U.S. patent application number 15/260756 was filed with the patent office on 2018-03-15 for zonal communication and methods of evaluating zonal communication.
The applicant listed for this patent is SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to Gunnar Gerard De Bruijn, Philippe Enkababian, Polina Khalilova, Petr Kolchanov, Jesse Lee, Dmitriy Potapenko, Larry Todd.
Application Number | 20180073352 15/260756 |
Document ID | / |
Family ID | 61558685 |
Filed Date | 2018-03-15 |
United States Patent
Application |
20180073352 |
Kind Code |
A1 |
Potapenko; Dmitriy ; et
al. |
March 15, 2018 |
ZONAL COMMUNICATION AND METHODS OF EVALUATING ZONAL
COMMUNICATION
Abstract
Methods may include recording pressure and/or temperature data
at two or more time points in a region adjacent an isolated zone in
a wellbore created by one or more isolation devices; and
determining the degree of fluid communication around the one or
more isolation devices from characteristic changes in the recorded
pressure and/or temperature data. Methods may also include
injecting a fluid into an isolated zone in a wellbore created by
one or more isolation devices; recording pressure and/or
temperature data at two or more time points in a region adjacent
the isolated zone; and determining the degree of fluid
communication around the one or more isolation devices from
characteristic changes in the recorded pressure and/or temperature
data.
Inventors: |
Potapenko; Dmitriy; (Sugar
Land, TX) ; Lee; Jesse; (Sugar Land, TX) ;
Todd; Larry; (The Woodlands, TX) ; De Bruijn; Gunnar
Gerard; (Houston, TX) ; Kolchanov; Petr;
(Sugar Land, TX) ; Khalilova; Polina; (Houston,
TX) ; Enkababian; Philippe; (Richmond, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
SCHLUMBERGER TECHNOLOGY CORPORATION |
Sugar land |
TX |
US |
|
|
Family ID: |
61558685 |
Appl. No.: |
15/260756 |
Filed: |
September 9, 2016 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 47/18 20130101;
E21B 47/113 20200501; E21B 47/103 20200501; E21B 47/10 20130101;
E21B 47/117 20200501; E21B 47/135 20200501 |
International
Class: |
E21B 47/10 20060101
E21B047/10; E21B 43/14 20060101 E21B043/14; E21B 43/26 20060101
E21B043/26; E21B 33/10 20060101 E21B033/10; E21B 47/06 20060101
E21B047/06; E21B 47/18 20060101 E21B047/18; E21B 47/12 20060101
E21B047/12 |
Claims
1. A method comprising: recording pressure and/or temperature data
at two or more time points in a region adjacent an isolated zone in
a wellbore created by one or more isolation devices; and
determining the degree of fluid communication around the one or
more isolation devices from characteristic changes in the recorded
pressure and/or temperature data.
2. The method of claim 1, further comprising preparing a wellbore
treatment to modify the determined degree of fluid communication
around the one or more isolation devices.
3. The method of claim 1, wherein the recorded pressure and/or
temperature data is transmitted to the surface by one or more
selected form a group consisting of pressure pulses, i-coil, and
fiber optics.
4. The method of claim 1, wherein the recorded pressure and/or
temperature data is transmitted in real time.
5. The method of claim 1, wherein pressure data is recorded and
wherein a decrease in pressure over time is indicative of minimal
fluid communication outside of the isolated zone.
6. The method of claim 1, wherein pressure data is recorded and
wherein an increase in pressure over time is indicative of fluid
communication outside of the isolated zone.
7. The method of claim 1, wherein temperature is recorded and
wherein an increase in temperature over time is indicative of
minimal fluid communication outside of the isolated zone.
8. The method of claim 1, wherein temperature is recorded and
wherein a decrease in temperature over time is indicative of fluid
communication outside of the isolated zone.
9. The method of claim 1, wherein recording pressure and/or
temperature data is performed using a memory gauge.
10. The method of claim 1, wherein recording pressure and/or
temperature data is performed during stimulation of the isolated
zone.
11. The method of claim 1, wherein recording pressure and/or
temperature data is performed during production of the isolated
zone.
12. A method comprising: injecting a fluid into an isolated zone in
a wellbore created by one or more isolation devices; recording
pressure and/or temperature data at two or more time points in a
region adjacent the isolated zone; and determining the degree of
fluid communication around the one or more isolation devices from
characteristic changes in the recorded pressure and/or temperature
data.
13. The method of claim 12, wherein the injected fluid is a
stimulating treatment.
14. The method of claim 12, further comprising preparing a wellbore
treatment to modify the determined degree of fluid communication
around the one or more isolation devices.
15. The method of claim 12, wherein pressure data is recorded and
wherein a decrease in pressure over time is indicative of minimal
fluid communication outside of the isolated zone.
16. The method of claim 12, wherein pressure data is recorded and
wherein an increase in pressure over time is indicative of fluid
communication outside of the isolated zone.
17. The method of claim 16, wherein the increase in pressure is
characterized as a pressure differential in the range of 100 psi to
5000 psi.
18. The method of claim 12, wherein temperature is recorded and
wherein an increase in temperature over time is indicative of
minimal fluid communication outside of the isolated zone.
19. The method of claim 12, wherein temperature is recorded and
wherein a decrease in temperature over time is indicative of fluid
communication outside of the isolated zone.
20. The method of claim 22, wherein the decrease in temperature is
characterized as a pressure differential in the range of 2.degree.
C. to 100.degree. C.
Description
BACKGROUND
[0001] Following the cessation of drilling operations, completions
may be initiated in which downhole tubulars and equipment are
installed to enable the safe and efficient production from an oil
or gas well. During completions, sections of casing or pipe string
may be placed into the wellbore to enhance wall strength and
minimize the chances of collapse, burst, or tensile failure. Well
casings of various sizes may be used, depending upon depth, desired
hole size, and types of geological formations encountered. The
casing and other tubulars may, in some instances, be stabilized and
bonded in position using various physical and chemical
techniques.
[0002] Following completions, stimulation operations may be
conducted by initiating fractures or through the use of treatments
such as acids and other chemicals that increase the porosity of the
formation. Fracturing operations conducted in a subterranean
formation may enhance the production of fluids by injecting
pressurized fluids into the wellbore to induce hydraulic fractures
and introducing flow channels that connecting isolated reservoirs.
Fracturing fluids may deliver various chemical additives and
proppant particulates into the formation during fracture extension.
Following the injection of fracture fluids, introduced proppants
may prevent fracture closure as applied pressure decreases below
the formation fracture pressure. The propped open fractures then
allow fluids to flow from the formation through the proppant pack
to the production wellbore.
SUMMARY
[0003] This summary is provided to introduce a selection of
concepts that are described further below in the detailed
description. This summary is not intended to identify key or
essential features of the claimed subject matter, nor is it
intended to be used as an aid in limiting the scope of the claimed
subject matter.
[0004] In one aspect, embodiments in accordance with the present
disclosure may be directed to methods that include recording
pressure and/or temperature data at two or more time points in a
region adjacent an isolated zone in a wellbore created by one or
more isolation devices; and determining the degree of fluid
communication around the one or more isolation devices from
characteristic changes in the recorded pressure and/or temperature
data.
[0005] In another aspect, embodiments in accordance with the
present disclosure may be directed to methods that include
injecting a fluid into an isolated zone in a wellbore created by
one or more isolation devices; recording pressure and/or
temperature data at two or more time points in a region adjacent
the isolated zone; and determining the degree of fluid
communication around the one or more isolation devices from
characteristic changes in the recorded pressure and/or temperature
data.
[0006] Other aspects and advantages of the disclosure will be
apparent from the following description and the appended
claims.
BRIEF DESCRIPTION OF FIGURES
[0007] FIG. 1 is an illustration of a completion operation in which
cement is installed in an annular region created between a borehole
and an installed casing in accordance with embodiments of the
present disclosure.
[0008] FIG. 2 is an illustration of a zone isolated during a
completions operation in accordance with embodiments of the present
disclosure.
[0009] FIG. 3 is a graphical representation of representative data
measured in a region adjacent an isolated interval in accordance
with embodiments of the present disclosure.
[0010] FIG. 4 is an illustration of an interval experiencing
near-wellbore communication from an isolated zone during a
completions operation in accordance with embodiments of the present
disclosure.
[0011] FIG. 5 is a graphical representation of representative data
measured in a region adjacent an isolated interval experiencing
near-wellbore communication in accordance with embodiments of the
present disclosure.
[0012] FIG. 6 is an illustration of an interval experiencing
far-wellbore communication from an isolated zone during a
completions operation in accordance with embodiments of the present
disclosure.
[0013] FIG. 7 is a graphical representation of representative data
measured in a region adjacent an isolated interval experiencing
far-wellbore communication in accordance with embodiments of the
present disclosure.
[0014] FIG. 8 is a flow diagram illustrating a method of
determining the presence of zonal communication in accordance with
embodiments of the present disclosure.
[0015] FIG. 9 is an illustration of a computer system in accordance
with embodiments of the present disclosure.
DETAILED DESCRIPTION
[0016] In one aspect, methods in accordance with embodiments
disclosed here may be directed to the detection and quantification
of zonal communication following wellbore completion and cementing.
Methods in accordance with the present disclosure may monitor
changes in pressure and/or temperature in regions adjacent zones
isolated during completions and production to detect near- and
far-wellbore fluid communication. In one or more embodiments,
methods may allow early identification and mitigation of zonal
communication severity, which may allow an operator to address
potential problems and employ remedial measure such as modification
of stimulation protocols including reducing injection rates,
resetting packers, or the use of diverting treatments or fluid loss
materials.
[0017] Following the cessation of drilling operations, cementing
may proceed by casing the wellbore and emplacing a cement slurry
into an annulus created between a wall of the formation and a
section of installed casing (or an annulus between casing strings).
With particular respect to FIG. 1, a derrick 100 is shown installed
on a wellbore 101 traversing a formation 102. Within the wellbore
101 concentric segments of casing 104 are nested within each other,
in preparation for installation of a cement sheath between the
outside of the casing and the exposed formation and/or other
emplaced casing strings. During the cementing operation, a cement
slurry 106 is pumped into an annulus formed between formation 102
and the casing 104. In some embodiments, cement slurry may be
pumped into multiple annular regions within a wellbore such as, for
example, (1) between a wellbore wall and one or more casing strings
of pipe extending into a wellbore, or (2) between adjacent,
concentric strings of pipe extending into a wellbore, or (3) in one
or more of an A- or B-annulus (or greater number of annuli where
present) created between one or more inner strings of pipe
extending into a wellbore, which may be running in parallel or
nominally in parallel with each other and may or may not be
concentric or nominally concentric with the outer casing
string.
[0018] In some cases, wellbores may be stimulated after completions
using a number of stimulation techniques such as "plug and perf" in
which the casing of the wellbore is perforated using projectiles or
abrasive jetting to allow reservoir fluids to enter the wellbore.
During stimulation, a wellbore may be perforated in a number of
different locations in order to increase production, either in the
same hydrocarbon-bearing zone or in different hydrocarbon-bearing
zones, and thereby increase the flow of hydrocarbons into the well.
With particular respect to FIG. 2, a wellbore 202 may traverse one
or more zones of interest 204 within a subterranean formation. In
order to access the zones of interest 204, a perforating tool may
be lowered into the wellbore to create perforations 208 through a
cemented casing 206 and into the near wellbore.
[0019] Stimulation may target single or multiple zones within the
well at time through the use of various technologies. For example,
a wellbore may subdivided into a number of isolated zones and
individual zones may be stimulated in a controlled sequence, such
as from the toe of the well to the heel, using various treatment
fluids until all zones are treated. Stimulation techniques may
involve multiple steps such as running a perforating gun down the
wellbore to one or more target zones, perforating the target zones,
removing the perforating gun, treating the target zones with a
hydraulic fracturing fluid, and then isolating the perforated
target zones for subsequent production.
[0020] Completion operations may utilize the installation of
isolation devices inside the casing and/or liner to isolate one or
more target zones for stimulation or production from the remainder
of the well. In some embodiments, zones may be isolated with a
packer 210 emplaced on a string of tubing 207. Other isolation
devices in accordance with the present disclosure may include
tension packers, compression packers, hydraulic-set packers, plugs
such as bull plugs, bridge plugs, darts, and the like. Isolation
devices may also include packers offered commercially as a
component of BROADBAND.TM. Precision available from Schlumberger
Technology Corporation. In some embodiments, intelligent
completions may be used, which may involve the use of liner
systems, packers, subsurface flow controls, and subsurface safety
valves. Completion systems may also incorporate both sensing and
control systems, inflow control devices (ICDs), flow control valves
(FCVs), pressure gauges, and control lines that may allow users to
drain their reservoirs with granularity and may provide an
increased feedback regarding fluid movement and reservoir
drainage.
[0021] However, the use of isolation techniques and intelligent
completion systems within the wellbore may have limited
effectiveness in situations in which the cementing job behind the
casing that isolates the sections from the formation is incomplete
or defective. Fluid communication in the near- and far-wellbore may
not be evident during primary cementing, and cement
characterization methods are uncommon prior to production due to
the added time and costs. Inadequate characterization of fluid
communication may lead to uncertainty with regard to the level of
fluid communication between zones, which can lead to the diversion
of treatment fluids beyond installed isolation devices during
stimulation and loss of pressure control, overflushing at elevated
pressures, and infliction of formation damage or stimulation of
collateral intervals around the target. Further, during production,
pressure imbalances between neighboring stages (or laterals in a
multilateral well) may result in a higher pressure stage
disemboguing into a lower pressure stage rather than to the
surface, potentially damaging the zone and limiting production. In
another example, fluid communication may allow stages closer to the
heel of the well that produce water to contaminate hydrocarbon
streams transported from the toe of the well.
[0022] Returning to FIG. 2, monitoring of zonal fluid communication
in accordance with embodiments of the present disclosure may
involve the emplacement of a tool string including one or more
measuring modules 212 arranged adjacent a packer 210. Packer 210
may be engaged once in place at the target region, creating an
isolated zone 216 within the wellbore. The isolated zone may then
be stimulated using various physical and chemical techniques and/or
produced for hydrocarbons and connate fluids. In some embodiments,
measuring module 212 may be activated to measure pressure and/or
temperature in the regions of the well (such as 214) isolated from
fractured interval 208 to quantify the degree of fluid
communication. In some embodiments, sleeves 205 present on a
toolstring or coiled-tubing 207 may be engaged, allowing the
injection of treatment fluids into the isolated zone and/or to
allow production fluids to be transported through the tubing 207 to
the surface.
[0023] Measuring modules 212 may communicate pressure and/or
temperature data to the surface using any suitable
downhole-to-surface transmitting technology, including the use of
pressure pulses similar to that employed during
logging-while-drilling (LWD), wireline, i-coil, fiber-optics, and
the like. In some embodiments, the measuring module may incorporate
a memory gauge that samples and records downhole pressures or
temperatures, with the data being stored, ready for downloading to
acquisition equipment when the tool assembly has been retrieved to
surface. In some embodiments, data transmission from the measuring
module may occur in real time, which may enable an operator to
monitor fluid communication during stimulation operations or
production. While a number of data transmission techniques are
discussed, it is envisioned that any technology capable of relaying
pressure and temperature data to an operator remote from the
measurement location may be employed.
[0024] Zonal communication may be monitored in accordance with the
present disclosure by measuring the conditions in areas adjacent an
isolated region of the wellbore to detect fluid communication in
through near- and far-wellbore channels. With particular respect to
FIG. 3, a graphical representation of data received is presented
from a measuring module arranged as depicted in FIG. 2. During
stimulation, fluids injected into isolated zone 216 may be
communicated into adjacent region 214 containing measuring module
212, which creates environmental changes that are detectable by the
measuring module 212. When isolated properly, fluid flow from
isolated region 216 is minimal and ambient formation temperatures
heat the static fluid column in adjacent zone 214 over time, as
indicated by the solid black trace in FIG. 3. Similarly, in
situations having no fluid communication, wellbore fluids outside
of the isolated region 216 slowly depressurize in the absence of
the applied pressure of pumped fluids, as indicated by the dashed
trace in FIG. 3.
[0025] In one or more embodiments, one or more additional measuring
modules may be arranged above the isolated region. For example,
pressure and temperature gauges (including memory gauges) may be
installed above and below isolation packer to determine
differential pressures and temperatures across the packer. In some
embodiments, completions systems containing multiple pressure and
temperature gauges may include commercial completions systems such
as BROADBAND PRECISION.TM. available from Schlumberger Technology
Corporation.
[0026] Fluid communication around isolated zones may exhibit
characteristic and measurable changes in pressure and temperature
in zones adjacent isolated intervals. For example, fluid
communication may be evident by observing the magnitude of
differential in bottom hole pressure (BHP) and/or bottom hole
temperature (BHT). When fluids are injected into or drained from
the isolated interval, escaping fluids enter adjacent zones and
increase the fluid volume and measured pressure. Further,
measurable changes in temperature may be observed as cooler fluids
migrate from the isolated zones and/or exchange with warmer, less
dense, fluids from the adjacent zones.
[0027] Pressure differentials in accordance with the present
disclosure may be within a lower limit of greater than 0 psi or 10
psi to an upper limit of any of 5000 psi, 2000 psi, or 1000 psi,
where any lower limit can be used with any upper limit. In some
embodiments, the pressure differential may be within a lower limit
of any of -5000 psi, -2000 psi, or -1000 psi to an upper limit of
-100 psi or less than 0 psi, where any lower limit can be used with
any upper limit.
[0028] Temperature differentials in accordance with the present
disclosure may be within the range of a lower limit of greater than
0.degree. C. or 2.degree. C. to an upper limit of 100.degree. C.,
50.degree. C., or 10.degree. C., where any lower limit can be used
with any upper limit. In some embodiments, the temperature
differential may be within a lower limit of any of -100.degree. C.,
-50.degree. C., or -10.degree. C. to an upper limit of -2.degree.
C. or less than 0.degree. C., where any lower limit can be used
with any upper limit.
[0029] For example, near-wellbore communication, occurring in the
first few feet from the axis of the well such as near the casing
and formation wall and/or through a cement annulus, may allow
fluids to pass around isolation devices emplaced within the
wellbore. With particular respect to FIG. 4, defects in primary
cementing jobs may result in the formation of channels and
microannuli that allow fluid communication through the
near-wellbore area 402 or through cracks within the cemented
interval 404. In one or more embodiments, fluid communication from
the isolated zones may be may be identified by monitoring changes
in temperature in pressure in the adjacent zones. During
near-wellbore communication, diversion of injected or produced
fluids may migrate into an adjacent zone below an installed packer,
which may be measured using a measuring module that monitors
changes in pressure and temperature. With particular respect to
FIG. 5, fluid communication in the near-wellbore region may be
characterized by increases in pressure (dashed trace) and increases
in temperature (solid trace) over relatively short time scales
following the injection or production of fluids within the isolated
interval.
[0030] Fluid communication may also exist in the far-wellbore
regions, and occur deeper in the formation. With particular respect
to FIG. 6, depending on a number of factors, including the nature
of the formation and the use of intervention techniques such as
stimulation by acidization or perforation, fractures and other
defects may extend and connect to form channels that enable
far-wellbore fluid communication 602. Far-wellbore communication
may be characterized by changes in temperature and pressure that
occur over longer time scales than near-wellbore communication.
With particular respect to FIG. 7, a graphical representation of
pressure (dashed trace) and temperature (solid trace) as a function
of time shows a slow increase in pressure as fluids are diverted
from the isolated zones into the formation and back to the adjacent
zones containing the measuring module. Temperature changes in
far-wellbore communication may be less dramatic when compared to
the near-wellbore case as diverted fluids are equilibrated to
formation temperature as the fluid is redirected to the adjacent
zone.
[0031] Methods in accordance with the present disclosure are
directed to identifying and addressing zonal communication by
measuring pressure and/or temperature downhole during completion
and production. With particular respect to FIG. 8, a flow diagram
depicting an embodiment of a method for detecting fluid
communication is shown. Methods in accordance with the present
disclosure may begin following the isolation of one or more
intervals of a wellbore at 802 using various isolation
technologies. Following the initial zonal isolation, a measurement
module, installed proximate to and on a side opposing the isolated
interval created by the emplaced isolation device, is used to
record data, such as pressure and temperature, in the non-isolated
region of the wellbore at 804. Data recording may occur during a
stimulation or production process. For example, data recording may
follow the stimulation of an isolated stage, prior to the creation
and or stimulation of additional frac stages within the wellbore in
some embodiments.
[0032] Data measured during a selected wellbore operation, which
may include temperature and/or pressure data, may then be evaluated
to determine whether characteristic changes in the measured data
correspond to patterns established for the presence of near- and
far-wellbore communication at 806. Data measurements may include
the magnitude of change in temperature and pressure at two or more
time points, which may be obtained in real time during wellbore
operations in some embodiments. Fluid communication levels
quantified at 806 may then be used by an operator at 808 to adjust
the current completion design or to initiate remedial operations to
improve zonal isolation prior to subsequent operations. Adjustment
of completion or production design may include pumping isolation
pills designed to plug communication channels, changing treatment
volume, adjusting pumping rates, and the like.
[0033] Embodiments of the present disclosure may be implemented on
a computing system. Any combination of mobile, desktop, server,
embedded, or other types of hardware may be used. For example, as
shown in FIG. 16, the computing system (1600) may include one or
more computer processor(s) (1602), associated memory (1604) (e.g.,
random access memory (RAM), cache memory, flash memory, etc.), one
or more storage device(s) (1606) (e.g., a hard disk, an optical
drive such as a compact disk (CD) drive or digital versatile disk
(DVD) drive, a flash memory stick, etc.), and numerous other
elements and functionalities. The computer processor(s) (1602) may
be an integrated circuit for processing instructions. For example,
the computer processor(s) may be one or more cores, or micro-cores
of a processor. The computing system (1600) may also include one or
more input device(s) (1610), such as a touchscreen, keyboard,
mouse, microphone, touchpad, electronic pen, or any other type of
input device. Further, the computing system (1600) may include one
or more output device(s) (1608), such as a screen (e.g., a liquid
crystal display (LCD), a plasma display, touchscreen, cathode ray
tube (CRT) monitor, projector, or other display device), a printer,
external storage, or any other output device. One or more of the
output device(s) may be the same or different from the input
device(s). The computing system (1600) may be connected to a
network (1612) (e.g., a local area network (LAN), a wide area
network (WAN) such as the Internet, mobile network, or any other
type of network) via a network interface connection (not shown).
The input and output device(s) may be locally or remotely (e.g.,
via the network (1612)) connected to the computer processor(s)
(1602), memory (1604), and storage device(s) (1606). Many different
types of computing systems exist, and the aforementioned input and
output device(s) may take other forms.
[0034] Software instructions in the form of computer readable
program code to perform embodiments of the present disclosure may
be stored, in whole or in part, temporarily or permanently, on a
non-transitory computer readable medium such as a CD, DVD, storage
device, a diskette, a tape, flash memory, physical memory, or any
other computer readable storage medium. Specifically, the software
instructions may correspond to computer readable program code that
when executed by a processor(s), is configured to perform
embodiments of the present disclosure.
[0035] Further, one or more elements of the aforementioned
computing system (1600) may be located at a remote location and
connected to the other elements over a network (1612). Further,
embodiments of the present disclosure may be implemented on a
distributed system having a plurality of nodes, where each portion
of a computer system in accordance with the present disclosure may
be located on a different node within the distributed system. In
one embodiment of the present disclosure, the node corresponds to a
distinct computing device. Alternatively, the node may correspond
to a computer processor with associated physical memory. The node
may alternatively correspond to a computer processor or micro-core
of a computer processor with shared memory and/or resources.
[0036] Although the preceding description has been described herein
with reference to particular means, materials and embodiments, it
is not intended to be limited to the particulars disclosed herein;
rather, it extends to all functionally equivalent structures,
methods and uses, such as are within the scope of the appended
claims. In the claims, means-plus-function clauses are intended to
cover the structures described herein as performing the recited
function and not only structural equivalents, but also equivalent
structures. Thus, although a nail and a screw may not be structural
equivalents in that a nail employs a cylindrical surface to secure
wooden parts together, whereas a screw employs a helical surface,
in the environment of fastening wooden parts, a nail and a screw
may be equivalent structures. It is the express intention of the
applicant not to invoke 35 U.S.C. .sctn. 112(f) for any limitations
of any of the claims herein, except for those in which the claim
expressly uses the words `means for` together with an associated
function.
* * * * *