U.S. patent application number 15/516953 was filed with the patent office on 2017-08-31 for additive management system.
The applicant listed for this patent is Gro Merete ALENDA, Thomas David BAMBER, Bryan BUSSELL, Eric GRZELAK, Peter HAYWARD, Simon Charles HOLYFIELD, Ulrich KLEINE, OneSubsea IP UK Limited, Rolf RUSTAD, Harald SOLHEIM. Invention is credited to Gro Merete ALENDAL, Thomas David BAMBER, Bryan A. BUSSELL, Eric GRZELAK, Peter HAYWARD, Simon Charles HOLYFIELD, Ulrich KLEINE, Rolf RUSTAD, Harald SOLHEIM.
Application Number | 20170247986 15/516953 |
Document ID | / |
Family ID | 54541127 |
Filed Date | 2017-08-31 |
United States Patent
Application |
20170247986 |
Kind Code |
A1 |
BUSSELL; Bryan A. ; et
al. |
August 31, 2017 |
ADDITIVE MANAGEMENT SYSTEM
Abstract
A system including an additive management system configured to
oversee hydrate formation in a hydrocarbon extraction system, the
additive management system including a flow meter configured to
measure a fluid flow rate, a first sensor configured to measure at
least one of a fluid property and an environmental condition, and a
chemical injection device configured to inject a hydrate inhibitor
into a fluid flow.
Inventors: |
BUSSELL; Bryan A.; (Sutton,
GB) ; HAYWARD; Peter; (Hebden Bridge, GB) ;
KLEINE; Ulrich; (Langenhagen, DE) ; RUSTAD; Rolf;
(Radal, NO) ; SOLHEIM; Harald; (Radal, NO)
; ALENDAL; Gro Merete; (Bergen, NO) ; HOLYFIELD;
Simon Charles; (Norwich, GB) ; GRZELAK; Eric;
(Houston, TX) ; BAMBER; Thomas David; (Leeds,
GB) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
BUSSELL; Bryan
HAYWARD; Peter
KLEINE; Ulrich
RUSTAD; Rolf
SOLHEIM; Harald
ALENDA; Gro Merete
HOLYFIELD; Simon Charles
GRZELAK; Eric
BAMBER; Thomas David
OneSubsea IP UK Limited |
Sutton
Hebden Bridge
Langenhagen
Radal
Radal
Bergen
Norwich
Houston
Leeds
London |
TX |
GB
GB
DE
NO
NO
NO
GB
US
GB
GB |
|
|
Family ID: |
54541127 |
Appl. No.: |
15/516953 |
Filed: |
October 28, 2015 |
PCT Filed: |
October 28, 2015 |
PCT NO: |
PCT/US15/57878 |
371 Date: |
April 5, 2017 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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62069729 |
Oct 28, 2014 |
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62144178 |
Apr 7, 2015 |
|
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62173750 |
Jun 10, 2015 |
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62186050 |
Jun 29, 2015 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
G05D 7/0617 20130101;
E21B 47/06 20130101; G01F 1/00 20130101; E21B 37/06 20130101; E21B
41/0092 20130101; C10G 33/08 20130101; G05B 15/02 20130101; E21B
47/07 20200501 |
International
Class: |
E21B 41/00 20060101
E21B041/00; E21B 47/06 20060101 E21B047/06 |
Claims
1. A system, comprising: an additive management system configured
to oversee hydrate formation in a hydrocarbon extraction system,
the additive management system comprising: a first sensor
configured to generate feedback relating to at least one parameter
of a fluid flowing through the hydrocarbon extraction system; a
first chemical injection device configured to inject a hydrate
inhibitor into the fluid at a first location; a controller
configured to: receive the feedback from the first sensor;
determine a likelihood of hydrate formation in the fluid at the
first location based on the feedback; determine a flow rate of
hydrate inhibitor to inject into the fluid using the first chemical
injection device based on the likelihood of hydrate formation at
the first location.
2. The system of claim 1, wherein the controller is configured to
control the chemical injection device to inject the hydrate
inhibitor at the determined flow rate.
3. The system of claim 1, comprising a user interface operatively
coupled to the controller, wherein the controller is configured to
cause the user interface to display a recommendation to adjust a
flow rate of the hydrate inhibitor to the determined flow rate.
4. The system of claim 1, wherein the first sensor is a
conductivity probe, and wherein the controller is configured to
determine a proportion of water in the fluid based on feedback from
the conductivity probe and to determine the likelihood of hydrate
formation based on the proportion of water in the fluid.
5. The system of claim 4, wherein the conductivity probe is
disposed in a hanger of the hydrocarbon extraction system upstream
from the chemical injection device.
6. The system of claim 1, wherein the first sensor is configured to
measure temperature and pressure, and wherein the additive
management system comprises a second sensor configured to measure a
third parameter of the fluid, wherein the controller is configured
to determine the likelihood of hydrate formation based on feedback
from the first sensor and feedback from the second sensor.
7. The system of claim 1, wherein the additive management system
comprises: a second sensor configured to generate feedback relating
to at least one parameter of the fluid flowing through the
hydrocarbon extraction system a second chemical injection device
configured to inject the hydrate inhibitor into the fluid at a
second location; wherein the controller is configured to: receive
the feedback from the second sensor; determine a likelihood of
hydrate formation in the fluid at the second location based on the
feedback from the second sensor; and determine a second flow rate
of hydrate inhibitor to inject into the fluid using the second
chemical injection device based on the likelihood of hydrate
formation at the second location, wherein the first sensor is
proximate to the first chemical injection device and the second
sensor is proximate to the second chemical injection device.
8. The system of claim 1, wherein the controller is configured to
execute a modeling program using the feedback from the first sensor
to determine the likelihood of hydrate formation.
9. The system of claim 8, wherein the controller is configured to
execute the modeling program to determine the flow rate of hydrate
inhibitor to inject into the fluid, wherein the modeling program is
configured to determine a different flow rate of hydrate inhibitor
to inject for a start-up condition of the hydrocarbon extraction
system, a steady-state condition of the hydrocarbon extraction
system, or a shut-in condition of the hydrocarbon extraction
system.
10. The system of claim 1, comprising the hydrocarbon extraction
system.
11. A system, comprising: a controller configured to control an
amount and timing of injection of a hydrate inhibitor into a
hydrocarbon extraction system using feedback from a flow meter and
a first sensor.
12. The system of claim 11, wherein the controller is configured to
control the injection of the hydrate inhibitor with a chemical
injection device in response to the feedback from the flow meter
and the first sensor.
13. The system of claim 11, wherein the first sensor comprises a
pressure sensor or a temperature sensor.
14. The system of claim 11, wherein the controller is configured to
execute a modeling program using the feedback from the flow meter
and the first sensor to determine a likelihood of hydrate formation
and to control the amount and timing of the injection of the
hydrate inhibitor to reduce the likelihood of hydrate
formation.
15. A method for managing hydrate formation in a hydrocarbon
extraction system, comprising: receiving a flow rate from a flow
meter; receiving at least one of an environmental condition and a
fluid condition from a first sensor; identifying a hydrate
formation condition using feedback from the flow meter and the
first sensor; and controlling injection of a hydrate inhibitor in
response to the hydrate formation condition.
16. The method of claim 15, wherein the environmental condition
comprises temperature, pressure, or both, and wherein the fluid
condition comprises water content.
17. The method of claim 16, comprising: receiving the environmental
condition from the first sensor; receiving the fluid condition from
a second sensor; and identifying the hydrate formation condition
using the flow rate, the environmental condition, and the water
content.
18. The method of claim 15, wherein the first sensor comprises at
least one of a pressure sensor, a temperature sensor, a
conductivity probe, and a salinity sensor.
Description
CROSS REFERENCE TO RELATED APPLICATION
[0001] This application claims priority to and benefit of U.S.
Provisional Application No. 62/069,729, entitled "Monoethylene
Glycol Injection Control System", filed Oct. 28, 2014, U.S.
Provisional Application No. 62/144,178, entitled "Additive
Management System," filed Apr. 7, 2015, U.S. Provisional
Application No. 62/186,050, entitled "Additive Management System,"
filed Jun. 29, 2015, and U.S. Provisional Application No.
62/173,750, entitled "Method and System for Measuring the Injection
Rate of a Chemical in a Fluid Flow Stream," filed Jun. 10, 2015,
the disclosures of which are herein incorporated by reference in
their entireties for all purposes.
BACKGROUND
[0002] This section is intended to introduce the reader to various
aspects of art that may be related to various aspects of the
present invention, which are described and/or claimed below. This
discussion is believed to be helpful in providing the reader with
background information to facilitate a better understanding of the
various aspects of the present invention. Accordingly, it should be
understood that these statements are to be read in this light, and
not as admissions of prior art.
[0003] Hydrate formation in hydrocarbon extraction operations is an
industry wide concern. Hydrates are formations of ice and gas that
may form due to high pressures and low temperatures in hydrocarbon
extraction environments. In order to block hydrate formation, a
variety of hydrate inhibitors are used, such as mono-ethylene
glycol. These hydrate inhibitors may block hydrate formation by
lowering the freezing point of water. Unfortunately, hydrate
inhibitors may be used excessively to prevent hydrate formation,
which unnecessarily increases the cost of hydrocarbon extraction
operations.
BRIEF DESCRIPTION OF THE DRAWINGS
[0004] Various features, aspects, and advantages of the present
invention will become better understood when the following detailed
description is read with reference to the accompanying figures in
which like characters represent like parts throughout the figures,
wherein:
[0005] FIG. 1 is a schematic view of an embodiment of a hydrocarbon
extraction system with an additive management system;
[0006] FIG. 2 is a schematic view of an embodiment of an additive
management system;
[0007] FIG. 3 is a schematic view of an embodiment of an additive
management system coupled to a wellhead system;
[0008] FIG. 4 is a schematic view of an embodiment of an additive
management system coupled to a wellhead system;
[0009] FIG. 5 is a schematic view of an embodiment of an additive
management system coupled to a wellhead system;
[0010] FIG. 6 is a cross-sectional view of an embodiment of a
tubing hanger of a hydrocarbon extraction system including a
sensor;
[0011] FIG. 7 is a flow diagram of a method for controlling hydrate
formation of a hydrocarbon extraction system; and
[0012] FIG. 8 is a flow diagram of a method for controlling a ratio
of an injected chemical to water in a fluid flow.
DETAILED DESCRIPTION OF SPECIFIC EMBODIMENTS
[0013] One or more specific embodiments of the present invention
will be described below. These described embodiments are only
exemplary of the present invention. Additionally, in an effort to
provide a concise description of these exemplary embodiments, all
features of an actual implementation may not be described in the
specification. It should be appreciated that in the development of
any such actual implementation, as in any engineering or design
project, numerous implementation-specific decisions must be made to
achieve the developers' specific goals, such as compliance with
system-related and business-related constraints, which may vary
from one implementation to another. Moreover, it should be
appreciated that such a development effort might be complex and
time consuming, but would nevertheless be a routine undertaking of
design, fabrication, and manufacture for those of ordinary skill
having the benefit of this disclosure.
[0014] The present disclosure is directed to embodiments of an
additive management system configured to determine and monitor one
or more conditions of a hydrocarbon extraction system, such as a
hydrate condition (e.g., hydrate formation). In order to determine
and monitor the hydrate condition, the additive management system
includes a controller that receives feedback (e.g., data) from one
or several flow meters, sensors, chemical injection metering
valves, etc. of the hydrocarbon extraction system. The controller
or another device (e.g., computer) uses the feedback in algorithms,
modeling programs, and/or lookup tables to determine the hydrate
condition. For example, the controller may determine a likelihood
of hydrate formation based on an analysis of the feedback.
[0015] Additionally, in certain embodiments, the additive
management system may be configured to provide recommendations to a
user based on the hydrate condition (e.g., hydrate formation is
likely to occur) to reduce or block hydrate formation. For example,
the additive management system may provide recommendations to
adjust an amount or flow rate of an injected hydrate inhibitor. In
some embodiments, the additive management system may automatically
adjust an amount or flow rate of an injected hydrate inhibitor to
reduce or block hydrate formation. Furthermore, the additive
management system may enable precise and/or targeted monitoring
and/or control of hydrate formation throughout the hydrocarbon
extraction system. In particular, the additive management system
may provide recommendations and/or adjustments for the hydrate
inhibitor injection that are specific for and/or tailored for one
or more specific locations in the hydrocarbon extraction system.
For example, the additive management system may be configured to
distribute hydrate inhibitor (or another injected chemical)
[0016] Further, in some embodiments, the additive management system
may be configured to inject a chemical into a fluid flow of the
hydrocarbon extraction system and to determine a ratio of the
injected chemical to relative water in the fluid flow. For example,
the additive management system may inject one or more chemicals,
such as hydrate inhibitors (e.g., thermodynamic inhibitors and/or
kinetic inhibitors), pH modifiers, and/or scale inhibitors. The
additive management system may determine the ratio of the injected
chemical relative to water based at least in part on feedback from
one or more optical sensors, feedback from one or more conductivity
sensors, or a combination thereof. Additionally, the additive
management system may be configured to provide recommendations to
adjust the flow rate and/or amount of the injected chemical or to
automatically adjust the flow rate and/or amount of the injected
chemical based on the ratio of the injected chemical relative to
water. For example, the additive management system may compare the
ratio to a threshold (e.g., above a lower threshold or below an
upper threshold) or threshold range (e.g., between upper and lower
thresholds) and may provide recommendations to adjust or may
automatically adjust the flow rate and/or amount of the injected
chemical based on the comparison.
[0017] FIG. 1 is a schematic view of an embodiment of a hydrocarbon
extraction system 10 with an additive management system 12 that
determines and monitors one or more parameters or conditions of the
hydrocarbon extraction system 10. For example, as described in more
detail below, the additive management system 12 may determine or
monitor a hydrate condition (e.g., hydrate formation) and/or a
ratio or proportion of a chemical (e.g., a hydrate inhibitor)
relative to water in a fluid flow. Additionally, as described in
more detail below, the additive management system 12 may provide
recommendations to a user, monitoring system, or control system
relating to recommended adjustments for one or more parameters of
the hydrocarbon extraction system 10 and/or may automatically
adjust one or more parameters of the hydrocarbon extraction system
10 based on the determined parameters and conditions of the
hydrocarbon extraction system 10 (e.g., via a control system).
Further, the additive management system 12 may enable precise
and/or targeted monitoring and/or control of parameters and
conditions throughout the hydrocarbon extraction system 10. In
order to monitor and/or control the one or more parameters and/or
conditions of the hydrocarbon extraction system 10, the additive
management system 12 may include sensors 14 (e.g., conductivity
probes, solid particulate sensors, temperature sensors, pressure
sensors, optical sensors, salinity sensors, water sensors, etc.),
chemical injection metering valves (CIMV) 16, hydrate inhibitor
regeneration systems 18, flow meters 20 (e.g., wet-gas flow meter,
multi-phase flow meter), fluid control devices 22, and control
systems 24.
[0018] As illustrated, the hydrocarbon extraction system 10 may
include one or more wellhead systems 26 with a wellhead 28 coupled
to a production tree 30 (e.g., Christmas tree). The wellhead
systems 26 couple to a well 32 that enables hydrocarbon extraction
(e.g., oil and/or natural gas) from a subterranean reservoir 34. As
the hydrocarbons exit the well 32, the wellhead system 26 may
direct the hydrocarbons to the surface through risers 36 for
collection and/or processing at a rig 38 or shore facility. In some
embodiments, multiple wells 32 may be part of the hydrocarbon
extraction system 10. These wells 32 and wellhead systems 26 may
couple to a manifold 40 with a jumper system 42 (e.g., jumper
cables, pipes, etc.). Accordingly, the rig 36 or shore facility may
then couple to the manifold 40 enabling fluid communication with
multiple wells 32.
[0019] During extraction operations, additional substances (e.g.,
water and sediment) may flow out of the wells 32 with the
hydrocarbon fluid flow. As the water moves with the hydrocarbons,
water (e.g., freezing water) and natural gas components may combine
to form hydrates due to high pressures and low temperatures in the
hydrocarbon extraction environment. However, as described below,
the additive management system 12 may monitor a hydrate condition
(e.g., hydrate formation) of the hydrocarbon extraction system 10
and may reduce, block, or inhibit formation of the hydrates by
injecting hydrate inhibitors (e.g., mono-ethylene glycol, methanol,
kinetic hydrate inhibitors, anti-agglomerates, etc.) in the
hydrocarbon extraction system 10.
[0020] As illustrated, in some embodiment of the disclosure, the
additive managements system 12 includes in some embodiment of the
disclosure, one more CIMVs 16 that inject one or more chemicals
into the fluid flow coming out of the wells 32. For example, one or
more CIMVs 16 may inject hydrate inhibitors (e.g., mono-ethylene
glycol, methanol, kinetic hydrate inhibitors, thermodynamic
inhibitors, anti-agglomerates), pH modifiers, and/or scale
inhibitors. In some embodiments, each wellhead system 26 (e.g.,
each branch of the Christmas tree 30 and/or each wellhead 28) may
include a respective CIMV 16 for chemical injection. In certain
embodiments, the manifold 40 may also include one or more CIMVs 16
that inject chemicals. In some embodiments, hydrocarbon extraction
system 10 may include CIMVs 16 in one or more of the wellhead
systems 26, the riser 36, the manifold 40, and/or other locations
in the hydrocarbon extraction system 10.
[0021] By including CIMVs 16 in each of the wellhead systems 26
and/or at other locations in the hydrocarbon extraction system 10,
the additive management system 12 is able to tailor/control (e.g.,
provide an appropriate amount--not too much, not too little of) the
flow of chemicals (e.g., hydrate inhibitors) in different areas of
the hydrocarbon extraction system 10. That is, the additive
management system 12 may be configured to control a plurality of
CIMVs 16, which may be disposed in different locations (e.g.,
different wellhead systems 26, the riser 36, the manifold 40, etc.)
of the hydrocarbon extraction system 10, and the additively
management system 12 may be configured to control two or more CIMVs
16 or each CIMV 16 of the plurality of CIMVs 16 differently to
provide a differential distribution of chemicals at the various
locations. For example, the additive management system 12 may cause
a first CIMV 16 to inject a first amount and/or first flow rate of
a chemical and may cause a second CIMV 16 to inject a second amount
and/or second flow rate of a chemical that is different from the
first amount and/or first flow rate. Further, as will be described
in more detail below, the additive management system 12 may monitor
hydrate formation for one or more locations of the hydrocarbon
extraction system 10 and may determine an amount and/or flow rate
of hydrate inhibitor to inject using each CIMV 16 of the one or
more locations, and the amount and/or flow rate of the hydrate
inhibitor may be specific for and/or optimized for the particular
location. For example, some wells 32 may produce or have higher
concentrations of water than other wells 32. In response, the
additive management system 12 may control one or more CIMVs 16 to
increase hydrate inhibitor injection at wellhead systems 26 that
experience significant water flow, while controlling one or more
different CIMVs 16 to reduce hydrate inhibitor injection at
wellhead systems 26 that produce small amounts of water. Moreover,
the additive management system 12 may account for environmental
conditions that enable hydrate formation such as temperature,
pressure, and salinity. For example, a first well 32 that is at a
lower temperature and/or higher pressure than a second well 32 may
receive more hydrate inhibitor injection than the second well 32,
because the temperatures and/or pressures at the first well 32 are
more likely to produce hydrates. In other words, the additive
management system 12 may control one or more CIMVs 16 to increase
hydrate inhibitor injection at wells 32 that experience
environmental conditions favorable to hydrate formation (e.g., low
temperatures and/or high pressures) and/or may control one or more
CIMVs 16 to reduce hydrate inhibitor injection at wells 32 that do
not.
[0022] As explained above, the additive management system 12 may
include a variety of sensors 14 (e.g., conductivity probes, solid
particulate sensors, temperature sensors, pressure sensors, optical
sensors, salinity sensors, water sensors, etc.) and flow meters 20
(e.g., wet-gas flow meters, multi-phase flow meters). The sensors
14 may measure one or more conditions and/or parameters of the
hydrocarbon extraction system 10. For example, as will be described
in more detail below, the sensors 14 may measure and/or generate
feedback relating to temperature, pressure, salinity, conductivity,
electromagnetic radiation, attenuation of one or more wavelengths
of light, water content (e.g., water cut) in a fluid flow, or any
other suitable parameter. Additionally, the flow meters 20 may
measure the flow rate of a fluid (e.g., flow). In some embodiments,
the multi-phase flow meters 20 may measure the full three-phase
performance over the entire gas volume fraction (GVF) and water
liquid ratio (WLR) ranges.
[0023] The sensors 14 and the flow meters 20 may be placed in
different locations in the hydrocarbon extraction system 10. For
example, in some embodiments, the sensors 14 and/or the flow meters
20 may be disposed in one or more of the wellhead systems 26 (e.g.,
each wellhead system 26), the manifold 40, the riser 36, the pipes
of the jumper system 42, and/or other locations in the hydrocarbon
extraction system 10. In certain embodiments, the sensors 14 and/or
flow meters 20 may be mounted on a pipe section downstream of a
bend, change in cross-sectional area, or other point to facilitate
a liquid rich area. In some embodiments, at least one sensor 14
and/or at least one flow meter 20 may be disposed proximate to
(e.g., upstream and/or downstream of) each CIMV 16.
[0024] By placing the sensors 14 and the flow meters 20 about
different locations of the hydrocarbon extraction system 10, the
additive management system 12 may measure or determine parameters
and/or conditions in the hydrocarbon extraction system 10 at each
location and may enable the control systems 24 to accurately
control injection of one or more chemicals (e.g., hydrate
inhibitors) at each location based on the parameters and/or
conditions at the respective location. That is, the amount and/or
flow rate of chemical injected may be individualized and/or
specific for each CIMV 16 and/or for each desired location of the
hydrocarbon extraction system 10 (e.g., each wellhead system 26,
the Christmas tree 30, the riser 36, the manifold 40, the jumper
system 42, or any combination thereof) based on the parameters
and/or conditions in a region proximate to each CIMV 16 and/or at
each desired location. For example, in some embodiments, the
control systems 24 may use feedback (e.g., signals) from the
sensors 14 and/or the flow meters 20 to determine a hydrate
condition for one or more locations (e.g., each location) having
the sensors 14 and/or flow meters 20, and the control systems 24
may determine an amount and/or flow rate of hydrate inhibitor to
inject using one or more CIMVs 16 (e.g., each CIMV 16) based at
least in part on the hydrate condition for the location proximate
to the respective CIMV 16.
[0025] FIG. 2 is a schematic view of an embodiment of an additive
management system 12. As illustrated, the additive management
system 12 includes one or more control systems 24 that communicate
with and/or control various sensors 14, flow meters 20, flow
control device 22 (e.g., choke), CIMVs 16, and hydrate inhibitor
regeneration systems 18. As will be explained in detail below, the
control system (e.g., controller) 24 includes one or more
processors 60 that execute instructions stored by one or more
memories 62 (e.g., tangible, non-transitory memory devices) to
control the additive management system 12. During operation, the
controller 24 may receive feedback from the various sensors 14,
such as one or more pressure sensors 64, one or more temperature
sensors 66, one or more conductivity probes (e.g., conductivity
sensors) 68, and/or one or more optical sensors 70. In some
embodiments, the pressure sensor 64 and the temperature sensor 66
may be combined (e.g., a pressure and temperature transmitter
(PTTx)). Additionally, the controller 24 may receive feedback from
the various flow meters 20 (e.g., wet-gas flow meter, multi-phase
flow meter). The controller 24 may be operatively coupled to the
sensors 14 and the flow meters 20 via any suitable communication
link, such as, for example, RS-422, RS-435, RS-485, Ethernet,
controller area network (CAN) (e.g., CAN bus, CANopen), optical
fibers, and/or wireless communication.
[0026] The controller 24 may determine measurement data (e.g.,
real-time or substantially real-time measurement data) based on the
feedback from the sensors 14 and/or the feedback from the flow
meters 20. For example, the measurement data may include one or
more conditions (e.g., environmental conditions) of the hydrocarbon
extraction system 10, such as pressure and/or temperature.
Additionally, the measurement data may include one or more flow
characteristics (e.g., flow parameters) of a fluid flow in the
hydrocarbon extraction system 10, such as flow rate (e.g. mass flow
rate), fluid density, salinity, composition, concentration, and so
forth. In particular, the controller 24 may determine flow
characteristics of the process fluid (e.g., the hydrocarbon flow)
upstream of a chemical injection point and/or flow characteristics
of the process fluid downstream of a chemical injection point after
mixing with the injected chemical. For example, as will be
described below in FIGS. 3-5, the additive management system 12 may
include sensors 14 and/or flow meters 20 that are disposed upstream
and/or downstream of a CIMV 16. In some embodiments, the controller
24 may use the feedback from the upstream and the downstream
sensors 14 and/or flow meters 20 to determine one or more flow
parameters. For example, the controller 24 may compare measurements
upstream and downstream to determine a ratio of an injected
chemical relative to water, content of water, etc.
[0027] Further, it should be noted that the controller 24 may
determine flow characteristics for one or more components of a
fluid flow. For example, the fluid flow may include water, oil,
gas, hydrogen sulfide, carbon dioxide, nitrogen, salts, and/or one
or more injected chemicals (e.g., hydrate inhibitors, pH modifiers,
scale inhibitors, etc.). In some embodiments, the controller 24 may
determine the flow rate (e.g., mass flow rate) and/or fluid density
for one or more components of the fluid flow.
[0028] In certain embodiments, the controller 24 may determine an
amount, proportion, percentage, or concentration of one or more
components in the fluid flow relative to the total fluid flow. For
example, the controller 24 may determine the water content (e.g.,
water cut) in the fluid flow, which may be a proportion,
percentage, or concentration of water relative to the fluid flow.
Additionally, the controller 24 may be configured to determine an
injected chemical content in the fluid flow, which may be a
proportion, percentage, or concentration of the injected chemical
relative to the fluid flow. However, it should be appreciated that
the controller 24 may be configured to determine the percentage of
any suitable component in the fluid flow. In some embodiments, the
controller 24 may determine the amount (e.g., proportion,
percentage, or concentration) of one or more components in the
fluid flow relative to the total fluid flow based on feedback from
one or more conductivity probes 68. For example, the one or more
conductivity probes 68 may be microwave open-ended coaxial probes.
In certain embodiments, the one or more conductivity probes 68 may
be conductivity probes as described in U.S. Pat. No. 6,831,470,
which is incorporated by reference in its entirety herein for all
purposes, and the controller 24 may use any of the methods and
techniques described in U.S. Pat. No. 6,831,470 for processing
signals from the conductivity probe to determine the amounts of the
components in a fluid. For example, in one embodiment, the
conductivity probe 68 may generate an alternating current
electrical signal (e.g., a reference signal), which may be
reflected by the fluid and detected by the conductivity probe
(e.g., reflected signal). The reflected signal may be compared to
the reference signal to determine the electromagnetic properties of
the fluid, which may be used to determine the amount of one or more
components in the fluid flow (e.g., using one or more algorithms,
models, look-up tables, etc.). For example, the amplitude
attenuation and phase shift between the reference signal and the
reflected signal may be used to derive the complex reflection
coefficient of the fluid flow, the fluid conductivity, and/or the
fluid permittivity.
[0029] In some embodiments, the controller 24 may determine the
amount (e.g., proportion, percentage, or concentration) of one or
more components in the fluid flow relative to the total fluid flow
based on feedback from one or more optical sensors 70. The optical
sensors 70 may be infrared, reflectance-type sensors. In some
embodiments, the optical sensors 70 may be configured to emit light
in the mid-wavelength infrared region, the long-wavelength infrared
region, and/or the far-infrared region. For example, the optical
sensors 70 may be configured to emit one or more wavelengths of
light in the range of 2 micrometers (.mu.m) to 50 .mu.m, 2.5 .mu.m
to 15 .mu.m, 3 .mu.m to 12 .mu.m, or any other suitable range. In
particular, the optical sensors 70 may be configured to emit light
at one or more wavelengths corresponding to absorption peaks of one
or more components in the fluid. For example, the optical sensor 70
may emit a first wavelength of light with an absorption peak for
water, a second wavelength of light with an absorption peak for an
injected chemical (e.g., hydrate inhibitor), a third wavelength of
light with an absorption peak for oil, and so forth. Additionally,
the optical sensors 70 may be configured to detect light (e.g., in
the mid-wavelength infrared region, the long-wavelength infrared
region, and/or the far-infrared region) after the emitted light has
interacted with the fluid flow. In some embodiments, the optical
sensors 70 may be configured to emit and detect a plurality of
wavelengths of light corresponding to various substances in the
fluid flow. The controller 24 may be configured to determine the
amounts of one or more components in the fluid flow based on the
detected light (e.g., reflected light).
[0030] Further, by using the conductivity probes 68 and/or the
optical probes 70, the controller 24 may be configured to detect
very low amounts of water in the fluid flow. For example, the
controller 24 may detect water in a fluid flow when the water
content is between approximately 10 parts per million (ppm) and 500
ppm, 30 ppm and 250 ppm, or 50 ppm and 100 ppm. In some situations,
the water content may not be measurable (e.g., water concentration
below the level measured by sensors). In these situations, the
controller 24 may use a modeling program (e.g., computer-based
modeling program, physics-based modeling program) to predict the
amount of water flowing through the hydrocarbon extraction system
10. Additionally, as will be described in more detail below, in
certain embodiments, the controller 24 may determine an amount,
proportion, percentage, or concentration of one or more components
in the fluid flow relative to one or more other components in the
fluid flow based on feedback from the conductivity probes 68,
feedback from the optical sensors 70, or both. For example, the
controller 24 may be configured to determine a ratio of an injected
chemical relative to water in the fluid flow.
[0031] Additionally, in some embodiments, the controller 24 may be
configured to receive feedback from the sensors 14 and/or the flow
meters 20 for verification and/or redundancy purposes. For example,
the controller 24 may be configured to receive feedback from a
conductivity probe 68 and feedback from an optical sensor 70 that
are disposed proximate to one another in the same general location
in the hydrocarbon extraction system 10 such that the flow
characteristics of the fluid as it flows by the conductivity probe
68 are substantially the same as the flow characteristics of the
fluid as it flows by the optical sensor 70. In this manner, if the
conductivity probe 68 fails or malfunctions, the controller 24 may
still determine parameters (e.g., the water content and injected
chemical content) based on feedback from the optical sensor 70 and
vice versa. In this manner, the conductivity probe 68 and the
optical sensor 70 may be redundant.
[0032] Further, the controller 24 may be configured to compare one
or more parameters determined based on feedback from the
conductivity probe 68 to the same one or more parameters determined
based on feedback from the optical sensor 70 to verify and/or
reduce uncertainty in the determined parameters. For example, the
controller 24 may compare a first value of the water content and a
first value of the injected chemical content determined based on
feedback from the conductivity probe 68 to a second value of the
water content and a second value of the injected chemical content,
respectively, determined based on feedback from the optical sensor
70. In some embodiments, the controller 24 may determine a
difference between a first value of a parameter determined from
feedback from the conductivity probe 68 and a second value of the
parameter determined from feedback from the optical sensor 70 and
may compare the difference to the threshold, which may be stored in
the memory 62. In certain embodiments, the controller 24 may
determine a level of certainty for the determined measurement based
on the comparison. In some embodiments, the controller 24 may be
configured to provide a warning or an alarm in response to a
determination that the difference is greater than the threshold,
which may be indicative of an undesirably high level of uncertainty
for the determined and/or may be indicative of a failure or
malfunction of the conductivity probe 68 and/or the optical sensor
70. For example, the controller 24 may be operatively coupled to a
user interface 72, which may include a display and/or a speaker,
and may cause the user interface 72 to provide the warning or
alarm.
[0033] Still further, in some embodiments, each CIMV 16 may include
a flow meter 20 to generate feedback relating to the chemical
injection flow rate. In one embodiments, each CIMV 16 may include
an ultrasonic flow meter 20 configured to measure a range of flow
rates between approximately 0.5 liters per hour to 26,500 liters
per hour, or more. As noted above, the controller 24 may control
each CIMV 16 to inject a chemical at a designated or assigned
injection rate. To verify that each CIMV 16 is injecting the
chemical at its respective assigned injection rate, the controller
24 may compare the assigned injection rate to an injection rate
determined based on feedback from the flow meter 20 of the
respective CIMV 16 to confirm or verify the actual injection rate
of the chemical. In some embodiments, the controller 24 may provide
a warning or alarm (e.g., via the user interface 72) if a
difference between the assigned injection rate and the determined
injection rate is greater than a threshold, which may be stored in
the memory 62. For example, a difference that is greater than the
threshold may be indicative of a failure or malfunction of the CIMV
16.
[0034] As noted above, the sensors 14 and the flow meters 20 may be
disposed about in a plurality of different locations of the
hydrocarbon extraction system 10. To enable targeted monitoring
and/or control of parameters and conditions of the hydrocarbon
extraction system 10 in the different locations, the controller 24
may be configured to associate feedback from each sensor 14 and
feedback from each flow meter 20 with the location of the
respective sensor 14 or flow meter 20. For example, in some
embodiments, each sensor 14 and each flow meter 20 may be coupled
to the controller 24 via an individual channel or a separate pinout
in a multibus, and the controller 24 may determine the location of
the feedback from each sensor 14 and each flow meter 20 based on
the channel or pinout from which the controller 23 received the
feedback. In certain embodiments, one or more of the sensors 14 and
one or more of the flow meters 20 may include a tag or memory
device 73, which may be configured to store information about the
respective sensor 14 or flow meter 20. For example, the tag or
memory device 73 may store identification information (e.g., an
identification number, a unique identification number, etc.) and/or
location information. The sensors 14 and the flow meters 20 may be
configured to transmit the information from the tag or memory
device 73 to the controller 24 with the generated feedback, and the
controller 24 may determine the location of the sensors 14 and the
flow meters 20, and therefore the generated feedback, based on the
information. In some embodiments, the memory 62 may store a lookup
table or database linking the information to the respective
location, and the controller 24 may access the lookup table or
database using the information to determine the location. It should
be appreciated that the above-mentioned examples are not intended
to be limiting, and any suitable techniques for determining the
location of the sensors 14 and the flow meters 20 may be used.
[0035] The controller 24 may use the determined measurement data to
determine one or more hydrate conditions for the hydrocarbon
extraction system 10. In some embodiments, the controller 24 may
determine a plurality of hydrate conditions for a plurality of
locations about the hydrocarbon extraction system 12 using the
measurement data from the plurality of sensors 14 and flow meters
20 and the information stored in the tags 73 of the sensors 14 and
flow meters 20. For example, the controller 24 may determine a
hydrate condition for each wellhead system 26, a hydrate condition
for one or more locations about the riser 36 (e.g., at different
depths along the riser 36), a hydrate condition for the manifold
40, a hydrate condition for one or more locations about the pipes
of the jumper system 42, and so forth.
[0036] In order to determine the one or more hydrate conditions
(e.g., whether the water in the fluid flow will form or is likely
to form hydrates), the controller 24 may be configured to use the
measurement data with one or more modeling programs, algorithms,
hydrate formation curves, look-up tables, databases, or any
combination thereof. For example, the controller 24 may include one
or more modeling programs, algorithms, hydrate formation curves,
look-up tables, and/or databases stored in the memory 62 that the
processor 60 executes or accesses to determine hydrate formation.
In some embodiments, the controller 24 may communicate with another
computer(s) 74 that include one or more processors 76 and one or
more memories 78 that run the modeling programs, algorithms,
hydrate formation curves, look-up tables, and/or databases. In some
embodiments, the computer 74 may receive the measurement data
directly from the sensors 14, flow meters 20, etc. and/or from the
controller 24.
[0037] In particular, the modeling programs, algorithms, hydrate
formation curves, look-up tables, and/or databases may predict or
estimate the likelihood of hydrate formation (e.g., the hydrate
condition) based on different values of at least one parameter of
the hydrocarbon extraction system 10. For example, the modeling
programs, algorithms, hydrate formation curves, look-up tables,
and/or databases may predict or estimate the likelihood of hydrate
formation based on one or more parameters of a hydrocarbon fluid
flow, such as temperature, pressure, flow rate (e.g., flow rate of
water, flow rate of oil, flow rate of gas), fluid density,
salinity, composition (e.g., relative amounts of oil, gas, water,
carbon dioxide, hydrogen sulfide, nitrogen, hydrate inhibitor, or
any other component), water content, and/or hydrate inhibitor
content. In some embodiments, the modeling programs, algorithms,
hydrate formation curves, look-up tables, and/or databases may
define one or more boundary conditions for the one or more
parameters such that values of the one or more parameters (e.g.,
alone or in combination with other parameters) that meet or violate
the one or more boundary conditions are likely to result in hydrate
formation.
[0038] In certain embodiments, the memory 62 and/or the memory 78
may store a plurality of modeling programs, algorithms, hydrate
formation curves, look-up tables, and/or databases that each
predict or estimate the likelihood of hydrate formation based on a
different parameter or a different combination of parameters. By
way of example, the memory 62 may store a first modeling program
that estimates the likelihood of hydrate formation based on
temperature, a second modeling program that estimates the
likelihood of hydrate formation based on temperature and pressure,
a third modeling program that estimates the likelihood of hydrate
formation based on temperature, pressure, and water content, and a
fourth modeling program that estimates the likelihood of hydrate
formation based on temperature, pressure, water content, and
hydrate inhibitor content. In such embodiments, the controller 24
may be configured to select a modeling program, algorithm, hydrate
formation curve, look-up table, and/or database based on the
parameters determined by the controller 24 using the feedback from
the sensors 14 and flow meters 20. For example, the controller 24
may select the second modeling program if the controller 24
determines pressure and temperature and may select the third
modeling program if the controller 24 determines pressure,
temperature, and water content. In some embodiments, the memory 62
and/or the memory 78 may also store a level of certainty for each
of the plurality of modeling programs, algorithms, hydrate
formation curves, look-up tables, and/or databases, which may
increase with the number of parameters used by the respective
modeling program, algorithm, hydrate formation curve, look-up
table, or database. That is, the determination of hydrate formation
may have a higher level of certainty when more information (e.g.,
more parameters) is used. Further, in some embodiments, the memory
62 may store a plurality of modeling programs that model different
states of the hydrocarbon extraction system 10. For example, the
modeling programs may model start-up, steady-state, look ahead
scenarios (e.g., planned shut-in, unplanned shut-in, shut down,
etc.), among others. Further, in some embodiments, the modeling
programs may include a real-time transient production simulator
configured to enable presentation of flow variables in real time
between points of measurements. In some embodiments, the real-time
transient production simulator can be used for forecasting and
providing what-if scenarios from current conditions, yielding live
estimates of cool-down times, no-touch times, and other information
for hydrate management. Further, alarms (e.g., alarms triggered by
the real-time transient production simulator, alarms triggered by
the modeling programs, etc.) may be configured to notify control
room operators of potential operational issues before they
occur.
[0039] In operation, the controller 24 (or the computer 74) may
determine the value of at least one parameter of the hydrocarbon
extraction system 10 based on feedback from at least one sensor 14,
feedback from at least one flow meter 20, or both, and may use the
value of the at least one parameter in at least one modeling
program, algorithm, hydrate formation curve, look-up table, or
database to determine the hydrate conditions (e.g., the likelihood
of hydrate formation). As noted above, in some embodiments, the
controller 24 may select a modeling program, algorithm, hydrate
formation curve, look-up table, or database based on the parameters
determined by the controller 24. Additionally, if the controller 24
determines that hydrate formation is likely, the controller 24 may
determine an amount and/or flow rate of a hydrate inhibitor to
inject to reduce or block hydrate formation. In some embodiments,
the controller 24 may use the modeling program, algorithm, hydrate
formation curve, look-up table, and/or database to determine the
amount and/or flow rate of the hydrate inhibitor to inject based on
the hydrate condition. For example, the controller 24 may input one
or more values of one or more parameters into a modeling program,
and the modeling program may output both the hydrate condition and
an amount and/or flow rate of hydrate inhibitor to inject based on
the hydrate condition.
[0040] In some embodiments, the controller 24 may be configured to
execute one or more algorithms to determine an amount and/or a flow
rate of hydrate inhibitor to inject based on the hydrate condition.
For example, in one embodiment, the controller 24 may be configured
to use the Hammerschmidt equation, which is provided below:
x = d .times. M .times. 100 K + d .times. M , ##EQU00001##
where x is the concentration of the hydrate inhibitor in weight
percent, d is the depression of the hydrate point in degrees
Celsius, M is the molecular weight of the hydrate inhibitor, and K
is a dimensionless constant for the particular hydrate inhibitor.
In particular, the controller 24 may determine a desired depression
of the hydrate point (i.e., d) to reduce or block hydrate formation
based on the determined hydrate condition, and the controller 24
may determine (e.g., solve for) the concentration of hydrate
inhibitor to inject based on the desired depression of the hydrate
point. In some embodiments, the controller 24 may determine the
flow rate (e.g., mass flow rate) of hydrate inhibitor to inject
based on the determined concentration of hydrate inhibitor and the
flow rate (e.g., mass flow rate) of water in the fluid flow. The
hydrate inhibitor may be become diluted after it is injected into
the hydrocarbon fluid flow and mixes with other substances, which
may decrease the concentration of the hydrate inhibitor and may
decrease the effectiveness of the hydrate inhibitor. The diluted
hydrate inhibitor may be referred to as rich hydrate inhibitor,
while the higher purity hydrate inhibitor (e.g., the hydrate
inhibitor reclaimed using the hydrate inhibitor regeneration
systems 18 and/or the hydrate inhibitor injected using the CIMVs
16) may be referred to as lean hydrate inhibitor. In some
embodiments, x may be the concentration of the rich hydrate
inhibitor, and the controller 24 may determine the mass flow of
hydrate inhibitor to inject based on the mass flow of water, the
concentration of the rich hydrate inhibitor, and the concentration
of lean hydrate inhibitor, which may be known or determined from
the hydrate inhibitor regeneration systems 18. For example, the
controller 24 may determine the mass flow of hydrate inhibitor to
inject using the following equation:
m I = m W .times. ( x x L - x ) , ##EQU00002##
where m.sub.I is the mass flow of the hydrate inhibitor (e.g.,
kg/d), m.sub.W is the mass flow of water (e.g., kg/d), x is the
concentration of the rich hydrate inhibitor (e.g., weight percent),
and x.sub.L is the concentration of the lean hydrate inhibitor
(e.g., mass percent).
[0041] Further, the controller 24 and/or the computer 74 may
determine hydrate condition and the amount and/or flow rate of
hydrate inhibitor to inject for a plurality of locations about the
hydrocarbon extraction system 10. For example, the controller 24
may determine hydrate condition and the amount and/or flow rate of
hydrate inhibitor to inject for each area or region including a
CIMV 16. In some embodiments, the controller 24 (e.g., using the
modeling programs) may be configured to forecast or extrapolate
measurement data (e.g., determined from the sensors 14 and the flow
meters 20) to determine hydrate conditions and/or amounts and/or
flow rates of hydrate inhibitor to inject for other locations of
the hydrocarbon extraction system 10 that do not include the
sensors 14 and/or the flow meters 20. However, the forecasted or
extrapolated information may have a lower level of certainty than
the measurement data, but may be helpful in controlling hydrate
conditions throughout the entire hydrocarbon extraction system 10
with a limited number of sensors 14.
[0042] If the controller 24 and/or the computer 74 determines that
hydrate formation is likely or will be likely in a future scenario,
the controller 24 and/or computer 74 may advise or warn an operator
through the user interface 72. In particular, the controller 24
and/or the computer 72 may cause the user interface 72 to display
an indication that hydrate formation is likely and to display a
recommended amount and/or flow rate of hydrate inhibitor to inject
to reduce or block the hydrate formation. As will be appreciated,
in embodiments in which the additive management system 12
determines a hydrate condition and an amount and/or flow rate of
hydrate inhibitor to inject for a plurality of locations about the
hydrocarbon extraction system 10, the user interface 72 may also
display an indication of the location for each hydrate condition
and recommendation for the amount and/or flow rate of hydrate
inhibitor to inject. In some embodiments, the user interface 72 may
also display a level of certainty for the respective hydrate
condition and/or recommended amount and/or flow rate of hydrate
inhibitor to inject. For example, the level of certainty may be
determined by the controller 24 and may be based on a level of
certainty of the modeling program (or hydrate formation curve,
look-up table, algorithm, database, etc.) used, as well as any
redundant measurements (e.g., feedback from the conductivity probe
68 and feedback from the optical sensor 70, etc.) used by the
controller 24. The operator may then provide instructions to the
additive management system 12 to increase, start, decrease, and/or
stop hydrate inhibitor injection through one or more CIMVs 16. In
particular, the operator may provide instructions to the additive
management system 12 to adjust hydrate inhibitor injection through
the one or more CIMVs 16 using the recommended hydrate inhibitor
injection settings (e.g., flow rate, amount, and/or location)
determined by the controller 24 and/or the computer 74.
[0043] In some embodiments, the additive management system 12 may
automatically adjust hydrate inhibitor injection based on sensor 14
and flow meter 20 feedback. In particular, the additive management
system 12 may control one or more CIMVs 16 to automatically adjust
hydrate inhibitor injection based on a determined amount and/or
flow rate of hydrate inhibitor to inject to reduce or block a
determined hydrate condition. Once the CIMVs 16 are activated, the
controller 24 and/or computer 74 may monitor the amount of hydrate
inhibitor injected into the fluid flow and may update the modeling
programs based on the amount of hydrate inhibitor injected. For
example, the controller 24 and/or the computer 74 may continue to
monitor feedback from the sensors 14 and the flow meters 20 to
determine updated hydrate conditions and to determine updated
amounts and/or flow rates of hydrate inhibitor to inject. In some
embodiments, the modeling programs may be smart or learning
modeling programs that may be configured to learn based on
historical data.
[0044] In some embodiments, the additive management system 12 may
also be configured to monitor the hydrate inhibitor regeneration
system 18. During operation, the hydrate inhibitor regeneration
system 18 removes hydrate inhibitor from the fluid flow when it
reaches the rig 38. As noted above, the concentration of the
hydrate inhibitor entering the hydrate inhibitor regeneration
system 18 may be rich from dilution with other substances, which
reduces the effectiveness of the hydrate inhibitor. Thus, by
separating the hydrate inhibitor from the fluid flow, the hydrate
inhibitor regeneration system 18 may recover lean hydrate inhibitor
that has a higher concentration than the rich hydrate inhibitor,
which may reduce the amount of hydrate inhibitor used. In some
embodiments, the hydrate inhibitor regeneration system 18 may be
configured to determine the concentration of the rich and lean
hydrate inhibitor. As noted above, by measuring the concentration
(e.g., strength, potency) of the hydrate inhibitor before and after
injection (e.g., rich and lean concentrations), the controller 24
may determine how much hydrate inhibitor should be injected to
block hydrate formation. The controller 24 and/or computer 74 may
also receive input from the hydrate inhibitor regeneration system
18 indicating how much hydrate inhibitor is available for use
(e.g., the rich and lean hydrate inhibitor tank volume
measurements) and the concentration (e.g., potency) of the hydrate
inhibitor. This information may likewise be fed into the modeling
programs enabling the modeling programs to provide feedback to an
operator about whether there is enough hydrate inhibitor for future
hydrate prevention scenarios (e.g., shut down, start up), warn a
user to order more hydrate inhibitor, etc.
[0045] In some embodiments, the additive management system 12 may
include flow control devices 22 (e.g. chokes) that facilitate
mixing between the hydrate inhibitor and the fluid flowing out of
the well 32. In some embodiments, the controller 24 may receive
feedback from a sensor 14 and/or flow meter 20 that measures the
concentration of hydrate inhibitor. If the measured concentration
is more or less than the expected concentration based on feedback
from the CIMV 16, the controller 24 may adjust the flow control
device 22 to increase mixing between the hydrate inhibitor and the
fluid flow.
[0046] FIG. 3 is a schematic view of an embodiment of the additive
management system 12 coupled to a wellhead system 26. As explained
above, the additive management system 12 enables precise and/or
targeted control of the hydrate formation throughout the
hydrocarbon extraction system 10, which reduces the amount of
hydrate inhibitor used as well as the hydrate inhibitor
infrastructure. Accordingly, FIG. 3 illustrates hydrate inhibitor
injection into a specific wellhead system 26.
[0047] The additive management system 12 includes sensors 14, a
flow meter 20, and a CIMV 16 that couple to a controller 24. In
operation, the flow meter 20 measures the flow rate of fluid
exiting the well 32. In some embodiments, the flow meter 20 may be
a wet-gas flow meter or multi-phase flow meter capable of measuring
a fluid flow rate as well as the concentration of water in the
fluid flow. In addition, the controller 24 receives feedback from
additional sensors 14. For example, the additive management system
12 may include a pressure sensor, a temperature sensor, a
conductivity probe, a solid particulate sensor, and a salinity
sensor among others that couple to the wellhead system 26. In some
embodiments, the sensor 14 may be a conductivity probe 68 capable
of measuring the concentrations of one or more components in the
fluid flow. For example, in some embodiments, the conductivity
probe 68 may be configured to measure low concentrations of water
in the fluid flow. In certain embodiments, the sensor 14 may be an
optical sensor 70, which may be configured to measure the
concentrations of one or more components in the fluid flow, such as
the concentration of water. Moreover, in some embodiments, the
conductivity probe 68, the optical sensor 70, and/or a
wet-gas/multiphase flow meter 20 may be placed before the CIMV 16
to block inclusion of the hydrate inhibitor in the measurement of
water content of the fluid flow.
[0048] In operation, the controller 24 combines the information
from the flow meter 20 (e.g., wet-gas flow meter, multi-phase flow
meter) and the sensors 14 to determine how much hydrate inhibitor
should be injected into the fluid flow. As explained above, the
flow meter 20 measures the flow rate of fluid exiting the well 32
while the sensors 14 measure one or more environmental conditions
(e.g., pressure, temperature, water content, salinity, etc.). In
some embodiments, the additive management system 12 may include a
sensor 14 (e.g., conductivity probe 68 and/or optical sensor 70)
configured to measure low concentrations of water in the fluid
flow. In order to increase accurate measurement of the water
content, the sensor 14 may be placed upstream from the CIMV 16 to
block inclusion of the hydrate inhibitor in the water content
measurement. In some embodiments, the additive management system 12
may also provide redundant measurement of hydrate inhibitor
injection into the fluid flow. For example, the additive management
system 12 may receive feedback from the CIMV 16 as well as a flow
meter 20 (e.g., an ultrasonic flow meter) to measure the flow rate
of the injected hydrate inhibitor. As noted above, the controller
24 may be configured to compare the flow rate measured by the flow
meter 20 to the set injection rate of the CIMV 16 to determine
whether the CIMV 16 is injecting the hydrate inhibitor at the
correct rate. The flow meter 20 may be disposed in the CIMV 16, or
may be disposed proximate to the CIMV 16 and directly upstream or
downstream of the injected hydrate inhibitor such that the flow
meter 20 receives the hydrate inhibitor before the hydrate
inhibitor is injected into the fluid flow. In certain embodiments,
the additive management system 12 may also include a sensor 14
(e.g., a conductivity probe 68, an optical sensor 70, etc.) to
measure the concentration of hydrate inhibitor entering the fluid
flow. In some embodiments, the flow meter 20 may be configured to
measure the concentration of hydrate inhibitor entering the fluid
flow. As explained above, by measuring the concentration (e.g.,
strength, potency) of the hydrate inhibitor before injection, the
modeling programs are able to determine how much hydrate inhibitor
should be injected to block hydrate formation. While FIG. 3
illustrates sensors 14 and the flow meter 20 coupled to the
Christmas tree 30 (e.g., production tree), the sensors 14 and flow
meter 20 may be coupled to other areas of the wellhead system 26
(e.g., wellhead 28, jumper system 42, etc.).
[0049] FIG. 4 is a schematic view of an embodiment of the additive
management system 12 coupled to a wellhead system 26. The additive
management system 12 includes sensors 14, a flow meter 20, and a
CIMV 16 that couple to a controller 24. In some embodiments, the
additive management system 12 may include a sensor 14 (e.g., a
conductivity probe 68 and/or an optical sensor 70) downstream of
the CIMV 16 to measure one or more flow parameters of the fluid
flow after mixing with a chemical injected via the CIMV 16. For
example, the conductivity probe 68 and/or an optical sensor 70 may
be configured to determine the water content, the hydrate inhibitor
content, or an injected chemical content, as described above. In
certain embodiments, the conductivity probe 68 and/or the optical
sensor 70 may be configured to generate feedback that may be used
by the controller 24 to determine a ratio of an injected chemical
relative to water in the fluid flow. For example, the conductivity
probe 68 may measure the electromagnetic properties of the mixed
fluid (e.g., downstream of the CIMV 16) at two different
electromagnetic frequencies. The controller 24 may be configured to
compare signals from the conductivity probe 68 at each frequency to
determine a ratio of an injected chemical relative to water in the
fluid flow based on the frequency-dependence of the measured
electromagnetic properties. The controller 24 may be configured to
use one or more algorithms (e.g., to calculate the fluid
conductivity, fluid permittivity, and/or complex reflection
coefficient), look-up tables (e.g., including empirical data),
models, and so forth to derive the ratio of the injected chemical
relative to water based on the electromagnetic properties. In some
embodiments, the controller 24 may compare signals at different
wavelengths (e.g., two or more wavelengths) from the optical sensor
70 to determine a ratio of an injected chemical relative to water
in the fluid flow. As will be described in more detail below, the
controller 24 may be configured to adjust the injection rate of an
injected chemical or to provide a recommendation to adjust the
injection rate of an injected chemical to achieve a desired ratio
of injected chemical to water in the fluid flow.
[0050] FIG. 5 is a schematic view of an embodiment of a section of
the additive management system 12 coupled to a wellhead system 26.
The additive management system 12 includes sensors 14, a flow meter
20, a flow control device 22, and a CIMV 16 that couple to a
controller 24. As illustrated, the additive management system 12
includes sensors 14 upstream and downstream of the CIMV 15. For
example, the additive management system 12 may include an upstream
conductivity probe 68 and a downstream conductivity probe 68 and/or
an upstream optical sensor 70 and a downstream optical sensor 70.
In this manner, the controller 24 may be configured to determine
the water content in the fluid upstream of the CIMV 16, the water
content in the fluid downstream of the CIMV 16, and the injected
chemical content (e.g., the hydrate inhibitor content) in the fluid
downstream of the CIMV 16. Further, the controller 24 may be
configured to determine a ratio of an injected chemical relative to
water in the fluid flow. For example, the controller 24 may
determine or derive the electromagnetic properties of water based
on feedback (e.g., a first signal) from an upstream conductivity
probe 68. Additionally, the controller 24 may be configured to
determine or derive the electromagnetic properties of a
water-chemical mixture based on feedback (e.g., a second signal)
from a downstream conductivity probe 68. Further, the controller 24
may be configured to compare the electromagnetic properties of the
water with the electromagnetic properties of the water-chemical
mixture to determine a ratio of injected chemical relative to
water. Additionally or alternatively, the controller 24 may receive
signals at multiple wavelengths from a downstream optical sensor
70, and the controller 24 may analyze the signals at the multiple
wavelengths to determine a ratio of injected chemical relative to
water. For example, the upstream optical sensor 70 and/or the
downstream optical sensor 70 may each be configured to emit at
least a first wavelength corresponding to an absorption peak of
water and a second wavelength corresponding to an absorption peak
of the injected chemical. In some embodiments, the controller 24
may be configured to determine the ratio of the injected chemical
to water based on the measured absorbance at each wavelength, the
path lengths of water and the injected chemical, and the absorption
coefficients of water and the injected chemical (e.g., using
Beer-Lambert's law).
[0051] In some embodiments, the additive management system 12 may
include a flow control device 22. As explained above, the flow
control devices 22 (e.g. chokes) facilitate mixing between the
injected chemical (e.g., hydrate inhibitor) and the fluid flowing
out of the well 32. In some embodiments, the controller 24 may use
feedback from a sensor 14 (e.g., the conductivity probe 68 and/or
the optical sensor 70) downstream from the flow control device 22
to determine whether the injected chemical has mixed adequately
with the fluid flow. If mixing is inadequate, the controller 24 may
adjust the flow control device 22 to increase mixing between the
fluid flow and the injected chemical.
[0052] FIG. 6 is a cross-sectional view of an embodiment of a
hanger 100 (e.g., a tubing hanger) of the hydrocarbon extraction
system 10. The tubing hanger 100 may include a production bore 102
(e.g., a main bore) and an outlet passage 104 that branches off
from the production bore 102. Additionally, the tubing hanger 100
may include a wireline plug 106 configured to seal the production
bore 102 above the outlet passageway 104. Further, the tubing
hanger 100 may include a CIMV 16 configured to inject a chemical
into the outlet passageway 104. To measure one or more properties
of the fluid flow (e.g., water content) upstream of the injection
point, the tubing hanger 100 may include one or more sensors 14
(e.g., a conductivity probe 68) upstream of the injection point. In
particular, a conductivity probe 68 may be disposed within the
production bore 102. In some embodiments, the conductivity probe 68
may be disposed within the production bore 102 below the wireline
plug 106. However, it should be appreciated that the additive
management system 12 may include the sensors 14 in any suitable
location about the tubing hanger 100, such as in the outlet
passageway 104 upstream of the CIMV 16 and/or in the outlet
passageway 104 downstream of the CIMV 16. Providing sensors 14 in
the tubing hanger 100 may be desirable because the sensors 14 may
be removable or retrievable with the tubing hanger 100.
[0053] FIG. 7 is an embodiment of a method 120 for controlling
hydrate formation of the hydrocarbon extraction system 10. The
method 120 may be a computer-implemented method. For example, one
or more steps of the method 120 may be executed using the
controller 24 (e.g., the processor 60) and/or the computer 74. The
method 120 may include receiving (block 122) feedback from one or
more sensors 14 and/or one or more flow meters 20 disposed in
hydrocarbon extraction system 10. Additionally, the method 120 may
include determining (block 124) one or more parameters based on the
feedback. For example, the controller 24 may be configured to
determine one or more parameters of a fluid flow in the hydrocarbon
extraction system 10, such as pressure, temperature, flow rate,
fluid density, composition (e.g., water content, injected chemical
content, hydrate inhibitor content, a ratio of an injected chemical
to water, etc.), or any other suitable parameter. Further, the
method 120 may include determining (block 126) a hydrate condition
based on the one or more parameters. In particular, the controller
24 may estimate the likelihood of hydrate formation based on the
one or more parameters using the one or more modeling programs,
hydrate formation curves, algorithms, database, and/or look-up
tables described in detail above. Additionally, the method 120 may
include determining (block 128) an amount and/or a flow rate (e.g.,
mass flow) of a hydrate inhibitor to inject based on the hydrate
condition. In particular, the controller 24 may determine an amount
and/or flow rate of a hydrate inhibitor to inject to reduce or
block hydrate formation. The controller 24 may determine the amount
and/or flow rate using the modeling programs and/or one or more
algorithms, as noted above. Further, as noted above, the controller
24 may be configured to determine a hydrate condition and an amount
and/or flow rate of hydrate inhibitor to inject for a plurality of
locations about the hydrocarbon extraction system 10.
[0054] Additionally, in some embodiments, the method 120 may
include providing (block 130) an indication of the amount and/or
flow rate of hydrate inhibitor to inject. For example, the
controller 24 may cause the user interface 72 to display the
indication. In this manner, an operator may view the recommended
injection settings and may manually adjust the CIMVs 16 to the
recommended injection settings or may provide inputs to the
controller 12 to adjust the CIMVs 16 to the recommended settings.
In certain embodiments, the method 120 may include adjusting (block
132) the amount and/or flow rate of the hydrate inhibitor to
inject. For example, the controller 24 may control the CIMVs 16 to
adjust the amount and/or flow rate in a closed-loop control.
Further, the method 120 may continue receiving feedback (block
122), determining parameters (block 124), determining the hydrate
condition (block 126), and determining an amount and/or flow rate
of hydrate inhibitor (block 128).
[0055] FIG. 8 is an embodiment of a method 150 for controlling a
ratio of an injected chemical relative to water (e.g.,
ratio=chemical/water) in a fluid flow of the hydrocarbon extraction
system 10. The method 150 may be a computer-implemented method. For
example, one or more steps of the method 150 may be executed using
the controller 24 (e.g., the processor 60) and/or the computer 74.
The method 150 may include determining (block 152) a ratio of an
injected chemical relative to water in a fluid flow. In particular,
the controller 24 may determine the ratio based at least in part on
two electromagnetic radiation (EMR) signals. For example, the
controller 24 may receive two EMR signals at two different
frequencies from a conductivity probe 68 downstream of an injection
point (e.g., downstream of a CIMV 16) and may determine the ratio
of the injected chemical relative to water based on a comparison of
the electromagnetic properties in the fluid in the first EMR signal
at the first frequency and the electromagnetic properties in the
fluid in the second EMR signal at the second frequency. In some
embodiments, the controller 24 may receive a first EMR signal from
a conductivity probe 68 upstream of an injection point and a second
EMR signal from a conductivity probe 68 downstream of the injection
point, and the controller 24 may determine the ratio by comparing
electromagnetic properties of the fluid in the first and second EMR
signals. Further, in some embodiments, the controller 24 may
receive a first EMR signal (e.g., a mid-infrared signal) from an
optical sensor 70 upstream of an injection point and a second EMR
signal (e.g., mid-infrared signal) from an optical sensor 70
downstream of the injection point, and the controller 24 may
determine the ratio based at least in part on the absorbance of the
two EMR signals, the absorption coefficient of the injected
chemical, the absorption coefficient of water. In certain
embodiments, the controller 24 may receive EMR signals (e.g.,
mid-infrared signals) at multiple wavelengths (e.g., at least two
wavelengths) from an optical sensor 70 downstream of an injection
point, and the controller 24 may determine the ratio based at least
in part on the absorbance of the EMR signals at the multiple
wavelengths, the absorption coefficient of the injected chemical,
the absorption coefficient of water. Additionally, in some
embodiments, the controller 24 may be configured to measure a
property of the chemical prior to injection and may be configured
to use the measured property in the determination of the ratio. In
one embodiment, the controller 24 may measure the water content of
the injected chemical prior to injection. For example, as noted
above, the lean hydrate inhibitor (e.g., MEG) may still include
some water after the regeneration process, so it may be desirable
to determine the water content in the hydrate inhibitor prior to
injection.
[0056] Additionally, the method 150 may include determining (block
154) whether the ratio is within a desired threshold or threshold
range. For example, the threshold range may be between
approximately 1:1000 and 1000:1, 1:500 and 500:1, 1:250 and 250:1,
1:100 and 100:1, 1:75 and 75:1, 1:50 and 50:1, 1:25 and 25:1, 1:10
and 10:1, 1:5 and 5:1, or any other suitable range. In one
embodiment, the threshold (e.g., upper threshold or lower
threshold) may be 1:1. In some embodiments, the threshold or
threshold range may be based on the type of injected chemical. By
way of example, MEG may have a threshold range that is between
approximately 1:10 and 10:1, and kinetic hydrate inhibitors may
have a threshold range between approximately 1:1 and 1:1000.
Accordingly, the controller 24 may be configured to select a
threshold range from the memory 62 based on the type of injected
chemical.
[0057] Further, in some embodiments, the method 150 may include
providing (block 156) an indication to adjust the injected chemical
rate in response to a determination that the ratio is not within a
desired threshold or threshold range. For example, the controller
24 may cause the user interface 72 to display the indication. In
some embodiments, the controller 24 may determine an amount and/or
flow rate of chemical to inject to achieve the desired ratio, and
the controller 24 may cause the user interface 72 to display the
recommended injection setting (e.g., amount and/or flow rate).
Additionally, in some embodiments, the method 150 may include
adjusting (block 158) the amount and/or flow rate of the injected
chemical to achieve the desired ratio. For example, the controller
24 may control one or more CIMVs 16 to adjust an amount and/or flow
rate of the injected chemical.
[0058] While the invention may be susceptible to various
modifications and alternative forms, specific embodiments have been
shown by way of example in the drawings and have been described in
detail herein. However, it should be understood that the invention
is not intended to be limited to the particular forms disclosed.
Rather, the invention is to cover all modifications, equivalents,
and alternatives falling within the spirit and scope of the
invention as defined by the following appended claims.
* * * * *