U.S. patent application number 10/708032 was filed with the patent office on 2005-06-02 for method and system for determining an optimum pumping schedule corresponding to an optimum return on investment when fracturing a formation penetrated by a wellbore.
This patent application is currently assigned to Schlumberger Technology Corporation. Invention is credited to Mack, Mark, Rodgers, Darren, Siebrits, Eduard, Williams, Michael John.
Application Number | 20050115711 10/708032 |
Document ID | / |
Family ID | 34622745 |
Filed Date | 2005-06-02 |
United States Patent
Application |
20050115711 |
Kind Code |
A1 |
Williams, Michael John ; et
al. |
June 2, 2005 |
Method and system for determining an optimum pumping schedule
corresponding to an optimum return on investment when fracturing a
formation penetrated by a wellbore
Abstract
A new method for determining a pumping schedule that will
produce an acceptable return on investment for a particular well
includes selecting a pumping schedule, which includes an initial
pumping schedule and a remaining pumping schedule, adapted for
fracturing a formation around one or more perforations in the
particular well. Using the initial pumping schedule, interrogate a
pump data model to produce a set of fracture characteristics. A set
of tiltmeter sensors and micro-seismic sensors placed adjacent the
fracture in the formation will also generate a set of fracture
characteristics. If the set of fracture characteristics originating
from the pump data model do not substantially match the set of
fracture characteristics originating from the tiltmeter sensors and
the micro-seismic sensors, the pump data model must be calibrated.
When the pump data model is calibrated, use the remaining pumping
schedule to interrogate the calibrated pump data model thereby
producing a production rate and a return on investment
corresponding to the production rate. If the return on investment
is not an "optimum" return on investment, change either the
proportions of frac fluid and proppant in the remaining pumping
schedule or the viscosity of the fluid or the injection rate until
a new remaining pumping schedule is determined. When the new
remaining pumping schedule interrogates the calibrated pump data
model, hopefully an "optimum" production rate and an "optimum"
return on investment will be determined for the particular well.
The owner of the particular well or other field engineers or other
decision-making personnel will then consider the "optimum" return
on investment before using the remaining pumping schedule to
continue fracturing the formation around the perforations in the
wellbore.
Inventors: |
Williams, Michael John;
(Houston, TX) ; Rodgers, Darren; (Katy, TX)
; Siebrits, Eduard; (Stafford, TX) ; Mack,
Mark; (Houston, TX) |
Correspondence
Address: |
SCHLUMBERGER TECHNOLOGY CORPORATION
IP DEPT., WELL STIMULATION
110 SCHLUMBERGER DRIVE, MD1
SUGAR LAND
TX
77478
US
|
Assignee: |
Schlumberger Technology
Corporation
110 Schlumberger Drive MD1
Sugar Land
TX
|
Family ID: |
34622745 |
Appl. No.: |
10/708032 |
Filed: |
February 4, 2004 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60481623 |
Nov 11, 2003 |
|
|
|
Current U.S.
Class: |
166/308.1 |
Current CPC
Class: |
E21B 43/267
20130101 |
Class at
Publication: |
166/308.1 |
International
Class: |
E21B 043/26 |
Claims
1. A method of determining a pumping schedule adapted for
fracturing a formation penetrated by a wellbore, comprising the
steps of: defining a selected pumping schedule to include an
initial portion and a remaining portion; interrogating a pump data
model in response to at least one of said initial portion and said
remaining portion thereby generating a return on investment;
deciding if said return on investment is a particular return on
investment; and determining said pumping schedule to be said
initial portion and said remaining portion of said selected pumping
schedule when said return on investment is said particular return
on investment.
2. A method of determining a pumping schedule corresponding to a
particular return on investment for a particular wellbore, the
pumping schedule including an initial pumping schedule and a
remaining pumping schedule, comprising the steps of: (a) fracturing
one or more perforations in a formation penetrated by the
particular wellbore, thereby creating one or more fractures in said
formation, in accordance with said initial pumping schedule; (b)
analyzing a set of fracture characteristics associated with said
one or more fractures in response to the fracturing step; (c)
interrogating a pump data model in accordance with said remaining
pumping schedule; and (d) determining a particular return on
investment for said particular wellbore in response to the
interrogating step, said pumping schedule corresponding to said
particular return on investment for said particular wellbore being
determined when said pump data model is interrogated in response to
said remaining pumping schedule.
3. The method of claim 2, wherein the analyzing step (b) for
analyzing a set of fracture characteristics associated with said
one or more fractures in response to the fracturing step comprises
the steps of: (b1) analyzing a set of fracture characteristics
associated with said one or more fractures in response to the
fracturing step; and (b2) calibrating a pump data model in response
to the analyzing step (b1) thereby generating a calibrated pump
data model.
4. The method of claim 3, wherein the interrogating step (c) for
interrogating a pump data model in accordance with said remaining
pumping schedule comprises the steps of: (c1) interrogating said
calibrated pump data model in response to said remaining pumping
schedule.
5. The method of claim 4, wherein the determining step (d) for
determining a particular return on investment for said particular
wellbore in response to the interrogating step comprises the step
of: (d1) determining a particular return on investment for said
particular wellbore in response to the step of interrogating said
calibrated pump data model in response to said remaining pumping
schedule, said pumping schedule corresponding to said particular
return on investment for said particular wellbore being determined
when said calibrated pump data model is interrogated in response to
said remaining pumping schedule.
6. The method of claim 3, wherein the interrogating step (c) for
interrogating a pump data model in accordance with said remaining
pumping schedule comprises the steps of: (c1) changing a proportion
of said frac fluid and said proppant in said remaining pumping
schedule thereby generating a new remaining pumping schedule; and
(c2) interrogating said calibrated pump data model in response to
said new remaining pumping schedule.
7. The method of claim 6, wherein the determining step (d) for
determining a particular return on investment for said particular
wellbore in response to the interrogating step comprises the step
of: (d1) determining a particular return on investment for said
particular wellbore in response to the step of interrogating said
calibrated pump data model in response to said new remaining
pumping schedule, said pumping schedule corresponding to said
particular return on investment for said particular wellbore being
determined when said calibrated pump data model is interrogated in
response to said new remaining pumping schedule.
8. A method of determining a return on investment associated with a
particular wellbore before completing a fracturing of a formation
penetrated by the wellbore, said formation being fractured in
response to a particular pumping schedule, a pump data model
generating one or more values indicative of said return on
investment when interrogated by at least a portion of said pumping
schedule, said method comprising the steps of: (a) before
completing said fracturing of said formation, interrogating said
pump data model in response to said at least a portion of said
pumping schedule; and (b) generating one or more values indicative
of said return on investment in response to the interrogating
step.
9. The method of claim 8, wherein the interrogating step (a)
further comprises the steps of: calibrating said pump data model;
and before completing said fracturing of said formation,
interrogating the calibrated pump data model in response to said at
least a portion of said pumping schedule.
10. A method of determining a pumping schedule adapted for
fracturing a formation penetrated by a wellbore, said pumping
schedule including an initial pumping schedule and a remaining
pumping schedule, comprising the steps of: (a) fracturing said
formation penetrated by said wellbore in accordance with said
initial pumping schedule thereby generating fractures in said
formation; (b) interrogating a pump data model in response to said
remaining pumping schedule thereby generating a return on
investment; (c) in response to the interrogating step, deciding
whether said return on investment is a particular return on
investment; and (d) in response to the deciding step (c),
determining said pumping schedule to be said initial pumping
schedule and said remaining pumping schedule when said return on
investment is said particular return on investment.
11. The method of claim 10, wherein the fracturing step (a) for
fracturing said formation penetrated by said wellbore in accordance
with said initial pumping schedule comprises the steps of: (a1)
fracturing said formation penetrated by said wellbore in accordance
with said initial pumping schedule; (a2) generating a set of
fracture characteristics in response to the fracturing step (a1);
(a3) analyzing said set of fracture characteristics; and (a4)
calibrating a pump data model in response to the analyzing step
(a3) thereby generating a calibrated pump data model.
12. The method of claim 11, wherein the interrogating step (b) for
interrogating a pump data model comprises the step of: (b1)
interrogating said calibrated pump data model in response to said
remaining pumping schedule thereby generating a return on
investment.
13. The method of claim 11, wherein the interrogating step (b) for
interrogating a pump data model comprises the step of: (b1)
changing a proportion of a frac fluid and a proppant in said
remaining pumping schedule thereby generating a new remaining
pumping schedule; and (b2) interrogating said calibrated pump data
model in response to said new remaining pumping schedule thereby
generating a return on investment.
14. The method of claim 11, wherein generating step (a2) for
generating a set of fracture characteristics comprises the steps
of: interrogating the pump data model in response to the initial
pumping schedule thereby generating a set of pump data model
fracture characteristics, generating a set of tiltmeter data
fracture characteristics on the condition that a tiltmeter data
sensor is located adjacent the fractures, and generating a set of
micro-seismic data fracture characteristics on the condition that a
micro-seismic data sensor is located adjacent the fractures.
15. The method of step 14, wherein the analyzing step (a3) for
analyzing said set of fracture characteristics comprises the step
of: determining whether said set of pump data model fracture
characteristics substantially matches said set of tiltmeter data
fracture characteristics and said set of micro-seismic data
fracture characteristics.
16. The method of claim 15, wherein said pump data model is
calibrated thereby generating said calibrated pump data model in
response to the analyzing step (a3) when said set of pump data
model fracture characteristics substantially matches said set of
tiltmeter data fracture characteristics and said set of
micro-seismic data fracture characteristics.
17. The method of claim 16, wherein the interrogating step (b) for
interrogating a pump data model comprises the step of: (b1)
interrogating said calibrated pump data model in response to said
remaining pumping schedule thereby generating a return on
investment.
18. The method of claim 16, wherein the interrogating step (b) for
interrogating a pump data model comprises the step of: (b1)
changing a proportion of a frac fluid and a proppant in said
remaining pumping schedule thereby generating a new remaining
pumping schedule; and (b2) interrogating said calibrated pump data
model in response to said new remaining pumping schedule thereby
generating a return on investment.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims benefit of U.S. Provisional Patent
Application No. 60/481,623 filed on Nov. 11, 2003.
BACKGROUND OF INVENTION
[0002] The subject matter of the present invention relates to a
system and method for real time control of hydraulic fracturing
treatments of a formation penetrated by a wellbore, and, in
particular, a system and method for determining an optimum pumping
schedule which corresponds to an optimum production rate and an
optimum return on investment when fracturing a perforated formation
penetrated by a wellbore.
[0003] When fracturing a formation penetrated by a wellbore, a
particular pumping schedule is utilized for pumping fracturing
fluid into a plurality of perforations in a formation penetrated by
the wellbore. Oil and other hydrocarbon deposits will produce from
the fractured perforations in response thereto, the oil and other
hydrocarbon deposits flowing uphole. A particular production rate
corresponds to the particular pumping schedule, the particular
production rate representing the rate at which the oil and other
hydrocarbon deposits flow uphole. A particular return on investment
corresponds to the particular production rate of the hydrocarbon
deposits flowing uphole, the particular return on investment
representing the amount of a client's profits being derived from a
producing well in connection with the particular production rate of
the oil and other hydrocarbon deposits being produced from the well
and flowing uphole in relation to the costs for fracturing and
producing that well.
[0004] A client will want to know whether a particular return on
investment, associated with a particular production rate and a
particular pumping schedule for a single well is an "optimum" one.
The term "optimum" is defined by the client. Therefore, it is
desirable to determine in advance for a particular well, before a
fracturing operation is completed, whether a selected pumping
schedule is an "optimum" pumping schedule which, when utilized,
will fracture a well in a particular manner such that oil and other
hydrocarbon deposits will be produced at an "optimum" production
rate thereby generating an "optimum" return on investment for the
client.
SUMMARY OF INVENTION
[0005] One aspect of the invention involves a method of determining
a pumping schedule adapted for fracturing a formation penetrated by
a wellbore, comprising the steps of: defining a selected pumping
schedule to include an initial portion and a remaining portion;
interrogating a pump data model in response to at least one of the
initial portion and the remaining portion thereby generating a
return on investment; deciding if the return on investment is an
acceptable return on investment; and determining the pumping
schedule to be the initial portion and the remaining portion of the
selected pumping schedule when the return on investment is an
acceptable return on investment.
[0006] Another aspect of the present invention involves a method of
determining a pumping schedule corresponding to a particular return
on investment for a particular wellbore, the pumping schedule
including an initial pumping schedule and a remaining pumping
schedule, comprising the steps of: (a) fracturing one or more
perforations in a formation penetrated by the particular wellbore,
thereby creating one or more fractures in the formation, in
accordance with the initial pumping schedule; (b) analyzing a set
of fracture characteristics associated with the one or more
fractures in response to the fracturing step; (c) interrogating a
pump data model in accordance with the remaining pumping schedule;
and (d) determining a particular return on investment for the
particular wellbore in response to the interrogating step, the
pumping schedule corresponding to the particular return on
investment for the particular wellbore when the pump data model is
interrogated in accordance with the remaining pumping schedule.
[0007] Another aspect of the present invention involves a method of
determining a return on investment associated with a particular
wellbore before completing a fracturing of a formation penetrated
by the wellbore, the formation being fractured in response to a
particular pumping schedule, a pump data model generating one or
more values indicative of the return on investment when
interrogated by at least a portion of the pumping schedule, the
method comprising the steps of: (a) before completing the
fracturing of the formation, interrogating the pump data model in
response to at least a portion of the pumping schedule; and (b)
generating one or more values indicative of the return on
investment in response to the interrogating step.
[0008] Another aspect of the present invention involves a method of
determining a return on investment associated with a particular
wellbore before completing a fracturing of a formation penetrated
by the wellbore, the formation being fractured in response to a
particular pumping schedule, a pump data model generating one or
more values indicative of the return on investment when
interrogated by at least a portion of the pumping schedule, the
method comprising the steps of: (a) calibrating the pump data
model; (b) before completing the fracturing of the formation,
interrogating the calibrated pump data model in response to at
least a portion of the pumping schedule; and (c) generating one or
more values indicative of the return on investment in response to
the interrogating step.
[0009] Another aspect of the present invention involves a method of
determining a pumping schedule adapted for fracturing a formation
penetrated by a wellbore, the pumping schedule including an initial
pumping schedule and a remaining pumping schedule, comprising the
steps of: (a) fracturing the formation penetrated by the wellbore
in accordance with the initial pumping schedule thereby generating
fractures in said formation; (b) interrogating a pump data model in
response to the remaining pumping schedule thereby generating a
return on investment; (c) in response to the interrogating step,
deciding whether the return on investment is an acceptable return
on investment; and (d) in response to the deciding step,
determining the pumping schedule to be the initial pumping schedule
and the remaining pumping schedule when the return on investment is
an acceptable return on investment.
[0010] Further scope of applicability of the present invention will
become apparent from the detailed description presented
hereinafter. It should be understood, however, that the detailed
description and the specific examples, while representing a
preferred embodiment of the present invention, are given by way of
illustration only, since various changes and modifications within
the spirit and scope of the invention will become obvious to one
skilled in the art from a reading of the following detailed
description.
BRIEF DESCRIPTION OF DRAWINGS
[0011] A full understanding of the present invention will be
obtained from the detailed description of the preferred embodiment
presented hereinbelow, and the accompanying drawings, which are
given by way of illustration only and are not intended to be
limitative of the present invention, and wherein:
[0012] FIG. 1 illustrates a perforating gun perforating a formation
penetrated by a wellbore;
[0013] FIG. 2 illustrates how a fracturing fluid is pumped into the
perforations in the formation and fracturing the formation in
accordance with a pumping schedule;
[0014] FIG. 3 illustrates how oil or other hydrocarbon deposits are
produced from the fractured perforations in the formation and flow
uphole, the hydrocarbon deposits flowing uphole having a production
rate in barrels/day and a return on investment corresponding to the
production rate;
[0015] FIGS. 4, 5, and 6 illustrate three separate wells wherein,
by way of example, three separate pumping schedules associated with
the three separate wells are used before an "optimum" pumping
schedule is realized which corresponds to an "optimum" return on
investment;
[0016] FIGS. 7 and 8 illustrate one particular well wherein one
pumping schedule is used for the purpose of determining an
"optimum" pumping schedule which corresponds to an "optimum" return
on investment;
[0017] FIGS. 9 and 10 illustrate three separate "time line merged"
inputs that are input to a computer system in a well logging truck
situated near the particular well of FIGS. 7 and 8, the three
separate inputs being an initial pumping schedule, tiltmeter data
originating from sensors disposed near a fracture in a formation,
and micro-seismic data also originating from sensors disposed near
the fracture in the formation;
[0018] FIG. 11 illustrates a construction of the computer system in
the well logging truck of FIGS. 9 and 10;
[0019] FIG. 12 illustrates a block diagram representing a
functional operation that is practiced by the computer system of
FIG. 11, the computer system including a memory which stores a pump
data model;
[0020] FIG. 13 illustrates how and why it is sometimes necessary to
calibrate the pump data model;
[0021] FIGS. 14 through 16 illustrate how an "optimum" pumping
schedule which corresponds to an "optimum" return on investment is
determined, a remaining pumping schedule being used (and possibly
iteratively modified) to interrogate the calibrated pump data model
in order to determine an "optimum" production rate and an "optimum"
return on investment.
DETAILED DESCRIPTION
[0022] Referring to FIG. 1, a perforating gun 10 is disposed in a
wellbore 12 and a packer 14 isolates a plurality of shaped charges
16 of the perforating gun 10 downhole in relation to the
environment uphole. The shaped charges 16 detonate and a
corresponding plurality of perforations 18 are produced in a
formation 20 penetrated by the wellbore 12.
[0023] Referring to FIG. 2, when the formation 20 is perforated, a
fracturing fluid 22 is pumped downhole into the perforations 18 in
accordance with a particular pumping schedule 24. An example
pumping schedule is illustrated in FIGS. 9 and 14. In response
thereto, the formation 20 surrounding the perforations 18 is
fractured (see FIG. 9 for an example of a fracture surrounding the
perforations 18 in the formation 20 which is created in response to
the pumping of the fracturing fluid 22 into the perforations 18 in
accordance with the pumping schedule 24).
[0024] Referring to FIG. 3, when the formation 20 surrounding the
perforations 18 is fractured, oil or other hydrocarbon deposits 26
begin to flow from the fractures, into the perforations 18, into
the wellbore 12, and uphole to the surface. The oil or other
hydrocarbon deposits flow at a certain "production rate" 28 (in
barrels/day) thereby generating a "return on investment" 30. A
client or owner of the wellbore 12 will want to know the return on
investment 30 in connection with the production rate 28 of FIG. 3
in order to further determine whether to continue producing the
hydrocarbon deposits 26 from the wellbore 12. In fact, the client
has an "optimum" return on investment in mind and hopes that the
wellbore 12 of FIG. 3 will achieve an "optimum" production rate 28
that corresponds to the "optimum" return on investment.
[0025] Referring to FIGS. 4, 5, and 6, one method for determining
an "optimum" pumping schedule for producing oil or other
hydrocarbon deposits at an "optimum" production rate and thereby
achieving an "optimum" return on investment is illustrated.
[0026] In FIG. 4, a fracturing fluid 22a is pumped into
perforations 18 in the formation 20 in accordance with a first
pumping schedule (pumping schedule 1) 24a. Responsive thereto, oil
and other hydrocarbon deposits 26 begin to flow from the fractured
formation 20, into the perforations 18, into the wellbore 12, and
uphole to the surface at a first production rate (production rate
1) 28a thereby achieving a first return on investment (return on
investment 1) 30a. However, assume that the first return on
investment (return on investment 1) 30a is not an "optimum" return
on investment from the client/wellbore owner's point of view.
Therefore, the first pumping schedule (pumping schedule 1) 24a is
not the "optimum" pumping schedule. As a result, in FIG. 5, the
method of FIG. 4 (i.e., the method for determining an "optimum"
pumping schedule for producing oil or other hydrocarbon deposits at
an "optimum" production rate thereby achieving an "optimum" return
on investment) is repeated with a different pumping schedule
(pumping schedule 2) in an effort to determine an "optimum" pumping
schedule for achieving the client/wellbore owner's "optimum" return
on investment.
[0027] In FIG. 5, a fracturing fluid 22b is pumped into
perforations 18 in the formation 20 in accordance with a second
pumping schedule (pumping schedule 2) 24b. Responsive thereto, oil
and other hydrocarbon deposits 26 begin to flow from the fractured
formation 20, into the perforations 18, into the wellbore 12, and
uphole to the surface at a second production rate (production rate
2) 28b thereby achieving a second return on investment (return on
investment 2) 30b. However, assume that the second return on
investment (return on investment 2) 30b is not an "optimum" return
on investment from the client/wellbore owner's point of view.
Therefore, the second pumping schedule (pumping schedule 2) 24b is
not the "optimum" pumping schedule. As a result, in FIG. 6, the
method of FIGS. 4 and 5 (i.e., the method for determining an
"optimum" pumping schedule for producing oil or other hydrocarbon
deposits at an "optimum" production rate thereby achieving an
"optimum" return on investment) is repeated again with a different
pumping schedule in an effort to determine an "optimum" pumping
schedule for achieving the client/wellbore owner's "optimum" return
on investment.
[0028] In FIG. 6, a fracturing fluid 22c is pumped into
perforations 18 in the formation 20 in accordance with a third
pumping schedule 24c. Responsive thereto, oil and other hydrocarbon
deposits 26 begin to flow from the fractured formation 20, into the
perforations 18, into the wellbore 12, and uphole to the surface at
a third production rate 28c thereby achieving a third return on
investment 30c. Assume now that the third return on investment 30c
is an "optimum" return on investment from the client/wellbore
owner's point of view. Therefore, the third pumping schedule 24c is
the "optimum" pumping schedule. As a result, in FIG. 6, although
the aforementioned method of FIGS. 4 through 6 (for determining an
"optimum" pumping schedule for producing oil or other hydrocarbon
deposits at an "optimum" production rate thereby achieving an
"optimum" return on investment) was repeated a plurality of times
in connection with a corresponding plurality of wellbores, that
method did successfully determine the "optimum" pumping schedule
for achieving the client/wellbore owner's "optimum" production rate
and the client/wellbore owner's "optimum" return on investment.
However, one disadvantage associated with the method of FIGS. 4
through 6 relates to the fact that three wellbores (in our example)
were fractured in an attempt to determine the "optimum" pumping
schedule that achieves the "optimum" return on investment.
[0029] Referring to FIGS. 7 through 16, the aforementioned
disadvantage associated with the method of FIGS. 4 through 6 (for
determining an "optimum" pumping schedule for producing oil or
other hydrocarbon deposits at an "optimum" production rate
achieving an "optimum" return on investment) is eliminated when the
method of FIGS. 7 through 16 (for determining an "optimum" pumping
schedule for producing oil or other hydrocarbon deposits at an
"optimum" production rate achieving an "optimum" return on
investment) is utilized. Recall that the aforementioned
disadvantage associated with the method of FIGS. 4 through 6
relates to the fact that a "plurality of wellbores" (three
wellbores in our example) were fractured in an attempt to determine
the "optimum" pumping schedule that achieves the "optimum" return
on investment. In FIGS. 7 through 16, the advantage of the method
(for determining an "optimum" pumping schedule for producing oil or
other hydrocarbon deposits at an "optimum" production rate
achieving an "optimum" return on investment) of FIGS. 7 through 16
relates to the fact that a "single wellbore" is fractured in an
attempt to determine the "optimum" pumping schedule for achieving
the "optimum" return on investment; and, during the fracturing of
that "single wellbore" of FIGS. 7 through 16, the "optimum" pumping
schedule for achieving the "optimum" return on investment is
determined. Therefore, a method associated with a "single wellbore"
for determining an "optimum" pumping schedule for producing oil or
other hydrocarbon deposits from the "single wellbore" at an
"optimum" production rate thereby achieving an "optimum" return on
investment is discussed in the following paragraphs with reference
to FIGS. 7 through 16 of the drawings.
[0030] In FIGS. 7 and 8, referring initially to FIG. 7, a
fracturing fluid 32 is pumped into the perforations 18 of a
wellbore 12 in accordance with a pumping schedule 34. In FIGS. 7
and 8, the wellbore 12 is referred to as a "particular well 36" in
order to emphasize the fact that "one single wellbore" is being
fractured during the practice of a new and novel method in
accordance with the present invention for determining an "optimum"
pumping schedule that achieves an "optimum" production rate and an
"optimum" return on investment, where the word "optimum" as in
"optimum return on investment" represents a term which can only be
defined by the owner of the particular well 36. In FIG. 8, in
response to the fracturing fluid 32 which was pumped into the
perforations 18 of the particular well 36, oil and other
hydrocarbon deposits 38 are produced from the particular well 36,
the oil or other hydrocarbon deposits 38 flowing from the fractures
in the formation 20, into the perforations 18, into the wellbore,
and uphole to the surface. The oil or other hydrocarbon deposits 38
flow at a production rate 40 in barrels per day. A graph of that
production rate 40 is illustrated in FIG. 8. In FIG. 8, the y-axis
of the graph of that production rate 40 is the production rate
("prod rate") in barrels/day and the x-axis of the graph of that
production rate 40 is "time". The graph of the production rate 40
is divided into two parts: an "actual" production rate 40a
associated with an "initial portion of the pumping schedule" 34 of
FIG. 7, and two "predicted" production rates 40b and 40c which
would be associated with a "remaining portion of the pumping
schedule" 34 of FIG. 7: a first "predicted" production rate 40b and
a second "predicted" production rate 40c. The "actual" production
rate 40a (of the oil or other hydrocarbon deposits 38 produced from
the particular well 36) reflects the rate at which the oil or other
hydrocarbon deposits 38 were actually produced from the particular
well 36 in response to the "initial portion of the pumping
schedule" 34, that "initial portion of the pumping schedule" 34
representing the actual pumping of the fracturing fluid 32 into the
perforations 18 of the particular well 36. The first "predicted"
production rate 40b and the second "predicted" production rate 40c
(of the oil or other hydrocarbon deposits 38 produced from the
particular well 36) each reflect the rate at which the oil or other
hydrocarbon deposits 38 may, sometime in the future, be produced
from the particular well 36 in response to the "remaining portion
of the pumping schedule" 34, that "remaining portion of the pumping
schedule" 34 representing a "future potential pumping" of the
fracturing fluid 32 into the perforations 18 of the particular well
36, the "future potential pumping" taking place sometime in the
future. Therefore, in FIG. 8, the "actual" production rate 40a is
the result of the actual pumping of a fracturing fluid 32 into the
perforations 18 in response to an "initial portion of the pumping
schedule" 34 and one of the two "predicted" production rates 40b
and 40c may result from the "future potential pumping" of the
fracturing fluid 32 into the perforations 18 in response to the
"remaining portion of the pumping schedule" 34, where the
"remaining portion of the pumping schedule" 34 has not yet been
implemented. If the first "predicted" production rate 40b will
follow the "actual" production rate 40a (sometime in the future) in
response to the "remaining portion of the pumping schedule" 34, a
"first return on investment" 42 will be the result; however, if the
second "predicted" production rate 40c will follow the "actual"
production rate 40a (sometime in the future) in response to the
"remaining portion of the pumping schedule" 34, a "second return on
investment" 44 will be the result. The client/owner of the wellbore
will want to "avoid an undesirable return on investment" (see
element numeral 46 in FIG. 8). Assuming that the "second return on
investment" 44 is the undesirable one, the client/owner of the
wellbore may want to either stop any further pumping of the
fracturing fluid 32 into the perforations 18 in accordance with the
"remaining portion of the pumping schedule" 34 because of an
undesirable return on investment, or that owner of the wellbore may
want to modify the "remaining portion of the pumping schedule" 34
for the purpose of achieving a desirable return on investment. The
following discussion with reference to FIGS. 9 through 16 will set
forth a method and system by which the owner of the wellbore can
determine if an "optimum remaining pumping schedule" associated
with pumping schedule 34 can be determined (for the particular
"single" well 36) that will achieve an "optimum" production rate
and an "optimum" return on investment.
[0031] In FIGS. 9 and 10, the pumping schedule 34 includes an
"initial pumping schedule" 34a and a "remaining pumping schedule"
34b. In FIG. 9, fracturing fluid and proppant 48 is pumped into the
perforation(s) 18 of the particular well 36 in accordance with the
"initial pumping schedule" 34a. In response thereto, a fracture
system 50 is created in the formation around the perforations(s)
18. In FIG. 9, micro-seismic data sensor(s) 52 and tiltmeter data
sensor(s) 54 are located adjacent the fractures 50. The
micro-seismic data sensor(s) 52 and the tiltmeter data sensor(s) 54
are adapted to respectively generate output signals 52a and 54a in
response to the creation and further development of the fractures
50, the output signals 52a and 54a being communicated to the
surface. In FIGS. 9 and 10, the micro-seismic data sensor(s) 52 are
adapted to generate output signals 52a that are communicated to the
surface (in response to the creation and further development of the
fractures 50) representing "micro-seismic data" 52b; and the
tiltmeter data sensor(s) 54 are adapted to generate output signals
54a that are communicated to the surface (in response to the
creation and further development of the fractures 50) representing
"tiltmeter data" 54b. In FIGS. 9 and 10, the "initial pumping
schedule" 34a, the tiltmeter data 54b, and the micro-seismic data
52b are "time line merged" via a "time line merging" block 56 in
FIGS. 9 and 10 wherein a first portion of the tiltmeter data 54b
and a first portion of the micro-seismic data 52b are associated
with a first time of the initial pumping schedule 34a, and a second
portion of the tiltmeter data 54b and a second portion of the
micro-seismic data 52b are associated with a second time of the
initial pumping schedule 34a, and a third portion of the tiltmeter
data 54b and a third portion of the micro-seismic data 52b are
associated with a third time of the initial pumping schedule 34a,
etc. That is, the tiltmeter data 54b and the micro-seismic data 52b
are synchronized with respective times on the initial pumping
schedule 34a. In response thereto, a signal representing a "time
line merged initial pumping schedule, tiltmeter data, and
micro-seismic data" 58 is provided as "input data" to a computer
system 60 located in a well logging truck 62 situated at the
earth's surface.
[0032] In FIG. 11, the computer system 60 of FIGS. 9 and 10 is
illustrated. The computer system 60 includes a processor 60a
operatively connected to a system bus, a recorder or display device
60b operatively connected to the system bus, and a program storage
device 60c operatively connected to the system bus. The "time line
merged initial pumping schedule, tiltmeter data, and micro-seismic
data" (plus other data including downhole temperature and bottom
hole pressure) 58 is provided as "input data" to the computer
system 60. The program storage device 60c stores a "bottom hole
sensors answer product software" 60c1, the "bottom hole sensors
answer product software" 60c1 further including a "pump data model"
60c2. When the processor 60a of the computer system 60 executes the
"bottom hole sensors answer product software" 60c1 stored in the
program storage device 60c, the recorder or display device 60b will
record or display a "diagnostic display" 60b1. The "pump data
model" 60c2 and the "diagnostic display" 60b1 will be discussed
later in this specification. The computer system 60 of FIG. 11 may
be a personal computer (PC), a workstation, or a mainframe.
Examples of possible workstations include a Silicon Graphics Indigo
2 workstation or a Sun SPARC workstation or a Sun ULTRA workstation
or a Sun BLADE workstation. The program storage device 16c is a
memory or other computer readable medium which is readable by a
machine, such as the processor 60a. The processor 60a may be, for
example, a microprocessor, microcontroller, or a mainframe or
workstation processor. The program storage device 60c, which stores
the Bottom Hole Sensor Answer Product software 60c1, may be, for
example, a hard disk, ROM, CD-ROM, DRAM, or other RAM, flash
memory, magnetic storage, optical storage, registers, or other
volatile and/or non-volatile memory.
[0033] In FIG. 12, a block diagram is illustrated which represents
a functional operation that is performed when the "bottom hole
sensors answer product software" 60c1 is executed by the processor
60a of the computer system 60 of FIG. 11. In FIG. 12, when the
"bottom hole sensors answer product software" 60c1 is executed by
the processor 60a of the computer system 60 of FIG. 11, the
received "input data" (representing the "time line merged initial
pumping schedule, tiltmeter data, and micro-seismic data" 58) is
split into three parts: the initial pumping schedule 34a, the
tiltmeter data 54b, and the micro-seismic data 52b, the initial
pumping schedule 34a being provided as "input data" to the "pump
data model" 60c2. The "pump data model" 60c2, which constitutes a
portion of the "bottom hole sensors answer product software" 60c1,
is a modeling or simulation program. In response to the initial
pumping schedule 34a, the "pump data model" 60c2 portion of the
"bottom hole sensors answer product software" 60c1 will generate a
set of "pump data model fracture characteristics" 64. The "pump
data model fracture characteristics" 64 include the following
information representing characteristics of the fracture 50 in FIG.
9 (see element numeral 64a in FIG. 12): fracture length (the length
of fracture 50 shown in FIG. 9), fracture height, fracture width,
fracture volume (hydraulic and propped), treating pressure, net
pressure, bottom hole pressure, temperature, tilts from modeling,
and/or pump parameters. In response to the tiltmeter data 54b, the
"bottom hole sensors answer product software" 60c1 will generate a
set of "tiltmeter data fracture characteristics" 66. The "tiltmeter
data fracture characteristics" 66 include the following information
representing characteristics of the fracture 50 in FIG. 9 (see
element numeral 66a in FIG. 12): fracture length, fracture height,
fracture width, fracture volume, and/or orientation with respect to
the tiltmeter 54 in FIG. 9. In response to the micro-seismic data
52b, the "bottom hole sensors answer product software" 60c1 will
generate a set of "micro-seismic data fracture characteristics" 68.
The "micro-seismic data fracture characteristics" 68 include the
following information representing characteristics of the fracture
50 in FIG. 9 (see element numeral 68a in FIG. 12): fracture length,
fracture height, fracture width, fracture volume and/or orientation
with respect to the micro-seismic data sensor 52 in FIG. 9. In
response to the "pump data model fracture characteristics" 64, the
"tiltmeter data fracture characteristics" 66, and the
"micro-seismic data fracture characteristics" 68, the "bottom hole
sensors answer product software" 60c1 will then generate the
"diagnostic display" 60b1 which is recorded or displayed on the
"recorder or display device" 60b of the computer system 60 of FIG.
11. However, if the "pump data model fracture characteristics" 64
do not substantially match the "tiltmeter data fracture
characteristics" 66 and the "micro-seismic data fracture
characteristics" 68, the "pump data model" 60c2 itself may need to
be calibrated.
[0034] In FIG. 13, a block diagram is illustrated which represents
a calibration procedure for calibrating the "pump data model" 60c2.
In FIG. 13, it was noted above that, if the "pump data model
fracture characteristics" 64 do not substantially match the
"tiltmeter data fracture characteristics" 66 and the "micro-seismic
data fracture characteristics" 68, the "pump data model" 60c2
itself may need to be calibrated. FIG. 13 represents a calibration
procedure for calibrating the "pump data model" 60c2. In FIG. 13,
refer to step 70: if the "pump data model fracture characteristics
64 do not substantially match the tiltmeter fracture
characteristics 66 and the micro-seismic data fracture
characteristics 68, calibrate the "pump data model" 60c2. In step
72, when calibrating the "pump data model" 60c2, monitor the
diagnostics display 60b1 and simultaneously change at least some of
the characteristics of the "pump data model" 60c2 thereby creating
a "modified" pump data model 60c2; for example, change the
following characteristics of the "pump data model" 60c2: (1) the
"rock properties", and (2) the "friction of the proppant in the
wellbore". In step 74, interrogate the "modified" pump data model
60c2 using the initial pumping schedule 34a (a step which is shown
in FIG. 12) thereby creating a "modified" set of "pump data model
fracture characteristics" 64. In step 76, do the "modified" set of
"pump data model fracture characteristics" 64 substantially match
the "tiltmeter data fracture characteristics" 66 and the
"micro-seismic data fracture characteristics" 68? If no, repeat
steps 72, 74, and 76. If yes, step 78 indicates that the "pump data
model" 60c2 is now calibrated.
[0035] Now that the "pump data model" 60c2 is properly calibrated,
the "remaining pumping schedule" 34b of FIG. 9 will now be used to
interrogate the calibrated "pump data model" 60c2 for the purpose
of determining the "pump data model fracture characteristics" 64
associated with the "remaining pumping schedule" 34b including the
"production rate" and the "return on investment" associated with
the particular well 36 of FIG. 9. In response thereto, the owner of
the particular well 36 can determine whether the particular well 36
will ultimately produce an "optimum" return on investment.
[0036] In FIG. 14, the pumping schedule 34 of FIG. 9 is illustrated
again. The pumping schedule 34 includes an initial pumping schedule
34a and a remaining pumping schedule 34b.
[0037] In FIG. 15, the remaining pumping schedule 34b is used to
interrogate the pump data model 60c2 (in the manner illustrated in
FIG. 12) to determine a production rate and a return on investment
for the particular well 36 of FIG. 9. The owner of the particular
well 36 hopes: (1) that the production rate will be an "optimum"
production rate, and (2) that the return on investment will be an
"optimum" return on investment. In FIG. 15, if all goes well, in
steps 80, 82, 84, and 86, the "remaining pumping schedule" 34b of
FIG. 14 (step 80) interrogates the "pump data model" 60c2 of FIG.
12 (step 82) thereby producing a production rate which, hopefully,
is an "optimum" production rate (step 84) and a return on
investment which, hopefully, is an "optimum" return on investment
(step 86).
[0038] However, if the aforementioned production rate of step 84 in
FIG. 15 is not an "optimum" production rate, and if the
aformentioned return on investment of step 86 in FIG. 15 is not an
"optimum" return on investment, it may be necessary to change some
of the characteristics of the remaining pumping schedule 34b in
FIG. 14 in order to ensure that the "pump data model" 60c2 of step
82 in FIG. 15 will produce an "optimum" production rate and an
"optimum" return on investment.
[0039] In FIG. 16, therefore, when the "pump data model" 60c2 of
step 78 in FIG. 13 is properly calibrated, the following steps
should be taken in order to ensure that the "pump data model" 60c2
produces an "optimum" or "acceptable" production rate and an
"optimum" or "acceptable" return on investment. In step 88 of FIG.
16, when the "pump data model" 60c2 is calibrated, determine the
"remaining pumping schedule" 34b and use the "remaining pumping
schedule" 34b to interrogate the "pump data model" 60c2. In step
90, interrogate the "pump data model" 60c2 using the "remaining
pumping schedule" 34b. In step 92, determine a new set of "pump
data model fracture characteristics" 64 of FIG. 12 corresponding to
the "remaining pumping schedule" 34b. In step 94, determine a
"production rate" corresponding to the "remaining pumping schedule"
34b. In step 96, determine a "return on investment" corresponding
to the "production rate". In step 98, is the "return on investment"
determined in step 96 an "acceptable" or "optimum" return on
investment? If no, in step 100, recalling from FIG. 14 that the
"pumping schedule" 34 includes a "frac fluid" column and a
"proppant" column, change the proportions of "frac fluid" and
"proppant" in the "remaining pumping schedule" 34b to determine a
"new remaining pumping schedule". In step 102, use the "new
remaining pumping schedule" to interrogate the "pump data model"
60c2 (in the manner illustrated in FIG. 12). Repeat steps 90, 92,
94, and 96 to determine a "new return on investment". In step 98,
is the "new return on investment" an "acceptable" or "optimum"
return on investment? If yes, in step 104, the "new remaining
pumping schedule", which produced the "new return on investment",
corresponds to an "acceptable" or "optimum" return on
investment.
[0040] A functional description of the operation of the present
invention will be set forth in the following paragraphs with
reference to FIGS. 1 through 16 of the drawings.
[0041] The present invention pertains to a method and system for
determining an optimum pumping schedule corresponding to an optimum
return on investment when fracturing a formation penetrated by a
wellbore. A pumping schedule is selected for pumping fracturing
fluid into a plurality of perforations in a formation penetrated by
a wellbore. When the formation is fractured, a production rate and
a return on investment is determined for the particular well.
However, that production rate and return on investment is a
function of the pumping schedule selected. If an "optimum" pumping
schedule is selected for fracturing the plurality of perforations
in the formation penetrated by the wellbore, an "optimum"
production rate (i.e., the rate at which the oil or other
hydrocarbon deposits are produced from the fractured perforations)
is produced and, as a result, an "optimum" return on investment is
the result, where the term "optimum" is determined by the owner of
the wellbore. The "optimum" pumping schedule has been determined by
selecting a plurality of pumping schedules for a respective
plurality of wellbores and, after fracturing the perforations in
those plurality of wellbores, eventually determining the "optimum"
pumping schedule that corresponds to the "optimum" return on
investment". However, a plurality of wellbores are utilized during
the above-referenced practice of determining the "optimum" pumping
schedule that corresponds to the "optimum" return on
investment.
[0042] A better method (for determining an "optimum" pumping
schedule that corresponds to an "optimum" production rate and an
"optimum" return on investment) would involve determining the
"optimum" pumping schedule that corresponds to the "optimum" return
on investment for "one particular wellbore", and not for a
plurality of wellbores as previously described. According to this
better method, a "particular pumping schedule" 34 is divided into
an "initial pumping schedule" 34a and a "remaining pumping
schedule" 34b; and "one particular wellbore" 36 is selected to be
fractured in accordance with that "particular pumping schedule" 34.
The Earth formation penetrated by the "one particular wellbore" 36
is perforated in the manner described above with reference to FIG.
1 of the drawings. Then, the resulting perforations 18 in the
formation penetrated by the "one particular wellbore" 36 are
fractured in accordance with the "initial pumping schedule" 34a in
the manner described above with reference to FIGS. 2 and 9 of the
drawings thereby producing a fracture system 50 in the formation. A
set of micro-seismic data sensor(s) 52 and a set of tiltmeter data
sensor(s) 54 are placed adjacent the fractures 50, as shown in FIG.
9 of the drawings. The micro-seismic data sensor(s) 52 generate a
plurality of micro-seismic data 52a and the tiltmeter data
sensor(s) 54 generate a plurality of tiltmeter data 54b. The
"initial pumping schedule" includes a plurality of times, as shown
in FIG. 9 of the drawings. The "initial pumping schedule" 34a, the
tiltmeter data 54b, and the micro-seismic data 52b then undergo
"time line merging" 56 of FIG. 9, wherein, the plurality of
tiltmeter data 54b and the plurality of micro-seismic data 52b
which corresponds, respectively, to the plurality of times of the
"initial pumping schedule" 34a are determined. As a result of the
aforementioned "time line merging" 56, a "time line merged initial
pumping schedule, tiltmeter data, and micro-seismic data" output
signal 58 is generated. The "time line merged initial pumping
schedule, tiltmeter data, and micro-seismic data" output signal 58
is provided as an "input signal" to a computer system 60 of a well
logging truck 62, as shown in FIGS. 9 and 10. In response to the
"time line merged initial pumping schedule, tiltmeter data, and
micro-seismic data" output signal 58, the processor 60a of the
computer system 60 in the well logging truck 62 executes a stored
software called the "Bottom Hole Sensors Answer Product Software"
60c1 that includes a "pump data model" 60c2. In response to the
execution of the stored software 60c1 by the processor 60a, as
shown in FIG. 12, the "initial pumping schedule" 34a will
interrogate the "pump data model" 60c2 and thereby generating the
"pump data model fracture characteristics" 64, the tiltmeter data
54b will generate the "tiltmeter data fracture characteristics" 66,
and the micro-seismic data 52b will generate the "micro-seismic
data fracture characteristics" 68. In FIG. 12, the "pump data model
fracture characteristics" 64, the "tiltmeter data fracture
characteristics" 66, and the "micro-seismic data fracture
characteristics" 68 will collectively generate a "diagnostic
display" 60b1 that is recorded or displayed on the recorder or
display device 60b of the computer system 60 disposed in the well
logging truck 62. If the "pump data model fracture characteristics"
64 of FIG. 12 do not substantially match the "tiltmeter data
fracture characteristics" 66 and the "micro-seismic data fracture
characteristics" 68, the "pump data model" 60c2 of FIGS. 11 and 12
must be calibrated in the manner described above with reference to
FIG. 13 of the drawings. When the "pump data model fracture
characteristics" 64 of FIG. 12 substantially matches the "tiltmeter
data fracture characteristics" 66 and the "micro-seismic data
fracture characteristics" 68, the "pump data model" 60c2 is
calibrated. At this point of the novel method of the present
invention, referring to FIGS. 14 and 15, the "remaining pumping
schedule" 34b of the pumping schedule 34 interrogates the
calibrated "pump data model" 60c2 and, hopefully, an "optimum"
production rate for the particular well 36 of FIG. 9 is determined
and an "optimum" return on investment for the particular well 36 of
FIG. 9 is also determined. In FIG. 16, if the "optimum" production
rate and the "optimum" return on investment is not determined when
the "remaining pumping schedule" 34b of FIG. 14 fractures the
perforations 18 of the particular wellbore 36 of FIG. 9, as shown
in FIG. 16, change the proporations of the "frac fluid" and the
"proppant" in the "remaining pumping schedule" 34b of FIG. 14 (see
block 100 of FIG. 16) to thereby create a "new remaining pumping
schedule" and then use the resultant "new remaining pumping
schedule" to interrogate the "pump data model" 60c2 (see block 102
of FIG. 16). If the resultant "production rate" and the resultant
"return on investment" are acceptable (i.e., an "optimum"
production rate and an "optimum" return on investment are
generated), the owner of the particular wellbore 36 of FIG. 9 must
now consider whether or not to continue to actually fracture the
particular wellbore 36 using either the "remaining pumping
schedule" 34b or the "new remaining pumping schedule" in the manner
described above with reference to FIG. 2 of the drawings.
[0043] Functional Specification for the Bottom Hole Sensors Answer
Product Software 60c1
[0044] A functional specification associated with the "Bottom Hole
Sensors Answer Product Software" 60c1 of FIG. 11 will be set forth
in the following paragraphs:
[0045] User interactions are performed through the Recorder or
Display Device 60b in FIG. 11. Where a specification indicates a
display, it refers to this device and where it refers to the User
doing something it infers interaction with this device. The display
is a terminal screen and the input device can be a keyboard, mouse
or a touch screen.
[0046] Where the input device is a touch screen, the input device
and the terminal screen are the same thing.
[0047] Timeline merging (56 in FIG. 10 and 58 in FIG. 11)
[0048] 1. The pump parameters are treated as the Primary Source,
this serves as the timeline for the merged dataset.
[0049] 2. All other sources (e.g. microseismic, tiltmeter, bottom
hole pressure, temperature etc.) are considered as Secondary
Sources.
[0050] 3. Data from Secondary Sources is intially buffered.
[0051] 4. The time location for an observation in the Secondary
Source is read from the buffer.
[0052] 5. The corresponding time is located in the Primary
Source
[0053] 6. The information from the Secondary Source buffer is
appended to the Primary Source information at the correct time,
creating the Merged Data Set.
[0054] 7. This operates continuously during real-time data
acquisition so that the Merged Data is continuously available for
processing.
[0055] 8. If Secondary Source data appears with timestamps more
recent than the more recent Primary Source data, it is buffered
until needed.
[0056] 9. If the Primary Source ends (or fails), one of the
Secondary Sources will be selected, by the user, to become the
Primary Source so that data-merging can continue.
[0057] Pump Data Model Fracture Characteristics (64 and 64a in FIG.
12 and 60c2 in FIG. 11)
[0058] 1. The forward model includes information on rock
properties, such as Young's Modulus, in-situ stress, Poisson's
Ratio, permeability, reservoir pressure etc.
[0059] 2. There are multiple available fracture models (1-, 2- and
3-dimensional) and the user selects whichever is most appropriate
for the current job.
[0060] 3. This is a numerical model based on physical
principles
[0061] 4. The model is used to create predictions of the possible
observables such as the examples listed in 64a of FIG. 12.
[0062] 5. These output predictions are stored ready for display
along-side observations for comparison.
[0063] Tiltmeter Data Fracture Characteristics (66 in FIG. 12)
[0064] 1. An inversion algorithm is used to calculate the size and
shape of the distortion that resulted in the tilt.
[0065] 2. There are multiple such algorithms avialable and the user
selects whichever is most appropriate for the current job.
[0066] Microseismic Data Fracture Characteristics (68 and 68a in
FIG. 12)
[0067] 1. The user can view the microseismic event locations in
three orthogonal two-dimensional views (East vs. North, North vs.
Depth and East vs. Depth).
[0068] 2. Interactively the user may draw a box around a sub-set of
the microseismic points, relating to the hydraulic fracture.
[0069] 3. The interpretation in step 2 allows the experienced user
to differentiate microseismic events from the fracturing from, say,
events generated by movement of an existing fault plane nearby.
[0070] 4. The microseismic points lying inside a particular
interpretation box are considered as an interpretation set.
[0071] 5. For each interpretation set, the minimum-distance
least-squares line through the points is considered to be the
interpreted axis of the fracture.
[0072] 6. The center of the fracture is considered to be located at
the mean position of the microseismic events in the interpretation
box.
[0073] 7. The length of the fracture is determined by the furthest
distance of a microseismic event along the interpreted axis in
either direction.
[0074] 8. The length is stored in each direction as a half-length,
so that asymmetry of the fracture may be determined.
[0075] 9. The height of the fracture is determined by the further
distance of a microseismic event perpendicular to the axis along
the minimum-distance least-squares plane through the points.
[0076] 10. The height is stored in each direction from the center
as a half-height, so that again symmetry can be analyzed.
[0077] 11. The elliptical area of the fracture is determined from
the length and height information.
[0078] 12. The rectangular area of the fracture is determined from
the length and height information.
[0079] 13. The orientation of the fracture is determined as the
orientation of the interpreted axis.
[0080] 14. The fracture characteristics determined from the
microseismic information are stored (by 60c in FIG. 11).
[0081] Diagnostic Display (60b1 in FIG. 11 and FIG. 12)
[0082] 1. The diagnostic display is completely configurable in
terms of which graphs are displayed.
[0083] 2. The configuration for a particular job contains graphs
that compare stored information. This can be observations, results
from the Pump Data Model (64 and 64a in FIG. 12), results from the
Tiltmeter Data (66 and 66a in FIG. 12), results from the
Microseismic Data (68 and 68a in FIG. 12)
[0084] 3. The interaction for the user to intepret fracture
characteristics from microseismic described above, can be achieved
using a diagnostic plot.
[0085] 4. Diagnostic plots can carry automatic alarms. These alarms
can be triggered by any information trigger (for example
greater-than, less-than a value; difference between modeled and
observed values of the same property etc.) see 70 in FIG. 13
[0086] 5. The alarms alert the user immediately to early-warning
signals that the original operation is not producing the desired
results.
[0087] 6. Alarms can be set for any observation, any fracture
characteristic derived from observation, or any model output.
[0088] 7. Alarms can be created for any mathematical combination of
the values described in step 6.
[0089] 8. The Diagnostic Displays can show predictions based on the
portion of the pump schedule not yet pumped.
[0090] 9. The Diagnostic Displays can show results from production
simulation and return on investment.
[0091] Calibration of the pump model (72, 74, 76 and 78 in FIG.
13)
[0092] 1. The user decides to perform a calibration, and so clicks
on the "Calibrate" button to initiate the process.
[0093] 2. The pump schedule is split into the fixed portion (that
which has been pumped so far 34a in FIG. 14) and the remaining
portion (that which is yet to be pumped 34b in FIG. 14).
[0094] 3. Concentrating on the fixed portion, the user can further
split the pumpshcedule into calibration intervals.
[0095] 4. The user selects a match-point within each calibration
interval (in time) where the obesrvations and the model will be
compared.
[0096] 5. The user selects the appropriate quantity (rock
properties or friction of the proppant) to vary to achieve the
match.
[0097] 6. The program iteratively adjusts the appropriate quantity
to improve the match at the define match-points until the
root-mean-square difference between the modeled and measured values
is below a user-defined limit. This is an iterative
optimization.
[0098] 7. Once the match is good as defined in step 6, the Pump
Data Model is considered to be calibrated and useful for
predictions.
[0099] Optimizing the remaining pump schedule
[0100] 1. The fixed portion and remaining portion of the pump
schedule (80 in FIG. 15) are used with the Pump Data Model to
provide a prediction for the current job.
[0101] 2. The output from the Pump Data Model includes a propped
fracture length and a fracture conductivity. It is the fracture
characteristics resulting from completing the current job with the
remaining portion of the pump schedule (90 in FIG. 16)
[0102] 3. The fracture length and conductivity, along with rock
properties are inputs to a production simulator (84 in FIG.
15).
[0103] 4. The production simulator is a numerical simulator that
uses mass-balance and flow equations to model the predicted flow of
hydrocarbons through the well during reservoir production.
[0104] 5. There are several production simulators available and the
user selects the most appropriate one for this job.
[0105] 6. The production simulator uses specified well controls
(for example a constant draw-down pressure) to numerically model
the production expected from the fractured well.
[0106] 7. The output of the production simulator is the production
vs. time (commonly known as the Decline Curve (the "Production
Rate" in 94 of FIG. 16). It may also include other production
parameters, such as water-cut versus time.
[0107] 8. The outputs from the production simulator are forwarded
to the Return On Investment calculation (86 in FIG. 15).
[0108] 9. The return on investment considers the cost of the
fracture treatment and the monetary value of the decline curve,
plus any costs associated with handling unwanted production (such
as the water-cut). These are the known costs.
[0109] 10. The return on investment simulator is a numerical
simulator that provides a monetary value over time for the results
of the fracturing.
[0110] 11. There are several ways to calculated return on
investment available. The user selects the most appropriate.
[0111] 12. The return on investment provides an output of return
versus time from the production data and the known costs. (96 on
FIG. 16)
[0112] 13. An adjustment is made to the fluid and proppant pumped
in the remaining portion of the pump schedule.
[0113] This is made under the constraint of the total materials
available at the well-site minus the total materials pumped so far
(102 on FIG. 16).
[0114] 14. Steps from 1 through 13 are repeated iteratively to
improve the return on investment in line with the client's
definition of an "optimum" return. (98 on FIG. 16). The results of
each iteration are used in calculating the best updates to make in
step 13, so that this scheme converges to the optimum solution over
a few iterations.
[0115] 15. The remaining portion of the pump schedule that has been
determined by the above scheme represents an optimum alternative to
the original remaining portion of the pump schedule (104 in FIG.
16).
[0116] 16. A graphical display contrasts the return on investment
for continuing with the original remaining portion or, instead,
using the newly determined remaining portion.
[0117] 17. The client is then able to select between the
alternatives, and any changes are relayed to the pump operator.
[0118] 18. This calibration and optimization scheme can be
recalculated at any time during the job. The portion of fixed
schedule being determined at the time the user begins to
calibrate.
[0119] 19. The calibration and optimization are rapid operations
compared to the length of the pump schedule.
[0120] The invention being thus described, it will be obvious that
the same may be varied in many ways. Such variations are not to be
regarded as a departure from the spirit and scope of the invention,
and all such modifications as would be obvious to one skilled in
the art are intended to be included within the scope of the
following claims.
* * * * *