US 3687203 A
A substantially vertical fracture in a well formation is partially filled to prevent healing of the fracture, and the unfilled portion of the fracture is utilized for production flow.
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Description (OCR text may contain errors)
United States Patent Malone 1 Aug. 29, 1972  METHOD OF INCREASING WELL 3,241,613 3/1966 Kern et a1. ..166/281 X PRODUCTIVITY 3,428,129 2/ 1969 Cook ..166/308 X 3,126,056 3/ 1964 Harrell ..166/28l X  ggi 3,455,388 7/1969 Huitt ..l66/308 x 3,547,198 12/ 1970 Slusser ..166/308 X  Assignee: Halliburtou Company, Du 3,456,733 7/1969 Flickinger ..l66/308 X Okla. 3,323,594 6/ 1967 Huitt et a1 ..166/308 3,228,470 1/ 1966 Papaila ..166/254  Flled- Jul-Y 3,302,718 2/1967 Prats et a1 ..166/254  Appl. No.: 59,777
Primary Examiner-Stephen J. Novosad Attomey-John H. Tregoning  US. Cl. ..166/308, 166/283, 166/307  Int. Cl. ..E21b 43/26 57 ABSTRACT 8 Fi ld f ..16 4, [5 1 e 0 Search 6/308 281 283 25 307 A substantlally vertical fracture m a well formation 1s "mes partially filled to prevent healing of the fracture, and  Refe Cited the unfilled portion of the fracture is utilized for UNITED STATES PATENTS p ction flow. 3,224,506 12/ 1965 Huitt et al ..166/308 X 4 Claims, 2 Drawing Figures PATENTEUAUGZQ m2 .687203 i INVENTOR. g 2. 10 100 William T. Malone METHOD OF INCREASING WELL PRODUCTIVITY This invention relates to the treatment of oil and gas wells. More particularly, this invention relates to hydraulic fracturing in a well formation.
Hydraulic fracturing for production stimulation is common procedure in the present day oil and gas industry. Fracturing treatments are performed on wells of various potentials to help increase production rate.
Basically, hydraulic fracturing is the application of fluid pressure to a desired section of the formation. The fluid under pressure penetrates the more permeable zones to form a hydraulic wedge and causes parting to occur in the formation. With continued pumping, the perforation is extended, thus creating a new and larger channel to the well bore. It has been found that the fracture produced will in most cases be vertical, or near vertical, with respect to the well bore.
The normal means of fracturing is to perforate in the zone to be fractured, create the fracture and then add a propping agent to the fluid in varied quantities to pack and fill the fracture. Without the propping agent a fracture tends to heal or close and reduce the fracture flow capacity. The flow capacity of a fracture filled with a propping agent is largely dependent on the characteristics of the propping agent and while the propping agent within the fracture provides and preserves a more permeable path for production flow, it also tends to partially restrict the flow of the fluid from the fracture into the bore hole. In addition, the release of formation fines from the fracture surfaces which can become integrated within the propping agent, the embedding of the propping agent in the formation, and the crushing of the propping agent under the weight of the overburden can seriously reduce the permeability of the propping agent and the flow capacity of the fracture.
Moreover, it is desirable to use relatively inexpensive and easily available propping agent such as ordinary screened river sand. However, because of the desire to prevent a reduction in the fracture flow capacity, in most instances it has been necessary to employ other types of propping agents which are generally more round and have a higher compressive strength than the ordinary river sand. These other types of propping agents still act to partially restrict the flow of the fluid from the fracture into the bore hole and normally they are more expensive and less available than the ordinary screened river sand.
The present invention provides a method which will increase the flow capacity in a generally vertical fracture by virtually eliminating the restriction on the flow caused by the propping agent.
To accomplish this, a fracture is initiated in a nonproductive zone and is extended up into a producing zone. The well is then treated in a conventional manner with a suitable material such as sand or other solids or with fluids which set solid or semisolid. The material settles in the bottom portion of the vertical or near vertical fracture and fills up to some height less than the height of the fracture to hold a portion of the fracture above the settled material open. This open portion or channel above the bed of material allows the part of the fracture in the producing zone to have infinite ability to conduct production flow from the formation into the well bore.
. a bed of some height has been formed.
Referring now in detail to the drawings, in the present method the bore wall 10 is perforated in a conventional manner in a nonproducing zone 11a and slightly below the producing zone 11 and a fracture 12 is then created by the appliedpressure of a fracturing fluid through the casing 10a and is extended up into the producing zone 11. Previously, there was some question as to whether a fracture initiated in a nonproducing zone would proceed into the producing zone or merely go down the beddingplane. Recent tests now show that the fracture will continue into the producing zone.
A predetermined amount of material 13, such as a proppant, cement slurry, resin or the like is then added to the fracturing fluid to partially fill the fracture. As will be seen later, the particular material selected to fill a portion of the fracture is relatively unimportant because of its limited effect on the production flow in the fracture. As the material particles enter the fracture 12, they begin the settle to the bottom of the fracture 12 under the influence of gravity. The particles continue to settle until a bed 14 is formed. The actual height of the bed 15 and the length of the bed 16 depends on fluid and fracture characteristics.
Thus, the bed of material is left in the bottom portion of the fracture essentially within the nonproducing zone and, due to the limited formation elasticity, an upper portion 17 of the vertical fracture above the bed and in the producing zone 1 1 remains open. Preferably, the bed extends up to and not into the producing zone 11, but as long as an open channel in the producing zone 11 above the bed remains a part of the fracture will have an infinite ability to conduct the production flow from the formation into the well bore.
Since this production flow in the open channel does not flow through the material filling the fracture almost any material can be used including ordinary screen river sand. In addition, the filler material can be treated with resin or cement to shut off water or other undesirable fluids from the fracture. One manner of accomplishing this is to pump into the fracture a mixture of kerosene, cement and water. The mixture is pumped in under dynamic conditions, however, once in the fracture it is static and gravitational separation will occur causing the cement to set in the fracture and allowing the kerosene to flow out of the fracture. Furthermore, the open channel, once obtained, can be acidized in the conventional manner with hydrochloric acid or other acids to further etch the walls of the open channel portion of the fracture and assist in the increase of production flow.
Various procedures can be utilized to carry out the above described invention. The following is one such procedure and is offered only to illustrate the invention and is not in any way intended to limit the invention.
In illustrating this particular procedure the well treated, the formation of the well, and treatment materials are presumed to have certain characteristics. The distance from adjacent wells or well spacing is 40.0
acres, with a drainage radius, which is one-half the distance between the wells, of 660.0 feet. There is no tubing in the hole during fracturing and the inside diameter of the casing in the hole is 4.892 inches. The piping system of the well is adapted to withstand a maximum pressure of 5,000 PSI at the well head. The depth of the formation is approximately 10,000 feet and the vertical extent of the formation is about 50 feet. The permeability of the formation or the ability of the formation to conduct fluid is 0.00500 darcies. The formation has a damage ratio of 1.00 which means that there will not be any skin damage to the formation. The modulus of elasticity of the formation is 4.0 X PSI and the pressure at the bottom of the hole or at the formation is 7,500 PS1. The base fluid used to fracture the well is water, with 2 percent potassium chloride added to the water to protect the formation clays from swelling. The gelling agent used to impart viscosity to the base fluid is guar gum. Other additives to the base fluid include a pH control additive to control the pH of the base fluid, a fluid loss control additive, such as finely divided silica flour, to prevent the base fluid from bleeding into the formation from the fracture, and a nonemulsifying agent to reduce surface tension of the fluid. The fluid loss control additive has an efficiency of 0.001000. The spurt loss or initial loss of the fracturing fluid into the formation before the loss control additive takes effect is negligible.
In carrying out this procedure it is common in this field of the art to make certain additional presumptions. The fracture formed is presumed to be substantially vertical with its maximum vertical extent limited to the vertical height or length of the formation. It
should be noted that in some cases the vertical extent of the fracture may not extend the entire vertical length of the formation and is in part dependent on the injection rate and fluid viscosity of the fracturing fluid. The formation, although not necessarily true, for purposes of carrying out this particular procedure is considered uniform in thickness and homogeneous over the drainage area of the well. In addition, the equations for pumping fracture width, as set forth in the September 1961 issue of the Journal of Petroleum Technology, in the article by T. K. Perkins and L. R. Kern Widths of Hydraulic Fractures, and the production increase curves, as set forth in the article by .l. M. Tinsley, J. R. Williams, R. L. Tiner and W. T. Malone, Vertical Fracture Height Its Effect on Steady-State Production Increase in the May, 1969 issue of the Journal of Petroleum Technology, are considered valid.
A further presumption involves the distribution of the proppant in the fracture. It is felt that the proppant distribution in the fracture will be in accordance with certain sand transport model correlations. in these correlations it has been found that the movement of the sand in a vertical fracture is primarily dependent upon the fluid viscosity, fluid velocity and particle size. As the sand enters the fracture, it begins to settle to the bottom of the crack, under the influence of gravity. A bed of sand builds up until it becomes high enough to cause the cross-sectional area to be reduced to a point where the fluid velocity is sufficient to carry the sand in suspension. At this point an equilibrium condition is reached where the bed in neither growing nor shrinking as long as the conditions such as rate do not change.
Any sand that enters the system is carried over the equilibrium bed and deposited ofi the end causing the bed extension to grow horizontally and vertically at the same time. The equations used in predicting this bed height are set forth in the article by R. E. Babcock, C. L. Prokop, and R. O. Kehle, Distribution of Propping Agents in Vertical Fractures in the November, 1967 issue of Producers Monthly.
With these characteristics for the well, formation and treatment materials in mind, it has been found that a vertical fracture approximately 50 feet in vertical height and 198 feet in horizontal length can be filled with a propping agent of No. 10-20 sand to give a bed height at the opening of the fracture of approximately 25 feet if certain conditions are met during the fracturing and propping treatment. These conditions include first pumping 5,000 gallons of a proppant free fluid into the well to initiate and condition the fracture and then pumping 45,000 gallons of fluid carrying the proppant into the well. Forty-five thousand pounds of sand are added to the fluid with an average concentration of 1.00 pound per gallon. The gel concentration of the fluid is 50 pounds per 1,000 gallons. The injection rate of the fluid is 15 barrels per minute with a maximum pressure at the well head of 1,000 PS1. The hydraulic horsepower used is 1,100. In addition to having a bed height of 25.2 feet the total area of the fracture filled with the sand will be 10,000 square feet and treatment under these conditions has been found to produce a fracture width of 0.538 inch. This particular treatment in which the fracture is approximately half filled with proppant at the opening into the bore, has been found to increase production flow by three times over the production flow prior to the treatment. It should be noted that these conditions or parameters can be varied to vary the filled area of the fracture.
It will be apparent that many widely different embodiments of this invention may be made without departing from the spirit and scope thereof, and, therefore, it is not intended to be limited except as indicated in the appended claims.
What is claimed is:
1. A process for producing an open channel in a first subterranean zone comprising:
contacting a second subterranean zone with a fracturing fluid, said second zone being adjacent to and below said first zone,
applying sufficient pressure to said fluid to initiate a fracture in said second zone,
introducing a sufficient quantity of said fluid into said fracture to extend said fracture into said first zone, and,
maintaining a pressure on said fluid sufficient to hold said fracture open while placing a sufficient quantity of propping agent into said fracture to substantially fill said fracture up to about the base of said first zone.
2. The process of claim 1, wherein said first zone and second zone are penetrated by a bore hole.
3. The process of claim 2, wherein said bore hole is fitted with suitable casing and annular sealant to isolate said first and second zones within said bore hole.
4. The process of claim 3, wherein said fluid contacts said second zone through a set of perforations.