U.S. patent number 3,586,105 [Application Number 04/862,225] was granted by the patent office on 1971-06-22 for detecting changes in rock properties in a formation by pulse testing.
This patent grant is currently assigned to Esso Production Research Company. Invention is credited to Carlton R. Johnson, Aaron E. Pierce, Saul Vela, Edward G. Woods.
United States Patent |
3,586,105 |
Johnson , et al. |
June 22, 1971 |
DETECTING CHANGES IN ROCK PROPERTIES IN A FORMATION BY PULSE
TESTING
Abstract
A method of detecting induced changes in the rock properties of
subterranean formations. The preferred use of the method is in
determining the presence and orientation of induced fractures in
the formation. In this use of this method, the formation is first
pulse tested between the well to be fractured and at least one
additional well. Preferably the pulse tests are conducted between
the well to be fractured and at least three surrounding wells which
are in noncollinear directions from the first well. The first well
is then fractured and a second series of pulse tests between the
fractured well and the other wells is conducted. The presence and
orientation of the fracture can be determined by comparison of the
pulse tests within the formation before and after fracturing.
Inventors: |
Johnson; Carlton R. (Houston,
TX), Vela; Saul (Houston, TX), Woods; Edward G.
(Houston, TX), Pierce; Aaron E. (Humble, TX) |
Assignee: |
Esso Production Research
Company (N/A)
|
Family
ID: |
25337981 |
Appl.
No.: |
04/862,225 |
Filed: |
September 30, 1969 |
Current U.S.
Class: |
166/250.1;
166/271; 166/308.1; 73/152.39; 73/152.54 |
Current CPC
Class: |
E21B
43/17 (20130101); E21B 43/26 (20130101); E21B
47/02 (20130101); E21B 49/008 (20130101) |
Current International
Class: |
E21B
49/00 (20060101); E21B 47/02 (20060101); E21B
43/25 (20060101); E21B 43/17 (20060101); E21B
43/26 (20060101); E21B 43/16 (20060101); E21b
049/100 () |
Field of
Search: |
;166/250,252,254,271,308
;73/151,152,155 |
References Cited
[Referenced By]
U.S. Patent Documents
Primary Examiner: Calvert; Ian A.
Claims
We claim:
1. A method of testing a subterranean formation comprising:
a. pulses testing between a plurality of locations within the
formation by changing the fluid flow rate at at least one location
in the formation and measuring the resultant change in pressure
with time at at least one other location in the formation;
b. then, changing the rock properties of the formation at one of
said locations; and
c. then, pulse testing a second time between the locations.
2. A method as defined in claim 1 wherein the locations are
horizontally spaced in the formation at a plurality of wells.
3. A method as defined in claim 2 wherein the locations are at a
first well and at least three noncollinear wells which are
horizontally spaced about the first well.
4. A method as defined by claim 3 wherein the rock properties of
the formation are changed by hydraulically inducing a fracture at
the first well.
5. A method as defined by claim 4 wherein the pulse tests of steps
(a) and (c) are in the same direction.
6. A method as defined by claim 4 wherein the pulse tests of steps
(a) and (c) are in reverse directions.
7. A method as defined by claim 4 further comprising measuring the
timelags of the pulse tests of step (a), measuring the timelags of
the pulse tests of step (c), and determining the ratios of the
timelags of step (a) to the timelags of step (c).
8. A method as defined by claim 7 further comprising comparing the
timelag ratios and orientation of the other wells with respect to
the first well to determine the presence and orientation of the
induced fracture at the first well.
9. A method of determining the presence and orientation of
hydraulically induced fractures within a subterranean formation
comprising:
a. pulse testing within the formation between a first well to be
fractured and at least three surrounding, noncollinear wells by
changing the fluid flow rate at least one of said wells and
measuring the resultant change in pressure with time at the
remaining wells;
b. then, hydraulically fracturing the formation at the first
well;
c. then, repeating step (a);
d. measuring the timelags of the pulse tests of step (a), measuring
the timelags of the pulse tests of step (c), and determining the
ratio of the time lags of step (a) to the time lags of step (c);
and
e. comparing the timelag ratios and orientation of the surrounding
wells with respect to the first well to determine the presence and
orientation of the induced fracture at the first well.
10. A method of testing a subterranean formation comprising:
a. pulse testing between a plurality of locations within the
formation by changing the fluid flow rate at least one location in
the formation and measuring the resultant change in pressure with
time at least one other location in the formation;
b. then, changing the rock properties of the formation between at
least two of said locations; and
c. then, pulse testing a second time between the locations.
11. A method as defined in claim 10 wherein the locations are
vertically spaced within the formation at a well.
Description
BACKGROUND OF THE INVENTION
1. Field of the Invention
This invention relates to a method of measuring and testing. More
specifically, this invention relates to a method of formation
logging to determine induced changes in the rock properties of the
formation by pulse testing.
2. Description of the Prior Art
In recent years, hydraulic fracturing of a producing formation to
increase the production of oil and gas has been used quite
extensively and successively. Well fracturing is the splitting of
rock under tension. When a rock is put under tension, it will
stretch in proportion to the applied stress, up to its yield point;
at which point, rock, being brittle, ruptures with little or no
plastic deformation. In order to obtain a well fracture, hydraulic
pressure is applied to the rock of the producing formation within
the well bore, thus creating tensile force around the hole. As the
hydraulic pressure increases, these tensile forces become great
enough that they finally pull the rock apart and start the fracture
or split which is lengthened by fluid being pumped into the hole.
In other cases, the formation rock sometimes is not actually
fractured because it already exists in a fractured state. In these
cases, the fluid under hydraulic pressure must only overcome the
confining stresses to open and extend the existing fractures.
To better study the effect of fracturing upon oil and gas recovery,
it is necessary to know the nature and direction of such fractures.
This is especially important in determining flow patterns and in
determining the optimum method of producing oil from a formation.
As the method of the invention is useful in determining the nature
and extent of the fractures in a hydrocarbon-bearing formation, its
importance to the recovery of oil and gas is immediately
apparent.
The impression packer is one device which has been developed to
determine the nature of induced fractures in a formation. This
device has a resilient and deformable member which can be lowered
into the well bore after fracturing. The resilient member is forced
against the walls of the well bore by hydraulic or mechanical force
and an impression of the well bore is imprinted on the deformable
member. The device is then deflated and withdrawn from the
wellbore. Visual inspection of the impressions made on this device
reveals the general orientation of the fractures at the well bore.
Such a device has a number of inherent drawbacks. First, it can
only be employed in an uncased hole since it must contact the
fractured formation. Second, the device reveals the nature and
extent of the fracture only in the immediate vicinity of the well
bore. The fracture may extend for hundreds of feet beyond the well
bore; however, the impression packer by its very nature can only
investigate the nature and extent of the fracture in a tiny
fraction of this length. The induced fracture may also diverge
radically from its orientation at the well bore, but the impression
packer is ineffective in detecting such a divergence. Finally,
unless auxiliary equipment is employed with the impression packer,
the azimuth or direction of the fractures cannot be determined. As
the packer is withdrawn from the hole, there is no assurance that
it will remain in the same position it occupied at the formation.
The operator therefore cannot relay with any degree of certainty on
the relative position of the impressions on the packer when it is
brought to the surface.
Pulse testing is a relatively new method for determining formation
properties. Pulse testing involves the transmission of a sequence
of transient pressure pulses in a formation by changing the rate at
which fluids flow into or out of the formation through a well. The
resultant changes in pressure with time are measured at another
location in the formation to determine the formation properties.
This method may be used in locating and evaluating reservoir
heterogeneities such as faults, fractures, permeability variations,
changes in fluid saturations and the like. The present invention is
an improvement on the basic pulse testing technique. The present
invention isolates the effect of induced changes from other
reservoir heterogeneities which may be present. It permits
evaluation of the induced changes alone.
SUMMARY OF THE INVENTION
This invention relates to a method for detecting changes in
formation rock properties by pulse testing before and after
changing these properties. The primary use of the method is in
determining the orientation of induced fractures. In practicing the
method, the well to be fractured is first chosen and then pulse
tests are conducted between that well and at least one other well.
The well is then fractured and a second series of pulse tests is
conducted. The pulse test results before and after fracturing
determine the nature and extent of the induced fracture.
It is one of the objects of this invention to provide a method for
determining the nature and extent of induced changes in rock
properties within a subterranean formation. It is another object of
this invention to determine the nature and extent of induced
fractures in the formation.
The objects and nature of this invention will become more apparent
from a discussion of the following drawings and preferred
embodiment.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a plan view of a section of an oil field showing a
portion of the wells in the field.
FIG. 2 is a graph of the orientation between pulsing and response
wells versus the time lag ratio measured at each of the response
wells.
FIG. 3 is the graph of FIG. 2 and illustrates a graphical method of
determining fracture orientation.
DESCRIPTION OF THE PREFERRED EMBODIMENTS
The method of this invention may be used to determine the nature
and extent of a variety of induced changes in reservoir rock
properties. The following discussion, however, will be directed
primarily to the preferred application of the method --determining
the location and orientation of induced vertical fractures in a
subterranean formation.
FIG. 1 is a plan view of a portion of an oil field. The field has
been drilled with a regular pattern of wells in rows extending
north-south and east-west. The distance between wells in each row
is 933 feet. The alternate rows are offset so that the wells in
that row are midway between the wells in the adjacent row.
As shown in FIG. 1, well A represents a well to be fractured. Well
E is in the same north-south row and is located 933 feet due south
of well A. Wells B and C are in the adjacent row to the east. These
wells are 660 feet from well A in the directions N45.degree.E and
S45.degree.E as shown in FIG. 1. Well D is in the adjacent
north-south row to the west of well A. This well is 660 feet from
well A in the direction S45.degree.W.
In the practice of this invention, the formation is first pulse
tested prior to fracturing well A. The precision of determining
fractures orientation is dependent upon the number of well pairs
that are tested. As will be described in greater detail herein,
some information on fracture orientation can be determined by pulse
testing between the well to be fractured and a single adjacent well
before and after fracturing. However, in order to clearly define
fracture orientation, it is preferred to pulse test between the
well to be fractured and at least three offset, noncollinear wells.
Wells are noncollinear in this sense when a line drawn between the
wells does not intersect the well to be fractured. For example,
wells B and C would be noncollinear. Wells B and D would be
collinear, since a line drawn between these wells would intersect
well A. It will generally be preferred to induce the pulse at the
well to be fractured and to monitor the response at the surrounding
wells. In this manner, one series of pulses from Well A can be
simultaneously measured at the offset wells. It should be
recognized however that it is possible to conduct a pulse test in
the opposite manner, with a series of pulses induced in the offset
wells and the response measured at well A.
Following the initial pulse testing of the well pairs, well A is
fractured, generally by hydraulic fracturing. The configuration of
the induced fracture can be readily determined by techniques known
to those skilled in the art. The fracture length, width, and fluid
conductivity can be determined within reasonable accuracy using
conventional analytical techniques.
At this point it should be noted that nearly all induced fractures
in a subterranean formation are vertical. At one time it was felt
that these fractures were predominantly oriented in horizontal
direction. In recent years it has been found that this original
conclusion is generally erroneous. Stress analysis of subterranean
formations has shown that, in all except very shallow formations or
unusual stress conditions, an induced fracture will lie in a
vertical plane which intersects the well bore. Under induced
stress, the formation will part against the least of the forces
that are imposed on the formation. At even intermediate depths, the
weight of the overburden becomes so great that the forces in a
horizontal direction are the least and vertical fractures will be
created when sufficient stresses are induced in the formation.
Following fracturing at well A, the pulse tests are repeated
--preferably in the same manner as the first tests. The size of the
induced pulses, the time length of the pulses, the time between
pulses, and the direction of pulses should be the same before and
after fracturing. It should be recognized, however, that it is
possible to reverse the direction of the pulses if desired. For
example, if prior to fracturing the pulses are induced at well B
and received at well A, the direction may be reversed after
fracturing and the pulses induced at well A and received at well
B.
The physical properties which are measured during pulse testing
include response amplitude and timelag. These properties are
functions of the fluid diffusivity of the formation. It has been
found that fracture orientation can be determined by simply
comparing the timelags before and after fracturing. Timelag is
defined as the time lapse in minutes between the change in flow
rate which terminates a pulse and the maximum response amplitude
measured at the response well which corresponds to that pulse.
The following table 1 gives the results of pulse testing between
well pairs A-B, A-C, A-D, and A-E before and after fracturing well
A. ##SPC1##
It has been found that the timelag ratio (the timelag before
fracturing divided by the timelag after fracturing) is a maximum
when the fracture lies on a line between the pulsing well and the
response well; it is a minimum when the fracture is perpendicular
to a line between the wells. It can be seen from inspection of
table 1 that the fracture is generally oriented toward wells B and
D and generally perpendicular to a line between well A and well C.
This is apparent from the radical change in timelag at wells B and
D as shown by the high timelag ratio and by the relatively
unchanged timelag at well C. This is perhaps more clearly shown in
FIG. 2, where the timelag ratio at each well pair is shown as a
function of the orientation between the pulsing well and the
responding well. Thus, some indication of fracture orientation can
be seen from the timelag ratio at a single well pair.
The information obtained can be used to define more precisely the
orientation of the fractures if sufficient well pairs are tested.
This method is a graphical analysis and requires a minimum of three
noncollinear responding wells. It has been found that the
relationship between fracture orientation and timelag ratio can be
reasonably approximated by the following two equations:
##SPC2##
The application of this graphical method is perhaps best explained
with reference to FIG. 3. The time lag ratio for each responding
well is first plotted as a function of the orientation of that well
from the pulsing well. An overlay curve is then produced by
plotting the mathematical expressions of equations 1 and 2 between
0.degree. and 360.degree.. Conveniently on this overlay curve, the
fracture is assumed to be positioned at 0.degree. and 180.degree..
Such a curve will be W-shaped with peaks at 0.degree., 180.degree.
and 360.degree. and with minima at 90.degree. and 270.degree..
Since this mathematical expression is a function of the distance
between the pulsing and responding wells, a separate curve must be
derived for each well spacing. As shown in FIG. 3, curve 1 is
derived for a well spacing of 660 feet; curve 2 is derived for a
well spacing of 933 feet. These curves are then shifted over the
timelag ratio-orientation plots until the best fit between data and
curves is obtained. Note that the data points representing the 660
feet well spacing must correspond to curve 1, and that the data
point representing the 933 feet well spacing must fit curve 2. When
the best fit between data and curves is obtained, the peaks of the
curve represent the orientation of the fracture; thus, as shown in
FIG. 3 at lines 3 and 4, the fracture at well A is oriented at
N30.degree.E and S30.degree.W.
The pulse test data may also be analyzed using conventional
reservoir-modeling techniques. An example of one such technique is
given in Jahns, "A Rapid Method for Obtaining Two-Dimensional
Reservoir Description from Well Pressure Response Data," Society of
Petroleum Engineers Journal, Dec. 1966, pp. 315--317. Such
techniques are particularly suitable where the reservoir is
strongly heterogeneous. In a homogeneous reservoir the ratio
between timelag and the square of the distance between wells should
be a constant. Where the pulse test results prior to fracturing
show a wide variation in these ratios, reservoir-modeling should be
employed. In the use of such reservoir-modeling techniques, the
reservoir description obtained by pulse testing prior to fracturing
may be rotated about the fractured well with the orientation of the
fracture held constant. The best fit between the pulse test data
obtained subsequent to fracturing and the results obtained by
shifting the reservoir model will give the relative orientation of
the fracture.
While this method has been described with reference to its primary
use --the determination of vertical fracture orientation, it should
be apparent that the method has broad applicability. The method may
be used to detect a wide variety of induced changes in formation
rock properties. As examples, but not limitations, the method may
be used to determine the effect of increasing the formation
pressure in a naturally fractured reservoir and whether the
increased pressure has increased the fluid conductivity of these
fractures. The method is also useful in determining the
effectiveness of creating a permeability barrier at the oil-water
contact of a well to reduce water coning. In such a use, the pulse
tests would be conducted between vertically spaced points in the
formation at a single well. The induced permeability barrier would,
of course, lie between these vertically spaced points. Also the
method can be used to determine the presence and extent of
horizontal fractures.
* * * * *