CA2226988A1 - Method for vertically extending a well - Google Patents

Abstract

The present invention is a method for fracturing a zone to collect fluids from the zone through a well bore. The method introduces into the well bore a series of fracturing fluids to fracture the sediments either above or below the bottom of the well bore. A fracture extends from the well bore into the sediments which can include a plurality of producing zones.

Description

METHOD FOR VERTICALLY EXTENDING A WELL
The present application claims priority from copending U.S. Provisional Application Serial No. 60/035,492 entitled "METHOD FOR VERTICALLY EXTENDING A WELL" and filed January 14, 1997, which is incorporated herein by this reference.

FIELD OF THE INVENTION
The present invention relates generally to a method for completing wells that collect fluids from a subterranean zone and, particularly, to a method for fracturing a subterranean zone for oil and/or gas production.

BACKGROUND OF THE INVENTION
The conventional process to produce fluids, such as oil and/or gas, from one or more subterranean zones is to drill a well into the zones. The zones are hydraulically fractured to increase the zone's permeabilities by providing fractures in the zones along which fluids can travel. The increased permeabilities increase the recovery of oil and/or gas by the well.
The process of hydraulically fracturing a target zone is composed of numerous steps. In the most common process, the steps include cementing a production casing in a well, loading an explosive device such as a perforating gun, lowering the device into the well by a wireline or similar device to-the depth of the target zone, perforating the production casing in the well by triggering the explosive device, introducing a fluid into the target zone through the perforations to hydraulically fracture the target zone, and introducing a proppant into the fracture to restrict closure of the fracture after the fluid is removed from the well. The lengths of the fractures are typically limited to the target zone to prevent undesired fluids from other zones from flowing into the target zone along the fractures, to prevent the loss of the desired fluid into adjacent thief zones, and to prevent the commingled production of fluids from different zones. Thus, the casing is cemented in the well bore not only for well bore support but a]so to isolate the target zone from other zones. This technique is especially adapted for use in fracturing discrete, continuous zone-type deposits of the type shown in Fig. 1 from the well 50. The sandstone layer 54 a,b in such deposits is relatively thin (e.g., less than 200 feet) and is theref'ore easily--targeted for fracturing by this technique.
I'he technlque is not effective in recovering oil and/or gas f'rom thick deposits, such as many tight-sands gas deposits. Gas contained in such deposits is much more difficult to recover than the gas in the continuous zone-type deposits exemplified in Fig. 1 due to their differing geologic charac:teristics distributed over great vertical heights. As ~5 shown in Fig. 2, the gas in tight sands deposits is contained in isolated, discontinuous sandstone stringers 58 of varying shapes and sizes which are in poor fluid communication with one another and are spaced over a vertical depth of typically more than about 500 feet and frequently over several thousand feet. Due to their highly heterogeneous nature, tight sands deposits include not one but a plurality of gas reservoir zones spaced over this large vertical depth interval. Due to the extreme thickness of tight sands deposits, the above-described conventional fracturing technique is of limited effect:iveness in fracturing the numerous stringers 58 to permit the gas in the stringers to flow into the well 62. To fracture a multiplicity of such zones, the steps described above could be repeated for the larger stringers 58 and not the smaller stringers 58 due to cost prohibitions, thereby resulting in high well completion costs but also decreased oil and/or gas recoveries.
The fracturing technique described above is also not effective for frac-turing zones located at greater depths than the bottom of the well. To employ the conventional fracturing technique, the well must be drilled to the depth of the target produc:ing zone. This is often impractical and/or uneconomical for deep zones and/or for existing wells that for various reasons were originally drilled shallower than a desired targel zone.

~ s a result of the high cost to drill and complete a well according to the above-noted technique, it is uneconomical to produc:e the oil and/or gas in many zones, especially zones located at depths below the bottom of the well or contained in the very thick tight sands deposits. Consequently, many oil and/or- gas deposits are deemed uneconomic and therefore not recoverable.

SUMMARY OF THE INVENTION
Pn objective of the present invention is to provide an inexpensive method to produce fluids from subterranean zones.
A related objective is to provide an inexpensive method for completing a well.
Pnother objective is to provide an inexpensive method for produc:ing fluids from subterranean zones that are located below the total depth drilled in a well previously drilled or to be drilled.
Yet another objective is to provide an inexpensive method for producing fluids from tight sands deposits.
The present invention realizes one or more of the above objectives by providing a method for vertically extending a hydraulic fracture either upwards or downwards through a multiplicity of zones. In one aspect of the present ~5 invention, the method includes the steps of introducing into the well bore a first fracturing fluid to initiate a fracture in a zone and introducing a second fracturing fluid, having a different composition than the first fracturing fluid, to propagate the fracture in a substantially vertical direction.
The direction of propagation of the fracture (i.e., upwards or downwards) is controlled by controlling (inter alia) the density (i.e., specific gravity) and thereby the static pressure gradient of the second fracturing fluid in the well bore. In one embodiment , to propagate the fracture upwards the average pressure gradient is preferably less than about 65% of the average fracture extension pressure gradient of the zones to be fractured. Based on an average fracture extension pressure gradient of 0.88 psi/ft, the average fluid pressure gradient preferably ranges from about 0.25 to about 0.58 psi/ft:. In another embodiment, to propagate the fracture downwards the average pressure gradient preferably is more than about 120% of the average fracture extension pressure gradient of the zones to be fractured. Based on the average fracture extension pressure gradient of 0.88 psi/ft, the average fluid pressure gradient preferably ranges from about 1.10 t:o about 1.40 psi/ft.
To initiate a single unidirectional fracture, the initial fracture breakdown is achieved by a very slow injection of a relatively low density fluid. The initial fracture is then extencled by a high viscosity fluid injected to a high volume rate to form a fracture having a size sufficient to accommodate a sufficient amount of the second fracturing fluid to cause the dominantly upward or downward fracture S propagation. To yield this result, the initial fracture preferably has a vertical height of at least about 700 feet (i.e., about 350 feet radius from the point of injection).
l'he initial fracture extending fluid preferably has a high viscosity of at least about 500 Cp. The fluid's injection rate should be as high as practical for the pumping equipment available.
l'o facilitate a ~om;n~ntly vertical fracture growth, the second fracturing fluid (i.e., fracture pad) preferably has a relatively low viscosity and a relatively low injection rate.
In one embodiment, the second fracturing fluid has a preferred viscosity of no more than about 50 Cp and an inject:ion rate of less than about 20 bbl/min. In another embodiment, the ~second fracturing fluid has a preferred viscosity of no ~Lore than about 100 Cp.
To achieve vertically upward growth, this second fracturing fluid should have a specific gravity of less than about 1.0 and preferably less than about 0.5 to create dominantly vertical upward growth. To achieve vertically downward growth, the second fracturing fluid should have a specific gravity preferably of more than about 2.5 and, more preferably more than about 3.0 to maximize vertically downward growth.
Additional fracturing fluids can be introduced to complete the well. For example, fracturing fluids containing various types and sizes of proppants can be introduced to prop the fracture open for later oil and/or gas production.
I'he completed fracture preferably has a ratio of its vertical length component to its horizontal length component of more than about 1.0, more preferably more than about 2.0 and most preferably ranging from 5 to 8. The vertical component preferably ranges from about 1,500 to about 10,000 feet.
I'he present invention addresses the limitations of existing well completion methods. The present invention can provide an inexpensive method to produce fluids from subterranean zones, particularly zones located at considerable depths, and thick and/or irregular zones, such as the typical tight sand deposits. The fracture of the present invention can extend vertically over thousands of feet in contrast to fractures yielded by existing fracturing techniques, which generally extend vertically only over a few hundred feet or less.
I'he present invention can extend a downward growing fracture to penetrate and produce oil/gas from zones which are ~5 much deeper than the drilled total depth of the well. The substantially vertical fractures of the present invention thus permit the well to produce fluids from zones at much greater depths than the drilled depth of the well. The present invention can decrease drilling time for wells and thereby decrease the time and rate required to drill and complete such wells.
The tall slender (i.e., elongated) vertical fractures of the present invention enable existing completed wells to be easil~ and cheaply modified to produce fluids from subterranean zones that are deeper than the wells. The wells can be vertically extended without extensive and costly redrilling or deepening of the well. The preSent invention therefore can significantly increase the productivity of many existing wells.
In light of the unique capabilities of the present invention described above, the invention can significantly increase existing oil and/or gas reserves. It renders economic many oil and/or gas deposits that are presently uneconomic based on existing fracturing and/or other well completion techniques.
In yet another aspect of the present invention, a method is provided for forming the fracture by propagating the fracture up from the bottom of the well bore. The well bore thus extends to the bottom of the lower-most zone of interest.
~5 An uncemented casing is set from the surface down to the bottom of the lowest zone of interest. The length of the annulus between the uncemented casing and the well bore wall from the top of the upper-most zone of interest and bottom of the lGwer-most zone of interest is uncemented but filled with a permeable gravel pack to permit the multiple zones located along the length to be in fluid communication with one another via the open well bore. The permeable gravel pack is preferably substantially consolidated.
The method includes the following steps: (i) selecting a desired ratio of the height and horizontal length of the fracture; (ii) based on the ratio, selecting a permeability and median grain size for a sand or gravel-pack proppant material to be packed into a water or liquid-filled annulus between the well bore and the production casing; (iii) placing the proppant material into the water- or liquid-filled annulus; and (iv) injecting at fracture pressures a fracture initiation fluid, such as a gelled water frac pad, through the annulus and into the formation at the bottom of the uncemented casing to cause fracture initiation. Some of the proppant in the annulus gravel pack may be carried by the fracture initi~tion fluid into the fracture. Additional fracturing fluids, including proppant-containing slurries, can be passed through the annulus and into the growing fracture as needed to achieve the desired fracture growth.

It is a surprising and unexpected result that the ratio of the fracture height and its horizontal length is related to the magnitudes of the proppant permeability and the average cross-sectional area of the annulus, (i.e., the fluid transmissibility of the proppant-packed annular area). "Fluid transmissibility" of the annulus is the mathematical product of the fluid permeability of the gravel pack proppant in the annulus and the average cross-sectional area of the annulus normal to the direction of fluid flow through the annulus.
It has been discovered that the rate of fracture propagation in the vertical direction (and therefore to the magnitude of the fracture height) is in part directly related to the magnitude of the fluid transmissibility. The rate of fracture propagation in the horizontal direction (and therefore to the magnitude of the horizontal length of the fracture) is inversely related in part to the magnitude of the fluid transmissibillty. Other factors influencing the rate of fracture propa-gation horizontally and vertically include the viscosity of the fracturing fluid, the fracturing fluid injection rate, and the pressure gradient within the proppant-packed annular area. The pressure gradient is related to the fracturing fluid injection pressure at the bottom of the well bore and the fracturing fluid out-flow pressure from the top of the proppant-packed annular area.

This method permits the vertical and horizontal extent of the fracture to be controlled by the selection of these parameters. Preferably, the parameters are selected to provide a fracture having a significantly greater height than horizontal fracture length. Typically, the ratio of the fracture height to the fracture length horizontal length is no less than about 2:1, more typically no less than about 3:1, and most typically no less than about 5:1. Ratios of 10:1 and more are desired and achievable. The method provides the ability to maximize the upward growth of the fracture while minimizing the outward fracture growth. As will be appreciated, for oil-bearlng formatlons such as tlght sands, lt ls deslrable to have one or more fractures extendlng across multlple zones to great helghts whlle malntalnlng the horlzontal length of the fracture to relatlvely low magnitudes. In thls manner, the cost to frac a well ln such applicatlons ~is substantlally mlnimlzed by substantlally mlnimizing the ~volume of fracturing fluids consumed in propagatlng the fracture outwardly. Most commonly, the method wlll form a slngle fracture and not a multlplicity of fractures, across the multiple zone~s) of interest.
Whlle not wlshlng to be bound by any theory, lt is believed that the surprising abllity of the method to preferentially vertlcally extend the fracture ls due ln part to the method's unlque abllity to bypass obstacles, such as pliable shales, salts or coals, which are difficult to fracture by other techniques. The gravel-packed, uncemented open well bore permits the fracturing fluid to initiate fractures both above and below the obstacle which are collectively able to apply a sufficient force to the obstacle through a "scissors-type" action to fracture the obstacle.

BRIEF DESCRIPTION OF THE DRAWINGS
Fig. 1 depicts a well completed according to existing fractu~ing techniques;
Fig. 2 depicts another well completed according to existing fracturing techniques;
Fig. 3 depicts a well completed according to a first embodiment of the present invention;
Fig. 4 depicts a well completed according to a second embodiment of the present invention;
Fig. 5 is a plan view of a fracture completed according to either embodiment of the present invention;
Figs. 6A-E depict the propagation of a fracture according to the first embodiment for vertically upward fracture growth;
Figs. 7A-C depict the propagation of the fracture in the first embodiment during introduction of the proppant-carrying fracture (i.e., fracture packing fluid);
Figs. 8A-C depict the gel breaking process in the first embodimenti Figs. 9A-D deplct the propagation of the fracture in the second embodiment for vertically downward fracture growth;
Fig. 10 is a plot of the vertical fracture depth against horizontal distance from the well bore in the second embodiment;
Fig. 11 is a composite of Figs. 9A-D and 10;
Fig. 12 depicts the propagation of the fracture in the second embodiment at various stages of introduction of the fracture transition fluid;
Fig. 13 depicts the gel breaking process in the second embodiment;
Fig. 14 is a plot of fracture depth, width, and area against fracturing fluid volume in experiment l;
Fig. 15 is a plot of fracture depth, width, and area against fracturing fluid volume in experiment 2;
Fig. 16 is a plot of fracturing fluid volume and height of gel-broken fracturing fluid against time for experiment 2;
and Figs. 17A and B depict yet another embodiment of a well according to the present invention.

DETAI LED DESCRI PT ION

A first aspect of the present invention is based on the recognition that a more efficient system for recovering fluids from deep zones and/or tight sands deposits is to employ substantially vertical fractures of relatively tall vertical heights and shorter horizont~l lengths emanating from an open segment of a well bore. Two embodiments of such a system are depicted in Figs. 3 and 4. In the first embodiment of Fig. 3, the well bore 66 extends through the zone(s) 70a,b,c of interest and intermediate zones 72 a,b with a fracture 74 extending vertically upward through the various zone(s). In the second embodiment of Fig. 3, the well bore 78 has a depth less than the depth of a zones(s) 82a of interest with a fracture 86 extending vertically downward through the various zone(s) 82a, b, 84. In both vertical figures, the planes of the fracture 74, 86 are in the plane of the page. Unlike existing fracturing techniques, both embodiments described herein have a single fracture extending vertically through a plurality of zones.
In both embodiments, the well 10 includes the well bore 90a,b, a well casing 94a,b, a well head (not shown), and a production casing 98a,b positioned within the well casing 94a,b. The well bore 90a,b generally has a diameter ranging from about 7 to about 15 inches. The well casing 94a,b generally has a diameter ranging from about 4 to about 10 ~5 inches. The well casing 94a,b is preferably cemented to the wall of the well bore 90a,'c). The well head ~not shown) is supported by the well casing 94a,b. The production casing 98a,b is attached to the we:Ll head.
The cemented portion of the well casing should extend below the depth of any exposed water-producing sediments to seal such sediments from the open well bore 90a,b.
The open well bore 102a,b is located below and in c~mmlln;cation with the lower portion of the production casing 98a,b. As discussed below, the hydraulic pressure on the sediments 70c, 82b from the Eracturing fluid in the open well bore 102a,b causes the formt~tion of the fracture 74, 86 from the open well bore 102a,b. The fracturing fluid can be any compressible or non-compressible fluid used to initiate and propagate hydraulic fractures through the rocks or sediments.
The fractures 74, 86 extend from the open well bore 102a,b through various intermediate non-productive sediment zones 72a,b and 84 to and through one or more desirable zones 70, 82. Valuable fluids, such as water, oil and/or gas, travel along the fractures 74, 82 into the well 66, 78 for collection. In the first embodiment of Fig. 3, the fracture 74 generally has a vertical height (i.e., vertical component) ranging from about 1,500 lo about 5,000 ft, a horizontal length (i.e., horizontal component) ranging from about 500 to about 1,500 ft, and a width at the well bore ranging from about 0.10 to about 0.50 inches. In the second embodiment of Fig. 4, the fracture 82 generally has a vertical length ranging from about 2,500 to about 10,000 ft, a horizontal length ranging from about 500 to about 2,000 ft, and a width at the well bore ranging from about 0.10 to about 0.50 inches.
As will be appreciated, the use of the fracture 82 in the second embodiment to extend the well 78 to the deeper zone 82a permits a shallower well to be drilled to access the zone 82a than is allowable with existing methods.
Referring to Fig. 5, a plan view of the well bore and fracture pattern 106 is depicted for both embodiments. The vertical fracture (plan view) pattern 106 is typically about 0.2 to about 0.5 inches wide at the well bore 110 and tapers down to about "0" inches iIl width at the fracture tip. As will be appreciated, the precise fracture pattern can vary depending upon the characteristics of the rocks to be fractured.
Returning to Figs. 3 and 4, for optimal results, it is important to maximize the vertical components 110, 114 of the fractures 74, 86- (or rate of growth (i.e., increase) in the vertical direction during fracturing) while minimizing the horizontal components 118, 122 ~or rate of growth in the horizontal direction durinq fracturing). The ratio of the vertical component (or rate of growth (i.e., increase) in the vertical direction during fracturing) to the horizontal ~5 component (or rate of growth in the horizontal direction during fracturing) is preferably more than about 2.0 and more preferably ranges from about 4.0 to about 7Ø
As will be appreciatecl, the direction and shape of the fractures 74, 86 can be influenced by (i) variations in the fracture extension pressure gradients of the various sediments to be fractured, ~ii) fracturing fluid friction pressure losses, and (iii) density (i.e., specific gravity) of the fracturing fluids. The difference between the average fracture extension pressure gradient of the zone(s)/sediments to be~fractured and the average pressure gradient of the fracturing fluid in the fracture can be used to control the ratio of vertical to horizontal growth and thereby the geometry of the vertical fracture. The greater the difference between them equates to a greater vertical to horizontal growth ratio. When the average fracture extension pressure gradient of the rock exceeds the average static fracture fluid pressure gradient, the fracture will propagate (i.e., grow) upwards. When- the average fracture extension pressure gradient is less than the average static fracture fluid pressure gradient, the fracture will propagate (i.e., grow) downwards.
To form a vertical fracture propagating upwards in the first embodiment, the average static pressure gradient of the fracture propagation fluid preferably is no more than about ~5 65%, and preferably less than about 40~, of the average rock fracture extension pressure gradient of the zone(s) to be fractured. Based on an average rock fracture extension pressure gradient of 0.88 psi/ft, the average static fracture propagating fluid pressure gradient preferably is no more than 5 about 0.60 psi/ft and more ]preferably ranges from about 0.45 down to about 0.20 psi/ft or less.
To form a vertical fracture propagating downwards in the second embodiment, the average static pressure gradient of the fracture propagation fluid preferably is more than about 120%, and more preferably over about 140%, of the average fracture extension pressure gradient of the zone(s) to be fractured.
Based on an average fracture extension pressure gradient of 0.88 psi/ft, the average pressure gradient preferably is more than about 1.05 psi/ft and more preferably ranges from about 1.20 to about 1.40 psi/ft.
The fluid friction loss along the fracture also influences the geometric shape of the fracture. Higher friction loses -resulting from high viscosities and high injection rates ~i.e., about 65 bbl/min. or higher), cause the fracture to propagate upward, outward and downward in a more symmetrical radial pattern resulting in a penny-shaped fracture. The friction loss increases with fracturing fluid viscosity and volumetric injection rate.
Referring to Fig. 3, the process used to form the ~5 fracture 74 of the first embodiment will now be described.

Before fracturing can be initiated, the well head casing 94a, well head (not shown), and production casing 98a are installed in the well bore 90a. The production casing is positioned in the well bore to yield the open well bore 102a below the production casing 98a.
To prepare the well 66 for the fracturing fluid (not shown), a cleaning fluid (not shown) can be correlated in the open well bore 102a. The cleaning fluid scours the walls of the well bore 102a and displaces and removes mud in the well bore 1~2a.
Referring to Fig. 6A, after well preparation, the first fracturing fluid, a fracture initiation fluid 120, is introduced into the open well bore 102a through the production casing 98a to form a fracture in the zone 70c. The fracture will typically propagate in a plane that is substantially perpendicular to the zone's axis of least principal stress (i.e., horizontally). The fracture initiation fluid 120 will move to the bottom of the well bore 90a and fill the open well bore 102a, displacing the cleaning fluid and causing the fracture 74 to form from the top 124 of the open well bore 102a. At the top of the open well bore, the exposed portion of zone 70c is shallowest and therefore has the least principal stress breakdown pressure for fracture initiation.
While not wishing to be bound by any theory, it is believed that as the fracture length increases, the fracture initiation fluid will have increased friction loss (causing increased friction pressure) along the length of the fracture, causing the fracture to propagate vertically by extending itself into the adjacent zones with slightly higher fracture extension pressures.
After fracture initiation, the fracture initiation fluid 120 preferably has a relatively high viscosity and preferably is injected at as high a rate as practical to create a relatively high friction ]oss to propagate or extend the fracture. The fracture initiation fluid is preferably gelled water having an average viscosity of no less than about 305 Cp, more preferably greater than about 500 Cp, and even at least about 1,000 Cp is desirable in some cases. The gelled water fracture initiation fluid is substantially free of a proppant.
To facilitate vertica:L fracture growth into shallower zones, the preferred average pressure gradient of the fracture initiation fluid~in the well bore is as noted above. This pressure gradient will cause the fracture to grow upward rather than downward.
The resulting fracture 124 has sufficient horizontal and vertical lengths and widths to accommodate later fracturing fluids for vertical growth of the fracture. A vertical fracture height of at least about 500 feet, and more preferably ranging from about 800 to about 1,200 feet, is preferred to initiate the desired vertical fracture growth.
The acceleration in the growth rate of the vertical fracture component 110 increases as the total vertical length 110 of the fracture increases. The maximized growth rate in the vertical fracture component L10 is realized when the vertical fracture height is more than about 2,000 feet.
Referring to Fig. 6B, following the formation of the fracture 124 a proppant-carrying fracture (i.e., well bore packing) fluid 128 can be introduced into the well bore 102a to displace the lighter fracture initiation fluid 124 upwards and fill the lower portion of the fracture 132 with proppant.
The lower portion of the fracture will thereby be propped open. The displaced frac:ture initiation fluid 124 will continue propagating the fr~cture 132 vertically upwards.
The well bore packing fluid 128 is a proppant-containing slurry. This proppant/liquid slurry preferably ranges from about 65 to about 75% by volume liquid and about 25 to about 35% high strength~j high density proppant. This yields a fluid specific gravity-preferably ranging from about 2.75 to about 3.18. The static fluid pressure gradient of this slurry preferably ranges from about 1.19 to about 1.38 psi/ft.
The proppant in the slurry preferably has a specific gravity of more than about 7Ø The preferred proppant is steel shot (7.5 specific gravity) having a size ranging from ~5 about 10 to about 16 mesh ~Tyler).

The gelling agent of the well bore packing fluid 128 is caused to break and release the proppant preferably within about 10 to about 20 minutes after introduction into the fracture where its temperalure rapidly increases up to the normal formation temperature. This increase in temperature activates a gel-breaking agent contained in the gelled slurry.
The proppant then settles out of the slurry and settles to the bottom of the fracture 130.
Referring to Figs. 6C-D, to propagate the fracture upward to yield the desired vertical component 110 while substantially minimlzing the horizontal component 118, a low density fracture propagation fluid 136 is next introduced into the well bore 102a. This low density fracture propagation fluid 136 may be a low viscosity nitrogen foam, or a low viscosity ungelled water.
The static fluid pressure gradient of this vertical growth fracture propagation fluid should be less than about 0.50 psi/ft and preferably ranges from about 0.20 to about 0.45 psi/ft. Consequently, the specific gravity of the fracture propagation fluid should be less than about 1.15 and more preferably ranges from about 0.46 to about 1.04. The difference between the typical rock fracture extension pressure gradient and the static fluid pressure gradient should be greater than 0.40 psi/ft and preferably ranges from about 0.43 to about 0.68 psi/ft or more. This difference yields a very large upward ,~riving force pushing a spearhead of the fracture propagation fluid in the fracture 144 more strongly vertically rather than horizontally. The fracture propagation fluid 136 preferably has a low viscosity and is introduced at a relatively low rate to maximize the ratio of vertical fracture height to horizontal length by substantially minimizing friction pressure along the fracture. The preferred viscosity is less than about 10 Cp and more preferably ranging from abc,ut 1 to about 3 Cp. Preferably, the fr'acture propagation fluid rate is less than about 20 bbl/min.
To further maximize the fracture height produced by the fracture propagation fluid 136, the fluid can include a fluid loss inhibitor. The fluid loss inhibitor prevents the loss of fluid through microfractures and fissures in the sediments through which the fracture propagates. A preferred fluid loss inhibitor may be benzoic acid crystals which yields a filter cake barrier over all of the permeable zones. Later gas production from-the zones will vaporize the benzoic acid, thereby eliminating the filter cake barrier. Alternatively, other gas vaporizable crystals or flakes can be used for this purpose.
Referring to Fig. 6E, a high viscosity fracture transition fluid 160 can be introduced into the well 66 to ~5 increase the width of the fracture 144 to prevent screen-out of proppant-containing fracturing fluids in later stages. As will be appreciated, screen-out can occur at fluid interfaces.
The fluid preferably increases the width of the fracture at the well bore to more than about 0.25 inches and more preferably more than about 0.40 inches. The width increase is caused by the high friction pressure along the fracture from the high viscosity of the fluid. The fracture transition fluid displaces the lighter fracture propagation and fracture initiation fluids and the liquid component of the well bore packing fluid upwards, thereby causing additional vertical fracture growth.
The fracture transition fluid 160 preferably has a viscosity of no less than about 350 Cp and more preferably ranging from about 500 Cp to about 1,000 Cp or higher. The preferred fracture transition fluid is a gelled water. The gelling agent in the fracture transition fluid can be any suitable gelllng agent.
As will be appreciated, the width of the fracture depends upon the viscosity and the injection rate of the fracture transition fluid. Preferably, the injection pumping rate is more than about 35 bbl/min, more preferably more than about 50 bbl/min, and most preferably more than about 60 bbl/min.
When the transition fracture 160 (Fig. 6E) has the desired horizontal length component, the propagation of the ~5 horizontal component 118 (Fig. 3) can be arrested by introducing a moderate to low concentration of fracture proppant into the fracture transition fluid. This proppant will create a fracture-tip screen-out as the fracture attempts to propagate further in the horizontal direction and the proppant gets wedged into the very narrow fracture tip.
Accordingly, the magnitude of the horizontal component 118 tFig. 3) of the fracture depends upon when the proppant is added to the fracture transition fluid.
The proppant will not, however, screen-out the vertical growth of the fracture. As the fracture transition fluid flows upward through the fracture, the fracture is too wide (i.e., 0.25 to 0.40 inches) for screen-out to occur. Thus, the fracture transition fluid will continue to propagate the vertical component 110 tFig. 3) of the fracture.
Any standard fracture proppant may be used to induce this horizontal fracture tip screen to stop horizontal fracture growth. The proppant size preferably ranges from about 16 to about 30 mesh-(Tyler). The concentration of the proppant in the tip-screen-off portion of the fracture transition fluid (i.e., slurry) may start at about 10% and gradually increase to about 40% by volume.
If the fracture transition fluids were to be introduced without the previous introduction of the fracture initiation and fracture propagation fluids in the manner described ~5 herein, a traditional, penny-shaped fracture would result.

Such a fracture would not realize the cost and production benefits of the present invention.
Referring to Figs. 7A-C, a proppant-carrying fracture slurry (i.e., fracture packing fluid) 164 can be introduced into the well 66 to carry proppant into the fracture while continuing to grow the frtlcture in the vertically upward direction. The proppant-carrying fracture slurry 164 preferably ranges from about 55 to about 70% by volume liquid and about 30 to about 45% by volume proppant.
The fracture packing fluid (i.e., proppant-carrying fracture slurry) 164 uses any of the available proppants and gelling agents capable of carrying the proppant concentration.
In the event the filter cake barrier formed by the fluid loss inhibitor in the prior injected fracture fluids breaks down or is displaced as the fracture grows, the fracture packing fluid will quickly reseal, replace or reinforce the filter cake barrier to prevent or minimize any further fluid losses.
The upper limit on the vertical growth of the fracture is determined by the time selected for breaking the gelling agent in the fracture packing fluid to cause the proppant to settle out of the slurry. ~hen t:he gelling agent is broken, the proppant will fall, the vertical and the fracture growth will be arrested.

Referring to Figs. 8A-C, the gelling agent is preferably broken in time sequence upward from the bottom to the top of the fracture 172 over a designated period of time. In this manner, the proppant will settle out of the fracture packing fluid substantially uniformly along the length of the fracture 172. If the gel breaking agent were to be broken in time sequence downward from the top of the fracture or simultaneously throughout the fracture packing fluid, then portions of the fracture would close before proppant could be placed in the fracture portions, thereby adversely impacting the ability of oil and/or gas to flow vertically along the fracture.
The gel breaking agent:s in the fracture transition and fracture packing fluids therefore should take into account the temperature gradient over the total vertical component of the fracture 172 and the cooling of the sediments by the volume of the various fluids displacled past the sediments during the above-described steps and the time period over which the gelling agents are to be broken. As soon as enough of the proppant-carrying fracture slurry ~i.e., fracture packing fluid) is broken at the bottom of the fracture to drop enough proppant to cover the open hole portion of the well bore, then, the well operator should start flowing (or swabbing) the well bore to cause the unbroken gelled proppant-carrying ~5 fracture slurry to flow downward and through the proppant-sand pack to filter out the proppant sand from the partially broken gel water (even before the gel is fully broken). This building of a proppant pack by downward flow of the slurry through the sand pack will grow a wider fracture sand pack than would the uniform breaking of a gelling agent.
The various fracturing fluids described above can include a salt to control the oleophilic or hydrophilic character of the sediments and to reduce the hydration and swelling of clay in the well 66 and cause the attachment of the clay to the walls of the well 66. As will be appreciated, hydration and mobility of the clay can cause plugging and premature sanding off of portions of the fracture. While not wishing to be bound by any theory, it is believed that the cations in the salt will enter the space between clay mineral plates and replace the sodium cations by ion exchange, thereby causing dehydration and shrinkage of the clay and possible change of surface wettability.
Depending upon whether the sediments initially have an oleophilic or hydrophilic character, the fracture water salt solution includes either a dominant mono-valent cation or a ~smln~nt multi-valent cation. For hydrophilic sediments, the preferred cation is potassium. For oleophilic sediments, the preferred cations are calcium and/or magnesium, with divalent calcium being most preferred. Such divalent cations will ~5 induce clay mineral shrin~:age and preserve the oleophilic nature of the sediments. In the case of oleophilic sediments, it is desired that the fracture fluid be substantially free of mono-valent cations to avoid changing the mineral-surface wettability of the sediments from their natural oleophilic nature to an artificially-induced hydrophilic nature. Such a fluid appears to reduce the thickness of the expandable-clay-mineral, adsorbed water layers, and thereby shrinks the clay mineral assemblages.
The calcium chloride salt in a high pH (over 10 pH) water solution appears to cement the clay minerals to the other silicate minerals in the sediments. A "Topermorite"-like cementing material is formed by creating a hydrated calcium silicate with the dissolution of a surface layer on the clay minerals and other silicate surfaces. Such cementation of the clay minerals to the other silicate surfaces prevents the clay minerals and other ultra fine grained minerals from migrating and plugging the pore space constrictions during production.
The preferred salt is calcium chloride in a concentration ranging from 0.5% to 2.0% with a pH ranging from about pH 9.5 to about pH 10.5 or pH 11Ø
In the second embodiment, the fracture is propagated downward rather than upward. The processes used to yield the two different embodiments are different in a number of respects. A key distinction is the use of significantly heavier spearhead fracturing fluids in the second embodiment to cause downward as opposed to upward growth of the fracture.
These differences are discussed in detail below.
Referring again to Fig. 4, the well 78 should be drilled to a depth that is within the envelope of gas saturated reservoir 82a that do not contain significant water producing zones 82a.
Referring to Fig. 9A, after formation of the open well bore 102b, as discussed abo~e, the fracture initiation fluid 120 is used to form the fracture 180 as described above. The rate o~f injection of the fracture initiation fluid 120 is preferably gradually increased over time from a low to a high injection rate.
Referring to Figs. 9B-D, a high density fracture propagation fluid 188 is next introduced into the well 78 to extend the fracture. The high density fracture propagation fluid 188 displaces the lighter fracture initiation fluid upwards and propagates the fracture 184 upwards and downwards.
Figs. 9B-D illustrate the propagation of the fracture 184a-c at various stages during introduction of the high density fluid.
The fracture propagation fluid 188 in the second embodiment significantly differs from the fracture propagation fluid 136 in the first e]~bodiment. Unlike the fracture propagation fluid 136, the fracture propagation fluid 188 ~5 contains preferably an ultra fine mesh (i.e., less than àbout 325 mesh (Tyler~) heavy proppant, typically a mineral powder, to create a high density slurry. The proppant content of the fracture propagation fluid preferably ranges from about 40 to about 45~ by volume.
The preferred proppant has a specific gravity of no less than about 4.5 and more preferably about 5Ø To further increase the density, one c:an use a mixture of about 40% of 325 heavy mineral powder plus about 3% of iron (steel) shot/grit ballast with a specific gravity of about 7.5 in a 10 size ranging from about 50 to about 150 mesh (Tyler).
The heavy mineral proppant also serves as a fluid loss preventative. Without such a preventative, the fluid in the various fracturing fluids may flow into pores or cracks in the rock and thereby decrease the fluid content of the slurry.
Such fluid loss may cause the residual slurry to plug the hydraulic fracture and terminate fracture growth.
The proppant causes the fracture propagation fluid to have a relatively high specific gravity and static pressure gradient in the fracture. The specific gravity preferably is more than about 2.5 and more preferably ranges from about 2.75 to about 2.90. The resulting static fluid pressure gradient in the fracture ranges from about 1.19 to about 1.25 psi/ft (minimum of about 1.08 psi,/ft). The difference between the typical fracture extension pressure gradient and the fluid ~5 pressure gradient ranges from about 0.3 psi/ft to about 0.38 psi/ft or more. This difference yields a very large downward driving force pushing a spearhead of the fluid 188 more strongly vertically downward rather than horizontally outward.
The fracture propagation fluid 188 preferably has a S relatively low viscosity to reduce the friction pressure. The viscosity is preferably no more than about 100 Cp and preferably less than about 50 Cp. By combining the low viscosity with a slow pumping rate of about 20 bbl/min or less, the fluid friction loss along the fracture growth path is low enough for the density forces to dominate the fracture growth pattern.
The fracture propagation fluid 188 can be prepared by initially forming a moderately high density slurry using the heavy mineral proppant and then combining the slurry with the cast iron (steel) shot/grit ballast. The slurry is formed by dispersing the heavy mineral powder in a low viscosity polymer-dispersant-solution. The solids content of the slurry preferably ranges from about 35 to about 45% by volume.
Because of the difference in sizes between the two solids dispersed in the slurry, this slurry has a substantially lower viscosity and reduced risk of accidental screen-off than a slurry of equal percentage total solid content with all of the solid particles having a nearly uniform particle size.
The fracture propagation fluid 188 is preferably injected ~5 at low rates ~i.e., about 10 bbl/min and lower) in the initial stages and higher ratio (i.e., 30 bbl/min and higher) in later stages. In this manner, t;he introduction of the fracture propagation fluid is able to keep pace with the increasing rate of fracture propagation.
The fracture propagation fluid 188 can be introduced during fracturing either continuously or discontinuously. The discontinuous addition of the fracturing fluid 188 results in "slugs" of the fracturing fluid moving down the open well bore 102b.
Referring to Fig. 10, a high viscosity, high gel strength fracture transition fluid 200 can be introduced to increase the fracture width from about 0.15 inch up to about 0.3 to 0.4 inch or more at the well bore prior to introduction of any normal fracture proppant. The proppant content of the fracture transition fluid is gradually increased from about 10% to about 30% by volume. When the fracture horizontal length of the transition zone has reached its desired length, then the proppant is added to the high viscosity transition fracture fluid to cause a fracture-tip-screen-out thereby stopping the fracture horizontal growth.
The viscosity is preferably at least about 350 Cp and more preferably about 300 t:o about 1000 Cp. The relatively high viscosity provides a high friction pressure along the fracture which greatly increases the fracture width.

The coarse proppant particles in the transition zone slurry will cause screen--out to occur as the fracture propagates horizontally but not vertically. As the very narrow, wedge-shaped, fracture tip propagates horizontally, the fracture transition fluid 200 will surge or spurt into the newly created void. The coarse proppant particles will be caught between the opposing walls of the fracture causing screen-out to occur at the horizontal fracture tip. As the fluid flows through the screen-out barrier, additional proppant will collect at the screen-out barrier. The screen-out barrier will thereby greatly reduce or stop the rate of growth in the horizontal direction. In contrast, the bottom of the fracture transition fluid 200 will push down on the top of the fracture propagation fluid 188 and will not experience screen-out. Near the well bore and all along the fracture, in this transition zone below the start of adding proppant, the fracture width is so wide (e.g., from 0.3" to 0.4" or wider) that the proppant can not screen out to stop the vertical downward growth.: Accordingly, the fracture 194 will continue to grow vertically downward but not horizontally outward.
Fig. 11 is a composite overview depicting Figs. 9A-D and 11 side-by-side. The overview shows the steady downward progression of the fracture over time as the fracture propagation and transition fluids are introduced into the well 78.

A proppant slurry (i.e., fracture packing fluid) (not shown), like that employed in the first embodiment, can be introduced into the well 78 to pack the fracture with proppant. The preferred proppant is a conventional proppant sand or other proppant as desired.
The proppant content of the fracture packing fluid is preferably changed over time in response to a change in the proppant size. The preferred maximum proppant concentration is no more than about 45% by volume.
The proppant causes the fracture packing fluid to have a moderate specific gravity aLnd pressure gradient in the well bore and a mediu~L viscosity. The specific gravity preferably ranges from about 1.60 to about 1.75. The fluid pressure gradient in the well bore preferably ranges from about 0.70 to about 0.76 psi/ft.
The fracture proppant slurry acts to substantially minimize growth in the horizontal direction of the fracture.
In the event that the fracture-tip screen-out barrier noted above breaks down or is disp~laced as the fracture width grows, the proppant in the fracture proppant slurry will quickly reseal, replace, or reinforce the barrier to prevent or substantially minimize further growth in the horizontal fracture direction 122.
Fluid loss from the fracture packing fluid will not cause ~5 the proppant to settle out of the fluid. The filter-cake barrier formed by the proppant in the fracture propagation fluid will prevent, or substantially minimize, the loss of fracture fluid from the fracture packing fluid as it flows through the fracture, except in the very limited area of fracture-tip growth beyond the area previously contacted by the fracture propagation f:Luid. Any such fluid loss will cause placement of proppant at the fracture tip and thereby accentuate and reinforce the barrier at the fracture tip as noted above.
The limited growth in t]ne horizontal direction will cause an increase of growth in the vertical direction. The fracture proppant slurry will force the fracture propagation and fracture transition fluids downwards and the fracture will propagate to a greater depth.
A well completion fluid (not shown), which was not employed in the first embodiment, can be introduced into the well 78 to pack the shallower portions of the fracture with a tail-in proppant. The proppant content of the fracture proppant slurry preferably ranges from about 35 to about 45%
by volume.
The preferred tail-in proppant is either CARBO-PROPO or sintered bauxite proppant. The tail-in proppant in the well bore packing fluid has a size preferably ranging from about 12 to about 20 mesh (Tyler) and more preferably from about 16 to ~5 about 20 mesh (Tyler). Arly suitable gelling agent can be included in the fluid to suspend/disperse the tail-in proppant.
Fig. 12 illustrates the downward progression of the fracture over time. The transition 210 between the fracture 5 transition fluid 200 and fracture propagation fluid 188 is shown at various points 210~-c.
The proper placement of the proppants in the various fluids along the fracture depends upon the relationship of the proppant injection time to lhe time and sequence of breaking the various gelling agents in the various fracturing fluids described above. The gelling agents must be broken in the proper sequence to cause the proppant to settle out of the fluids sequentially from the bottom of the fracture to the top of the fracture over a designated period of time. The gelling agent breaking time is preferably indexed to the time that the bottom of the fracture packing fluid reaches the desired fracture depth. In other words, the gel breaking process in the fracture proppant slur:ry begins at the point that the proppant reaches the desired fracture depth and moves progressively upwards. l'o accomplish this result, the initially injected portions of the fracture proppant slurry will have a gelling agent breaking time that is progressively decreased for later injecte~ portions of the fluid.
The gelling agents in the fracture proppant and fracture ~5 transition fluids are preferably timed to break about 5 to about 10 hours or longer after the breaking of the gelling agents in the initially introduced portion of the main fracture proppant slurry.
Fig. 13 illustrates the gel breaking process. Fig. 13 shows that the fracture continues to propagate downward until the gel is completely broken. The gel breaking interface 220 is shown at various points 220a-e.
The use of a fracture transition fluid, and well completion fluid, each having a proppant of progressively larger~ median sizes, creates a fracture 86 that is sequentially filled with the smallest proppant first and the largest proppant last. This sequential filling of the fractures with progressively larger proppant results in high permeability of the fractures and thereby higher recoveries of fluids from the zones.
After sanding-off of the fractures 86, a completion fluid (not shown) can be circulat:ed through the well 78 to remove the remaining proppant slurry from the well bore and initiate production of fluids from the fracture and adjacent reservoir zones. The completion flu:id can be any light-weight fluid, preferably light-weight nitrogen foam.
In a second aspect of the present invention, the fracture is formed by extending the fracture up from the bottom of the lower-most zone of interest. A proppant material, such as ~5 sand or gravel, is packed into the annulus between the walls of the well bore and the outer wall of the production casing before the fracture is initiated. Preferably, the well-bore diameter is substantially uniform to maintain a substantially constant fluid velocity in the annular area. A low viscosity, fracturing fluid (i.e., a frac pad having a viscosity of no more than about 20 Cp) is then injected around the bottom of the production casing and up through the proppant-packed annulus to initiate fracturing of the zone(s) of interest.
Referring to Figures 17A and B, a well 10 according to this embodiment is depicted before fracture initiation. The well 10 includes the well bore 90, the well casing 94 located inside of the well bore '30, a well head (not shown), a production casing 98 attached to the well head and preferably having a smaller outer diameter than the upper well casing 94, and a cement plug or packer 200 can be located outside the upper well casing 94 at the interface between the upper most zone of interest 70a and above the adjacent undesirable zone.
The cement plug or packer acts to seal the undesirable zone from the fracturing fluid and thereby inhibit the overlying undesirable zones from fracturing. Thus, the undesirable zone is not in fluid communication with the annulus formed by the well bore and production casing and therefore with the zone(s) of interest. The top of the gravel packed proppant sand bed 204 can be open (i.e., uncemented) as desired, to permit the ~5 fluid to flow between the production 98 and the well bore 90 for possible removal through the well casing 94. A high porosity and high permeability proppant material 204, such as sand, is located in the annulus defined by the well bore and the production casing. The proppant material 204 and the perforations 208 in the production casing 98 or an open hole interval below the production casing 98 provide a path of flow 212 for the fracturing fluid during fracture initiation.
As can be seen from the figure, the annulus between the well bore and the product:ion casing is not cemented or otherwise sealed across the zone(s) of interest. Thus, the multiple zone(s) between the bottom of the well bore and the plug or packer 200 are in fluid communication with one another via the sand packed annulus 202.
The ratio between the vertical and horizontal fracture components 110 and 118, respectively, depends upon a multitude of controllable variables such as the fluid transmissibility of the proppant-packed ,~nnulus, the fracturing fluid viscosity, the rate of injection of the fracturing fluid, and the fracturing fluid density. The annular area in the fluid transmissibility ec~ation noted above is taken along the line A-A. The line A-A is substantially normal to direction of fluid flow through the annulus.
The magnitude of the fluid transmissibility is directly related to the rate of fracture propagation in the vertical ~5 direction (and therefore to the magnitude of the vertical fracture component 110) and inversely related to the rate of fracture propagation in the horizontal direction (and therefore to the magnitude of the horizontal fracture component 118). As noted above, the well 10 is depicted before fracturing is initiated. The fracture is depicted in dashed lines to signify the appearance of the fracture after fracturing is completed.
The permeability of the proppant-packed annulus preferably is at least aLbout 50 millidarcys, and more preferably ranges from about 100 millidarcys to about 100 darcys, and most preferably from about 1 darcy to about 50 darcys. The median size of the proppant material 204 preferably is coarser than about 40 mesh (Tyler), and more preferably ranges from about 20 to about 5 mesh (Tyler), and most preferably from about 20 to about 10 mesh (Tyler).
The process to form a fracture according to this process will now be described. Beiore fracturing is initiated, the proppant is packed into the annulus by injecting a proppant-containing slurry, such as sand/water slurry, downwardly through the production casing 98, the perforations 208, or around the end of the production casing 98, and then upwardly in the annulus. The sand packed annulus is preferably formed by a fluidized bed process. After the fluidized bed of sand in moderate concentrations has filled the annulus, then the sand concentration in the injected slurry can be increased and the rate of slurry injection can be decreased thereby increasing the concentration of sand in the fluidized bed until it becomes a substantially consolidated sand pack and the bed ceases to be fluiclized. A low-viscosity fracture initiation fluid is then introduced into the production casing 98 and is pumped around the bottom of the production casing 98 or out through the perforations. The fracture initiation fluid preferably has a viscosity ranging from about 1 to about Cp. The fracture initiation fluid is preferably substantially free of proppant before introduction into the well bore. A preferred fracture initiation fluid is a frac pad, such as a lightly gelled water without any proppant.
The fracture initiation fluid flows down the production casing, along the fluid flow path 212, around the bottom of the production casing 98 below the substantially consolidated annulus sand pack and out into the formation to initiate and propagate a vertical fracture in the zone(s) or formation(s) of interest. After the fracture has been initiated out into the zone or formation, injection of the fracture initiation fluid is continued at a relatively low rate (preferably at as low a rate as is sustaini~ble at pressures exceeding the fracture extension pressure preferably by at least about 100 psi and more preferably by from about 100 to about 200 psi).
During this fracture initiation fluid injection, a back ~5 pressure is maintained on the fluid flowing up the open annulus between the production casing 98 and the upper casing 94 above the annulus sand p~lck in the annulus of the zone of interest to be frac stimulated. This back pressure is maintained at a pressure below the fracture extension pressure of the upper portion of the frac zone but is slowly increased during the frac injection process until the back pressure exceeds the fracture extension pressure preferably by at least about 100 psi and more preEerably by from about 100 psi to about 300 psi. Then a relatively high viscosity ~i.e., preferably more than about 20 Cp) gelled fracturing fluid is injected to open the fracture width and extend it in horizontal length.
When the fracture 74 is sufficiently enlarged and horizontally extended, then in one embodiment a fracturing slurry containing increasing concentrations of proppant material (i.e., proppant sand) is injected into the production casing 98. The proppant is typically from about 20 to about 40 mesh (Tyler) but in some ~pplications can be either coarser or finer mesh material. The fracture proppant-laden propagation fluid preferably has a viscosity of at least about 100 Cp.
Additional fluids can be introduced into the production casing, as desired, to widen the fracture and to continue propagation of the fracture to greater horizontal length and ~5 to pack the fracture with a sand-off to complete the welI 10.

Such additional fluids can include further proppant materials that are coarser than the proppant material 204 and the second proppant material.
A suitable fiber syslem can be used to prevent the proppant material in the annulus from flowing through perforations in the production casing after well completion.
In an alternative embodiment of this process, the production casing can be elevated a slight distance above the bottom 220 of the well bore to provide a fluid pathway for the various fracturing and well completion fluids. In this embodiment, the production casing 98 is not perforated.
This embodiment differs from the previous embodiment by uniquely providing a means to control the ratio of vertical height fracture growth to the horizontal length fracture growth. By this means, it is possible to achieve vertical fracture growth heights of several thousand feet (i.e., 2000 feet; 3000 feet; 4000 feet; 5000 feet vertical fracture height) while limiting the horizontal growth to only a few hundred feet (i.e., 200 feet; 400 feet; 800 feet horizontal length, respectively). The resulting high vertical height fracture is hereinafter referred to as the "tall frac." This tall frac requires much less proppant sand volume and lower frac costs to effectively produce the gas resources from all porous reservoirs penetrated by a well bore drilled through ~5 very thick zones of gas saturated porous reservoir rocks.

F~xAMpLE 1 A 12-1/4 inch hole is (~rilled to a depth of 2,500 feet.
A 9-5/8 inch surface casing was then set and cemented in the hole. Then, an 8-3/4 inch hole is drilled to a total depth of 5 12,500 feet. A 5-1/2 inch, 23 pound per foot, N-80\C-95 production casing is insta:Lled to a total depth of 12,000 feet, leaving about 500 feel of uncased, open hole below the casing. Alternatively, a 6-5/8 inch, 32 pound per foot, C-95\P-110 production casing could be installed depending upon well production requirements.
To guide and facilitate the fracture growth, the annulus around the production casing was packed with a high fluid permeability fracture sand up to the total height desired for the fracture growth. To fac:ilitate the annular proppant pack (i.e., gravel pack), a LYC)N's hydraulic inflatable casing packer was set at the bottorn of the production casing string where bottom was about 10 to about 100 feet above the bottom of the hole. A suitable fluid flow port was located above the packer for circulating the gravel pack in a slurry down the casing and up the annulus above the packer. When the desired volume of annulus sand pack slurry is circulated up the annulus, the fluid flow port is closed. The slurry gel is timed to break sequentially Erom the bottom to the top of the annular slurry column. The proppant settled out of the slurry to create a continuous annulus proppant pack from the bottom to the top of the interval to be fractured.
After the slurry gel was broken and the proppant had settled in the annulus, t:he production casing above the annular proppant packed co:Lumn was cemented to isolate the long, gas saturated, tight sand section ~i.e., from 7,500 foot to 12,500 foot depth) from the water sands located further uphole. After the emplacement of the gravel pack sand in the annulus over the gas saturated section ~i.e., from 12,400~foot production casing total depth to about 7,500 feet) and after emplacement of the cement over the water saturated section ~i.e., above about 7,500 foot depth) were completed, then the casing and the 10 to 100-foot open-hole section below the casing are cleaned out preparatory to conducting the hydraulic fracturing.
After preparation of the well, 100 barrels of a low viscosity or lightly gelled water fracturing fluid is initially injected at a slow rate of about 5 barrels/minute.
A single vertical fracture is initiated and propagated horizontally outward from the well bore as a result.
After about 100 barrels of the fracturing fluid was injected at about 5 barrels/minute, about 500 barrels of additional fracturing fluid were injected at about 40 barrels/
minute. The consequent increased friction pressure gradient ~5 within the fracture as a result of the higher injection rate caused the single vertical fracture to grow horizontally outward as well as vertically upward and downward along the open-hole well bore. Since the 0.44 psi/foot static pressure gradient of the gelled wate;r fracturing fluid was only about 50~ of the formation's least principal stress fracture extension pressure gradient (i.e., about 0.85 to about 0.9 psi/foot), the resulting buoyancy forces caused the fracture to grow preferentially upwa:rd rather than downward.
At the end of injecting the 600 barrels of the gelled water,'the fracture had a horizontal length of about 200 feet, a vertical length of about 675 feet and an average width of about 0.2 inches.
The gel of the first fracturing fluid was broken within about 30 minutes after introduction to yield ungelled water.
A second hydraulic fra,~turing fluid, having a different composition, was next introduced into the well bore. A total of 600 barrels of the fluid were introduced. The second fracturing fluld contained 250 tons of 10-16 mesh steel nugget proppant. Volumetrically, the slurry consisted of 70~ high viscosity gelled water anl~ 30~ steel shot (7.5 specific gravity), yielding a slurry density of 2.97 specific gravity and a static fluid pressure gradient within the fracture of about 1.287 psi/foot. The first 100 barrels of the slurry were pumped at a 10 barrels/minute rate with the r~m~ining 500 ~5 barrels being pumped at 40 barrels/minute.

The gel of this proppant slurry was broken within about 10-20 minutes after entering the fracture. The gel breaking agent was activated when the fluid warmed to the reservoir temperature of 220~F. Upon breaking of the gel, the heavy proppant settled to the bottom of the fracture and accumulated over a fracture area of about 100,000 square feet with a proppant porosity of about ~0%.
The proppant fallout extended horizontally about 500-600 feet along the bottom of the fracture. At the center of the fracture, the proppant pack extended vertically upward over about 200-300 feet of the well bore open-hole section. The fracture width was about 0.25 to 0.35 inches and the fracture proppant permeability was about 1,000 darcy or more. The high compressive strength of the proppant prevented significant loss of permeability, even under the high fracture collapse pressures of 10,000-12,000 psi. Consequently, the deposited high permeability proppant provided a high transmissibility flow path for gathering the gas and condensate from the bottom of the fracture and bringing the fluids into the well bore.
To extend the initial fracture upward to yield the desired vertical upward extent of the fracture while using a mi nim~lm volume of hydraulic fracturing fluid, a low viscosity, low density, spearhead fracturing fluid was injected into the well bore. The fluid was a 70% quality nitrogen foam (i.e., 70% nitrogen volume measured at 11,000 psi BHP).

Approximately 3,000 barrels of the fluid were injected at about 40 barrels/minute to create and propagate the fracture.
The fluid had a specific gravity of about 0.645 with a static pressure gradient of about 0.28 psi/foot. The difference between the spearhead fr~cturing fluid static pressure gradient of 0.28 psi/foot an~ the formation fracture extension pressure gradient was about 0.6 psi/foot. Benzoic acid crystals were added to the fluid to decrease fluid loss during fracturing.
A~high viscosity, gelled water (fourth) fracturing fluid was next introduced into the well bore. Approximately 2,000 barrels of the high viscosity fluid were introduced into the well bore at a rate of 40 barrels/minute. The fluid had a viscosity over about 400 Cp. The initial 500 barrels of the fluid increased the fracture width to at least 0.2 inches and, in some cases, over 0.25 inches. The desired fracture width was needed to prevent subsequent proppant-laden fracturing fluids from screening out at the boundary between fluids.
When the fracture reached the desired horizontal length, horizontal fracture propagation was terminated by adding a 35%
to 40% volumetric concentration of 16-30 mesh proppant to the fluid. The proppant sett]ed out at the fracture tips to create a fracture tip screen-out as the fracture attempted to grow further in the horizontal direction.

A medium viscosity (i.e., 200-300 centipoise), moderate density (i.e., 1.88 specific gravity, 0.815 psi/foot static pressure gradient) (fifth) fracturing fluid was next introduced into the well bore. The fluid consisted of 45%
5 proppant and 55~ gelled water. The proppant used was a 20-40 mesh sand. Approximately 31,200 barrels of the fluid were injected at the rate of 40 b,~rrels/minute to yield a vertical fracture height of 4,500 feet.
As the fluid flows upward, it will displace the prior injected fluids, thereby continuing to extend the top of the fracture to a greater vertical length. The fluid yielded a fracture width of about 0.35 inches after about 25,000 barrels of the fluid were introduced into the well bore.
Fig. 14 illustrates these results. The vertical dotted line labeled "Proppant Height Lost (after breaking gel)" and projected downward from the solid depth/volume line at each 1,000 foot interval represents the volume of water liberated from the fluid as-the gel breaks and the proppant falls to the bottom of the fracture where it accumulates. The dotted/
dashed line 230 connects the heights of propped fracture after the proppant settled out of the fluid when the fluid gel was broken. The water liberated from the fluid as the gel was sequentially broken from the bottom to the top of the fracture flowed upward in a counter-current fashion to the proppant falling downward.

The initiation of the hydraulic fracture by slowly pressurizing the 10-to-100 foot enlarged open-hole interval created a single, sy~netrica.l hydraulic fracture in the plane perpendicular to the leaslc principal stress axis in the sediments. Accordingly, the process prevented the development of tortuosity problems co~nonly associated with fracturing through multi-directional perforations in the casing.
Table 1: S - ~ of ~rP.ri~l~ U~ed in F~ E Fluid~

IDENTlTYTOTAL WATLR NITROGEN PROPPANT PUMPING
OF FLUID(BARRELS)(13ARRELS) (BARRELS) (TONS) HOURS
First 600 600 0 0 0.54 rl ch~nr~
Fluid Second 600 420 0 250 0.50 Fracturing Fluid Third 3,000 900 4.6x106 Scf 0 1.25 F ~h-t ir~

2 0 Fluid Fourth 2,000 1,325 0 348 0.83 Frach~ring Fluid Fifth 31,200 17,160 0 7,231 13.0 rl ~
Fluid TOTALS 37,400 20,405 4.6x106 Scf 7,829 16.1

3 o EXAMPT.F. 2 The well was prepared for the various hydraulic fracturing fluids in the manner described in Example 1.

After preparation of t:he well, 100-300 barrels of high viscosity, gelled water fracturing fluid were initially introduced into the well at: a slow rate of about 5 barrels/
minute. About 3,700 to 3,900 barrels of high viscosity gelled S water were next injected at the highest permissible pump rate (i.e., 60 barrels/minute) to cause the fracture to grow radially symmetric as a vertical penny-shaped fracture. The fracture propagated across intervening and highly resistant shale layers.
The fracture had a width of 0.5 inches, extended from about 350 feet above the top of the open well bore to about 350 feet below the bottom of the open well bore, and extended horizontally about 700 feet (i.e., 350 feet from each side of the well bore). Thus, the fracture was about 900 feet high, 700 feet long and about 0.5 inches wide.
A second hydraulic fracturing fluid, which was ungelled water, was injected at the rate of 20 barrels/minute. The ungelled water combined with the water from the first fracturing fluid, which had its gel broken prior to introduction of the seconcl hydraulic fracturing fluid, to propagate the fracture vertically upward. Approximately 3,500 barrels of the ungelled water were introduced into the well to provide a 7,500 barrel water spearhead to propagate upward fracture growth.

The resulting fracture had a vertical height of about 1,800 to about 2,000 feet, a horizontal length of about 700 to about 1,000 feet, and a fraclure width of about 0.15 to about 0.18 inches.
Next, 5,000 barrels of the high viscosity (third) fracturing fluid of Example 1 were introduced.
Finally, a high viscosity, moderate density, fourth fracturing fluid containing a proppant was introduced. The fourth hydraulic fracturing fluid, like the third hydraulic fracturing fluid, caused add:itional displacement of the first and second fracturing flu:ids, thereby further increasing vertical growth of the fraclure.
The final propped fracture had a vertical height of about

4,000 to about 5,000 feet, an average horizontal length of about 1,000 to about 1,500 feet, and an average propped fracture width of about 0.25 to about 0.4 inches.

~liMPT.~ 3 The well was prepared for the various hydraulic fracturing fluids in the manner described in Example 1 except that the production casing was cemented in place along its length to the well bore.
To initiate the fracture, 250 barrels for the 5-1/2 inch production casing (360 barrels for a 7 inch production casing) ~5 of a gelled water first fracturing fluid were injected into the well bore at an injection rate of about 5 barrels/minute.
The fluid caused the formation of a single hydraulic fracture near the top of the open-hole section. After about 90-100 barrels of the fluid were injected at about 5 barrels/minute, the fracture extended outward about 175 feet and upward about 200 feet and downward about 75 feet. The injection rate was then increased gradually from 5 barrels/minute up to about 40 barrels/minute. The resulting increased friction pressure within the fracture caused the fracture to grow downward along the open well bore until it: extended a little bit below the bottom of the well bore.
To extend the initial fracture downward to achieve maximum depth penetration with minimum hydraulic fracturing fluid injection, a special, low viscosity, high density, spearhead second fracturing fluid with a high static pressure gradient of 1.3 psi/foot and a specific gravity of 3 was injected into the fracture. The high density of the fluid was achieved by suspending a -325 mesh (i.e., 325-600 mesh) high density, crushed-mineral powder plus a 50-150 mesh cast iron shot/grit ballast in a low viscosity polymer-dispersant-water solution. The 325-600 mesh mineral powder, plus the 50-150 mesh cast iron shot/grit ballast, built a filter cake over any permeable porosity zone to greatly reduce any fluid loss from the fluid. In later steps, the filter cake acted as a very ~5 effective fluid loss preventative, thereby giving a very high effectiveness of propagating the fracture with very little loss of the fracturing fluid.
The fluid was introduced according to the following injection pumping schedule:
(i) inject the first 500 barrels at 5 barrelsJminute;
~ii) inject the next 500 barrels at 10 barrels/minute;
(iii) inject the next 1,000 barrels at 15 barrels/minute;
(iv) inject the next 1,000 barrels at 20 barrels/minute;
(v) inject the last 1,000 barrels at 30 barrels/minute.
The viscosity of the fluid was less than 100 centipoise.
The fluid caused the fracture to propagate vertically downward continuously at a rate of about 340 feet per hour.
The resulting fracture had dimensions of about 0.15 inches wide by 1,400 feet horizontal length, yielding a vertical flow cross-sectional area of about 17.5 square feet.
The fluid was prepared by making a moderately high density slurry by dlspersing the 325-600 mesh spinel powder in a low viscosity polymer-dispersant-solution. When mixed in the proportions of 35% by volume powder dispersed in 65%
polymer-dispersant-solution, the resulting low viscosity slurry had a density of 2.386 and a 1.033 psi/foot static pressure gradient. Next, the 50-150 mesh cast iron shot/grit with a specific gravity of about 7.5 was added to the slurry.
The resulting fluid consisted of 12.5% by volume cast iron shot/grit, 30.6~ by volume of the spinel powder, and 56.9% by volume of the polymer-dispersant-solution.
Two thousand barrels of a high viscosity (i.e., over 400 Cp), high density third fracturing fluid were introduced into the well at a rate of 30 barrels/minute. The concentration of the proppant, a 16-30 mesh cast iron shot, was gradually increased during introduction of the fluid. First, a 10%
volume of 50-150 mesh cast iron ballast was dispersed in the fluid to give a fluid density (with ballast) of 1.68 specific gravity with a 0.727 psi/foot pressure gradient. The initial 300 barrels of the fluid were injected without any proppant.
The next 700 barrels of fluid had a gradually increasing concentration of a 16-30 me,h proppant until a concentration of 45% proppant was realized. The final 1,000 barrels of the fluid consisted of 45% of the 16-30 mesh proppant dispersed in the fluid. In all stages, the fluid contained the 50-150 mesh cast iron ballast. The fini~l 1,000 barrels of the fluid had a high Viscoslty, exceeding 400 centipoise, and a specific gravity of 2.25 with a 0.973 psi/foot static pressure gradient. The fluid increased the fracture width from about 0.15 to about 0.25 inches or more. The proppant was suspended in the fluid using a hydroxyethylcellulose dispersing/
suspending gelling agent.
The fluid not only increased the fracture width but also ~5 increased the vertical length of the fracture. The horizontal length, however, was limited in growth due to the 16-30 mesh proppant causing a screen-out at the fracture tips. The horizontal length of the fracture after the introduction of the fluid ranged from about 1,200 to about 1,400 feet.
Next, approximately 56,000 barrels of a medium viscosity (i.e., 200-300 centipoise), moderate density (i.e., 1.88 specific gravity, 0.815 psi/foot pressure gradient), fourth fracturing fluid was introduced into the well at the rate of 30 barrels/minute. The fluid was 45~ proppant and 55% gelled water.' The proppant was a 16-30 mesh proppant sand.
The fluid caused a downward displacement of the previously injected fracturing fluids, thereby continuing to extend the bottom of the fracture to even greater depths. As described previously, the hLorizontal growth of the fracture was limited by the proppant barrier existing along the fracture tip.
The growth of the vertical and horizontal lengths of the fracture and the fracture area as a function of the injected volume of the fourth fracturing fluid is illustrated in Fig.
15. The horizontal fractw~e length is assumed to remain a constant 1,500 feet. Also, the fracture width is assumed to remain nearly constant after reaching about 0.35 inches at 25,000 barrels of the fourth fracturing fluid were injected.
At this point in time, the fracture has a vertical flow, ~5 cross-sectional area of about 29-30 square feet. Note especially the dotted line l~rojections 240a-g from the solid depth/volume line 250 at each 1,000 foot interval labeled "Volume Added After Breaking Slurry Gel." The dotted line extension 240 at each 1,000 foot interval represents the volume of water liberated from the fourth fracturing fluid as the gelling agent is broken and the proppant falls to the bottom of the fracture to build upward the proppant-packed portion of the fracture. The water liberated from the slurry as the gelling agent is sequentially broken from the bottom of the fracture to the top will flow upward in a counter-current fashion (i.e., the water will flow counter-current to the settling proppant).
Finally, 300 barrels of a tail-in proppant fifth fracturing fluid containing 54 tons of high permeability, high crushing strength, 16-20 mesh CARBO-PROPO or sintered bauxite proppant (i.e., 40% of slurry volume) suspended in gelled water were introduced into the well bore at a rate of 30 barrels/minute. The gelling agent was broken about 5 minutes after introduction of the f:Luid into the sediments.
The natural gas flowing upward through the 30 square feet of cross-sectional area of the fracture (i.e., 1,500 feet horizontal length by 0.02 feet average fracture width) of the packed proppant from the third fracturing fluid was collected and channeled through the p~cked tail-in proppant to the 500 feet of open-hole well bore wall. The 500 feet of fracture opening into the open-hole well bore had a cross-sectional area of about 10 square feet ~i.e., 500 feet high by 0.02 feet wide~. At an 8,000 psi fracture closure pressure, the tail-in proppant had a retained permeability of about 400 darcy over the 10 square foot area of t:he fracture entry into the open-hole well bore, resulting in about 4,000 darcy-square-foot fluid transmissibility. Likewise, at about 8,000 psi fracture closure pressure, the packed proppant from the third fracturing fluid had a retained permeability of about 7 darcy.
The 7 ~darcy permeability iIl the 30 square foot, horizontal cross-sectional area of the fracture proppant resulted in about 200 darcy-square-foot fluid transmissibility from the packed proppant into the packed tail-in proppant.
Consequently, the packed tail-in proppant effectively collected the natural gas flowing upward through the 200 darcy-square-foot transmissibility of the packed proppant from the third fracturing fluid and transmitted the gas into the well bore through a 4,000 darcy-square-foot transmissibility packed tail-in proppant fracture pack.
The fifth fracturing fluid was introduced when the previously introduced fourth fracturing fluid was close to sand-off of the well bore. The tail-in proppant had a higher fluid transmissibility than the proppant in the fourth fracturing fluid and thereby enhanced flow of the gas from the ~5 fracture into the well bore for collection.

In another experiment, additional amounts of the fourth fracturing fluid having a very short gel-breaking time were continued until a total s;and-out was realized. In this experiment, the fifth fracturing fluid was not introduced into the well bore. This configuration is sometimes preferable because it is often difficult to estimate accurately when the well bore is close to san(l-off from the fourth fracturing fluid.
Fig. 16 depicts the relationship between gelling agent breaki~g time (horizontal axis) and the total volume of the fourth fracturing fluid introduced into the well bore and the desired fracture depth (vertical axis). For the desired fracture depth of 8,000 feet below the bottom of the production casing, the gel breaking time for the initially injected portion of fourth fracturing fluid was about 23.3 hours. In other words, the fourth fracturing fluid will reach the depth of 8,000 feet below the bottom of the production casing in about 23.3 hours. The gelling agent breaking time decreased progressively from the 23.3 hours at the start of the injection of the fourth fracturing fluid down to 0.5 hours after injecting 54,000 barrels of the fluid as shown by the dotted line 260.
The gelling agent breaker employed considered the temperature gradient existing along the vertical length of the ~5 fracture and the cooling of the gradient as the various fluids moved through the fracture. The gel breaking in the fourth fracturing fluid preferably began at 23.3 hours and then sequentially progressed to higher elevations as shown by the dotted line 270. After about 7 hours and 12,000 barrels of S fourth fracturing fluid injection, the gelling agent in all of the injected fifth fracturing fluid was broken. The sequential gel-breaking of the fifth fracturing fluid allowed the proppant to settle and fill the fracture volume from the bottom to the top of the fracture over the 7-hour gel-breaking time interval.
After completing the 54,000 to 56,000 barrels of fourth fracturing fluid injection with sequentially timed gelling agent breaking to fill the fracture from the bottom up with gravity settled proppant, additional amounts of fourth fracturing fluid with a gelling agent breaking time of 0.5 hours after entry into the formation was continued until a near sand-off condition was achieved. At that point, the fifth fracturing-fluid was introduced.
The gelling agent breakers in the second fracturing fluid and the third fracturing fluid were timed to break about 1 or 2 hours before the breaking of the gel in the initial portion of the fourth fracturing fluid. The gelling agent in the first fracturing fluid broke about 8-10 hours after injection.
Table 2 presents a summary of the various hydraulic fracturing fluids used.

Table 2: Summary of Materials Used in Hydraulic Fracturing Fluids IDENTITY OF FLUIDTOTAL WATER PROPPANT
(BARRELS)(BARRELS) (TONS) First Fracturing Fluid360 360 0 Second Fracturing Fluid 4,000 2,276 1,663 Third Fracturing Fluid2,000 1,193 522 Fourth Fracturing Fluid 56,000 30,800 12,978 TOTALS 62,360 34,629 15,163 While various embodiments of the present invention have been described in detail, i.t is apparent that modifications and adaptations of those embodiments will occur to those skilled in the art. However, it is to be expressly understood 15 that such modifications and adaptations are within the scope of the present invention, as set forth in the following claims.

Claims (17)

What is claimed is:

1. A system for fracturing a plurality of adjacent zones, comprising:
a well bore in communication with the surface, the well bore including a conduit within and spaced from the well bore such that an annulus is defined between the well bore and the conduit, wherein the plurality of adjacent zones are in fluid communication with one another by means of the annulus and wherein the annulus is for receiving a fracturing fluid to form a fracture in the plurality of adjacent zones; and a plurality of solid particles located in the annulus area between the well bore and the conduit.

2. The system, as claimed in Claim 1, wherein the plurality of adjacent zones are located at different depths and an undesired zone is adjacent to the upper surface of the shallowest of the plurality of adjacent zones and wherein the undesired zone is sealed from the annulus.

3. The system, as claimed in Claim 1, wherein the plurality of solid particles located in the annulus area defines a transmissibility and the magnitude of the transmissibility is directly related to a rate of fracture propagation for the fracture in the vertical direction.

4. The system, as claimed in Claim 1, wherein the plurality of solid particles located in the annulus area defines a transmissibility and the magnitude of the transmissibility is indirectly related to a rate of fracture propagation for the fracture in the horizontal direction.

5. A method for fracturing multiple subterranean zones to collect fluids from one or more of the zones through a well bore, comprising the steps of:
selecting at least one of a height and a width for a fracture to be formed in the multiple subterranean zones;
based on the at least one of the selected height and width, selecting a fluid transmissibility for a well bore contacting the zones;
placing a particulate material in the well bore to provide the selected fluid transmissibility in the well bore;
and thereafter passing a fracturing fluid through the well bore to fracture the zones.

6. The method, as claimed in Claim 5, wherein the fluid transmissibility is at least about 40 millidarcies.

7. The method, as claimed in Claim 5, wherein the particulate material has a median size ranging from about 40 to about 4 mesh (Tyler).

8. The method, as claimed in Claim 5, wherein the particulate material in the well bore has a permeability ranging from about 50 millidarcies to about 100 darcies.

9. The method, as claimed in Claim 5, wherein the fracturing fluid is substantially free of proppant before introduction into the well bore.

10. The method, as claimed in Claim 5, wherein the fracturing fluid has a viscosity ranging from about 1 to about 20 Cp.

11. The method, as claimed in Claim 5, further comprising after the thereafter passing step:
introducing a fracturing slurry containing a proppant material into the well bore.

12. The method, as claimed in Claim 11, wherein the median size of the particulate material is less than the median size of the proppant.

13. The method, as claimed in Claim 5, wherein the magnitude of the-fluid transmissibility is directly related to a rate of fracture propagation in the vertical direction.

14. The method, as claimed in Claim 5, wherein the magnitude of the fluid transmissibility is indirectly related to a rate of fracture propagation in the horizontal direction.

15. The method, as claimed in Claim 5, wherein the ratio of the height of the fracture to the horizontal length of the fracture is no less than about 1:1.

16. The method, as claimed in Claim 5, wherein the multiple subterranean zones define a tight sands deposit.

17. A method for fracturing multiple subterranean zones to collect fluids from one or more of the zones through a well bore, comprising the steps of:
forming a well bore passing through the multiple subterranean zones;
placing a particulate material in the well bore to provide a selected fluid transmissibility in the well bore, wherein a portion of a conduit passing through the multiple subterranean zones in the well bore defines an annular area between the conduit exterior and the well bore that contains the particulate material; and thereafter passing a fracturing fluid through the well bore to form a fracture in the multiple subterranean zones and transport the particulate material into the fracture.