U.S. patent application number 12/477190 was filed with the patent office on 2010-03-11 for subsea fluid sampling and analysis.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to Graham Birkett, Kentaro Indo, Akira Kamiya, Jonathan Machin, Lars Mangal, Julie Morgan, Oliver C. Mullins, Gary Oddie, Pascal Panetta, Morten Stenhaug, Stephane Vannuffelen, Ricardo Vasques, Tsutomu Yamate.
Application Number | 20100059221 12/477190 |
Document ID | / |
Family ID | 39638145 |
Filed Date | 2010-03-11 |
United States Patent
Application |
20100059221 |
Kind Code |
A1 |
Vannuffelen; Stephane ; et
al. |
March 11, 2010 |
SUBSEA FLUID SAMPLING AND ANALYSIS
Abstract
Subsea apparatus and a method for sampling and analysing fluid
from a subsea fluid flowline proximate a subsea well is provided,
wherein the apparatus comprises at least one housing located in
close proximity to said subsea fluid flowline; at least one fluid
sampling device located in the housing in fluid communication with
a said subsea fluid flowline for obtaining a sample of fluid from
the subsea fluid flowline; at least one fluid processing apparatus
located in the housing in fluid communication with said subsea
fluid flowline for receiving and processing a portion of the fluid
flowing through said fluid flowline or in fluid communication with
the fluid sampling device, for processing the sample of fluid
obtained from the subsea fluid flowline for analysis, while keeping
the sample of fluid at subsea conditions; a fluid analysis device
located in the housing, the fluid analysis device being in fluid
communication with the fluid processing device and/or with the
fluid sampling device, the fluid analysis device being used for
analysing said sample of fluid or the processed sample of fluid to
generate data relating to a plurality of properties of said sample
of fluid and communicating said data to a surface data processor or
to at least one other subsea apparatus; and conveying means
included in the housing for conveying the housing means from one
subsea fluid flowline to another subsea fluid flowline or for
conveying the housing to the surface.
Inventors: |
Vannuffelen; Stephane;
(Clamart, FR) ; Vasques; Ricardo; (Bailly, FR)
; Yamate; Tsutomu; (Kanagawa, JP) ; Kamiya;
Akira; (Kanagawa, JP) ; Indo; Kentaro;
(Edmonton, CA) ; Oddie; Gary; (Cambridgeshire,
GB) ; Machin; Jonathan; (Aberdeenshire, GB) ;
Morgan; Julie; (South Guildford, AU) ; Stenhaug;
Morten; (Sandsli, NO) ; Birkett; Graham;
(Houston, TX) ; Mullins; Oliver C.; (Ridgefield,
CT) ; Mangal; Lars; (Croissy Sur Seine, FR) ;
Panetta; Pascal; (Paris, FR) |
Correspondence
Address: |
SCHLUMBERGER
200 GILLINGHAM LANE MD 200-9
SUGAR LAND
TX
77478
US
|
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
Sugar Land
TX
|
Family ID: |
39638145 |
Appl. No.: |
12/477190 |
Filed: |
June 3, 2009 |
Current U.S.
Class: |
166/264 ;
166/335; 166/339 |
Current CPC
Class: |
E21B 49/081 20130101;
E21B 41/04 20130101; E21B 49/086 20130101 |
Class at
Publication: |
166/264 ;
166/335; 166/339 |
International
Class: |
E21B 49/08 20060101
E21B049/08; E21B 43/36 20060101 E21B043/36; E21B 41/04 20060101
E21B041/04 |
Foreign Application Data
Date |
Code |
Application Number |
Jun 4, 2008 |
GB |
0810189.1 |
Claims
1. Subsea apparatus for sampling and analysing fluid from a subsea
fluid flowline proximate a subsea well, comprising: at least one
housing located in close proximity to said subsea fluid flowline;
at least one fluid sampling device located in the housing in fluid
communication with a said subsea fluid flowline for obtaining a
sample of fluid from the subsea fluid flowline; at least one fluid
processing apparatus located in the housing in fluid communication
with said subsea fluid flowline for receiving and processing a
portion of the fluid flowing through said fluid flowline or in
fluid communication with the fluid sampling device, for processing
the sample of fluid obtained from the subsea fluid flowline for
analysis, while keeping the sample of fluid at subsea conditions; a
fluid analysis device located in the housing, the fluid analysis
device being in fluid communication with the fluid processing
device and/or with the fluid sampling device, the fluid analysis
device being used for analysing said sample of fluid or the
processed sample of fluid to generate data relating to a plurality
of properties of said sample of fluid and communicating said data
to a surface data processor or to at least one other subsea
apparatus; and conveying means included in the housing for
conveying the housing means from one subsea fluid flowline to
another subsea fluid flowline or for conveying the housing to the
surface.
2. Subsea apparatus as in claim 1, further comprising at least one
electronic device which incorporates at least one software model
used to provide information regarding the production of said subsea
well.
3. Subsea apparatus as in claim 1, wherein the fluid analysis data
is used to control at least one subsea piece of equipment.
4. Subsea apparatus as in claim I, wherein the fluid processing
apparatus separates the sample of fluid into at least a liquid and
a gaseous phase, or mixes the sample of fluid with at least one
other different fluid, or enriches the sample of fluid.
5. Subsea apparatus as in claim 1, wherein at least one data
processing device is located in the housing and is in communication
with the fluid analysis device.
6. Subsea apparatus as in claim 1, wherein the conveying means is
an attachment for a detachable subsea vehicle.
7. Subsea apparatus as in claim 6, wherein the conveying means is
an attachment for a remotely operated vehicle (ROV) and/or an
autonomous underwater vehicle (AUV).
8. Subsea apparatus as in claim 1, which comprises a plurality of
fluid analysis devices which are connected to each other.
9. Subsea apparatus as in claim 1, which comprises a plurality of
housings connected to each other in a modular fashion located in
close proximity to said subsea fluid flowline, and wherein each
fluid analysis device of each housing is in fluid communication
with each other, and each fluid sampling device of each housing is
in fluid communication with each other.
10. A method of sampling and analysing fluid from a subsea well,
the method comprising: locating at least one housing in close
proximity to a subsea flowline proximate said subsea well, said
housing comprising at least one fluid analysis device, at least one
fluid processing apparatus and at least one fluid sampling device,
the fluid sampling device being in fluid communication with said
subsea flowline, the fluid processing apparatus being in fluid
communication with said subsea flowline and/or with the fluid
sampling device, the fluid analysis device being in fluid
communication with the fluid processing device and/or with the
fluid sampling device; obtaining a sample of fluid from the subsea
flowline, and storing it in the fluid sampling device; transferring
the sample of fluid to the processing device, and processing the
sample of fluid with the processing device for analysis by the
fluid analysis device, while keeping the sample of fluid at subsea
conditions; transferring the sample of fluid from the processing
device to the fluid analysis device; analysing the properties of
the fluid with the fluid analysis device to obtain fluid analysis
data subsea; communicating the fluid analysis data to at least one
other subsea apparatus or to a surface data processor; and
conveying the housing from said subsea fluid flowline to another
subsea fluid flowline or to the surface.
11. The method as in claim 10, wherein the fluid sampling device is
in fluid communication with a fluid processing apparatus, the fluid
processing apparatus being in fluid communication with the well
fluid flowing in the subsea flowline and the sample of fluid is
obtained from the well fluid in the subsea flowline via the fluid
processing apparatus.
12. The method as in claim 10, wherein at least one data processing
device is locatable in the housing and is in fluid communication
with the fluid analysis device, and which further comprises
processing fluid analysis data received from the fluid analysis
device by means of the data processing device and communicating the
processed data to another apparatus or to the surface.
13. The method as in claim 10, wherein the conveying means is an
attachment for a detachable subsea vehicle.
14. The method as in claim 10, wherein there are a plurality of
housings, and which further comprises connecting the plurality of
housings to each other in a modular fashion, and wherein each fluid
analysis device of each housing is in fluid communication with each
other, and each fluid sampling device of each housing is in fluid
communication with each other.
Description
BACKGROUND OF THE INVENTION
[0001] This invention relates to subsea apparatus for fluid
sampling and/or analysis. In particular, the invention relates to a
subsea apparatus for fluid sampling and/or analysis used in the oil
and gas industry.
[0002] Understanding the properties of fluids in wells in the oil
and gas industry is critical for the assessment of oil or gas
reservoirs. For example, the fluid properties may be used for the
proper management of oil and gas reservoirs including for instance
production management and flow assurance. Fluid sampling and/or
analysis may be performed during various phases of the exploration,
development and production phases of a reservoir. Conventional
tools are able to take a fluid sample from the well and bring it to
surface where it is processed and analysed. For example, often
times the phase behavior of the fluid may be studied using an
analysis known in the industry as PVT analysis which measures,
inter alia, the bubble point of the fluid as well as its wax, and
asphaltene content. Also, compositional analysis of the fluid
sample may be performed as well as analysis of its H.sub.2S,
CO.sub.2, Hg, and heavy metal content. Also, well known are tools
and methods for measuring the density and viscosity of the fluid
its, water content, etc.
[0003] More and more of these measurements are arranged to be
performed downhole. This is because, generally, obtaining a correct
estimation of fluid phase behavior requires that a sample with a
pressure and temperature as close as possible to the conditions
present at the wellhead be taken so that wax and asphaltenes do not
precipitate out of the fluid. Fluid properties at the surface may
differ from those present at the wellhead. Sampling of the fluid at
the surface is therefore not a suitable option for the correct
estimation of the fluid phase behavior in subsea oil or gas wells.
However, the conditions prevalent in a subsea environment make
access to a subsea fluid sample rather difficult.
[0004] In a subsea oil or gas well installation, fluid flows from
different well heads are often mixed through a series of manifolds.
This poses an additional complication in the sampling and analysis
of subsea wells. Sampling and analysis of the fluid flowing from
each individual well would be preferred as it would provide a
valuable understanding of the production capabilities and
peculiarities of each well which in turn could be used for proper
field management. Also, the properties of the fluid produced by
subsea wells may change significantly over a short period of time.
Thus, if the analysis of the samples that have been taken is done
at a later time at a surface, the value of the data will be
diminished.
[0005] Various apparatus, methods and systems for sampling and
analyzing well fluids have been identified previously. U.S. Pat.
No. 6,435,279 discloses a method and apparatus for sampling fluids
from an undersea wellbore utilizing a self-propelled underwater
vehicle, and a collection and storage device. The '279 patent
describes a method for sampling a fluid produced from a subsea
well, the method comprising a remotely operated vehicle (ROV)
having a collecting device for collecting a sample of fluid and a
storage facility for the collected sample of fluid wherein said
collecting device and storage facility are connected to the ROV.
The collecting device is used to collect a sample from a subsea
location, storing the sample in the ROV and then transferring it to
a surface location.
[0006] International patent applications WO 2008/087156, and WO
2006/096659 disclose various systems and methods for subsea
sampling. The WO 2008/087156 patent application describes a subsea
sampling and data collection device that is coupled to a flowline
at a flowline installation. The WO 2008/087156 sampling and data
collection device includes a sample collection system having a
probe insertable into a flowline to collect a fluid sample. The WO
2008/087156 application is assigned to the same assignee as the
present invention and it is hereby incorporated by reference for
all purposes allowable under the law to the extent that its
disclosure does not contradict with the present invention.
[0007] An article entitled "Improved production sampling using the
Framo multiphase flow meter" by Framo Engineering AS in October
1999 discusses a multiphase flow meter used in fluid sampling,
including subsea with the aid of remotely operated vehicles
(ROV).
[0008] From the description above it is evident that for effective
production and flow assurance management in subsea oil and gas
reservoirs, there is a real need to obtain a good understanding of
produced fluid on a well by well basis and to measure the variation
of fluid properties from each of these wells with time. The present
invention provides an improved apparatus and associated method that
facilitate the sampling and the characterization of the fluids at a
subsea environment, and as close as possible to each well head. The
present invention and method also enable analysis of sampled fluid
to occur on a real time basis and thus obtain accurate real time
analysis data for well performance and management.
BRIEF SUMMARY OF THE INVENTION
[0009] A first aspect of this invention provides subsea apparatus
for sampling and analysing fluid from a subsea fluid flowline
proximate a subsea well, comprising: [0010] at least one housing
located in close proximity to said subsea fluid flowline; [0011] at
least one fluid sampling device located in the housing in fluid
communication with a said subsea fluid flowline for obtaining a
sample of fluid from the subsea fluid flowline; [0012] at least one
fluid processing apparatus located in the housing in fluid
communication with said subsea fluid flowline for receiving and
processing a portion of the fluid flowing through said fluid
flowline or in fluid communication with the fluid sampling device,
for processing the sample of fluid obtained from the subsea fluid
flowline for analysis, while keeping the sample of fluid at subsea
conditions; [0013] a fluid analysis device located in the housing,
the fluid analysis device being in fluid communication with the
fluid processing device and/or with the fluid sampling device, the
fluid analysis device being used for analysing said sample of fluid
or the processed sample of fluid to generate data relating to a
plurality of properties of said sample of fluid and communicating
said data to a surface data processor or to at least one other
subsea apparatus; and [0014] conveying means included in the
housing for conveying the housing means from one subsea fluid
flowline to another subsea fluid flowline or for conveying the
housing to the surface.
[0015] The fluid analysis data can be real time data, and this real
time data is communicated to at least one electronic device which
incorporates at least one software model used to provide
information regarding the production of said subsea well. The
software model may also used to provide predictions regarding the
production of the well.
[0016] In one form of the invention the fluid analysis data is used
to control at least one piece of subsea equipment. The fluid
processing apparatus separates the sample of fluid into at least a
liquid and a gaseous phase, or mixes the sample of fluid with at
least one other different fluid, or enriches the sample of
fluid.
[0017] In one form of the invention the fluid sampling device is in
communication with the well fluid. The fluid sampling device may
also be in communication with a fluid processing apparatus, the
fluid processing apparatus being in communication with the well
fluid.
[0018] Further according to the invention, at least one data
processing device may be locatable in the housing and may be in
communication with the fluid analysing device. The data processing
device processes data received from the fluid analysis device and
communicates the data.
[0019] The conveying means may be an attachment for a detachable
subsea vehicle such as, for example, a remotely operated vehicle
(ROV) or an autonomous underwater vehicle (AUV).
[0020] The subsea apparatus may further comprise a plurality of
housings which are connectable to each other in a modular fashion.
The fluid analysis device of each housing may be in fluid
communication with the fluid analysis device of another connected
housing. In the same way, the fluid sampling device of each housing
may be in fluid communication with the fluid sampling device of
another fluid sampling device of a connected housing, and the data
processing device of each housing may be in fluid communication
with the data processing device of a connected housing.
[0021] A second aspect of this invention provides a method of
sampling and analysing fluid from a subsea well, the method
comprising: [0022] locating at least one housing in close proximity
to a subsea flowline proximate said subsea well, said housing
comprising at least one fluid analysis device, at least one fluid
processing apparatus and at least one fluid sampling device, the
fluid sampling device being in fluid communication with said subsea
flowline, the fluid processing apparatus being in fluid
communication with said subsea flowline and/or with the fluid
sampling device, the fluid analysis device being in fluid
communication with the fluid processing device and/or with the
fluid sampling device; [0023] obtaining a sample of fluid from the
subsea flowline, and storing it in the fluid sampling device;
[0024] transferring the sample of fluid to the processing device,
and processing the sample of fluid with the processing device for
analysis by the fluid analysis device, while keeping the sample of
fluid at subsea conditions; [0025] transferring the sample of fluid
from the processing device to the fluid analysis device; [0026]
analysing the properties of the fluid with the fluid analysis
device to obtain fluid analysis data subsea; [0027] communicating
the fluid analysis data to at least one other subsea apparatus or
to a surface data processor; and [0028] conveying the housing from
said subsea fluid flowline to another subsea fluid flowline or to
the surface.
[0029] In one form of the invention the fluid sampling device is in
fluid communication with a fluid processing apparatus, the fluid
processing apparatus being in fluid communication with the well
fluid flowing in the subsea flowline and the sample of fluid is
obtained from the well fluid in the subsea flowline via the fluid
processing apparatus. The fluid sampling device may also be in
communication with a fluid processing apparatus that is in
communication with the well fluid.
[0030] Further according to the invention, at least one data
processing device may be locatable in the housing and may be in
fluid communication with the fluid analysis device, and which
further comprises processing fluid analysis data received from the
fluid analysis device by means of the data processing device and
communicating the processed data to another apparatus or to the
surface. The method may further include processing fluid data
received from the fluid analysis device and communicating the
data.
[0031] The method may also comprise deploying one or more housings
of the apparatus by means of a detachable subsea vehicle such as,
for example, a remotely operated vehicle (ROV) or an autonomous
underwater vehicle (AUV), the housings being connectable to each
other.
[0032] In a further form of the invention there may be a plurality
of housings, and the method may further comprise connecting the
plurality of housings to each other in a modular fashion, and
wherein each fluid analysis device of each housing is in fluid
communication with each other, and each fluid sampling device of
each housing is in fluid communication with each other.
[0033] Further aspects of the invention will be apparent from the
following description.
BRIEF DESCRIPTION OF SEVERAL VIEWS OF THE DRAWING
[0034] FIG. 1 shows a schematic side view of a subsea apparatus for
sampling and/or analysing fluid from a well according to one
embodiment of the invention;
[0035] FIGS. 2 shows a schematic side view of a housing of the
subsea apparatus for sampling and analysing fluid from a well as
shown in FIG. 1, attached to a remotely operated vehicle (ROV);
[0036] FIG. 3 shows a schematic side view of the subsea apparatus
for sampling and/or analysing fluid attached to a fluid processing
device indicating the flow direction through the components of the
fluid processing device;
[0037] FIG. 4 shows a diagrammatic view of a hydraulic sampling
device of the subsea apparatus for sampling and/or analysing fluid
from a well according to one embodiment of the invention;
[0038] FIG. 5a shows a diagrammatic view of a passive sampling
device of the subsea apparatus for sampling and/or analysing fluid
from a well according to another embodiment of the invention;
[0039] FIG. 5b shows a diagrammatic view of a passive sampling
device of the subsea apparatus for sampling and/or analysing fluid
from a well which uses venturi according to another embodiment of
the invention;
[0040] FIG. 6 shows a diagrammatic view of an active sampling
device of the subsea apparatus for sampling and/or analysing fluid
flow which uses a pump according to a further embodiment of the
invention;
[0041] FIGS. 7a, 7b and 7c show a series of diagrammatic views of
an adjustable inlet of a sampling device according to an embodiment
of the invention;
[0042] FIG. 8 shows a schematic layout of a fluid analyser of the
subsea apparatus for analysing fluid from a well;
[0043] FIG. 9 shows a schematic side view of a section of an
in-line fluid analyser of the subsea apparatus for sampling and
analysing fluid from a well according to one embodiment of the
invention;
[0044] FIG. 10 shows a schematic side view of a section of an
in-line fluid analyser of the subsea apparatus for sampling and
analysing fluid from a well which includes a phase behaviour fluid
analyser according to another embodiment of the invention;
[0045] FIGS. 11, 11a, 11b and 11c show schematic side view of a
sampling bottle for low shock sampling with a piston inside the
bottle of the subsea apparatus according to one embodiment of the
invention;
[0046] FIGS. 12, 12a, 12b and 12c show schematic side view of a
sampling bottle for low shock sampling without a piston inside the
bottle of the subsea apparatus according to one embodiment of the
invention;
[0047] FIG. 13 shows schematic view of a self retrievable sampling
bottle apparatus of the subsea apparatus according to one
embodiment of the invention; and
[0048] FIG. 14 shows a schematic overview of a controller
configuration used for the control of a number of subsea
apparatuses according to one embodiment of the invention.
DETAILED DESCRIPTION OF THE INVENTION
[0049] This subsea apparatus for analysing and/or sampling fluid
from a well according to the invention is applicable to subsea
installations or facilities in the oil and gas industry. In the
drawings FIG. 1 illustrates the basic layout of a subsea apparatus
10 for sampling and/or analysing fluid from a well according to the
invention. Subsea apparatus 10 is located in close proximity to the
wellhead of a well and includes a subsea fluid processing device 12
for processing fluid samples obtained from the well. The subsea
processing device 12 can be a phase separator, a phase accumulator,
a boosting pump, a water treatment unit, chemical injector or an
injection pump, depending on the application required.
[0050] The subsea processing device 12 includes a fluid sampling
device 14. The fluid sampling device 14 consists of a network of
pipes connected to different sampling points in the processing
device 12. The fluid sampling device 14 can also include a
distributor that can redirect the sampled fluid to different
outlet.
[0051] Subsea apparatus 10 further includes a remote operating
device (ROV) docking station 16 which allows the docking and
attachment of a remote operating device (ROV) 18 to the subsea
processing device 12.
[0052] As shown in FIG. 1, there is a fluid interface 20 in
communication with the sampling device 14 which is located below
the ROV docking station 16. The fluid interface 20 allows a
hydraulic connection between the ROV 18 and the processing device
12, and thus fluid at well pressure can travel between them. This
hydraulic connection can be initiated when the ROV 18 is docked at
the docking station and it can be disconnected when the ROV 18 is
removed.
[0053] A frame or skid 22 could also be docked to the docking
station with the help of an ROV 18. As illustrated in FIG. 2, the
skid 22 is attached to the ROV 18 with several instrumentation
modules connected thereto. This will be further described below.
Skid 22 can be docked to the docking station 16 as the ROV 18
approaches the installation. The skid 22 can then be detached from
the ROV 18 through a specific skid/ROV interface 24 and it can then
be left permanently on the installation of apparatus 10. The
skid/ROV interface 24 may be a fluid interface and skid 22 is in
communication with the fluid interface 20. By using a hydraulic
connection between skid 22 and fluid interface 20, the well fluid
can be directed to the instrumentation module 26 which is located
on the skid 22.
[0054] Skid 22 is designed so that other skids 22 of a similar type
can be connected to it. The design is modular so that the skids 22
can be configured and assembled in different orders, and then used
for different purposes.
[0055] Skid 22 can also be deployed using an autonomous under water
vehicle AUV. In this case, the skid interface 24 may include
instrumentation for the positioning of the AUV during docking.
[0056] An instrumentation module 26 is located inside skid 22 and
is connected to a controller/communication module 28.
Instrumentation module 26 contains the fluid analyzer and it is
used to perform fluid analysis and/or fluid sampling. It is
connected to the fluid interface 20 and it can receive the fluid
collected by the fluid sampling device 14. The type of analysis and
the sampling sequence is managed by the controller/communication
module 28. The controller/communication module 28 performs control
either through a pre-defined sequence stored in the controller,
from the surface with the use of a communication link, or in a
completely automated mode with the use of the fluid analysis data
obtained by the fluid analyzer in instrumentation module 26. It is
used to enable decisions to be made on how to process the sample of
fluid.
[0057] There are various different possible schemes for the
sampling which have been described previously in the art and these
can easily be implemented in conjunction with this invention.
[0058] The fluid analyzer in instrumentation module 26 consists in
a network of pipe connected to pumps, fluid properties sensors,
sample chambers, fluid conditioners and injectors. This system is
managed through the controller/communication module 28.
[0059] The fluid analysis data obtained by apparatus 10 is used to
control various types of subsea or surface equipment. This fluid
analysis data is based on real time sample measurements obtained
from the fluid sample that is obtained and also possibly analyzed
at wellhead conditions. This real time fluid data may be
communicated to an electronic device which incorporates at least
one software model and this model may be used to provide
information regarding the production of the well and to provide
predictions regarding the production of the well. Thus information
regarding reservoir assurance, or flow assurance management may be
obtained through the processing of this fluid data.
[0060] Details will now be provided of further embodiments of the
invention.
[0061] FIG. 3 illustrates an embodiment of the subsea apparatus for
sampling and/or analysing fluid from a well according to the
invention, which further includes a phase separator 30.
[0062] The phase separator 30 which may be used is one of the
typical examples of phase separators known in the art. Such a
typical phase separator consists of a pressure vessel 32 with an
internal pipe drilled with radial holes. The pressure vessel 32
includes a fluid inlet 34 and fluid outlet 36. The direction of
fluid flow is shown by arrows A in FIG. 3. The phase generator 30
was initially designed in the art as a device for fluid mixing
purposes but it can also be used as a fluid separator. In the
pressure vessel area, the fluid segregates depending on its
density, with gas separating out on top and the liquid (oil and
water) separating out at the bottom. As the fluid is forced through
the central pipe (with holes), the phases are remixed, leading to a
mixed fluid flow leaving at the outlet.
[0063] Phase generator 30 allows liquid can be sampled at the
bottom of the vessel while gas can be sampled at the top.
[0064] FIG. 3 further shows a retrievable ROV 18 with a skip 22
including a fluid sampling or analysis module 26 to be used for
fluid sampling, as well as a skip 22 including a fluid sampling or
analysis module 26 to be used for fluid analysis, and then a
multi-phase flow meter 38.
[0065] The hydraulic sampling device of apparatus 10 is illustrated
in FIGS. 5 and 6. Fluid sampling can be done either through a
passive or an active sampler. In the implementation of the
invention shown in FIGS. 5 and 6, the fluid sampling or analysis
module 26 has internal piping connecting the liquid sampling pipe
44 to the gas sampling pipe 46. It further includes an inlet pipe
40 to sample the fluid from the separator to the fluid analyzer in
module 26 and an outlet pipe 42 to re-inject the fluid to the
separator or main fluid flow line after it has been analyzed. The
direction of fluid flow is shown in FIGS. 5a, 5b and 6 by arrows
B.
[0066] Passive sampling devices 26 do not require any pump to
sample the fluid as these devices are based on passive mechanisms.
Two different possible implementations of passive sampling devices
are shown in FIGS. 5a and 5b. In FIG. 5b, the fluid movement inside
the sampling tubes is generated using a venturi device 48. The
outlet pipe 42 is connected to venturi device 48 which is located
further down the fluid flow line. The venturi device 48 generates a
pressure difference that drives the fluid through the piping system
and the fluid sampling or analysis module 26 or from the inlet to
the outlet.
[0067] In FIG. 5a, the fluid in the extraction line is dragged by
the main flow in a perforated pipe 50.
[0068] FIG. 6 describes an active sampler using a pump 52 to
generate the fluid flow from the inlet to the outlet.
[0069] In practice several different types of fluid sampling
devices can be used. For example, in FIGS. 5 and 6, with the use of
the proposed separator, it is possible to change the sampled liquid
phase by adjusting the position of the inlet inside the phase
separation chamber. The liquid phase of the fluid will accumulate
at the bottom while the gas phase will accumulate at the top of the
vessel.
[0070] One possibility is to have two or more inlet pipes 40.1 and
40.2 with different heights as is illustrated in FIG. 7a. If
required, the flow from these sampling pipes could be directed to a
manifold before being routed to the fluid sampling or analysis
module 26.
[0071] Another possibility which is described in FIG. 7b is to have
a sampling pipe with an adjustable height that is adjustable with
the use of mechanical actuators 56. The height H may then be
adjusted according to what is required. With time, the ratio
between the different phases of fluid produced by the well changes.
With such an adjustable sampling inlet, it is thus possible to
adapt the sampling device to the changes in production
conditions.
[0072] FIG. 7c describes an adjustable fluid sampling or analyzing
module 26 which uses a series of controllable valves 57 and 58
connected thereto to change the sampling point position. The valves
57 and 58 can be selectively closed. In the normal operation, all
valves 58 are closed except for the valve 57 which is at the level
of the sampling point. The fluid flow is illustrated in FIG. 7 by
arrows E.
[0073] In one embodiment of the invention there is a universal skid
22 used for fluid sampling and analysis. This skid 22 includes the
fluid interface 20, power/communication module 28, skid or ROV
interface 24, a local controller module and a fluid sampling or
analysis module 26. The local controller module controls the
working of the sampling or fluid analysis module 26.
[0074] One feature of apparatus 10 is its modularity. Apparatus 10
may be provided in different kinds of modules. Fluid, communication
and skid or ROV interfaces are designed to be fully interoperable
so that different kinds of modules of apparatus 10 can be
interconnected and configured in many different types of
configurations.
[0075] Another feature of apparatus 10 is that modules of apparatus
10 including skids 22 may be installed either on a temporary basis
or on a semi-permanent basis.
[0076] Before any fluid sampling or fluid analysis operation
starts, the skids 22 are fully engaged in an ROV 18 and connected
to the various fluid interfaces. An individual module of apparatus
10 comprising a skid 22 and its attached equipment can be retrieved
as required by an ROV 18.
[0077] The fluid sampling or analyzing device 26 which is mounted
in a skid 22 in apparatus 10 is shown in more detail in FIG. 8. The
device 26 is enclosed in a tool housing 59 and it includes fluid
flow lines 60 connected together and guiding the fluid from an
inlet to an outlet. The device 26 further includes pumps 62 which
can move the fluid there through. Fluid conditioners 64 which are
used to process the fluid and change properties such as the ratio
between the different fluid phases, or the fluid pressure, volume
or temperature are also included in device 26. Fluid processing
devices 12 may further include a separator, a mixer, and a PVT
(pressure, volume and temperature) device.
[0078] In device 26 injectors 66 can be used to inject fluids which
are different from the fluid which is flowing in a particular flow
line 60. The injected fluid can be used to generate an inhibitory
chemical reaction with the sampled fluid or it can change the phase
behavior of the fluid. Sample bottles or chambers 68 in device 26
are used to take and store samples of the fluid inside a flow line
60. Fluid property sensors 70 are also shown located on flow lines
60 in device 26.
[0079] In the drawings, FIG. 9 illustrates an embodiment of the
fluid sampling or analysis device 26 of apparatus 10 to be used for
fluid analysis with one possible configuration of sensors 70. In
this embodiment, device 26 is in-line with the sampling piping.
Various types of sensors 70 are shown in the in-line configuration
in a fluid flow line 60. These sensors may be, for example, a lamp
72 and spectrophotometer 74 arrangement, a fluorescence detector
76, a resistivity sensor 78, an X-ray or gamma ray density sensor
80, a pressure and temperature gauge 82, a density or viscosity
sensor 84, a vibrating wire 86, an in-line CO2 sensor 88, or an
in-line H2S sensor 90. In FIG. 9 the fluid sample is shown to flow
in either direction through the flow line 60.
[0080] The fluorescence detector 76 can be used to, for example,
detect traces of oil in water. This information can be useful for
the assessment of subsea processing, for example, when water is
separated from oil before being re-injected into the formation.
[0081] The fluid resistivity sensor 78 can be used to detect water
resistivity, which can be very useful information which can in turn
be used to detect injection water breakthrough. Injection water
used for reservoir stimulation will usually have a resistivity
different from that of formation water. Water resistivity changes,
therefore, can be correlated with injection water breakthrough.
[0082] The fluid sampling or analysis device 26 can also include
fluid conditioners. One possible fluid conditioner is a phase
separator. This can be used for water or oil sampling. The main
phase separator will give a liquid or gas separation. The phase
separator within the fluid sampling or analysis device 26 can
therefore be used to separate the oil from the water if
necessary.
[0083] Another sensor which may form part of device 26 is a unit to
"flash" the sample. Sample flashing consists of dropping the
pressure of sample before injecting it with a specific sensor. This
method is well known in the analysis of HP (high pressure) live oil
samples by using gas chromatography.
[0084] The embodiment of device 26 which is illustrated in FIG. 9
is suitable for different types of application. These could
include, for example, NMR characterization for composition analysis
or viscosity measurement, gas chromatography, mass spectroscopy,
inductive coupled plasma chemical (ICP) analysis, electro-chemical
sensors, or pH or ion concentration measurement in water phase
using colorimetric methods.
[0085] In the drawings, FIG. 10 illustrates a further embodiment of
apparatus 10 of the invention which includes a fluid sampling or
analysis device 26 to be used for fluid analysis that has a further
possible configuration of sensors 70. Device 26 in this embodiment
can be used for several types of measurement. Device 26 includes
two seal valves 92 and 94 that can be opened and closed in order to
trap a fluid sample in between them. The volume of fluid in the
piping system between the two seal valves 92 and 94 forms a fluid
circulation loop. The fluid in the circulation loop can be
circulated with the circulation pump 96 and pump unit 103. Seal
valve 98 is used to force the fluid flow through the circulation
loop before valves 92 and 94 are closed.
[0086] A piston unit that is used to increase the volume trapped
between the seal valves and consequently to reduce sample pressure.
There is a pressure sensor connected to the circulation loop to
monitor pressure changes as the piston is retracted. The piston is
preferably retracted when the circulation pump 96 is operating. The
agitation created by the fluid moving helps to prevent a problem
posed by fluid supersaturation. It is well-known in the art that
estimation of bubble point requires some agitation as the pressure
is changed. The circulation loop can include an ultrasonic
transducer that will also generate agitation and this helps to
prevent supersaturation.
[0087] A scattering detector 100 sensor is used in device 26 in
order to detect bubbles or solid particles forming in a fluid flow
line 60. The scattering detector 100 used is known in the art and
is used to measure the attenuation of light as it passes through a
cell. Formation of solid particles and gas bubbles will lead to an
increase in the attenuation of light. This sensor is used to detect
the fluid bubble point which indicates at which pressure gas starts
to form in the flow line. Such sensors can be used to detect the
gas condensate dew point, the fluid bubble point, gas bubble
formation or the presence of solid particles.
[0088] A density and viscosity sensor 84 may also be included in
device 26. It is used to measure the evolution of the parameters of
density and viscosity against pressure.
[0089] An optical spectrometer (the lamp 72 and spectrometer 74
arrangement) may also be included in device 26 to measure fluid
optical absorption at various wavelengths. The optical
spectrometer, for example, can be used to estimate fluid
composition by NIR spectroscopy. It is of particular interest for
hydrocarbon analysis as the hydrocarbons have characteristic
absorption peaks around [1600; 1800] nm. Spectral analysis in the
visible range can also be used for monitoring asphaltene content of
the fluid.
[0090] Device 26 may also include a camera 102 which is used to
monitor the condition of the fluid in the flow lines for the
presence of bubbles or solid particles. In addition, device 26 may
also enclose a US transducer sensor 104.
[0091] Device 26 may be enclosed in a temperature control unit 106.
The temperature control unit 106 may enable the temperature of the
fluid to be changed. In this way by combining pressure and
temperature changes, device 26 can provide a comprehensive phase
diagram for the fluid trapped in the fluid flow lines 60 of the
device.
[0092] Device 26 may be used in various downhole conditions and can
be used in various applications such as, for example, the study of
fluid phase diagrams (bubble point detection, wax or asphaltene
onset, hydrate locus, etc), the study of fluid density and
viscosity versus pressure, and the study of fluid composition.
[0093] Another important feature of the invention is the ability to
sample fluid. FIG. 11 gives a possible configuration for a sampling
bottle 108. The sampling bottles 108 of apparatus 10 are configured
for low shock sampling. Low shock sampling comprises filling a
bottle 108 with the sample with a controlled flow rate. The goal is
to avoid fast pressure changes of the sample which could lead to
phase transition before the bottle 108 is filled.
[0094] The sampling bottle 108 can be implemented as follows:
[0095] A cylindrical bottle 108 with a piston 110 defining two
chamber spaces as it moves along the bottle's main axis. The sample
chamber 112 is located on one side of piston 110 is and the water
cushion chamber 114 is located on the other side of piston 110.
[0096] Bottle 108 is connected to the fluid sampling line as shown
in FIG. 11. In the initial position before the bottle 108 is
opened, shown in FIG. 11a, the volume of sample chamber 112 is
minimal while the cushion water chamber 114 side is full. For
sampling, the solenoid valve 116 and the choke valve 118 are
opened. The rate of sampling can be controlled by the choke 120.
The choke 120 controls the fluid flow and therefore the fluid flow
rate in the sample chamber 112. The sampling is completed once the
piston 110 reaches its final position on the other side of the
bottle 108. Both the solenoid valve 116 and the choke 120 can be
closed. Due to the controlled flow rate, the fluid is sampled with
minimum pressure changes.
[0097] It will be noted that low shock sampling can also be done
without the piston 110 being in the bottle as shown in FIG. 12c. In
this case, the sampling bottle 108 must be flashed long enough to
remove any of the initial filling water. FIG. 11b illustrates
bottle 108 during sampling.
[0098] Low shock sampling is a well known technique for downhole
fluid sampling. Other possible variations of fluid sampling have
also been described in the prior art.
[0099] The fluid sampling can be controlled either from surface or
it can be controlled through a predetermined sequence of actions to
be taken on a periodic base.
[0100] The combination of the fact that the fluid sampling or
analysis device 26 can be installed on a semi-permanent basis, the
configuration of the sampling skid 22 and the possibility that
sample can be obtained on a periodic basis, means that it is
possible to sample the fluid without mobilizing an ROV 18 with its
support vessel. Device 26 can therefore perform time-lapsed
sampling during the time it is installed on a subsea apparatus 10.
With the proposed configuration, the sampling can be performed
though period of time from a few months to a few years. Sample
bottles 108 can be retrieved at the surface by using an ROV 18 to
pick up the skid 22 on which the sample bottles 108 are
located.
[0101] A sampling bottle 108 may also include a temperature control
unit 122. Temperature control allows the sample temperature to be
kept the same as when it was in the fluid flow of the well. It
would avoid phase transition due to temperature changes. In
practice, the sample will tend to cool when it is sent to the
bottle 108. The temperature control system can consist of a simple
electrical heating system wrapped around the bottle.
[0102] Another important feature of the invention is the ability of
sampling bottles 108 to be retrieved to the surface before the skid
22 is changed. The bottle 108 may include means for energy storage,
a positioning system and a propulsion mechanism. An embodiment of
the apparatus 10 according to the invention which illustrates such
a configuration of a sample bottle 108 is shown in FIG. 13. The
bottle 108 in this embodiment is filled with compressed gas. An
inflatable structure such as a balloon 124 is connected to the
bottle 108 that is filled with compressed gas. The balloon 124 is
connected to the compressed gas through a solenoid valve 116.
[0103] The bottle 108 end fittings use male/female hot stabs 107
that can be released through a command sent from the skid
controller. The bottle 108 is fixed to the skid chassis through a
mechanical interface that can also be released by a command sent by
the skid controller. The bottle 108 also includes a localization
system that can communicate with the surface. When the bottle 108
needs to be released a command is sent from the surface and this
triggers the inflation of the balloon 124, as well as the release
of the end fitting and mechanical interface. In addition this also
activates a localization beacon 126. The bottle 108 is then buoyed
to the surface. Once back at surface, the bottle 108 can be located
and retrieved by a surface support vessel 128.
[0104] In FIG. 4 of the drawings the fluid sampling section and the
skids are shown to be in a modular configuration. The fluid
sampling device 26 is configured according to the configuration
described in FIG. 5a. The device 26 includes two sampling lines
located at different heights as is described in FIG. 7a. The longer
sampling line will sample liquid while the other shorter one will
sample gas. An extraction pipe 130 is common to the gas 44 and
liquid 46 sampling pipes. They form two primary loops through which
production fluid circulates.
[0105] The mechanical and hydraulic fluid interfaces are based on
standardized stab plates 134 including electrical and hydraulic
connections, as well as hydraulic valves 136 and 138. The valves
138 are closed when a skid 22 is engaged on top of it. In all other
circumstances the valves 136 and 138 are open. The mechanical
interfaces of the stab plates 134 and valves 136 and 138 are the
same on top of the phase separator as they are on the skids 22. In
this way the skids 22 can be stacked in any configuration on top of
the separator 30.
[0106] The valves 136 and 138 are configured to connect the fluid
sampling lines 46 with the extraction line 130. As the skids 22 are
connected one on top of another, the valves 138 from the lower
skids are closed while the upper valves 136 are opened. The valves
138 of the lower skid 22 are closed when the upper skid connects to
it. This takes place after hydraulic connection is completed. The
configuration of the valves 136 and 138 allows the liquid to
circulate from the separator 30 to the upper skid 22.
[0107] Fluid sampling and analysis devices 26 are located between
the sampling pipes 44 and the extraction pipes 130. There may be a
pump 132 associated with these devices 26 in order to circulate the
fluid from the sampling line 44 to the extraction line 130. This
configuration as shown in FIG. 4 allows for a fully modular
configuration.
[0108] Another important feature of the invention is the use of
subsea fluid analysis measurement by apparatus 10 to be used to
control subsea equipment. The information from the apparatus 10 can
be used, for example to control subsea equipment in a fully
automated mode, or to control subsea equipment from the surface
using the information obtained from apparatus 10. Different
controllers/communication modules 28 are connected in a network
configuration with, for example, an Ethernet architecture, which
allows communication and control between the different skids 22.
The information can either be sent to the surface or processed at
seabed level for the direct management of the control of other
subsea modules.
[0109] In a fully automated mode, the information obtained from the
sensors is directly processed at the seabed and a decision is made
at subsea apparatus 10. The information can be used to optimize
choke opening for example. Another possible example is the
optimization of chemical or water injection and the optimization of
phase separator operating conditions. The information can also be
sent to the surface for human based interpretation and decision
making.
[0110] FIG. 14 shows one embodiment of the subsea apparatus 10 and
method according to the invention in which a template of fluid
platforms are located on the seabed. FIG. 14 illustrates the flow
of fluids from different wellheads which are mixed through sets of
manifolds before being sent to the surface. Fluid platforms are
shown placed between a wellhead and a manifold. This configuration
enables the production fluid flow of each individual well to be
characterized.
[0111] Another important feature of the subsea apparatus 10 and
method according to the invention is the ability to combine the
measurements obtained from the fluid sensors of devices 26 in
apparatus 10 with the measurements obtained from other sensors on
the seabed.
[0112] One possibility is to combine fluid analysis results with
multiphase flow meter measurement for flow assurance prediction.
The measurement results can be fed to simulation software such as
OLGA.RTM. to predict possible flow assurance problems along the
subsea installation. For example, in a case where OLGA.RTM. is
handling 1D dynamic simulation of fluid phase behavior along the
subsea piping installation. It allows simulation from the wellhead
to the surface. Critical inputs for this type of software are phase
diagrams as well as the respective flow of each phase (water, oil
and gas) of the fluid. A phase diagram of each phase can be
obtained from a PVT sensor as illustrated in FIG. 10.
[0113] Another possibility is the use of composition measurement. A
gas chromatograph could be installed on the fluid sampling or
analysis device 26 to be used for analysis so as to provide the
detailed composition. Combined with equation of state this could
provide a phase diagram for each phase.
[0114] The apparatus 10 and method according to this invention in
combination with multiphase flow meter data may be used to obtain
real-time flow assurance prediction by feeding fluid properties
directly into the software models that are used for this purpose.
This would allow the control of subsea equipment to optimize
production condition.
[0115] Flow assurance problems are likely to happen during
installation shut-down, therefore, providing updated information on
fluid behavior just before the shut-down would be able to help
provide better management of the installation.
[0116] Another possible application of the apparatus and method
according to the invention is its use for the optimization of
chemical injection. Many chemicals are injected at different points
in a subsea installation to manage a flow assurance problem. By
sampling the fluid at the injector output after the inhibitor is
mixed with the production fluid, it is possible to assess the
efficiency of the chemical treatment and optimize the quantity of
chemical to be injected. For example, the measurements of a phase
behavior analyzer can be used to assess the efficiency of the
treatment. By comparing the phase behavior in real time, with the
operation safety envelop, it is possible to optimize the volume or
the type of chemical injected.
[0117] The measurement from the fluid sampling or analysis device
26 can also be used for a more accurate estimation of the flow rate
from each of the different phases from a multiphase flowmeter. An
important input parameter of a multiphase flow meter used in the
oil and gas industry is the density of each phase. The fluid
analysis device of FIG. 9 could provide an estimation of the
density of each phase that could be feedback in real-time to the
multiphase flow meter for a more accurate estimation of individual
flow rate.
[0118] In the subsea configuration of equipment illustrated in FIG.
14, the fluid flow from the different wellheads is mixed through
the manifolds before being brought back to the surface. The problem
of identifying the contribution of each well is known in the art as
allocation. The fluids before mixing can come from different
formations and from different pay zones. In addition, operators may
sometimes share export lines. In terms of revenue sharing,
allocation is extremely important. For allocation, fluid properties
as well as flow rate must be considered. Further, in terms of fluid
properties, from an allocation standpoint, the important parameters
are H2S content, CO2 content as well as hydrocarbon phase
composition. Therefore fluid analysis data obtained from the
apparatus 10 could be used for real time correction of allocation
calculation.
* * * * *