Subsea Development from Pore to Process
As oil companies step out into deeper waters, operators may discover that finding
oil and gas is the easy part—the real challenge lies in moving produced fluids from
the reservoir to the processing facility.
Amin Amin
Mark Riding
Randy Shepler
Eric Smedstad
Rosharon, Texas, USA
John Ratulowski
Shell Global Solutions (US Inc.)
Houston, Texas
For help in preparation of this article, thanks to Hussein
Alboudwarej, Moin Muhammad and Shawn Taylor,
Edmonton, Alberta, Canada; Kunal Dutta-Roy, James Garner
and John Kerr, Rosharon, Texas; and Lorne Simmons,
Sugar Land, Texas.
CHDT (Cased Hole Dynamics Tester), FloWatcher,
LFA (Live Fluid Analyzer for MDT tool), MDT (Modular
Formation Dynamics Tester), MultiSensor, OCM (Oil-Base
Contamination Monitor), OFA (Optical Fluid Analyzer),
Oilphase-DBR, PhaseWatcher, PIPESIM, Sensa, Vx,
WellWatcher and XLift are marks of Schlumberger.
1. Crabtree M, Eslinger D, Fletcher P, Miller M, Johnson A
and King G: “Fighting Scale—Removal and Prevention,”
Oilfield Review 11, no. 3 (Autumn 1999): 30–45.
4
To replace reserves from their fields on the
continental shelf, exploration and production
companies around the world are turning to
deepwater prospects. These prospects often
require an operator to fabricate a floating processing facility and move it onto the concession
before starting production. Some reservoirs,
however, are simply not large enough to justify
the expense of a dedicated processing facility.
Rather than let such fields lie fallow, operators
can take advantage of existing infrastructure by
tying marginal-field production back to platforms that serve other fields. Operators whose
fields have matured beyond peak production
take a similar approach. With excess production
capacity available at their platforms, these
operators may seek to host production from
other fields—even from other companies.
To reach a processing facility, production
from remote reservoirs must flow through
jumpers, manifolds, flowlines and risers designed
to withstand deep-ocean pressures, temperatures
and currents (next page). However, extending
tieback distances for several miles is not without
problems. Hydrocarbons dominated by heavy
fractions often have high viscosity; moving such
fluids from deepwater reservoirs can be difficult.
Any number of factors, acting singly or in
concert, can lead to scale, hydrate, asphaltene or
wax deposition in subsea flowlines. 1 These
deposits can be severe enough to impede flow to
surface processing facilities.
The onset and magnitude of flow-assurance
problems are largely influenced by the chemical
compositions of produced fluids and by their
temperatures and pressures as they travel from
one end of a production system to the other.
These problems can be mitigated. Through testing, design and monitoring, subsea production
assurance experts are able to anticipate and
manage conditions that affect hydraulic performance of production systems.
This article discusses production challenges
faced by deepwater operators. It also describes
new technologies and services developed to overcome obstacles to the flow of oil and gas from
subsea wellhead to platform. A Gulf of Mexico
scenario demonstrates how surveillance is
closely linked to flow-boosting and flowassurance functions in a subsea completion and
flowline tieback.
Setting the Stage
Subsea production systems do not remain static
over the course of their productive lives—
reservoir pressure declines, fluid composition
changes with depletion, water production
increases, and corrosion takes its toll. From
sandface to separator, operators must plan for
change. Facility upgrades and modifications are
generally more difficult and expensive in subsea
fields; therefore, operators must anticipate as
many of these changes as possible during the
original facilities design, and then manage the rest.
Oilfield Review
Dynamically positioned
semisubmersible drilling rig
Platform
Riser
Subsea blowout
preventer stack
Flowlines
Subsea
booster pump
Electrohydraulic
umbilical line
Openhole fluid sampling
Umbilical
termination assembly
Subsea trees
Subsea
monitoring
and control
module
Multiphase
flowmeter
Manifold
Subsea tree
Electrohydraulic flying lead to manifold
Electrohydraulic flying lead to subsea tree
Flexible
flowline
jumper
Electrical
submersible pump
Spring 2005
Subsea layout. Generally, oil, gas and water flow from wellbore to subsea tree, thence
to jumper, manifold and flowline, before finally reaching a riser that pipes it to surface
for processing. Pressurized reservoir fluid samples collected in an openhole wellbore
(upper left) will be analyzed at surface to characterize the physical properties of the
fluids. An electrical submersible pump in a completed well (foreground, lower left)
propels reservoir fluids thousands of feet up to the wellhead and beyond. Subsea trees
positioned atop each completed well contain pressure control valves and chemical
injection ports. A flowline jumper carries produced fluids from each subsea tree to
the manifold, which commingles production from the wells before sending it through a
flowline to a platform. A subsea booster pump, located downstream of the manifold,
pumps produced fluids along the length of the flowline and up the riser to the platform’s
production deck. Umbilical lines from the platform run back to a subsea umbilical
termination assembly before branching off to each wellhead and then to the manifold.
The umbilicals supply electric and hydraulic power for wellhead or manifold control
functions, and chemicals to suppress the formation of scale and hydrates in the
production stream. The umbilical lines also carry bidirectional communications and
control instructions between the platform, wellhead and downhole devices. In this
illustration, production from each well is allocated through a multiphase flowmeter
mounted on the manifold.
5
Sea level
100s of
feet
Flowline
1,000s of
feet
Wellhead
> Fighting an uphill battle. Oil, gas and water are sent upslope through miles of flowline and hundreds
or thousands of feet of elevation, only to come up against more backpressure at the production riser.
To push production up the riser to the platform, a subsea booster pump may be employed.
Water depth represents the greatest challenge to subsea production. It dominates all
process, design and economic considerations. To
exploit deepwater and ultradeepwater reservoirs,
operators must drill and complete wells in water
depths of 1,000 to 10,000 ft [305 m to 3,048 m] or
greater.2 Reservoirs that do not merit a dedicated
platform often must be produced from as few as
one to three wells. This number may also serve
adequately in larger reservoirs—the challenge
and expense of drilling in such deep waters will
often dictate the minimum number of wells to be
drilled in a reservoir. These water depths will
also dictate that most wells be completed
subsea, with wellheads and production-control
equipment placed at the seafloor.
From deepwater and ultradeepwater subsea
completions, produced fluids are sent to a production facility (above). In marginal fields,
operators may seek a nearby facility with capacity to handle their production. In some cases,
this facility may be miles away, in the shallower
water depths—200 to 600 ft [61 to 183 m]—of
the continental shelf.3
Fluid produced from a deepwater reservoir
experiences significant changes in pressure and
temperature as it moves from pore space to production riser. Reservoir pressure drives fluids
from formation pore spaces to the low-pressure
sink of a wellbore. Inside the wellbore, some
form of artificial lift may be required to produce
the fluids to the subsea wellhead, or tree. In
these cases, a gas lift system or electrical
submersible pump (ESP) will be employed.
While artificial lift adds energy to the well
flow, it also imparts changes in heat, pressure or
density to the produced fluids. For example,
gas lift works by injecting natural gas into the
2. Drillers have long endeavored to reach the 10,000-ft
mark. The record was finally broken in October 2003,
when the Discoverer Deep Seas, owned by Transocean
Inc., drilled an exploration well for ChevronTexaco on its
Toledo prospect. This Gulf of Mexico well, located in
Alaminos Canyon Block 951, was drilled in 10,011 feet
[3,051 m] of water.
3. A prime example is the Canyon Express Project, developed
to produce gas from three separate deepwater fields.
Production from two wells in the Camden Hills field
(developed by Marathon Oil Company), four wells in the
Aconcagua field (developed by TotalFinaElf, now Total),
and four wells in the King’s Peak field (discovered by
Amoco, now BP) is tied back to a platform some 55 miles
[89 km] north of Camden Hills. Over this distance, the
flowline must climb from a water depth of 7,200 ft
[2,195 m] at Camden Hills to reach the production platform
in 299 ft [91 m] of water at Main Pass Block 261. For a
review of Canyon Express operations: Carré G, Pradié E,
Christie A, Delabroy L, Greeson B, Watson G, Fett D,
Piedras J, Jenkins R, Schmidt D, Kolstad E, Stimatz G
and Taylor G: “High Expectations for Deepwater Wells,”
Oilfield Review 14, no. 4 (Winter 2002/2003): 36–51.
4. For more on electrical submersible pump applications,
problems and monitoring: Bates R, Cosad C, Fielder L,
Kosmala A, Hudson S, Romero G and Shanmugam V:
“Taking the Pulse of Producing Wells—ESP Surveillance,”
Oilfield Review 16, no. 2 (Summer 2004): 16–25.
Fleshman R and Lekic HO: “Artificial Lift for High-Volume
Production,” Oilfield Review 11, no. 1 (Spring 1999): 49–63.
5. Multiphase flowmeters are not used to measure
production in all subsea developments. Another way to
determine production from each well in a field is to allocate by difference. This technique requires the operator
to shut in production from a well, then measure the
decrease in production at the separator. By shutting in
production separately from each well in the field, the
operator can determine its contribution to total output.
For more on multiphase flowmeters: Atkinson I,
Theuveny B, Berard M, Conort G, Groves J, Lowe T,
McDiarmid A, Mehdizadeh P, Perciot P, Pinguet B,
Smith G and Williamson KJ: “A New Horizon in
Multiphase Flow Measurement,” Oilfield Review 16,
no. 4 (Winter 2004/2005): 52–63.
6. A hydrate is a crystalline solid consisting of water with
gas molecules in an ice-like cage structure. Water
molecules form a lattice structure into which many types
of gas molecules can fit. Under high pressure, gas
hydrates can form in temperatures well above freezing.
Gas hydrates are thermodynamically suppressed by
adding antifreeze materials such as salts or glycols. Gas
hydrates are found in nature, on the bottom of cold seas
and in arctic permafrost regions. In such environments,
hydrates affect both drilling and production operations.
For more on hydrate control while drilling: Ebeltoft H,
Yousif M and Soergaard E: “Hydrate Control During
Deep-water Drilling: Overview and New Drilling Fluids
Formulations,” paper SPE 38567, presented at the
SPE Annual Technical Conference and Exhibition,
San Antonio, Texas, USA, October 5–8, 1997.
6
production fluids. The injected gas reduces the
fluid density, thus helping reservoir pressure lift
the fluid to the tree. By contrast, impeller vanes
inside an ESP subject fluids to centrifugal force
and thereby compress the fluids. Furthermore,
an ESP relies on reservoir fluids to cool its
electric motor, thrust bearing and pump—the
exact amount of heat exchanged depends on
such variables as the composition of the fluid
(especially the volume of gas contained within
the fluid) and the efficiency of the mechanical
system. As it discharges from the ESP, the fluid
will carry this extra heat toward the subsea tree.4
Deep waters are cold; temperatures can drop
to around 39°F [4°C] at the seafloor. These
temperatures must be accommodated beyond
the subsea tree, where fluids enter a flowline
jumper that connects to a production manifold.
The change in fluid temperature between the
tree and the jumper will depend on the thermal
management strategy of the operator. Some operators use electrically heated flowlines; some use
foam-insulated pipe; some bury the flowline
beneath the seafloor for insulation; others use no
additional heat or insulation at all (next page, top).
Before reaching the subsea manifold, the
produced fluid may pass through a multiphase
flowmeter, used to measure production from
each well. 5 The oil, water and gas phases of
the reservoir fluid mix as they pass through the
flowmeter’s venturi. Upon entering the manifold,
the fluid is commingled with production
from other wells before exiting the manifold to
a flowline.
Flowlines tie fields back to a production
facility—often a fixed production platform in
shallower waters—but in some cases a tension
7. The bubblepoint marks the pressure and temperature
conditions under which the first bubble of gas breaks
out of solution in an oil. Initially, petroleum reservoir oils
contain some natural gas in solution. Often the oil is
saturated with gas when discovered, meaning that the
oil is holding all the gas that it can at reservoir temperature and pressure, and that it is at its bubblepoint.
Occasionally, the oil will be undersaturated. In this case,
as the pressure is lowered, the pressure at which the
first gas begins to evolve from the oil is defined as
the bubblepoint.
8. Similar flow behaviors are exhibited in deviated or
horizontal wells; for more on multiphase flow in deviated
wells: Baldauff J, Runge T, Cadenhead J, Faur M,
Marcus R, Mas C, North R and Oddie G: “Profiling and
Quantifying Complex Multiphase Flow,” Oilfield Review 16,
no. 3 (Autumn 2004): 4–13.
9. The Joule-Thompson effect produces a change in
temperature as gas expands. It is often assumed that
this change results in lower temperature. The change in
temperature, however, depends on the inversion point of
the gas. Each gas has its own inversion point, defined by
temperature and pressure. Below the inversion point, the
gas will cool, and above that point, it will heat up.
Oilfield Review
Temperature and Pressure Interactions
Changes in temperature and pressure along the
length of the flowline promote asphaltene
precipitation and wax deposition. Cold seafloor
temperatures also promote formation of
hydrates.6 Furthermore, as the oil crosses its
bubblepoint pressure, light hydrocarbon fractions evolve as a gas phase.7 This, in turn, makes
the oil more viscous, increasing backpressure on
the system and changing flow patterns by
increasing slippage, or differences in flow rates,
between produced oil, gas and water phases.
If flow velocity is not sufficient to keep the
production stream thoroughly mixed along the
entire length of flowline, then gravity segregation
of oil, gas and water may take place. This condition allows lighter phases to flow along the high
side of the flowline, with denser phases flowing
along the bottom. 8 Each phase flows at a
different speed, depending on the inclination of
the flowline.
Any vertical undulation in the flowline will
allow one phase to slow with respect to the
others; as the flowline climbs, the lighter gas
phase can slip past the heavier liquid, while in
downhill sections, the liquid can overtake the gas
phase. The erratic production regime that results
from such slippage between phases is known as
slug flow. This terrain-induced slugging can
adversely impact downstream processing facilities, and must be taken into consideration during
the design phase of the project. A further consequence of gravity segregation is that liquids can
accumulate in low-lying sections of the flowline
and promote long-term corrosion.
Commingling different production streams
from separate reservoir compartments can lead
to incompatible fluid mixing and subsequent
Spring 2005
Centralizer
Flowline
Carrier pipe
Optical
fiber
Passive insulation
Heating cables
> Pipe-in-pipe flowline. Some operators actively heat their flowlines as part
of a thermal management strategy. In this example, insulation provides
additional thermal support to electrical heating cables. Optical fiber can be
mounted along the length of the flowline as part of a distributed temperature
sensor system.
16,000
Hydrate
formation
line
14,000
Upper APE
12,000
WAT line
Pressure, psi
leg platform, floating production storage and
offloading vessel (FPSO), spar, semisubmersible,
caisson or even a shore-based processing facility
could be used. When tieback distance and pressure drop preclude natural production flow,
reservoir fluids must pass through a subsea
booster pump before being sent through a flowline and up a production riser.
The flowline might not trace a constant
azimuth from wellhead to platform, but may
bend slightly to follow the course of a previously
surveyed right-of-way. As it follows the undulating topography of the seafloor, the flowline
climbs gradually from the colder, deeper reaches
of the field up to relatively warmer, shallower
waters of the continental shelf, where the host
platform stands. If not managed properly, a
scenario such as this can lead to trouble.
A
10,000
Reservoir
8,000
B
6,000
C
4,000
D
E
2,000
Bubblepoint line
F
Flowline
0
0
50
100
150
Temperature, °F
200
250
300
> Oil phase diagram from a deepwater field in the Gulf of Mexico. Depending
on the design and operation of the production system, some or all of the
phase boundaries seen in this diagram may be crossed as oil is produced
from a reservoir. The oil follows a path along a line of steadily decreasing
temperature and pressure as it moves from reservoir, A, to flowline, F.
Temperature and pressure drops cause asphaltene to separate from solution,
B, when the oil crosses the upper edge of the asphaltene precipitation
envelope (Upper APE). Next, wax begins to form, C, as the oil crosses the wax
appearance temperature (WAT) line. It enters the hydrate range, D, before
crossing its bubblepoint line, E. Beyond this line, lighter hydrocarbons evolve
as gas to form a two-phase fluid before the fluid finally reaches the flowline, F.
formation of organic or inorganic solids within
the flowline. Pressure is released as fluids travel
up the riser. As the gas phase of the fluid
expands, Joule-Thompson cooling may lead to
the formation of hydrates within the riser.9
Asphaltene, wax and hydrate precipitation
behaviors are determined in laboratories from
samples collected downhole. The results indicate
ranges of operation that require mitigation
(above). A phase diagram is central to understanding the challenges faced by deepwater
operators, who must pay special attention to
components that fall out of reservoir fluids
with changes in pressure and temperature.
Particularly troublesome components include
asphaltenes, waxes and hydrates.
7
Asphaltenes are complex molecules occurring in many hydrocarbons. 10 These organic
compounds become destabilized and precipitate
as a result of shear in turbulent flow conditions;
they can also precipitate with changes in
pressure or temperature, or with changes in
composition resulting from blending or commingling of incompatible fluids during production.
Precipitated asphaltene particles can grow to
create significant blockages in wellbore tubulars
and flowlines.
Asphaltenes begin to precipitate in a pressure
range between the reservoir pressure and the
bubblepoint, known as the asphaltene precipitation envelope (APE). The APE is bounded on its
upper edge by relatively high pressures at low
temperatures and drops in pressure as temperature increases. At a given temperature within the
APE, asphaltene precipitation typically increases
as pressure decreases, reaching a maximum at the
bubblepoint pressure, at which point precipitation
decreases as pressure continues to decrease. The
oil becomes denser below the bubblepoint
pressure, as solution gas evolves from the oil,
allowing previously precipitated asphaltenes to
partially or completely resolubilize.
Paraffin or wax produced in crude oils can
adversely affect production by precipitation and
deposition within flowlines, causing blockages, or
by increasing the fluid viscosity through gelling.
Wax precipitates over a fairly wide range of
pressures, but this phenomenon is temperaturedependent. On a phase diagram, this pressure
range lies to the left of the wax appearance temperature (WAT) line. The wax appearance
temperature is that temperature at which a solid
wax phase forms within a hydrocarbon fluid, at a
given pressure. Below the wax appearance
temperature, significant viscosity increase,
deposition and gelling are possible. The WAT falls
slowly with pressure until it reaches the bubblepoint of the oil. Below the bubblepoint pressure,
the WAT increases with decreasing pressure.
Two other important parameters relate to
wax in the production stream: pour point and gel
strength. The pour point is the temperature, at a
given pressure, at which the static fluid may form
a gel. If a shutdown, blockage or flow interruption allows the fluid in the flowline to gel, it will
not start to flow again until a certain minimum
stress is applied. This yield stress is called the
“gel strength.”
Hydrates are icy crystalline structures that
contain gas molecules trapped in the spaces
between hydrogen-bonded water molecules.11
Hydrates exist at higher temperatures than ice,
and can coexist with water or ice depending on
8
temperature and pressure conditions. Hydrates
pose a plugging hazard to chokes, pipelines,
separators, flowlines and valves. The hydrateformation line maintains a relatively steady
temperature across a wide range of pressures
until it intersects the bubblepoint line, below
which the hydrate-formation temperature
decreases with decreasing pressure.
Stacking the Deck
Deep water to shallow, high pressure to low, cold
temperature to warm—these are the changes to
which oil, gas and water are subjected as they
are produced to surface. Understanding the
phase behaviors that accompany these changes
and predicting their timing and magnitude are
keys to developing successful design, operation
and remediation strategies that maximize return
on investment. This is the role of a subsea
production assurance team.
The realm of the subsea production assurance team extends from reservoir to riser,
helping offshore operators manage challenges to
flow imposed by low temperatures, high
pressures and extended tieback distances. Team
members specialize in flow prediction and
modeling, fluid analysis, artificial lift, multiphase
boosting, metering and allocation, measurement,
monitoring and control. These experts provide a
fully integrated multidisciplinary approach to
optimizing production from subsea fields.
Subsea production assurance can be divided
into three interrelated functions: flow assurance,
flow boosting and flow surveillance. Flow assurance involves analysis of reservoir fluid samples to
characterize phase behaviors and anticipate associated flow problems so that production facilities
can be designed and operated to prevent or
manage these problems. Flow boosting involves
the integrated design, placement and operation of
artificial lift systems and subsea booster pumps,
which are combined to overcome pressures
between the reservoir and the surface production
facility. Flow surveillance is used in a feedback
loop to measure pressure, temperature, flow rates
and a host of other variables that are instrumental
in fine-tuning the operation of pumps, chemical
injectors and other components to optimize
performance of the production system.
Subsea Flow Assurance
To optimize return on investment, operators
must identify and manage any changes that
might affect reservoir fluids as they move
through the production system to the processing
facility. Some of these changes are counterintuitive, and are recognized only through
Downhole
measurement
and sampling
Laboratory
analysis
Modeling
System
selection
Prevention
strategy
Remediation
strategy
> Typical flow-assurance design process.
Downhole pressures and in-situ fluid properties
are measured, and fluid samples are retrieved for
detailed laboratory analysis. The resulting
laboratory data are downloaded to specialized
engineering software to model variations in the
production system. These models are used to
formulate flow-assurance management strategies.
analysis of reservoir fluid samples and modeling
of fluid behaviors between the reservoir and the
processing facility. Flow-assurance specialists
provide a multidisciplinary approach to fluid
sampling, analysis and modeling. The information derived from analysis and modeling of fluid
behavior serves as a basis for developing an
overall production strategy.
Deposition of paraffin, hydrates, asphaltenes,
scales, and other such flow-assurance issues
must be addressed early in the design stage of
production systems. In fact, the flow-assurance
work process begins with formation fluid sampling during the drilling stage of the exploration
and appraisal program (above).12
Analysis of reservoir fluid samples is instrumental in defining phase behaviors and physical
properties of oil, gas and water produced in a
reservoir. More importantly, it will identify and
characterize the phase behavior of waxes,
asphaltenes and hydrates that precipitate from
the reservoir fluids with changes in temperature
and pressure. Other important components of
the production stream will be revealed through
sample analysis. For example, some reservoir
fluids contain trace amounts of corrosives,
such as carbon dioxide, hydrogen sulfide or
mercury; others may contain elements such as
nickel or vanadium that inhibit downstream
refining catalysts.
Properties of produced fluids impact the
design of a production facility—its components,
metallurgy, operational plans, contingency plans
and remediation programs. However, data
collected on poor-quality samples provide equally
Oilfield Review
C
Nitrogen-charged fluid
A
Fluid at initial reservoir
temperature and pressure
h
Asp
Liquid
e
en
alt
pre
cip
i
Single-phase
sample
tat
i
D
on
e
nve
lo
pe
100%
Pressure
Asphaltene
Critical point
75%
Multiphase zone
50%
n
,%
o
cti
i
ra
df
u
Liq
B
Multiphase
sample
25%
Gas
Liquid, %
0%
Temperature
Single-phase bottomhole sampler
Conventional bottomhole sampler
> Pressure-compensated fluid sampling. This phase diagram illustrates the changes in temperature
and pressure to which fluid samples will be subjected as they are drawn from a reservoir to the
surface. Point A shows a single-phase sample taken at reservoir temperature and pressure. As it
reaches the surface in a conventional sample container, the reduction in temperature and
subsequent drop in pressure cause asphaltenes to come out of solution and lighter components to
flash into a gaseous phase, at Point B. An identical sample drawn into a single-phase bottomhole
sampler will be pressurized to Point C before being brought to surface. Under pressure, this sample
does not cross the asphaltene precipitation envelope before reaching ambient temperature at Point D.
poor results, leading to over- or underdesign of
the production facility or mistaken assumptions
about operating procedures.
Reservoir fluid properties are best determined with testing of representative samples.
Samples can be taken using wireline-conveyed
formation testers, such as the openhole MDT
Modular Formation Dynamics Tester or the
CHDT Cased Hole Dynamics Tester, during drillstem testing (DST) or from a surface separator.
Samples taken using wireline formation testers
represent a value from a point in the wellbore,
while samples taken during a well test represent
an average over a producing interval. Fluid
properties, however, can vary across a field or
across a reservoir.13
Whenever possible, samples from multiple
depths or multiple wells should be considered to
identify and quantify variations. Understanding
the magnitude and nature of compositional
variation is important for system design. These
samples should be obtained early in the life of the
field, during the drilling stage, before production
depletes the reservoir below saturation pressure.
Flow-assurance models highlight the need for
representative samples. Ideal fluid samples are
Spring 2005
obtained under reservoir conditions, above
bubblepoint, with no asphaltene precipitation,
and with little or no contamination. At the laboratory, such a sample would be virtually identical
to the fluid in the reservoir. Unfortunately, some
of the very same solids that come out of solution
during production also come out of solution
during the sampling process.14 As samples are
brought to surface, changes in temperature and
pressure may lead to phase changes that alter
the fluid sample. Samples can also be altered by
contamination, frequently caused by drilling
fluid filtrate.
Advances in Sampling and Analysis
Fortunately, there are strategies for obtaining
good samples that reduce the potential for
contamination and phase changes. For example,
the MDT tool can take downhole fluid samples at
reservoir temperature and pressure. An OFA
Optical Fluid Analyzer system within the MDT
tool provides a qualitative measure of contamination by mud filtrate entering from the invaded
zone of the formation surrounding a wellbore.
For oil-base muds, sample contamination can be
quantitatively monitored using the OCM Oil-Base
Contamination Monitor.15 A methane detector in
the LFA Live Fluid Analyzer module of the MDT
tool provides a measure of gas content in the oil
phase and allows calculation of the gas/oil ratio
(GOR). This module can verify that the fluid
pressure has not dropped below bubblepoint
during sampling.16 Dropping below the bubblepoint would turn a single-phase fluid diphasic
and render the sample unrepresentative.
In the past, downhole samples would
invariably drop below bubblepoint as temperature and pressure decreased while the sample
tool was brought to surface. Sample chambers
carried by early downhole formation testers were
designed to withstand pressures downhole, but
were not designed to maintain such pressure on
the fluid sample itself. Oilphase, acquired by
Schlumberger in 1993, developed a single-phase
multisample chamber to overcome this problem.
After the downhole MDT pumpout module
fills a single-phase multisample chamber at
reservoir pressure, a nitrogen charge provides
overpressure to compensate for any temperatureinduced pressure drop as the sample is retrieved
to surface. This prevents flashing of the
sample to keep the fluid in single phase (left).
In many cases, a single-phase multisample
10. Asphaltenes are defined as the n-pentane or n-heptane
insoluble components of petroleum crudes that are soluble in toluene. For further information: Jamaluddin AKM,
Joshi N, Joseph D, D’Cruz D, Ross B, Creek J, Kabir CS
and McFadden JD: “Laboratory Techniques to Define the
Asphaltene Precipitation Envelope,” Petroleum Society
of the Canadian Institute of Mining, Metallurgy &
Petroleum, Paper 2000-68, presented at the Petroleum
Society’s Canadian International Petroleum Conference
2000, Calgary, June 4–8, 2000.
11. For more on gas hydrates: Collett TS, Lewis R and
Uchida T: “Growing Interest in Gas Hydrates,” Oilfield
Review 12, no. 2 (Summer 2000): 43–57.
12. Ratulowski J, Amin A, Hammami A, Muhammad M and
Riding M: “Flow Assurance and Subsea Productivity:
Closing the Loop with Connectivity and Measurements,”
paper SPE 90244, presented at the SPE Annual
Technical Conference and Exhibition, Houston,
September 26–29, 2004.
13. Ratulowski J, Fuex A, Westrich JT and Seiler JJ:
“Theoretical and Experimental Investigation of
Isothermal Compositional Grading,” paper SPE 84777,
SPE Reservoir Evaluation and Engineering 6, no. 3
(June 2003): 168–175.
For fluid property variation within a vertical wellbore:
Betancourt S, Fujisawa G, Mullins OC, Carnegie A,
Dong C, Kurkjian A, Eriksen KO, Haggag M, Jaramillo AR
and Terabayashi H: “Analyzing Hydrocarbons in the
Borehole,” Oilfield Review 15, no. 3 (Autumn 2003): 54–61.
14. Ratulowski et al, reference 12.
15. For more on the measurement of mud contamination in
downhole fluid samples: Andrews JR, Beck G, Chen A,
Cribbs M, Fadnes FH, Irvine-Fortescue J, Williams S,
Hashem M, Jamaluddin A, Kurkjian A, Sass B, Mullins
OC, Rylander E and Van Dusen A: “Quantifying
Contamination Using Color of Crude and Condensate,”
Oilfield Review 13, no. 3 (Autumn 2001): 24–43.
16. For more on pressure and temperature effects on
hydrocarbon samples, and a discussion on downhole
fluid-property evaluation tools: Betancourt et al,
reference 13.
9
chamber will be run in conjunction with a multisample module to allow pressurized reservoir
fluid samples to be transported offsite to a
pressure-volume-temperature (PVT) fluid
analysis laboratory.
These field-proven sampling systems are also
used in cased-hole applications. The CHDT tool is
fully combinable with MDT modules such as the
pumpout module, multisample module and the
OFA module. Other formation fluid samples may
be obtained with a DST-conveyed sample carrier
that complements existing wireline-conveyed
samplers and surface sampling services. These
carriers may be employed to collect samples in
wells containing hydrogen sulfide and in hightemperature, high-pressure or heavy-oil wells.
At the surface, fluid samples can be obtained
from a separator. In producing wells, recombined
fluid samples from a separator may be the only
option available for determining reservoir phase
behavior. Oilphase-DBR fluid sampling and
analysis service provides single-phase sample
bottles for transporting pressurized fluid samples
and can also provide bottles for transporting
pressurized gas samples.
Analysts take an incremental approach to
sample testing, allowing initial results to dictate
the course of subsequent tests. First, the composition and basic fluid properties of the sample are
analyzed. Next, samples are subjected to wax,
asphaltene and hydrate screening; samples that
screen positive are subjected to further detailed
analysis. Live fluid samples—those in which solution gas is preserved in oil samples, or in which
heavy ends are maintained in the vapor phase of
gas samples—are tested under special laboratory
conditions. PVT tests, gas chromatography
and mass spectrometry help to analyze phase
behavior, fluid composition and flow properties.
The Oilphase-DBR service uses several
special technologies to analyze reservoir fluids
and quantify conditions that promote deposition
of paraffins, hydrates and asphaltenes in the
production system. Hydrate-formation conditions
are measured in both the single-phase and twophase regions, while precipitation boundaries,
growth kinetics, morphology and solubility are
characterized both visually and quantitatively.
A laser-based solids detection system
evaluates changes in pressure, temperature or
composition to define the point at which solids
precipitate in a sample. The solids detection
system projects near-infrared laser light through
reservoir fluid in a special PVT cell. The intensity
of transmitted laser light decreases at the onset
of asphaltene precipitation. A high-pressure
microscope allows analysts to directly observe the
10
onset and growth of organic solid precipitates, at
pressures to 20,000 psi [138 MPa] and at temperatures to 392°F [200°C]. This microscope can
define the quantity and morphology of organic
solids as they grow in order to evaluate and
optimize the effectiveness of various chemicals
for solids inhibition or remediation. A controlledstress high-pressure rheometer operable to
6,000 psi [41.3 MPa] and 302°F [150°C] is used to
define the rheology of waxy crudes.
To better understand how paraffin, scale and
asphaltene are deposited, analysts use a rotating
shear deposition cell to model turbulent flow and
shear under pressure and temperature conditions found inside a flowline (right). Because
surface irregularities such as rust, pitting or
porosity influence deposition rates, special
sleeves can be inserted in the cell to simulate
the inner surface of the flowline. After running
the shear deposition cell, analysts remove the
sleeve inserts to measure the thickness and
composition of the deposits.
These advanced technologies aid the production assurance specialists in defining behaviors
of reservoir fluids to reduce uncertainty and
potential overdesign of the production system.
Results from fluid sample tests are fed into
modeling software to address flow-assurance
challenges. PIPESIM production system analysis
modeling can be employed to predict liquid
holdup and pressure loss, along with simulating
flow regimes and multiphase flow between wells,
pipelines and process equipment. Using this
modeling software, subsea production assurance
specialists determine optimal pipeline and
equipment size, carry out heat transfer calculations and generate flow models to predict
conditions under which hydrates form. Just as
important, it also models the effects of hydrate
inhibitors or remediation systems. These models
are integrated into the front-end engineering
design process to develop optimal production
systems and operability strategies that are
neither over- nor underdesigned.
Flow-assurance management strategies,
developed on the basis of fluid sample analysis,
generally take the form of thermal management,
pressure management, chemical treatments and
mechanical remediation.17 Thermal management
typically consists of circulating hot fluids, electrical heating and flowline insulation. Pressure
management can be carried out by downhole
pumps and seafloor booster pumps. Chemical
treatments are injected into the production
system to inhibit corrosion or deposition of wax,
scale and hydrates. Mechanical remediation
usually involves pigging of flowlines.18
Rotating
cylinder
Electrical
heating
cartridge
Deposit
Oil
Stationary
cylinder
Coolant
> Cross section of a shear deposition cell. To
simulate conditions within a flowline, shear forces
are generated in the reservoir fluid sample as it
spins between a rotating inner cylinder and a
stationary outer cylinder. Afterward, the thickness
and composition of any deposited materials are
measured.
Managing Pressure through Flow Boosting
Beyond its critical role in controlling phase
changes of reservoir fluids, pressure is the
driving force that moves those fluids from pore
spaces to processing facilities. To produce subsea
wells, pressure from the reservoir must work
against high static backpressures inherent in
extended tiebacks and long risers. Backpressure
comprises both frictional resistance to flow and
pressure head caused by the elevation change
between the subsea tree and the surface facility.
Backpressure invariably wins out as reservoir
pressure declines over time.
Conventional dry-tree wells are routinely
drawn down to wellhead pressures of 100 to
200 psi [689 to 1,379 kPa] before being
abandoned.19 By contrast, subsea wells with long
tiebacks may have to be abandoned much earlier
and at higher pressures, sometimes as high as
2,000 psi [13.8 MPa] at the subsea, or wet, tree.20
Such high abandonment pressures are dictated
by backpressure at the wet tree, which increases
in proportion to the length of flowline and riser,
in addition to the number of constrictions
caused by fittings or deposits within the
production system.
Increased backpressure requires a higher
bottomhole flowing pressure to maintain
production. Typically, without some form of artificial lift, this increased backpressure results in a
decline in reservoir production. Therefore, to
continue producing reservoir fluids through the
Oilfield Review
Cooling
pipes
Electric
motor
Outlet
Inlet
Gas
Liquid
Helicoaxial
pump
Mixing
section
> Framo subsea multiphase booster pump. This
pump uses a modular design consisting of an
integrated pumping and drive unit. The drive unit
can be powered by electric motor or water
turbine. All components subject to wear and tear
are located in a single, easily retrievable cartridge
that can be serviced from an intervention vessel.
flowline to the processing facility, this backpressure must be reduced.
Flow boosting helps manage pressures in the
production system using two complementary
approaches. First, downhole artificial lift is
employed where needed, especially when low
reservoir drive pressure cannot sustain acceptable production rates, or low gas/oil ratios (GOR)
are combined with highly viscous oil. Second,
seafloor booster pumps are used to propel
produced fluids along the length of the flowline
and up the production riser.
Artificial lift systems are installed to boost
energy downhole or to decrease effective fluid
density in a wellbore, thereby reducing hydrostatic load on the producing formation. Artificial
lift improves recovery by lowering the bottomhole pressure at which a well must be
abandoned. Gas lift and electrical submersible
pumps account for the two most common forms
of artificial lift in subsea wells.21
Operators routinely use gas lift to maximize
drawdown and increase total production of their
Spring 2005
offshore oil wells. A gas lift system draws highpressure gas from a surface production facility
and injects the gas into a well’s casing annulus.
Gas is then injected into the tubing fluids
through a gas lift valve housed in a side-pocket
mandrel made up in the tubing string. The
injected gas lowers the density of produced fluids
in the production tubing and lifts the fluids to
the wellhead. By lowering the weight of the
hydrostatic column in the tubing, the gas
decreases backpressure on the producing
formation, allowing more flow from the reservoir
into the well.
Total recovery will increase with the depth at
which the gas is injected. This depth is limited by
the operating pressure rating of standard gas lift
valves. Surface compression is required to push
the lift gas to deeper injection points, but this
compression pressure must not exceed the maximum operating pressure rating of the gas lift
valve. Standard gas lift valves are typically rated
to inject gas at operating pressures of 2,500 psi
[17.2 MPa] at valve depth. Beyond this pressure,
the bellows within the valve gradually fatigue,
eventually causing it to fail.
As operators venture into deeper waters,
higher operating pressures and greater lift-valve
depths are required to produce their subsea
wells. These requirements are being addressed
by new developments in gas lift technology. Using
Schlumberger XLift high-pressure gas lift system
technology, gas lift valves with bellows rated at
5,000 psi [34.5 MPa] can handle gas at greater
compression pressures than those allowed by
standard valves. This higher pressure rating
enables the valves to be installed at deeper setpoints, allowing increased drawdown, extended
productive well life and added reserves.
Where heavy crudes, limited access to
injection gas, high water cut or low bottomhole
pressures preclude the gas lift option, an
electrical submersible pump (ESP) can be used.
ESPs generate centrifugal force to pressurize
wellbore fluids and are capable of lifting fluids
from depths of 20,000 ft [6,100 m] or more. With
power ratings up to 1,500 hp [1,119 kW],
they can move up to 100,000 B/D [15,890 m3/d]
of fluids, depending on casing size and
drawdown requirements.22
On the seafloor, multiphase pumps provide
further flow-boosting capabilities that help
extend the life of a field. When backpressure
from a long tieback and riser prevents a well
from flowing naturally, a booster pump installed
near the wellhead can help draw down wellhead
pressure (left). The effect on the well is a reduction in backpressure, which allows increased
17. Ratulowski et al, reference 12.
18. Pigging allows operators to clean or inspect pipelines by
pumping a spherical or cylindrical device, known as a
pig, through the pipe. Fluid flowing through the pipe
propels the pig along the length of the pipeline. Scraper
pigs are fitted with cups, brushes, disks or blades to
clean out rust, wax, scale or debris inside the pipe.
Other pigs, often called smart pigs, can carry cameras,
magnetic or ultrasonic sensors and telemetry devices
to detect corrosion, cracks and gouges, or to measure
temperature, pressure or wax deposition.
19. Offshore completions can be loosely classified as
“dry-tree” or “wet-tree,” depending on where the
wellhead, or “tree” is located. Generally, dry-tree
completions are used in shallow to moderately deep
waters, where a wellhead is placed on a platform,
above sea level. In moderately deep waters, dry trees
can be found on compliant towers, spars and tension leg
platforms. Conversely, a wet tree is a subsea completion
for deep and ultradeep water depths. The wellhead is
situated on the seafloor, and production from the well is
piped from the subsea tree to the platform.
20. Devegowda D and Scott SL: “An Assessment of Subsea
Production Systems,” paper SPE 84045, presented at
SPE Annual Technical Conference and Exhibition, Denver,
October 5–8, 2003.
21. Shepler R, White T, Amin A and Shippen S: “Flow Boosting Key to Subsea Well Productivity,” presented at the
Deepwater Offshore Technology Conference,
New Orleans, November 30–December 2, 2004.
22. Shepler et al, reference 21.
11
The multiphase booster pump plays a critical
role in subsea production when used in conjunction with downhole gas lift. The behavior of
injected gas in the production stream must be
factored into the flowline operability plan when
gas lift is used. Whether it is injected or
liberated, gas will flow along the high side of a
flowline, hampering movement of fluids through
the flowline. 23 However, subsea multiphase
booster pumps are capable of handling a range of
fluid phases from 100% water to 100% gas, and
can manage transient flows generated in the
flowline due to gas separation.
By compressing the gas back into solution,
the ensuing reduction in gas volume allows more
liquid to be carried within the same volume of
pipe. Alternatively, the booster pump can be used
to flow the same volume of fluid through a
smaller diameter flowline. The subsequent
increase in flow velocity helps reduce heat loss,
thus lowering the risk of hydrate formation and
wax buildup.
When used in conjunction with an ESP, seabed
multiphase boosting takes up some of the
burden carried by the downhole pump. In
conventional dry-tree applications, an ESP must
be powerful enough to lift fluids to the separator.
In the case of ultradeep waters, however, the size
of the ESP must be sufficient to pump fluids to the
wet tree, through the tieback, and up the riser to
the topside separator. With extended tiebacks in
flow from the well. Rather than abandon subsea
wells at higher pressures, sometimes as high
as 2,000 psi, operators can use booster pumps
to extend production by reducing wellhead
pressures, in some cases to as little as 50 psi
[345 kPa].
By providing additional pressure for flow
boosting, seafloor booster pumps also fill an
important role in flow assurance. Without sufficient pressure in the flowline, a production
stream will eventually separate into multiple
phases. Gas will evolve out of solution, and
gravity will stratify the fluids. Gas, flowing at the
high side of the pipe, will overtake oil and water
as they flow more slowly along the bottom.
Ensuing transient flow conditions can cause
process upsets in surface production equipment.
Multiphase booster pumps pressurize production streams, compressing the gas, and
sometimes even driving it back into solution
(below). A production stream is expelled from a
multiphase booster pump as a homogeneous liquid, at elevated temperature and pressure and in
a steady-state flow regime. As it exits the booster
pump, the heat imparted by the pump is carried
off by the production stream, thereby helping to
reduce hydrate and wax formation problems. At
the same time, the pressure increase helps boost
flow velocities. The additional heat and pressure
supplied by the pump can have a positive influence on flow assurance.
1
2
3
ultradeep waters, the capacity of the ESP and the
number of pump stages must increase, sometimes
doubling the power from that needed to pump
fluid to surface. However, run life drops substantially as motor size increases.
With a multiphase seabed booster pump, the
size of an ESP can be decreased, thus extending
ESP run life and reducing the number of
required interventions.
Flow Surveillance
To anticipate and manage conditions in subsea
production systems, operators require the
capability to monitor, measure and analyze key
attributes, and they must have some means to
control subsea processes. Production systems
rely on instrumentation and control to predict
and mitigate flow-assurance and flow-boosting
problems. By taking measurements to characterize the system in real time, operators may be
able to minimize chemical consumption
or reduce energy input into the system by
decreasing flowline heating requirements or
pigging frequency.
Important downhole parameters, such as
temperature, pressure, flow rate, fluid density
and water holdup data, can be tracked on a
real-time basis by the FloWatcher integrated
permanent production monitor. Subsea flowmeters, such as PhaseWatcher fixed multiphase
well production monitoring equipment, measure
4
Impeller
Diffuser
> Helicoaxial booster pump. This Framo pump has four stages, with each stage comprising an impeller and a diffuser. The
design combines the capabilities of a centrifugal impeller with an axial gas compressor, and can operate across a range of
phases, from pure liquid to pure gas.
12
Oilfield Review
Sensor
systems
Acquisition
systems
Fluid property
models
Process
models
Operations
Changing parameters
Facilities
simulator
Multiphase
flowmeters
Dynamic data
acquisition system
Distributed
temperature sensor
Thermodynamic
models
Pressure and
temperature gauges
Multiphase
flow models
Electrical
submersible
pump monitors
Static data
storage system
Flowline
simulator
Monitoring
Wellbore
simulator
Optimization
Deposition
models
Model conditioning
> Integrating surveillance into flow assurance. Data such as temperatures, pressures and flow rates are collected from sensors at various points throughout
the production system. Models used during the design stage are conditioned to process the sensor data. These models can then be used to determine the
current state of the system and to optimize the system through a series of “what-if” runs.
multiphase flow rate and holdup, but require no
phase separation and are insensitive to slugs,
foam and emulsions. 24 These systems can be
combined with other sensors, such as sand
detectors, pressure gauges and fiber-optic
distributed temperature sensor (DTS) systems to
provide a constant stream of data for diagnosis
of wellbore and flowline performance. This
information allows the operator to make proactive operational decisions—changing a valve
setting, boosting pump output or starting
chemical injection—based on factual analysis
of validated data.
Data validation is an important aspect of subsea production assurance. Validated data are
required to ensure that decisions are based on
sound, proven information. Data can be validated
by comparing measurements from one sensor to
those from another corroborating sensor. For
example, DTS data can be compared to tree
temperature sensors located in close proximity
to the DTS. In many cases, however, much of the
validation information simply is not available
because of low data transmission rates provided
by production control systems.
Analysis generally requires comparison with
older data and modeling against expected performance. A surveillance workflow collects and
integrates data into a closed loop system to
optimize production (above).25
Spring 2005
The surveillance system utilizes data acquired
by real-time sensors, along with fluid and pressure data obtained during the drilling phase, to
monitor the state of the overall system. The same
engineering models used to design the system can
then be used to evaluate its performance.
Though wellbore and seabed monitoring and
control systems are installed to improve productivity of subsea wells, the capability of these
systems can be hampered by transmission bandwidth. Data transmission systems in the subsea
realm have not always kept pace with sensor
throughput. As subsea and downhole devices
become more intelligent, providing more data
and greater levels of diagnostics and control,
communications may prove to be the weakest
link in the system.
Great volumes of high-speed data must pass
to the surface to provide an operator with realtime control of the production system.26 However,
subsea control commands and production monitoring data are often bundled into a common
transmission system. All data and commands
pass through one of these systems, known as a
production control system (PCS), designed
largely for subsea valve control. Although most
production facilities have topside systems to
securely transmit large volumes of highbandwidth data around the world, seafloor
infrastructure can create information bottlenecks that delay timely analysis and action to
optimize production.
One way around the bottleneck is to separate
safety-critical control functions from subsea
monitoring processes. Separation can be
achieved through an industry-standard surveillance system with a high-bandwidth, networked
communications link to the surface. This communications link can be implemented by installing a
single low-cost fiber in the same umbilical used
for tree control. A subsea monitoring and control
(SMC) module has been developed as a central
connectivity hub for downhole and subsea
instrumentation that works in conjunction with
traditional PCS wellhead safety-valve control
systems. By taking this approach, the operator
can employ a surveillance and monitoring system
without interfering with the subsea safety functions of the PCS—in fact, its only impact is to
reduce the burden of data transmission on the
PCS. At the same time, the SMC permits data
integration topside through standard links, thus
providing the ability to utilize conventional datahandling and analysis systems similar to those
used in processing facilities onshore.
23. Shepler et al, reference 21.
24. Atkinson et al, reference 5.
25. Ratulowski et al, reference 12.
26. Amin A, Smedstad E and Riding M: “Role of Surveillance
in Improving Subsea Productivity,” paper SPE 90209,
presented at the SPE Annual Technical Conference and
Exhibition, Houston, September 26–29, 2004.
13
> Subsea data hub component of the subsea monitoring and control (SMC) module. A remotely operated vehicle (ROV)
inserts a subsea data hub into a receptacle during qualification testing (upper right). The receptacle, mounted to a
subsea tree (lower left), provides wet-connect capability for retrieval or upgrade of the data hub at the seabed. The
subsea data hub (upper left) handles simultaneous input from numerous sensors along the production system, including
third-party sensors operating on industry-standard protocols. It accepts input from a wide range of sensor types, such
as downhole temperature and pressure gauges, single- and multiphase flowmeters, downhole flow-control valves,
distributed temperature sensor systems, electrical submersible pump monitors, subsea multiphase pump monitors and
sand detectors.
The subsea monitoring and control module
allows subsea data acquisition and control
devices to communicate directly between the
subsea data hub and the topside data hub, using
a high-speed data link to avoid passing through
slower intermediary devices. The subsea data
hub connects sensors to the surveillance system
(above). The topside data hub is connected to
data recording, analysis and alarm systems.
The SMC is capable of communicating over
electrical or optical cable at rates up to
100 megabits/second—essentially creating a
seabed local area network. The surveillance
package mounts on a subsea tree or manifold,
and can be expanded or upgraded without affecting production. Compliance with the industry’s
Intelligent Well Interface Standardisation (IWIS)
procedure enables the open, plug-and-play SMC
system to interact seamlessly at optimal transmission rates with any networked combination of
acquisition sensors and control modules from
Schlumberger or third parties.27
14
Surveillance Scenario
Subsea surveillance scenarios have been devised
to test the capacity of the SMC to monitor and
detect flow-boosting and flow-assurance issues.
One laboratory simulation study, based on a
deepwater field in the Gulf of Mexico, relied on
input from several real and simulated instruments physically connected to an SMC. This
input was provided by pressure and temperature
gauges; a FloWatcher integrated production monitor for flow rate, fluid density and holdup
measurements; a Sensa fiber-optic DTS monitoring system; a flow-control valve and simulated
devices representing two ESPs, a subsea multiphase pump and a subsea multiphase flowmeter
(next page, top). This example shows how one
abnormal event can cascade into another,
with potential for adverse impact on the
production system.
In this simulation, electrical windings in one
of the ESP motors began to overheat, setting off
an alarm at the controller workstation when
pump temperature exceeded its specified set
point.28 ESP performance curves indicated that
the pump was operating outside of specifications,
so test personnel took corrective action to return
the pump to original operating conditions before
damage occurred (next page, bottom).
27. The Intelligent Well Interface Standardisation (IWIS)
Panel formed in 1995 as a joint industry project between
oil and gas operators and downhole equipment manufacturers and service companies. Their stated intent is
“To assist the integration of downhole power & communication architectures, subsea control systems and
topsides by providing recommended specifications
(and standards where appropriate) for the interfaces
between them, and other associated hardware requirements.” For more on the IWIS joint industry project:
http://www.iwis-panel.com/index.asp (accessed
February 4, 2005).
28. Shepler et al, reference 21.
Oilfield Review
FPSO
Subsea trees
Multiphase pump
Riser
Flowlines
Umbilical
Manifold and
multiphase flowmeter
> Seabed installation with multiphase pump, manifold, subsea trees and flowline leading to a distant
FPSO. This typical installation served as a model for a laboratory scenario in which increased water
production from one well was detected at a downhole pump and flowline.
ESP
STATUS: RUNNING
PhaseWatcher Vx
Flow rate
31,726.87 B/D
Gas volume fraction (GVF)
76.26%
1,750
1,500
Pressure, psi
Wellhead
PI 7.24 bbl/psi/day
Total GOR 318.68 scf/STB
Calculated free 38.33%
gas at intake
FloWatcher
TVD 7,850 ft
Density 0.55 g/cm
Discharge
2,775.45 psia pressure
Discharge
281.46 °F
temperature
Flow rate 32,652.1 B/D
Water cut 9.27%
WellWatcher
288.49 °F
Pump protector
temperature
DTS
Reservoir
pressure 6,112.4 psia
60 Hz
55 Hz
50 Hz
45 Hz
40 Hz
1,000
750
1,500
70 Hz
1,250
65 Hz
1,000
60 Hz
750
55 Hz
500
50 Hz
45 Hz
40 Hz
250
TVD 7,850 ft
BHFP 2,456.84 psia
Downhole
temp 163.65 °F
65 Hz
250
Intake
2,148.45 psia pressure
Intake
167.66 °F
temperature
3
70 Hz
1,250
500
Power, hp
384.51 psia
Wellhead
pressure
0
MultiSensor
Motor winding
temperature 292.11 °F
Vibration 4.39 g
Current leakage 0.42 mA
G
10.0
0
5,000
10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000
B/D
Motor vibration
5.0
0.0
-5.0
-10.0
> ESP performance display. Pump intake pressure, temperature sensors and water cut indicate that pump performance is outside of normal operating
parameters (red boxes).
Spring 2005
15
FPSO
Sea level
Flowline
Manifold
995 m
Hydrate zone
50
Temperature, °C
45
40
35
30
8,000
7,000
6,000
5,000
4,000
3,000
2,000
1,000
0
Depth, m
> An alarming drop in temperature. The unheated flowline in this scenario was buried to insulate it against cold
ocean temperatures. Fiber-optic DTS readings along the flowline normally show a steadily declining temperature
trend as the warm production stream decreases from 45°C [113°F] at the manifold, to 38°C [99°F] at the riser.
However, a sharp temperature drop, extending some 1,800 m [5,905 ft] from the riser base, was cause for concern.
It was attributed to hydrate formation.
Meanwhile, other sensors incorporated in the
system, particularly a FloWatcher production
monitor and a simulated seabed multiphase
flowmeter, relayed readings consistent with
increased water cut. An advisory system that
simultaneously analyzed sensor readings from
the wellbore and seabed suggested adjusting the
pump’s variable speed drive to reduce the ESP
motor speed, and choking back the downhole
control valve to decrease water production in
the well.
In this instance, the rise in pump temperature was attributed to increased water
production, which subsequently raised the fluid
density and caused the pump to work harder to
lift heavier fluids. By choking back water production at the downhole control valve, oil cut
increased, thus lowering fluid density and easing
the load on the pump. These actions led to cancellation of the alarm and returned pump
operations to a safe performance level.
Beyond its adverse effect on flow boosting,
the increased water cut also raised concerns
from a flow-assurance standpoint. The Sensa
fiber-optic monitoring system acquired DTS temperature traces along the flowline. These traces
were transmitted by the SMC system.29 Alarms
were generated as temperatures fell along a
length of flowline near the riser (above). The system event analyzer indicated that the flowline
temperature-pressure profile had crossed the
hydrate-formation curve (next page). This unexpected decrease in DTS temperature readings
corresponded to an increase in water cut and a
decrease in pipeline boarding pressure at the
production facility.
Increased water cut would eventually encourage the formation of hydrates in the presence of
any gas in the line. Based on analysis of SMC
output, test personnel took remedial action,
simulating an increase in methanol injection into
the pipeline while production was choked back.
This remediation caused temperatures to move
outside the hydrate envelope, forcing disassociation of any hydrates that may have formed in the
system. The well in the simulator was then
brought back on production, and methanol injection was adjusted to avoid further problems.
This simulation showed how the SMC surveillance system, wellbore and subsea sensors,
real-time data, static data and predictive models
can be integrated to monitor and interpret
system performance. Abnormal events were
recognized, diagnosed and resolved before they
became unmanageable. This response optimized
both the flow-assurance operating strategy
and the efficiency and reliability of the flowboosting systems.
One Step Forward, One Step Back
Innovative offshore well-completion technology
will drive advances in subsea production
assurance. New power-delivery systems,
separators, dehydrators, compressors, singleand multiphase pumps and flowmeters are being
developed for seafloor applications. These
technologies are paving the way for processing
produced fluids at the seafloor. Not all subsea
processing systems will have the same capabilities, but the ability to separate water from a
production stream results in lower lifting costs
and improves flow assurance by reducing
hydrate and scale formation.
29. Amin et al, reference 26.
16
Oilfield Review
EVENT ANALYZER – ANALYSIS
Schlumberger Event Analyzer has detected a possible
production assurance event.
Decrease of 3.41 °C
in 2 hours.
40
38
Degrees C
Pipeline 1A DTS has detected a
temperature DROP at the riser
in a HYDRATE zone.
36
34
32
30
Related events
FPSO Pipeline 1 Boarding Pressure
Decrease in FPSO pipeline 1 boarding pressure.
Pressure decrease of 121.23 psia in 2 hours.
4,000
1,400
3,500
1,300
PSIA
PSIA
Well 1A Production Pressure
Decrease in well 1A production pressure.
Pressure decrease of 996.4 psia in 2 hours.
3,000
1,200
2,500
1,100
2,000
1,000
FPSO Pipeline Water Production
FPSO control system indicates a water
production rate alarm for manifold 1.
Exit
Causes and Probabilities
> Event analyzer output. DTS, wellbore pressure and flowline pressure trends are integrated and displayed by the
subsea monitoring and control connectivity platform. Taken together, these trends indicate that the fluid system had
dropped into the hydrate formation zone.
As subsea completion technology matures,
developments such as coiled tubing have spurred
offshore operators and service companies to
apply their deepwater experience to marginal
fields in shallower waters on the continental
shelf. Continuous lengths of coiled tubing can be
manufactured to withstand pressures required of
subsea production lines, and require fewer welds
per mile than traditional pipelines.
Some single-well reservoirs on the US
Continental Shelf have been tied back to existing platforms, often using coiled tubing for
flowlines and umbilicals. For example, an
18-mile [30-km] coiled tubing tieback in the
Spring 2005
Gulf of Mexico was commissioned from 1,250-ft
[381-m] waters of Garden Banks Block 208 to an
existing platform at Vermillion Block 398 in
450 ft [137 m] of water. At Garden Banks
Block 73, 2.7 miles [4.3 km] of coiled tubing
were used to tie a single subsea well to a platform in water depths ranging from 500 to 700 ft
[152 to 213 m]. A well in 375 ft [114 m] of water
at West Cameron Block 638 was tied by coiled
tubing to another operator’s platform in 394 ft
[120 m] of water at West Cameron 648.
However, flowline systems in shallow waters
are not completely free of subsea production
assurance problems. In some cases, the problems
can be addressed by injecting methanol, corrosion inhibitors and paraffin suppressants at the
subsea tree. In any event, the reservoir must be
sampled, the samples must be analyzed, and the
analysis must be incorporated into the design
plan to anticipate and prevent production
assurance problems.
In deep and shallow waters, reservoir
fluid analysis and front-end engineering design,
coupled with advances in artificial lift, flow
boosting and fast-acting subsea monitoring
systems are turning small, sometimes isolated,
reservoirs into economically viable assets. —MV
17