODUCING FORMATIONS |
| US4938286A (en) * | 1989-07-14 | 1990-07-03 | Mobil Oil Corporation | Method for formation stimulation in horizontal wellbores using hydraulic fracturing |
| US5485882A (en) * | 1994-10-27 | 1996-01-23 | Exxon Production Research Company | Low-density ball sealer for use as a diverting agent in hostile environment wells |
| US6394184B2 (en) | 2000-02-15 | 2002-05-28 | Exxonmobil Upstream Research Company | Method and apparatus for stimulation of multiple formation intervals |
| US6488116B2 (en) | 2000-06-21 | 2002-12-03 | Exxonmobil Upstream Research Company | Acoustic receiver |
| DZ3387A1 (en) | 2000-07-18 | 2002-01-24 | Exxonmobil Upstream Res Co | PROCESS FOR TREATING MULTIPLE INTERVALS IN A WELLBORE |
| US6672405B2 (en) | 2001-06-19 | 2004-01-06 | Exxonmobil Upstream Research Company | Perforating gun assembly for use in multi-stage stimulation operations |
| US7026951B2 (en) * | 2001-07-13 | 2006-04-11 | Exxonmobil Upstream Research Company | Data telemetry system for multi-conductor wirelines |
| US7348894B2 (en) | 2001-07-13 | 2008-03-25 | Exxon Mobil Upstream Research Company | Method and apparatus for using a data telemetry system over multi-conductor wirelines |
| US7647964B2 (en) * | 2005-12-19 | 2010-01-19 | Fairmount Minerals, Ltd. | Degradable ball sealers and methods for use in well treatment |
| US8936085B2 (en) | 2008-04-15 | 2015-01-20 | Schlumberger Technology Corporation | Sealing by ball sealers |
| US9212535B2 (en) | 2008-04-15 | 2015-12-15 | Schlumberger Technology Corporation | Diversion by combining dissolvable and degradable particles and fibers |
| US9260921B2 (en) * | 2008-05-20 | 2016-02-16 | Halliburton Energy Services, Inc. | System and methods for constructing and fracture stimulating multiple ultra-short radius laterals from a parent well |
| CA2744068A1 (en) * | 2008-11-20 | 2010-05-27 | Udoka Obi | Sealing method and apparatus |
| CN101899968A (en) * | 2008-12-15 | 2010-12-01 | 韦尔Spm公司 | Improved ball injector |
| GB0906541D0 (en) * | 2009-04-16 | 2009-05-20 | Brinker Technology Ltd | Delivery method and compositions |
| CA2759799A1 (en) | 2009-04-24 | 2010-10-28 | Completion Technology Ltd. | New and improved blapper valve tools and related methods |
| US8851172B1 (en) | 2009-08-12 | 2014-10-07 | Parker-Hannifin Corporation | High strength, low density metal matrix composite ball sealer |
| CA2752864C (en) * | 2011-09-21 | 2014-04-22 | 1069416 Ab Ltd. | Sealing body for well perforation operations |
| RU2496970C1 (en) * | 2012-04-20 | 2013-10-27 | Открытое акционерное общество "Татнефть" имени В.Д. Шашина | Method for waterproofing work in fractured manifolds |
| US20140345875A1 (en) | 2013-05-21 | 2014-11-27 | Halliburton Energy Services, Inc. | Syntactic Foam Frac Ball and Methods of Using Same |
| US9869154B2 (en) | 2014-11-25 | 2018-01-16 | Baker Hughes, A Ge Company, Llc | Apparatus and methods for closing flow paths in wellbores |
| US10851615B2 (en) | 2015-04-28 | 2020-12-01 | Thru Tubing Solutions, Inc. | Flow control in subterranean wells |
| US9816341B2 (en) | 2015-04-28 | 2017-11-14 | Thru Tubing Solutions, Inc. | Plugging devices and deployment in subterranean wells |
| US10774612B2 (en) | 2015-04-28 | 2020-09-15 | Thru Tubing Solutions, Inc. | Flow control in subterranean wells |
| US10233719B2 (en) | 2015-04-28 | 2019-03-19 | Thru Tubing Solutions, Inc. | Flow control in subterranean wells |
| US9567826B2 (en) | 2015-04-28 | 2017-02-14 | Thru Tubing Solutions, Inc. | Flow control in subterranean wells |
| US10641069B2 (en) | 2015-04-28 | 2020-05-05 | Thru Tubing Solutions, Inc. | Flow control in subterranean wells |
| US11851611B2 (en) | 2015-04-28 | 2023-12-26 | Thru Tubing Solutions, Inc. | Flow control in subterranean wells |
| US10513653B2 (en) | 2015-04-28 | 2019-12-24 | Thru Tubing Solutions, Inc. | Flow control in subterranean wells |
| US9567824B2 (en) | 2015-04-28 | 2017-02-14 | Thru Tubing Solutions, Inc. | Fibrous barriers and deployment in subterranean wells |
| US9745820B2 (en) | 2015-04-28 | 2017-08-29 | Thru Tubing Solutions, Inc. | Plugging device deployment in subterranean wells |
| US10655427B2 (en) | 2015-04-28 | 2020-05-19 | Thru Tubing Solutions, Inc. | Flow control in subterranean wells |
| US9567825B2 (en) | 2015-04-28 | 2017-02-14 | Thru Tubing Solutions, Inc. | Flow control in subterranean wells |
| CA2992712C (en) | 2015-07-21 | 2020-02-18 | Thru Tubing Solutions, Inc. | Plugging device deployment |
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| US9920589B2 (en) | 2016-04-06 | 2018-03-20 | Thru Tubing Solutions, Inc. | Methods of completing a well and apparatus therefor |
| US10927639B2 (en) | 2016-12-13 | 2021-02-23 | Thru Tubing Solutions, Inc. | Methods of completing a well and apparatus therefor |
| WO2018200688A1 (en) | 2017-04-25 | 2018-11-01 | Thru Tubing Solutions, Inc. | Plugging undesired openings in fluid vessels |
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| US2754910A (en) * | 1955-04-27 | 1956-07-17 | Chemical Process Company | Method of temporarily closing perforations in the casing |
| US3010514A (en) * | 1957-10-09 | 1961-11-28 | Socony Mobil Oil Co Inc | Oil well cementing |
| US3376934A (en) * | 1965-11-19 | 1968-04-09 | Exxon Production Research Co | Perforation sealer |
| US3437147A (en) * | 1967-02-23 | 1969-04-08 | Mobil Oil Corp | Method and apparatus for plugging well pipe perforations |
| US4102401A (en) * | 1977-09-06 | 1978-07-25 | Exxon Production Research Company | Well treatment fluid diversion with low density ball sealers |
| US4160482A (en) * | 1977-09-06 | 1979-07-10 | Exxon Production Research Company | Ball sealer diversion of matrix rate treatments of a well |
| US4139060A (en) * | 1977-11-14 | 1979-02-13 | Exxon Production Research Company | Selective wellbore isolation using buoyant ball sealers |
-
1979
- 1979-05-03 US US06/035,564 patent/US4244425A/en not_active Expired - Lifetime
-
1980
- 1980-04-11 CA CA000349664A patent/CA1139217A/en not_active Expired
Also Published As
| Publication number | Publication date |
|---|---|
| US4244425A (en) | 1981-01-13 |
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