Directionally oriented slotting method

A method of fracturing a subterranean formation having a well bore extending thereinto. The method comprises the steps of: (a) placing a jetting tool in the well bore such that the jetting tool is positioned within the subterranean formation, the jetting tool including a jetting nozzle; (b) orienting, by rotating the jetting tool about a longitudinal axis, the jetting tool such that the directional orientation of the jetting nozzle substantially corresponds to a predetermined fracturing direction; and (c) cutting a slot in the subterranean formation (and/or casing) by substantially maintaining the jetting nozzle orientation established in step (b) while both (1) spraying a jetting fluid out of the first jetting nozzle and (2) moving the jetting tool longitudinally within the well bore along the longitudinal axis.

FIELD OF THE INVENTION 
The present invention relates to methods of fracturing subterranean 
formations. More particularly, but not by way of limitation, the present 
invention relates to methods of forming slots in casings and/or 
subterranean formations wherein the directional orientation of each slot 
corresponds to a preselected fracturing direction. 
BACKGROUND OF THE INVENTION 
In many instances, after a well is drilled to a desired depth, fractures 
must be induced in the surrounding formation in order to produce 
commercially significant quantities of hydrocarbons from the well. Certain 
prior art techniques of fracturing a well have involved the use of 
slotting tools to form slots in the formation at multiple locations for a 
given length of the well. Such slots could be made in either a random or 
organized pattern. 
Thereafter, through techniques commonly employed in the industry, fractures 
in the formation would be induced by pumping a fracturing fluid, 
containing proppants, under high pressure, into the well bore and through 
certain of the slots until a fracture was initiated. Fracturing operations 
were then continued until the fractures were propagated a sufficient 
distance into the formation surrounding the well bore. 
It is well known that after initiation of a fracture, a fracture will 
propagate away from the well bore in a radial direction that is 
perpendicular the minimum principal stress existing in the surrounding 
formation, i.e., the direction of propagation of the fractures is 
controlled by the state of stress existing in the surrounding formation. 
Nevertheless, heretofore, there has been no attempt in the art to align 
the slots produced by the slotting tools with the direction of fracture 
propagation, i.e., perpendicular to the minimum principal horizontal 
stress existing within the formation. 
Certain problems encountered in fracturing operations are believed to have 
been due to the failure of prior art methods and techniques to align the 
slots with the direction of fracture propagation within a formation. In 
particular, nonalignment of the slots resulted in the use of excessive 
pressures to fracture the well, and resulted in the development of a 
tortuous flow path for the fracturing fluid as it flowed from the initial 
fracture formed in a nonaligned slot to the main fracture. The tortuous 
path developed because a fracture that was initiated at a non-aligned slot 
would curve as it propagated through the formation to align itself with 
the direction of propagation of the main fracture. This tortuous path 
caused excessive pressure drop as the fracturing fluid was pumped 
therethrough, and generally inhibited the timely and efficient completion 
of a well such that maximum production could be achieved therefrom. 
The present invention solves all of the aforementioned problems by insuring 
alignment of the slots with the direction of fracture propagation within a 
field. By employing the method disclosed and claimed herein, lower 
fracture initiation pressures may be obtained, and other problems 
associated with near well bore tortuosity may be overcome. 
SUMMARY OF THE INVENTION 
The present invention is directed to a method for optimizing hydraulic 
fracturing operations by aligning well bore slots with the direction of 
fracture propagation, i.e., perpendicular to the minimum principal 
horizontal stress, existing within a formation. The present method can be 
used in both vertical and deviated wells (i.e., horizontal wells or wells 
drilled at an angle relative to a vertical well) and can be used to cut 
slots in both cased and uncased well bore sections. Through use of the 
present invention, many problems heretofore encountered in fracturing 
operations are avoided. For example, by forming, in accordance with the 
present invention, properly aligned slots through a well casing and/or 
into the formation being fractured, the fracture initiation process is 
facilitated whereby fractures are initiated at lower pressures and the 
problems associated with near well bore tortuosity are avoided. 
In one embodiment, the present invention provides a method of fracturing a 
subterranean formation having a well bore extending thereinto. The method 
comprises the steps of: (a) placing a jetting tool in the well bore such 
that the jetting tool is positioned within the subterranean formation, 
said jetting tool including a jetting nozzle; (b) orienting, by rotating 
the jetting tool about a longitudinal axis, the jetting tool such that the 
directional orientation of the jetting nozzle substantially corresponds to 
a selected fracturing direction; and (c) cutting a slot in the 
subterranean formation by substantially maintaining the jetting nozzle 
orientation established in step (b) while both (1) spraying a jetting 
fluid out of the jetting nozzle and (2) moving the jetting tool 
longitudinally within the well bore along the longitudinal axis. 
In a second embodiment, the present invention provides a method of 
fracturing a subterranean formation having a well bore extending thereinto 
with a casing positioned in the well bore. The inventive method comprises 
the steps of: (a) placing a jetting tool in the casing such that the 
jetting tool is positioned within the subterranean formation, said jetting 
tool including a jetting nozzle; (b) orienting, by rotating the jetting 
tool about a longitudinal axis, the jetting tool such that the directional 
orientation of the jetting nozzle substantially corresponds to a selected 
fracturing direction; and (c) cutting a slot in the casing by 
substantially maintaining the jetting nozzle orientation established in 
step (b) while (1) spraying a jetting fluid out of the jetting nozzle and 
(2) moving the jetting tool longitudinally within the casing along the 
longitudinal axis. 
Through the use of the method disclosed and claimed herein, efficient 
fracturing of a formation may be achieved, thereby allowing a greater 
degree of hydrocarbon recovery from the formation. Additional benefits 
from using the method disclosed and claimed herein will be apparent to 
those of ordinary skill in the art upon reference to the accompany 
drawings and upon reading the following Description of the Preferred 
Embodiments.

EXAMPLE 1 
Extrapolated S.sub.1 orientation from true north=N52E. 
CT measured deviation angle D=+8 
S.sub.1 +D=S.sub.2 
52+(+8)=60 degrees 
Induced fracture strike orientation (S.sub.2)=N6OE 
EXAMPLE 2 
Extrapolated S.sub.1 orientation from true north=N81.5E. 
CT measured deviation angle D=-22 
S.sub.1 +D=S.sub.2 
81.5+(-22)=58.5 degrees 
Induced fracture strike orientation (S.sub.2)=N58.5E 
Both examples were obtained from identified induced fractures obtained at 
two different depth markers from an oriented core retrieved from competent 
Devonian shale in Roane Co. West Virginia. Note consistency of induced 
fracture strike despite rotation of the principal scribe orientation in 
the recovered core. 
FIG. 4 shows a series of induced fracture data points, identified 
collectively as 30, at two different core depths in two core intervals. As 
can be seen in FIG. 4, this data supports the single point downhole 
hydraulic fracture orientation obtained from a downhole extensiometer 
device, 35, in the same well, with the median of 11 core induced data 
points being within 2 degrees of the inferred hydraulic fracture 
orientation obtained by use of the Total Halliburton Extensionmeter, 
another technique fully disclosed herein. The data points shown in FIG. 3, 
were obtained from the Devonian shale described above, in Roane Co., W. 
Va. The orientation of the minimum in-situ stress would be inferred to be 
substantially perpendicular to the induced fracture orientation, which in 
FIG. 4 would be approximately N30W. 
FIG. 5 is a three dimensional view of the relationship between the 
orientation of induced fractures and minimum and maximum stress 
orientation, where: 
.sigma..sub.Hmax =maximum in-situ horizontal stress orientation 
.sigma..sub.Hmin =minimum in-situ horizontal stress orientation 
.sigma..sub.v =vertical stress orientation. 
The orientation of the induced fracture will be perpendicular to the 
minimum in situ stress as shown on the .sigma..sub.Hmin axis and parallel 
to the maximum in situ stress as shown on the or .sigma..sub.Hmax axis. 
The induced fracture orientation will be at an approximately 45.degree. 
angle to the core when the core is oriented at 45.degree. angle to the 
maximum and minimum in situ stress. The orientation of the induced 
fracture will change with respect to the well bore but not with respect to 
the minimum and maximum in situ stress orientation. 
In a vertical well, the images are taken in a perpendicular plane to the 
vertical axis of the well. As a result, the strike orientation can be 
determined directly in relation to the principal scribe orientation which 
is recalculated with respect to compass direction or azimuth. In a 
deviated well, the apparent strike must be corrected for the deviation. In 
addition, the spatial orientation can be determined by calculating dip 
angle and direction from sequential slice images. FIG. 6 illustrates a 
graphical solution for measuring the fracture orientation in a deviated or 
horizontal well using CT imagery where: 
F=plane of induced fracture; 
S=line of induced fracture strike; 
A.sub.1 to A.sub.2 =a series of sequential axial CT slice images from 
interval Z; 
R=plane of longitudinal reconstructed CT image in horizontal plane: 
.alpha.=angle of well bore deviation from horizontal plane; 
.phi.=angle of well bore deviation form North; 
.beta.=angle of fracture trace deviation from .phi.; and 
.beta.+.phi.=strike orientation from North. 
The CT computer can be used to construct a longitudinal or horizontal image 
by reconstructing a series of axial slices. The fracture trace on the 
reconstructed longitudinal or horizontal image will represent the strike 
orientation. The same process as described above for a vertical well is 
then used to measure the azimuthal direction of the fracture trace. 
Determining The Direction Of Fracture Propagation Through Measurement Of 
Bore Hole Deformations 
A highly sensitive multi-arm caliper, such as the Total Halliburton 
Extensionmeter, may also be used to determine the direction of fracture 
propagation. That tool is the subject of U.S. Pat. No. 4,673,890, which is 
hereby incorporated by reference. Other downhole tools that may be used to 
measure bore hole deformations are depicted in U.S. Pat. Nos. 4,625,795 
and 4,800,753, both of which are hereby incorporated by reference. 
This method is the subject of a separate pending patent application which 
is also assigned to the assignee of the present application (application 
Ser. No. 07/902,108, filed Jun. 22, 1992, now U.S. Pat. No. 5,272,916). 
This method basically comprises the steps of exerting pressure on a 
subterranean formation by way of the well bore, measuring the diametral 
displacements of the well bore in three or more angularly offset 
directions at a location adjacent the formation as the pressure of the 
formation is increased, and then comparing the magnitudes of the 
displacements to detect and measure elastic anisotropy in the formation. 
The measurement of the in-situ elastic anisotropy in the form of 
directional diametral displacements at increments of pressure exerted on 
the formation are utilized to calculate directional elastic moduli in the 
rock formation and other factors relating to the mechanical behavior of 
the formation. 
In carrying out this method, a well bore is drilled into or through a 
subterranean formation in which it is desired to determine fracture 
related properties, e.g., the relationship between applied pressure and 
well bore deformation which allows the calculation of in-situ rock elastic 
moduli and in-situ stresses. A knowledge of such fracturing related 
properties of a rock formation, as well as fracture direction and fracture 
width as a function of pressure prior to carrying out a fracture treatment 
in the formation, allows the fracture treatment to be planned and 
performed very efficiently, whereby desired results are obtained. In 
addition, knowing the fracture direction allows the optimum well spacing 
in a field to be determined as well as the establishment of the shape of 
the drainage area and the optimum placement of both vertical and 
horizontal wells. 
Prior to casing or lining a well bore penetrating a formation to be tested, 
a measurement tool of the type described in U.S. Pat. No. 4,673,890 is 
lowered through the well bore to a point adjacent the formation in which 
fracture related properties are to be determined. The measurement tool 
includes packers whereby it can be isolated in the zone to be tested, and 
radially extendable arms are provided which engage the sides of the well 
bore and measure initial diameter and diametral displacements in at least 
two angularly offset directions. Preferably, the measurement tool includes 
six pairs of oppositely positioned radially extendable arms whereby 
diameters and diametral displacements are measured in six equally spaced 
angularly offset directions as shown in FIG. 7. The measurement tool must 
have sufficient sensitivity to measure incremental displacements in micro 
inches. 
After isolation, and once the extendable arms are in firm contact with the 
walls of the well bore adjacent the formation to be tested, the tool 
continuously measures diametral displacements as the pressure exerted in 
the well bore is increased. Generally, the measurement tool is connected 
to a string of drill pipe or the like and after being lowered and isolated 
in the well bore adjacent the formation to be tested, the pipe and the 
portion of the well bore containing the measurement tool are filled with a 
fluid such as an aqueous liquid. The measurement tool then measures the 
initial diameters of the well bore in the angularly offset directions at 
the static liquid pressure exerted on the formation. The measurement tool 
is azimuthally orientated so that the individual polar directions of the 
measurements are known. 
Additional fluid is pumped into the well bore thereby increasing the 
pressure exerted on the formation adjacent the measurement tool from the 
static fluid pressure to a pressure above the pressure at which one or 
more fractures are created in the formation. As the pressure is increased, 
the directional diametral displacements of the well bore are measured at a 
minimum of two and preferably at a plurality of pressure increments. For 
example, the directional diametral measurements can be simultaneously made 
once each second during the time period over which the pressure is 
increased. The measurements are recorded and processed electronically 
whereby the magnitudes of the diametral displacements in the various 
directions can be compared, e.g., graphically as shown in FIG. 8. In-situ 
elastic anisotropy in the formation is shown if the magnitudes of the 
diametral displacements are unequal. Thus, the measurements are used to 
detect whether or not the rock formation being tested is in a state of 
elastic anisotropy, and the measurement data corresponding to pressure 
exerted on the formation is utilized to calculate in-situ rock moduli and 
other rock properties relating to fracturing. When the formation 
fractures, the measurement data at the time of the fracture, and 
thereafter, is utilized to determine fracture direction and fracture width 
as a function of pressure. 
Thus, the method of the present invention basically comprises the steps of 
exerting increasing pressure on a formation by way of the well bore, 
measuring the incremental diametral displacements of the well bore in 
three or more angularly offset directions at a location adjacent the 
formation as the pressure on the formation is increased, and then 
comparing the magnitudes of the diametral displacements to determine if 
they are unequal and to thereby detect and measure elastic anisotropy in 
the formation. 
The angularly offset directions are azimuthally oriented, and the 
incremental diametral displacements are preferably measured in a plurality 
of equally spaced angularly offset directions. Once the azimuthal 
orientation of formation anisotropy is known, the tool may be reoriented 
for the purpose of directly measuring maximum and minimum displacements 
aligned in the inferred plane of minimum and maximum stress. 
Once the in-situ elastic anisotropy of a subterranean formation has been 
detected and measured as described above, directional elastic moduli, 
i.e., Young's modulus and/or shear modulus are determined using the 
pressure correlated displacement data obtained. That is, the Young's 
modulus of the formation in each direction is determined using the 
following formula: 
##EQU3## 
wherein E represents Young's Modulus; P.sub.1 represents a first pressure; 
P.sub.2 represents a greater pressure; 
D represents the initial well bore diameter; 
W.sub.1 represents the diametral displacement of the well bore at the first 
pressure (P.sub.1); and 
W.sub.2 represents the well bore diametral displacement at the second 
pressure (P.sub.2); and 
.mu. represents Poisson's Ratio. 
Young's modulus values obtained in accordance with this invention using the 
above formula are close approximations of the actual Young's modulus 
values of the tested formation in the directions of the well bore 
measurements. Young's modulus can be defined as the ratio of normal stress 
to the resulting strain in the direction of the applied stress, and is 
applicable for the linear range of the material; that is, where the ratio 
is a constant. In an anisotropic material, Young's modulus may vary with 
direction. In subterranean formations, the plane of applied stress is 
usually defined in the horizontal plane which is roughly parallel to 
bedding planes in rock strata where the bedding is horizontally aligned. 
Poisson's ratio (.mu.) can be defined as the ratio of lateral strain 
(contraction) to the axial strain (extension) for normal stress within the 
elastic limit. 
Young's modulus is related to shear modulus by the formula: 
EQU E=2G(1+.mu.) 
wherein 
E represents Young's modulus; 
G represents shear modulus; and 
Shear modulus can be defined as the ratio of shear stress to the resulting 
shear strain over the linear range of material. 
Thus, once the approximate Young's modulus in a direction is calculated, 
shear modulus can also be calculated. Both shear modulus and Young's 
modulus are based on the elasticity of rock theory and are utilized to 
calculate various rock properties relating to fracturing as is well known 
by those skilled in the art. The term stress, as it is used here, can be 
defined as the internal force per unit of cross-sectional area on which 
the force acts. It can be resolved into normal and shear components which 
are perpendicular and parallel, respectively, to the area. Strain, as it 
is used herein, can be defined as the deformation per unit length and is 
also known as "unit deformation". Shear strain can be defined as the 
lateral deformation per unit length and is also known as "unit detrusion". 
The term "elastic moduli" is sometimes utilized herein to refer to both 
shear modulus and Young's modulus. The directional diametral displacement 
and elastic moduli data obtained in accordance with this invention can be 
utilized to verify in-situ stress orientation, verify or predict hydraulic 
fracture direction in the formation, and to design subsequent fracture 
treatments using techniques well known to those skilled in the art. 
A preferred method for detecting and measuring in-situ elastic anisotropy 
in a subterranean rock formation penetrated by a well bore generally 
comprises the steps of: 
(a) placing a well bore diameter and diametral displacement measurement 
tool in the well bore adjacent the formation, the tool being capable of 
measuring well bore initial diameters and diametral displacements in a 
plurality of azimuthally oriented angularly offset directions at an 
initial pressure and at two or more successive pressure increments; 
(b) exerting initial pressure on the formation by way of the well bore; 
(c) increasing the pressure exerted on the formation; 
(d) measuring the diameters at the initial pressure and the diametral 
displacements at the two or more successive pressure increments in each of 
the azimuthally oriented angularly offset directions; 
(e) comparing the magnitudes of the diametral displacements to determine if 
they are unequal to thereby detect and measure in-situ elastic anisotropy 
in the formation; and 
(f) determining the approximate in-situ Young's modulus of the rock 
formation in each of the directions by multiplying the difference in 
pressure between two of the pressure increments by the initial diameter of 
the well bore and by 1 plus Poisson's ratio and dividing the product 
obtained by the difference between the diametral displacements at the 
pressure increments. 
A representative example of this method follows: 
EXAMPLE 
A well bore measurement tool of the type described in U.S. Pat. No. 
4,673,890 was used to test a subterranean formation. The measurement tool, 
connected to a string of tubing, was lowered to a location in the well 
bore adjacent the formation to be tested that had been cored to a diameter 
of 7 7/8", and the measurement tool was isolated by setting top and bottom 
packers. The string of tubing was filled with an aqueous liquid and the 
annulus between the tubing and the walls of the bore was pressured with 
nitrogen gas. 
The measurement tool included six pairs of opposing radially extendable 
arms whereby initial diameters and diametral displacements were measured 
in a substantially horizontal plane in six angularly offset directions 
designated D1 through D6 as shown in FIG. 7. After the arms were extended 
and stabilized against the walls of the well bore, the measurement tool 
was activated. Measurements were made and processed as the liquid pressure 
exerted on the formation was increased from the initial static liquid 
pressure by pumping additional liquid through the tubing against and into 
the tested formation at a rate of 3 gallons per minute. 
The diametral displacement measurements made by the measurement tool while 
the pressure was increased from about 1490 psi (static liquid pressure) to 
about 2380 psi are presented graphically in FIG. 8. As shown, the 
diametral displacements are not equal thereby indicating elastic 
anisotropy. The data presented in FIG. 8 covers the period from the start 
of pumping 11:21:35 a.m. to fracture initiation at 11:37:19 a.m. During 
that period, the testing went through three distinct phases indicated in 
FIG. 8 by the letters A, B and C. In phase A, the measured displacements 
were not linear and remained substantially constant in the directions D1, 
D2 and D6 indicating a hard quadrant while D3, D4 and D5 changed 
dramatically indicating a soft quadrant. The cause for the non-linearity 
is speculated to be movements associated with further seating of the arms 
and/or the closing of micro fractures in the formation. At a pressure of 
about 1647.7 psi and time of 11:32:19 a.m., the early nonlinearity came to 
an end, and a second phase (phase B) began during which the diametral 
displacements were generally linear. Phase B continued to the time of 
11:34:09 a.m. and a pressure of 2059.3 psi whereupon the fracturing phase 
(phase C) began and the displacements again became non-linear. 
When a fracture was induced at 11:37:19 a.m. there was a sudden change in 
the reading and shifting of the instrument. Prior to the shifting, seven 
one second diametral displacement readings were obtained from which the 
width of the induced fracture (the displacement in a direction 
perpendicular to the fracture direction) was determined to approximately 
0.027 inches and the fracture direction was determined to N 67.degree. E 
(magnetic). 
The directional stress moduli of the test formation were calculated using 
the linear displacement data obtained during phase B of the test period 
shown in FIG. 8. The calculations were made using the formulae set forth 
above, and the results are as follows: 
______________________________________ 
W.sub.1, W.sub.2, W.sub.2 --W.sub.1, 
E, 
Direction .mu.-inches 
.mu.-inches 
.mu.-inches 
10.sup.6 psi 
______________________________________ 
D1 343 1244 901 4.50 
D2 267 701 434 9.34 
D3 1670 4112 2442 1.66 
D4 1603 3882 2279 1.78 
D5 1508 4697 3189 1.27 
D6 -350 1375 1725 2.35 
______________________________________ 
From the values set forth above, it can be seen that the smallest 
difference between W.sub.2 and W.sub.1 took place in the direction D2 and 
the calculated Young's modulus is greatest in the direction D2. In this 
example, the fracture direction also corresponds to D2. 
Referring now to FIG. 9, a polar plot of the differences in the 
displacements (W.sub.2 -W.sub.1) in .mu.-inches for D1 through D6 is 
presented, and the fracture direction indicated by the measuring tool of N 
67.degree. E is shown in dashed lines thereon. As shown in FIG. 9, the 
actual fracture direction substantially corresponds with the direction D2 
in which the least well bore diametral displacement difference took place 
and in which direction the formation had the highest elastic moduli. 
Determining Fracture Orientation Through Strain Relaxation Measurement 
Techniques 
Additionally, fracture orientation may also be determined from strain 
relaxation measurements of an oriented core. This technique is well known 
in the prior art and fully discussed in the following papers, all of which 
are hereby incorporated by reference: (1) Teufel, L. W., Strain Relaxation 
Method for Predicting Hydraulic Fracture Azimuth from Oriented Core, 
SPE/DOE 9836 (1981); (2) Teufel, L. W., Prediction of Hydraulic Fracture 
Azimuth From Anelastic Strain Recovery Measurements of Oriented Core, 
Proceeding of 23rd Symposium on Rock Mechanics: Issues in Rock Mechanics, 
Ed. By R. E. Goodman and F. F. Hughes, p. 239, SME of AIME, New York, 
1982; (3) Burton, T. L., The Relation Between Recovery Reformation and 
In-Situ Stress Magnitudes, SPE/DOE 11624 (1983); (4) El Rabaa, W. and 
Meadows, D. L., Laboratory and Field Application of the Strain Relaxation 
Method, SPE 15072 (1986); (5) El Rabaa, W., Determination of the Stress 
Field and Fracture Direction in the Danian Chalk, 1989. 
In order to predict the azimuth of a hydraulic fracture, it is necessary to 
know the direction of the minimum horizontal compressive stress, because a 
hydraulic fracture propagates perpendicular to this stress direction. The 
strain relaxation method as outlined by Teufel, is based upon the 
assumption that an oriented sample of the formation, when retrieved from 
its downhole confined conditions, will relax (creep) in all directions. 
The magnitude of the recovered strain in any direction is proportional to 
the magnitude of the stress in that direction. Therefore, most recovered 
strain is aligned with the direction of maximum in-situ stress, or the 
direction of propagation of an induced hydraulic fracture. By 
instrumenting an oriented core immediately after its removal from the core 
barrel, a portion of the total recoverable strain can be measured. 
In general, the following are the idealistic core properties demanded by 
the method to produce reliable results: 
1. The core must be homogeneous and linearly visco-elastic. The core should 
also exhibit an isotropic creep compliance D(t) while maintaining a 
constant value of Poisson's ratio, i.e., Poisson's ratio is not time 
dependent; 
2. The core must be free of cracks; and 
3. It is preferable that the core is thermally isotropic, i.e., it has an 
equal coefficient of thermal expansion in all directions. 
Prediction of fracture azimuth from three diametrical measurements of a 
core requires that (1) the in-situ principal stresses not be equal, and 
(2) the maximum stress be oriented in the vertical direction (due to the 
overburden weight). Despite variations found in formation properties 
(except for cracks), the method has been successfully applied. 
The time dependent deformation that a core displays after its retrieval 
from a deep well is a result of displacements caused by the following 
effects: 
1. Release of in-situ stresses, which consists of the overburden stress and 
the in-situ horizontal stresses; 
2. Changes in core temperature; and/or 
3. Release of pore pressure (what is left from the endogenous reservoir 
pressure plus that created by the drilling fluids). 
Thus, for a core (with idealistic properties) taken from a vertical well, 
the change in its diameter for a specific period of time can be expressed 
by equation (1). 
EQU .DELTA.D=.DELTA.D.sub.st -(.DELTA.D.sub.p +.DELTA.D.sub.ov +.DELTA.D.sub.t) 
where .DELTA.D is the total displacement of the core diameter, and 
.DELTA.D.sub.st, .DELTA.D.sub.p, .DELTA.D.sub.ov, .DELTA.D.sub.t are the 
diametrical displacements due to release of horizontal stresses, pore 
pressure, overburden and temperature changes, respectively. The total 
displacement could be positive or negative, i.e., cores could show 
expansion or contraction during the relaxation period. However, the only 
directional displacements are caused by release of (unequal) in-situ 
horizontal stresses (assuming that all other effects cause only 
non-directional diametrical deformation). Therefore, according to strain 
relaxation theory, the direction of maximum stress is taken as parallel to 
the direction of the core experiencing the most expansion during 
relaxation, or perpendicular to the direction of most contraction by 
superposition principles, thereby allowing determination of fracture 
orientation. Core contraction caused by release of pore pressure and loss 
of moisture can be minimized or prevented by sealing the core; however, 
this method is not always successful. 
The specific techniques employed by this method generally involve taking an 
oriented piece of core from the bottom section of the core barrel (cores 
cut last) immediately upon its retrieval from the well bore. (The core 
piece must be the most homogeneous and crack-free available.) After 
cleaning the core sample, it as sealed with a fast drying sealer or 
wrapped in a polyethylene wrapper. 
The equipment used in this method includes a device base, displacement 
transducers, (3) aluminum ring (transducer carrier), and connecting rods. 
The aluminum ting can fit around a core piece of up to 4.25 in. diameter. 
The ring holds three pairs of DC displacement transducers to monitor three 
core diameters 60.degree. apart and named X, Y and Z axes. Transducer 
output is 400 microvolts per .+-.1 .eta..epsilon. (unit of strain) 
deformation of 4 in. diameter core. This output is measurable without 
amplification (unlike cantilever type devices utilizing strain gauges). 
The ring is adjustable up and down the core to accommodate various lengths 
of core up to 12 in. Vertical positioning of the ring allows one to choose 
the most homogeneous location for taking measurements along the core 
length. 
The core piece is held independently of the ring in the center of the 
device by six adjustable arms. To account for the temperature effect on 
the device output, temperature is measured in two opposite places in the 
ring. 
Since the measured displacements (strains) are 60.degree. apart, the 
direction of the principal strains can be calculated by the following 
equation: 
##EQU4## 
where: 
.theta. is the acute angle from the X-axis to the nearest principal axis. 
Terms .epsilon..sub.x, .epsilon..sub.y, and .epsilon..sub.z are the 
measured strain in the X, Y and Z axes respectively. Magnitude of maximum 
and minimum principal strains are calculated from the following equations: 
##EQU5## 
Core relaxation monitoring begins after installing the core in the center 
of a transducer support ring device with its bottom end pointing downward 
(or as it was in the core barrel). A known angle between a major 
scribeline on the core sample and the X-axis of the device must be 
maintained in all tests for future azimuth correction. Pre-test 
preparations usually take 15-30 minutes. Core displacements and 
temperature of the device were logged at regular (10-30 min) intervals. It 
is desirable to conduct measurements in a constant or nearly stable 
temperature (.+-.2.degree. C.) environment. Measurements were taken until 
the next core was ready for testing or until complete stabilization status 
was reached. Calibration of the device was done on-site before and after 
tests using a totally relaxed homogeneous rock sample having a diameter 
similar to the one tested. 
In applying the technique to actual field situations, there is one obvious, 
major complication. In analyzing an oriented core from a deep well, the 
strained measurements of the initial elastic recovery and part of the 
time-dependent (creep) recovery will be lost because of the finite time it 
takes to core the rock and bring the core to the surface. Since the 
elastic strain relief is unknown, it is essential to begin monitoring the 
time-dependent strain relief at the point as near as possible to the end 
of the elastic strain, i.e., it is necessary to quickly analyze the core 
in order to obtain the maximum amount of strain relief, and to minimize 
the error in determining the in-situ directions of the principal 
horizontal strains (stresses) from the relaxation data. 
Observing Fracture Direction Through Use Of Circumferential Acoustic 
Scanning Tool 
Another useful method for determining fracture orientation is through the 
use of Halliburton's Circumferential Acoustic Scanning Tool (CAST) which 
provides a full bore hole image during the fracturing procedure. The use 
of the CAST for determining the magnitude of the minimum principal 
horizontal stress is fully set forth in a pending application, which is 
also assigned to the assignee of this application (application Ser. No. 
07/897,325, filed Jun. 11, 1992, now U.S. Pat. No. 5,236,040). 
The CAST is the subject of U.S. Pat. No. 5,044,462, which is hereby 
incorporated by reference. By way of background, the CAST provides full 
bore hole imaging through use of a rotating ultrasonic transducer. The 
transducer, which is in full contact with the bore hole fluid, emits 
high-frequency pulses which are reflected from the bore hole wall. The 
projected pulses are sensed by the transducer, and a logging system 
measures and records reflected pulse amplitude and two-way travel time. 
The CAST provides a very thorough acoustic analysis of the well bore as 
typically some 200 shots are recorded in each 360.degree. of rotational 
sweep, and each rotational sweep images about 0.3" in the vertical 
direction; however, these parameters may be varied as the CAST has 
variable rotational speed and a selectable circumferential sampling rate, 
as well as variable vertical logging speeds. 
The images produced by the CAST yield very useful information, not only 
about fracture direction, but also about stress magnitude, formation 
homogeneity, bedding planes, as well as other geological features. The 
amplitude and travel time logs are typically presented as raster scan 
images. The raster scan televiewer images produce grey level images which 
can be processed to produce a variety of linear color scales to reflect 
amplitude and/or travel time variations. 
However, it must be remembered that sonic energy, not light, is responsible 
for the illumination of the details of the interior of the bore hole. The 
amount of illumination, otherwise known as gray shading, of a particular 
point of the amplitude image is determined by the amount of returning 
sonic energy; white indicates the highest amount of returned energy while 
black represents that very little, or essentially no sonic energy has 
returned from a particular shot. 
Likewise, in the case of travel time, white shading represents a fast 
travel time, while black represents a very long travel time, or no return. 
Since travel time is normally dependent on the distance of the two-way 
traverse, it can be surmised that the objects which are light gray or 
white are relatively close to the transducer, and objects which are dark 
gray or black are relatively far away. 
In general, fine grain, competent rocks, such as massive carbonates and 
tight sandstones, make good sonic reflectors. This means that televiewer 
images of these types of rocks would be white or light gray in amplitude, 
and probably travel time as well. On the other hand, shales and friable 
sandstones usually exhibit a rough, irregular reflective surface. 
Therefore, the images of such rocks are most likely to black or dark gray. 
The CAST is very useful in fracture reconnaissance. Because the CAST is 
recording a 360.degree. gap-free image, as opposed to simple log curves, 
spatial consideration such as fracture orientation, width, and density may 
be recognized and mapped. In particular, use of the CAST during an open 
hole microfrac test allows determination of the direction of fracture 
propagation. 
In order to determine fracture orientation with use of the CAST, it is 
necessary to distinguish open fractures from closed fractures. First, a 
fracture pattern must be recognized in the amplitude image as shown in 
FIG. 10. Next, the analyst must look for the corresponding pattern 
expression in the travel time track. If no corresponding pattern exists, 
it can be assumed that no cavity exists where the fracture intersects the 
bore hole; therefore, the fracture is closed. If a black shading does 
exist in the corresponding pattern of the travel time track as shown in 
FIG. 11, then the CAST has detected a cavity at the intersection of the 
fracture and the bore hole; therefore, the fracture is assumed to be open. 
Normally, the data obtained through use of the CAST is presented as two 
dimensional (horizontal and vertical) raster scan images of the 
"unwrapped" bore hole. The horizontal axis of the CAST images provides 
information as to the orientation of the induced fractures, i.e., the CAST 
images are presented as if the bore hole had been cut along the northerly 
direction and unwrapped. 
The CAST may also be oriented through use of any of a variety of known 
gyroscopic or magnetic means that may be attached to the tool or to an 
orientation sub. One such suitable device is the Omni DG76.RTM. 
four-gimbal gyro platform available from Humphrey, Inc., 9212 Balboa Ave., 
San Diego, Calif. 92123, (619) 565-6631. Similar gyroscopic/accelerator 
technologies may be substituted for the orientation means which include 
other mechanical rate gyros, ring laser-type gyros, or fiber optics-type 
gyros. 
Use of the CAST in conjunction with the open hole microfrac test will allow 
determination of fracture orientation. The wireline retrievable CAST may 
be lowered into the well bore during the microfrac test. Thereafter, the 
pressure of the fracturing fluid is gradually increased until fractures 
are induced in the formation. The fracture may be directly observed from 
the images produced by the CAST as they are initiated in the formation. In 
particular, as set forth above, the opening of the fractures is first 
observed in the amplitude image, and then confirmed in the travel time 
track. Thus, by noting the orientation of the fractures shown on the 
images produced by the CAST, the direction of the fracture propagation may 
be determined. 
The Inventive Slotting Method 
In the inventive method, typically, any of the aforementioned techniques 
for determining the direction of fracture propagation may be performed at 
various levels within a well bore, e.g., above and below the region of the 
formation of particular interest. After determining the direction of 
fracture propagation, drilling operations may be continued and, if 
desired, a casing may be installed in the well. Thereafter, a slotting 
device is placed in the well bore and is aligned and oriented such that 
the slots formed by the slotting device are aligned with the previously 
determined direction of fracture propagation, thereby eliminating the near 
well bore tortuosity phenomenon discussed above. 
Although this invention has been discussed in the context of several 
representative methods for determining the existing state of stress and 
the direction of fracture propagation within a field, the invention should 
not be considered limited to the representative methods discussed herein. 
Rather, the invention should be construed to cover all methods of 
determining the direction of fracture propagating within a given field. 
A tool string 102 preferred for use in the inventive slotting method is 
depicted in FIGS. 12-15. Tool string 102 includes a slotting assembly 104 
and a jetting tool 106 which is positioned below slotting assembly 104. 
Slotting assembly 104 includes: an elongate mandrel 108 having a 
passageway 110 extending longitudinally therethrough; an upper adapter 112 
which is threadedly connected to the upper end of mandrel 108; a lower 
adapter 114 which is threadedly connected to the lower end of mandrel 108; 
and a slip assembly 116 which surrounds mandrel 108. Slip assembly 116 
effectively provides (1) a housing 118 having a passageway 120 extending 
longitudinally therethrough and (2) a holding means 119 which can be 
selectively operated for holding the housing in fixed position in a well 
bore. Elongate mandrel 108 is slidably received in passageway 120 of slip 
assembly housing 118. 
Elongate mandrel 108 includes a lower elongate cylindrical portion 122, an 
upper elongate portion 124, and a short middle cylindrical portion 126 
extending between lower portion 122 and upper portion 124. A radial 
shoulder 132 is defined by the transition from lower portion 122 to middle 
portion 126. Lower cylindrical portion 122 has a cylindrical exterior 
surface 130. Mid-cylindrical portion 126 has a cylindrical exterior 
surface 134 having a smaller diameter than cylindrical surface 130. The 
exterior of upper elongate portion 124 comprises a plurality of 
semi-cylindrical portions 136 and a plurality of semi-cylindrical portions 
138. The exterior diameter of upper elongate portion 124 as defined by 
opposing semi-cylindrical portions 136 is substantially equal to the 
exterior diameter of middle cylindrical portion 126. However, the exterior 
diameter of upper elongate portion 124 as defined by opposing 
semi-cylindrical portions 138 is substantially equal to the exterior 
diameter of lower cylindrical portion 122. Opposing cylindrical portions 
138 of upper man&el portion 124 effectively provide elongate rails which 
allow mandrel 108 to be moved longitudinally within the slip assembly 
housing but prevent mandrel 108 from rotating within the slip assembly 
housing. 
Slip assembly housing 118 comprises: an upper sliding body 140; a wedge 
body 142 which is threadedly connected to sliding body 140; a J-slot 
sleeve 144 which is threadedly connected to wedge body 142; and a slip 
body 146 which covers J-slot sleeve 144. The interior diameter of the 
portion of slip assembly housing 118 defined by wedge body 142 and J-slot 
sleeve 144 corresponds to the external diameter of lower cylindrical 
portion 122 of mandrel 108. Consequently, lower mandrel portion 122, 
mid-mandrel portion 126, and upper mandrel portion 124 are each slidably 
receivable in wedge body 142 and J-slot sleeve 144. 
The interior of sliding body 140 substantially corresponds to the exterior 
shape of upper mandrel portion 124. As depicted in FIG. 14, the interior 
of upper sliding body 140 basically includes (a) a cylindrical bore 148 
having a diameter slightly larger than the diameter defined by 
semi-cylindrical portions 136 of upper mandrel portion 124 and (b) grooves 
150 sized for slidably receiving opposing rails 138 of upper mandrel 
portion 124. Since the diameter of bore 148 is slightly larger than the 
exterior diameter defined by semi-cylindrical portions 136 of upper 
mandrel portions 124, both upper mandrel portion 124 and middle mandrel 
portion 126 can be slidably received in upper sliding body 140. However, 
since the exterior diameter of lower mandrel portion 122 is larger than 
the diameter of bore 140, lower mandrel portion 122 cannot be received in 
sliding body 140. Consequently, the upward sliding movement of mandrel 108 
within slip assembly housing 118 will be limited by the abutment of radial 
shoulder 132 with the lower end of sliding body 140. 
Slip assembly 118 is operated by means of a J-slot 152 provided in J-slot 
sleeve 144. J-slot 152 is depicted in FIG. 15. Slip body 146 is operably 
associated with J-slot sleeve 144 by means of a lug 154 having a first 
portion threadably received in slip body 146 and a second portion which 
extends into J-slot 152. 
The holding means 119 of slip assembly 116 comprises: a plurality of 
(preferably three) drag springs 156 connected to the exterior of slip body 
146 by means of retaining bolts 158; a plurality of (preferably three) 
slips 160 positioned between wedge body 142 and slip body 146 and having 
lower crosspieces 161 slidably received in correspondingly shaped slots 
163 provided in the upper end of slip body 146; and a plurality of 
(preferably three) slip retaining springs 162. Each slip retaining spring 
has a first end which is connected to slip body 146 by means of screws 164 
and a second end which rests against a slip 160. 
Jetting tool 106 comprises: a body 166 having a passageway 168 extending 
longitudinally therethrough and having two threaded ports 170 extending 
through the wall of body 166; jetting nozzles 172 and 174 which are 
threadedly received in ports 170; and a back pressure valve 176 which is 
threadedly connected to the lower end of body 166. Ports 170 and jetting 
nozzles 172 and 174 are preferably positioned in body 166 such that the 
radial directional orientation of nozzle 172 (i.e., the radial direction 
in which nozzle 172 will operate with respect to the longitudinal axis of 
body 166) is 180.degree. from the radial directional orientation of 
jetting nozzle 174. The upper end of body 166 is threadedly connected to 
lower adapter 114. 
Back pressure valve 176 comprises: a valve body 178 having a passageway 180 
extending therethrough; a valve ball 182 positioned in passageway 180; and 
a ball retaining member 184 positioned in passageway 180. The lower 
portion of valve body passageway 180 is smaller than valve ball 182 and 
has a shape corresponding to that of valve ball 182 so that, when fluid is 
pumped into the upper end of jetting tool body 166, valve ball 182 seals 
against the small diameter portion of valve body passageway 180 whereby 
the fluid being pumped into jetting tool 106 is directed through nozzles 
172 and 174. Ball retaining member 184, on the other hand, operates to 
retain valve ball 182 in valve body passageway 180 when back flow is 
occurring through valve 176 and jetting tool 106. Such back flow will 
typically occur, for example, as tool string 102 is being lowered into the 
well bore. The back flow ability of valve 176 also allows recirculating 
operations to be conducted through tool string 102 in order to remove 
cuttings and other debris from the well bore. 
In the inventive method, a tubing string 186 having tool string 102 
included in the distal end thereof is inserted into a well bore 188 such 
that jetting tool 106 is positioned at a desired fracturing location 
within a subterranean formation 190. The portion of well bore 188 which is 
to be slotted can be either a cased well bore segment or an open (i.e., 
uncased) well bore segment. If the portion of well bore 188 being slotted 
is an uncased well bore segment, a sufficient amount of tubing is 
preferably included in tubing string 186 between slotting assembly 104 and 
jetting tool 106 such that slip assembly 116 can be set, in accordance 
with the procedure described hereinbelow, in an upper cased portion of 
well bore 188. 
When lowering tool string 102 into a casing 192, mandrel 108 slides 
downward through slip assembly 116 such that upper adapter 112 contacts 
and pushes against upper sliding body 140. At the same time, lug 154 is 
located in J-slot 152 at position 196 such that J-slot surface 198 
contacts and pushes lug 154. The force exerted by adapter 112 against 
sliding body 140 and the force exerted by J-slot surface 198 against lug 
154 operate jointly to (1) overcome the force exerted by drag springs 156 
against the casing wall such that slip assembly 116 is pushed downhole 
while (2) preventing wedge body 142 from sliding beneath slips 160 and 
engaging slips 160 against casing 192. 
When jetting tool 106 has been lowered to a desired longitudinal position 
within well bore 188, tubing string 186 is raised such that man&el 108 
slides upward through slip assembly 116 and radial shoulder 132 of man&el 
108 is placed in abutment with the lower end of upper sliding body 140. 
Tubing string 186 is then raised slightly further such that lug 154 moves 
from position 196 in J-slot 152 to position 200. Raising the tool string 
operates to move lug 154 from position 196 to position 200 since (1) the 
operation of drag springs 156 against casing 192 operates to hold slip 
body 146 and lug 154 in fixed position within the well bore while (2) the 
lifting of tool string 102 carries J-slot sleeve 144 upward relative to 
lug 154. 
Before or after lifting tool string 102 to move lug 154 to position 200, an 
orienting assembly 202 is delivered down the interior of tubing string 
186. Orienting assembly 202 comprises an orienting means 204 connected to 
the distal end of a multi-conductor logging cable 206. Assembly 202 also 
comprises an orienting sub 208 which is threadedly connected to orienting 
means 204. 
Orienting means 204 can generally be any device which is capable of 
indicating azimuthal orientation with respect to magnetic north when 
placed downhole. Examples of such instruments include gyroscopes, 
magnetometers, accelerometers, and the like. Orienting means 204 
preferably comprises a gyroscope. One device which is particularly 
well-suited for use in the present invention is the Omni DG76.RTM. 
four-gimbal gyro platform available from Humphrey, Inc., 9212 Balboa Ave., 
San Diego, Calif. Examples of other types of gyroscopic devices suitable 
for use in the present invention include other mechanical rate gyros, ring 
laser-type gyros, and fiber optics-type gyros. 
Orienting assembly 202 can be run into the well bore by means of a logging 
truck or other system which includes instrumentation for receiving and 
interpreting the directional information transmitted from orienting means 
204. 
Orienting sub 208 is preferably a solid elongate member having a groove 210 
formed in the lower exterior portion thereof. Orienting sub 208 is 
preferably sized such that the lower portion thereof, including groove 
210, can be received in the upper portion of mandrel 108 of slotting 
assembly 104. Groove 208 is preferably sized to receive a lug 212 which 
extends into the upper portion of mandrel passageway 110. Groove 208 is 
configured such that, as sub 208 is lowered into contact with lug 212, sub 
208 automatically rotates such that lug 212 is channeled into the upper 
portion 2 13 of groove 210. 
When assembling tool string 102, jetting tool 106 is connected to slotting 
assembly mandrel 108 such that the positions of jetting nozzles 172 and 
174 with respect to lug 212 are known. Additionally, orienting assembly 
202 is assembled such that the orientation of upper groove portion 213 
with respect to orienting sub 208 is known. Consequently, when orienting 
assembly 202 is delivered downhole such that lug 212 is received in groove 
portion 213, the directional orientations of jetting nozzles 172 and 174 
can readily be determined. 
With lug 154 located in J-slot position 200 and lug 2 12 received in 
orienting sub groove 213, tubing string 186, including mandrel 108 and 
J-slot sleeve 144, is rotated such that lug 154 moves from J-slot position 
200 to J-slot position 214. Until J-slot sleeve 144 has rotated 
sufficiently to place lug 154 in position 214, drag springs 156 prevent 
slip body 146 and lug 154 from rotating in the well bore. 
With lug 154 held in position 214 by J-slot surface 216, tool string 102 is 
further rotated until the directional orientation of jetting nozzles 172 
and 174 corresponds with the predetermined direction of fracture 
propagation existing in formation 190. During this portion of the rotating 
operation, J-slot surface 2 16 pushes against lug 154 such that the entire 
slotting assembly 104, including slip body 146, rotates within casing 192. 
In order to hold nozzles 172 and 174 in properly oriented position during 
the slotting operation, tubing string 186 is lowered such that mandrel 108 
slides downward through slip assembly 116 and upper adapter 112 contacts 
upper sliding body 140. Tubing string 186 is then further lowered such 
that upper adapter 112 pushes sliding body 140, wedge body 142, and J-slot 
sleeve 144 downward and lug 154 moves from position 214 in J-slot 152 
toward position 218. As this lowering step is occurring, drag springs 156 
hold slip body 146 in fixed position in casing 192 so that wedge body 142 
slides beneath slips 160. Slips 160 are thereby urged tightly against the 
interior wall of casing 192. With slips 160 thus positioned against casing 
192, slip assembly 116 is substantially prevented from moving either 
longitudinally or rotationally within casing 192. 
After properly orienting nozzles 172 and 174, orienting assembly 202 is 
preferably removed from tubing string 186. 
With jetting nozzles 172 and 174 thus oriented in casing 192, jetting 
nozzles 172 and 174 are preferably used to cut slots through casing 192, 
through any cement sheath 220 surrounding casing 160, and into formation 
190. This cutting procedure is accomplished by (1) pumping a hydraulic 
jetting fluid down tubing string 186 and through jetting nozzles 172 and 
174 while (2) raising tubing string 186 within casing 192. As tubing 
string 186 is raised, slotting assembly mandrel 108 slides upward through 
slip assembly housing 118. This upward movement of mandrel 108 carries 
jetting tool 106 upward at the same speed and over the same distance. 
It is also noted that, if desired, mandrel 108 can be transferred upward 
through slip assembly 116 prior to the slot cutting operation so that, 
during the slot cutting operation, mandrel 108 and jetting tool 116 are 
lowered while hydraulic jetting fluid is pumped through jetting nozzles 
172 and 174. 
The rate of ascent or descent of tubing string 186 and jetting tool 106 
during the cutting operation is controlled at the well head. As will be 
understood by those skilled in the art, an above-ground, remotely 
controlled, hydraulic ram can be used in order to ensure that a very 
smooth and well regulated rate of ascent or descent is obtained. As will 
also be understood by those skilled in the art, the rate of ascent or 
descent of jetting tool 106 could alternatively be controlled downhole by 
including a metering assembly in slotting assembly 104. 
With slip assembly 116 held in fixed position in casing 192 and with 
mandrel rails 138 retained in grooves 150 of upper sliding body 140 of 
slip assembly 116, elongate mandrel 108 and jetting nozzle 106 are 
prevented from rotating within casing 192 during the slot cutting 
operation. Consequently, the entire length of each slot will be aligned 
with the predetermined direction of fracture propagation within formation 
190. 
The hydraulic jetting fluid used in the inventive method can generally be 
any jetting fluid which is commonly used to cut slots in well casings 
and/or well bores. Examples include water, gels, foams, oil, diesel, 
kerosene, and combinations thereof. The jetting fluid will also preferably 
include an abrasive particulate material (e.g., sand). The particle size 
of the abrasive material must be small enough to allow the material to 
readily pass through jetting nozzles 172 and 174. The abrasive material 
will typically be present in the jetting fluid in an amount in the range 
of from about 0.25 pound to about 1 pound of abrasive material per gallon 
of fluid. 
After the cutting operation is completed, slip assembly 116 can be released 
by simply lifting tubing string 186. As tubing string 186 is lifted, 
mandrel radial shoulder 132 abuts and pushes against the lower end of 
upper sliding body 140. As the tubing string continues to move upward, 
radial shoulder 132 carries sliding body 140, wedge body 142, and J-slot 
sleeve 144 upward such that slips 160 are allowed to retract inward away 
from casing 192 and lug 154 moves to position 214 in J-slot 152. 
If more than one pair of opposing slots is to be cut in casing 192 and/or 
formation 190, the lowermost pair of slots will preferably be cut first. 
After releasing slip assembly 116, tubing string 186 will then be raised 
until jetting tool 106 is located at the longitudinal position where the 
next highest pair of slots is to be cut. As the tubing string is raised, 
lug 154 will be located at position 214 in J-slot 152 so that, unless the 
tubing string is rotated during the lifting operation, the nozzle 
orientation established in the preceding cutting operation should be 
maintained. However, in order to ensure that the proper nozzle orientation 
is maintained, it is preferred that orienting assembly 202 again be 
delivered downhole and that the orienting procedure be repeated. 
It will be understood that much of the benefit provided by the present 
invention will be obtained as long as the slots formed in accordance with 
the inventive method are oriented within about .+-.15.degree. (preferably 
within .+-.10.degree.) of the vertical plane extending through the 
longitudinal axis of jetting tool 106 which is perpendicular to the true 
minimum principal stress existing within the formation. Such deviation 
from the optimum slot orientation can occur due to inaccuracies inherent 
in the devices and methods employed to determine the direction of fracture 
propagation and in the devices used for orienting jetting tool 106. 
In addition to the above, it is noted that it is not necessary that the 
direction of fracture propagation be determined at each and every well 
within a field or region. Rather, after employing the methods and 
techniques disclosed and claimed herein to determine the direction of 
fracture propagation at a sufficient number of strategically located wells 
within a field or region (e.g. wells at the field boundaries), if the 
results obtained thereby are in substantial agreement, the stress pattern 
existing in the formation throughout a particular geographic region (or 
maybe for the entire region) may be determined. The number of wells that 
must be tested in order to determine the region-wide stress pattern will 
depend upon a multitude of factors; however, the direction of fracture 
propagation will preferably be determined at at least three wells that are 
strategically positioned or bounded around the region in order to have 
sufficient data from which to infer the direction of stress existing 
throughout the region. If this technique is employed, then at subsequent 
wells it would only be necessary to align the slotting device with the 
previously determined field or region wide direction of fracture 
propagation and fracture the well. Through this technique, the additional 
time and expense of determining fracture orientation at each and every 
well can be avoided. 
Additionally, in certain situations, it may be desirable to slot a given 
well in the direction of natural fractures existing within the formation. 
Of course, these fractures may or may not be aligned with the present 
stresses within the formation. Nevertheless, by slotting in the direction 
of such fractures, production of hydrocarbons may be increased. In 
particular, through the use of the Computed Tomography ("CT") technique or 
the oriented CAST tool to determine fracture direction, both of which are 
disclosed herein, with or without an open hole microfrac test, it is 
possible to determine the direction of natural fracture orientation. 
Therefore, aligning slots with the previously determined direction of 
natural fractures within a formation is also within the scope of the 
present invention. 
Through the use of the techniques disclosed herein, the direction of 
fracture propagation, or natural fractures, within a given formation may 
be determined. Thereafter, a slotting device may be oriented such that the 
slots produced by the device are aligned with the previously determined 
direction. Fracturing operations are then performed to complete the well. 
Of course, the present methods may be employed in both vertical and 
deviated wells; e.g. horizontal or wells drilled at an angle relative to a 
vertical well. When using the inventive method in horizontal or other 
highly deviated wells, coiled tubing can be used to deliver orienting 
assembly 202 downhole. Additionally, in horizontal and other highly 
deviated wells, back pressure valve 176 will preferably be replaced with a 
spring loaded ball valve or a poppet valve. 
Thus, the present invention is well adapted to carry out the objects and 
attain the ends and advantages mentioned above as well as those inherent 
therein. While presently preferred embodiments have been described for 
purposes of this disclosure, numerous changes and modifications will be 
apparent to those skilled in the art. Such changes and modifications are 
encompassed within the spirit of this invention as defined by the appended 
claims.