-
SPE 150495
Worldwide Drill-Stem-Testing Experiences in Heavy and
Viscous-Oil Offshore Environments That Improve Operational
Efficiency Alejandro Salguero, Curtis Wendler, Cidar Mansilla, and
Steven Woolsey, Halliburton
Copyright 2011, Society of Petroleum Engineers This paper was
prepared for presentation at the SPE Heavy Oil Conference and
Exhibition held in Kuwait City, Kuwait, 1214 December 2011. This
paper was selected for presentation by an SPE program committee
following review of information contained in an abstract submitted
by the author(s). Contents of the paper have not been reviewed by
the Society of Petroleum Engineers and are subject to correction by
the author(s). The material does not necessarily reflect any
position of the Society of Petroleum Engineers, its officers, or
members. Electronic reproduction, distribution, or storage of any
part of this paper without the written consent of the Society of
Petroleum Engineers is prohibited. Permission to reproduce in print
is restricted to an abstract of not more than 300 words;
illustrations may not be copied. The abstract must contain
conspicuous acknowledgment of SPE copyright.
Abstract Well testing operations in challenging environments are
becoming more common, and as a result, testing technologies have
had to continually improve or develop newer techniques that can
meet the more corrosive needs in the new areas. These testing
methods must not only achieve operational efficiency, increase
personnel safety and protect the environment, they must address
additional challenges in the new environments where current
development is taking place. In spite of the ongoing improvements,
however, there are still scenarios that remain problematic, and one
the most challenging continues to be the production and well
testing of heavy-oil reservoirs in sandstones or carbonates. This
is particularly true when testing operations are performed
offshore.
Heavy oils normally are defined as those with an API gravity
below 20 degrees with very high viscosities, a variable that is a
major factor in determining the flowing capacity of oil through the
reservoir, the completion string, and surface facilities. Pressures
and low temperatures can increase the viscosity of the oil to an
even higher value, depending on the wellbore characteristics,
geographical area, and the PVT properties of the crude. While most
onshore reservoirs are produced using cold production or steam
injection to reduce the viscosity, offshore environments present
more difficult scenarios due to the low temperatures at the sea bed
and in the ocean thermo-cline regions which further complicate the
typical complexity of all operations in this type of
environment.
Enhanced simplicity and reliability is critical in offshore
development because of the increased intervention cost compared to
the cost of onshore cases and the need to maintain environmental
safety. Thus, careful initial planning of these operations remains
paramount.
This paper reviews experiences that have occurred while testing
heavy-oil reservoirs using a wide range of equipment configurations
and procedures. The authors feel that this information will be
extremely valuable for operators and service personnel who are
planning well testing operations offshore. Introduction The normal
decline in production of many standard oil basins around the world
and the increasing demand for fossil fuels is driving operators to
look for new sources of hydrocarbons. These new sources of
hydrocarbons, normally known as non-conventional resources (Figure
1), need new technology to address the difficult environments and
increased investment in order to be commercially attractive.
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-
2 SPE 150495
Figure 3 ! Viscosity comparison for common substances.
Light Oil
Heavy oils are considered as non-conventional resources with
high proportions of high-molecular-weight compounds. This
hydrocarbon is referred to as heavy, because its density is
normally higher than standard oils. It has been defined as any oil
with a gravity lower than 20 API (Figure 2).
Heavy oil and bitumens are also characterized by high
viscosities, or resistance to flow. This makes the production
difficult, since oils do not flow readily in most of these
reservoirs. Additionally, heavy oils are defined as oils whose
viscosity is between 100 cp and 100,000cp (Figure 3) at reservoir
temperature. Viscosity is commonly defined as the resistance to
flow of fluids. This affects the following processes:
Fluid mobility in the reservoir (defined as k/ ) where fluid
movement will be dependant of reservoir physical conditions,
basically pressure and temperature
Processing and refining oil: Plants must consider the use of
viscosity reducers, blending, and heating systems Production in
offshore wells, where the temperature at seabed can reach values as
low as 38oF, and may sustain that
temperature for several thousand feet with a resultant increase
in viscosity. Production in unconsolidated reservoirs, because of
the necessity for a sand-control system in the well and the
need
to overcome the resistance to flow by a highly viscous fluid.
These viscous oils will not flow naturally in most of the cases; as
a result, a number of methodologies are typically
employed to assist in the movement of the hydrocarbon to
surface: Thermal production( cyclic steam stimulation, steamflood,
steam-assisted gravity drainage) is used to improve fluid
mobility in heavy oil reservoirs, when the conditions are
favorable for this method (onshore wells) Artificial lift methods
such as the progressing cavity pumps (PCP) and electro submersible
pumps (ESP) are
available for cold, heavy oil production. In addition, jet pumps
are used in some cases. For heavy oil well testing, artificial-lift
methods are normally used to evaluate the reservoir as well as to
perform the
artificial lift. Concepts to Consider When Considering Testing
in Heavy Oil Fluid Mechanics Oil viscosity changes dramatically
with temperature; therefore, at lower temperatures, the viscosity
can reach very high values. Although the best method to determine
viscosities is with a physical pressure volume tester (PVT)
analysis, there are some correlations that can be used to
approximate the preliminary values of viscosity. Two of those
correlations were used to illustrate the variation of viscosity
with temperature and pressure. Although the shape of the curve will
change for different oil compositions, the behavior of viscosity as
function of pressure and temperature will follow the same trend;
i.e., temperature will be the main factor that affects viscosity
(Figure 4).
API Type of Oil gr/cc! !
50 0.78
45 0.80
40 0.83
30 0.88
20 0.93
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Figure 2 ! Gravity of oil types.
Light Oil
Light Oil
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SPE 150495 3
When fluids have high viscosity, another consequence is that
flow behavior will exhibit a yield stress different from zero,
or non-Newtonian behavior similar to the behavior of a Bingham
plastic fluid, and therefore, will not follow Darcys law.
Therefore, heavy oils will flow only when the applied pressure
gradient exceeds a certain minimum value. Deep water Offshore wells
differ physically from onshore wells due to the influence of the
column of water above the sea bed. For this reason, deep-water
wells will exhibit differences in pressure trends, because of a
reduction in the stress, since part of the overburden is at ocean
depth (Wendler, C. and Mansilla, C., 2003). This primarily will
affect porosity values and compaction, especially for sandstones.
Temperature will have a different profile, and show different zones
with different trends, as shown in Figure 5. (Salguero, A. et al.,
2008a)
Based in this temperature profile, the ocean is divided into
three vertical zones. The top, which is the surface layer that
depends on surface temperature, the thermocline zone where the
water temperature drops as the depth increases, and the last layer
is the deep-water layer. Water temperature in this zone decreases
slowly as depth increases. Water temperature in the deepest parts
of the ocean averages at about 36F. 90 % of the total volume of the
ocean is found below the thermocline in the deep ocean.
(Ehlig-Economides, C.A., 2008)
This temperature profile affects oil viscosity in static
conditions in a long segment of the completion string from some
meters below the sea bed until several hundreds of meters above it,
as represented in Figure 6.
0
500
1000
1500
2000
2500
0 5 10 15 20 25Temperature (C)
OCEAN TEMPERATURE PROFILE
Surface
Termoclinal
Deep Water
Dep
th (m
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1000
1500
2000
2500
3000
3500
4000
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Dep
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Figure 5 ! Differences in Ocean Temperature Profile.
Figure 6 ! Temperature Profile changes in static conditions,
decreasing as depth increases.
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Figure 7 ! shows real data for an offshore well where pressure
and temperature gauges were set at different depths to measure
temperature profile.
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4 SPE 150495
In flowing conditions, temperature profile will depend of fluid
velocity, as well as reservoir temperature and depth below sea bed.
(Figure 7) There is software available that is frequently used to
calculate temperature profiles, in order to identify critical
rates, diluent injection depths, and surface temperature. Well
testing Any offshore operation must consider complex logistics, and
also, rig cost per day. When a heavy oil prospect is considered for
testing, detailed planning that includes this logistics complexity
and the daily rates must be executed. Experiences testing heavy oil
offshore wells were gained in a number of different countries, and
these experiences resulted in a broad range of best practices and
lessons learned being developed. It is clear in considering this
experience base that there are no simple, universal solutions. Some
of these cases will be reviewed later (Salguero, A. et al., 2008b).
Surface Equipment : The surface equipment package is a key factor
that must be considered when planning a well test, especially in
offshore rigs where physical space is reduced, and there are weight
restrictions that must be considered when accommodating heavy
equipment with a large footprint due to deck-loading concerns.
Surface Testing equipment for heavy-oil testing differs from
standard equipment, because it has been adapted for thermal
management through viscosity reduction to assure flow improvement.
The heat is provided through steam lines in tanks and some
separators as well as through different heat exchangers models.
Proper thermal models and calculations can be achieved by using
specialized software for equipment sizing and minimun steam
deliverabilty (See Figure 8).
Use of diluents or other hydrocarbons with lower API
(such as diesel) can be used to create a blend with less density
and viscosity. A combination of both methods is a common procedure,
and resulting variable calculations are normally performed using
engineering process-type software (Figure 9).
Chemicals especially designed to reduce viscosity are also
available and are used in some cases.
Multiphase flow meters have proven to be reliable technology to
measure hydrocarbon rates, especially where standard separators
have challenges with high viscosities, fluid emulsions, and
water/oil separation. In such operations, its accuracy will depend
on the instrument model and well conditions.
Fluid disposal is a very critical matter since heavy oils need
to align with certain viscosity requirements associated with
highly-effective burners in order to be efficiently burned. To
accommodate these requirements, testing volumes must be specified
during planning. In some cases, the use of a barge for fluid
storage must be considered due to
Manifold
Oil processBurnerPipelineTransport Facilities
Heater
Separator
MultiTube
Heated Tank
MPFM
HEATBlending
Figure 8 ! Flow Chart of Surface Testing Equipment for Heavy
Oil
Figure 9 ! Variable Calculations performed with process
software.
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SPE 150495 5
Sub Sea Test Tree
BOP can
Fluted Hanger
Injection Mandrel (Diesel, Viscosity
RD - Circulating ValveGAUGE CARRIER
OMNI VALVE
DRAIN VALVE
SELECT TESTER Valve
Electro Sumergible Pump
RD-CIRCULATING VALVEARMADA SAMPLERSGAUGE CARRIERTSTLocator
Seals
Hydraulic /Permanent Packer
Clamps
Real Time PDG type gauge (oulet)
Real Time ESP gauge (inlet)
the difficulty of burning highly viscous oil. When using a barge
for storage, ample planning is required for the removal of the
heavy oil from the barge and its subsequent transport and
disposal.
Artificial Lift Methods: Although a number of different
artificial lift methods exist and are used in conjunction with well
testing, the one that has been most effective and most readily
adaptable to offshore rigs is the electrical submersible pump (ESP)
since its configuration allows it to be adapted to the DST string
in several ways, and it can be adapted to almost any offshore
configuration Although ESPs are normally set below an ESP packer
for onshore or jack-up well tests, they are run typically in an
encapsulated form above the DST string when employed on floating
vessels. The ESP configuration will depend on the well geometry,
expected rates and viscosities expected. The fact that the
functional mechanism of these pumps generates heat makes them a
very attractive alternative for pumping highly viscous oil in cold
environments. (Figures 10a and 10b) Subsea Equipment: Some
modifications must be made to allow the passage of the electric
cable that powers the ESP through the BOP stack as well as
additional lines for realtime data acquisition and/or chemical
injection. BOP cans are normally used for this purpose. Also, all
the umbilical lines must be protected at the rotary table and gas
diverter depth from normal rig lateral movement, which could damage
or sever them, causing rig time loss, well-test premature
termination, or subsea equipment malfunction. Downhole Equipment:
If an ESP is used for the test, some details must be considered for
adapting the DST string to the use of lines, clamps, and also, the
position of the tools in the string (more specifically the testing
and circulating valves and how they are related to the position of
the pump). Typical rotationally operated testing packers can not be
used, due to the presence of umbilical cables and hydraulic lines
in the string. For the same reason, expansion or slip joints can
not be used with this configuration. The use of standard or
large-bore tools will depend on such test requirements as the use
of coiled tubing or high rates (flow assurance). Other common
methods used to evaluate heavy-oil wells will be also considered in
the examples section. Sampling and Data Acquisition: Real-time data
acquisition or sampling using wireline tools have been shown to
increase risk due to low fluid viscosity plus presence of paraffins
or even solids in some cases. ESPs normally have pressure and
temperature sensors (suction side) for real-time data acquisition;
other sensors can be installed in the discharge section using a
PDG-type gauge or any gauge powered with an umbilical line. This
facility allows a tester valve to be placed above the pump and
still obtain real-time data below the valve during a shut-in
period. The position of downhole samplers to
BOP can
Injection Mandrel (Diesel, Viscosity
RD - Circulating ValveGAUGE CARRIER
OMNI VALVE
DRAIN VALVE
SELECT TESTER Valve
RD-CIRCULATING VALVEARMADA SAMPLERSGAUGE CARRIERTSTLocator
Seals
Hydraulic /Permanent Packer
Clamps
Figure 10a " Example of a typical DST Tool String
Figure 10b " Example of a DST Tool String with an ESP.
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6 SPE 150495
characterize produced fluid must be carefully considered, since
the wellstream could reach the surface mixed with diluents used to
reduce heavy-oil viscosity. Examples Well A Heavy-Oil Testing in
Deep Water With Standard String (Figure 11) Reservoir temperature
was close to 130 F.
Objective: Reservoir evaluation, sample (Oil 12 API) in a
shallow unconsolidated sand below the sea bed in a deep-water area
(~ 6000 ft of water).
A 7-in. DST tool string with a mechanical packer had been used
on this job, in order to reduce pressure losses and increase
flowing capabilities . Screen was below the packer (no sand control
system). Surface equipment was designed for heavy-oil handling.
Coiled tubing was used to lift oil using preheated diesel.
The sand control screen collapsed, and sand production formed a
slurry with cold heavy oil in the string, sticking the coiled
tubing inside the tubing. Preheated diesel was pumped through the
coiled tubing and worked well as a lifting method. Single-phase
bottomhole samplers were used for fluid characterization. No
umbilical line protector was placed at the rotary table, causing
some hydraulic line damage. Additional heaters and blending lines
were used before burning the oil.
Well B Heavy-oil test using a closed chamber string This was an
unconsolidated sand reservoir without a sand-control completion.
Although the water was not very deep, sea-bed temperature was low
enough to increase viscosity. Objectives - Reservoir evaluation
(Oil 12 API) and single phase and bulk samples, using a closed
chamber system, avoiding the necessity for a heavy-oil flare.
Standard 5-in. DST tools and a mechanical packer configuration had
been used for this closed-chamber job. As the main requirement, a
wireless real time data acquisition sytem was also used to confirm
proper functioning of the closed-chamber valves and to follow the
test program. Flowing ports were equipped with sand screens.
Pressure drawdown was controlled by injecting Nitrogen into the
chambers, and partial perforating. A junk chamber was used for
initial formation cleaning. (Figure 12)
Well C Objectives: Reservoir evaluation of a heavy oil sand in
water deeper than 4300 ft using DST string and surface well testing
equipment.
In this case, a sand-control completion was performed in the
open hole prior to the well test. A flapper-type fluid-loss-control
valve was used due to high permeability sand. An ESP encapsulated
in 7-in. casing was run with memory gauges deployed above and below
the ESP. 5-in. DST tools were used below the ESP with an additional
single-shot circulating valve above the pump. The operator decide
to run the string in two steps, the first one with the DST string
and seals to sting into a seal-bore packer. The string was released
when landed in the seal bore. Subsequently, a second run with the
ESP was
Lower Surge Valve
Drain valve
SamplersGauge Carrier
No -go
RetainerSub sea test treeFlute hangerFlute hanger
Mechanical Packer
TCP guns
ATS Repeater
Slip Joints
Gauge Carrier
Gauge Carrier
ATS Repeater
Gauge Carrier
Upper Vent
Lower Vent
SELECT testerValve
OMNI cyclable reversing valve
RD single shot reversing valve
Drain valve
SamplerGauge Carrier
No -go
RetainerSub sea test treeFlute hangerFlute hanger
Sub
sea
tool
s
Mechanical Packer 9 5/8Jar +Safety Joint
Screen
Slip Joints
7 D
ST
tool
sFigure 11 " DST Tool String used in Well A
Figure 12 " DST Tool String used in Well B
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SPE 150495 7
landed in the extension joint seal-bore receptacle. This
configuration would make it possible to repair or change the pump
if needed, reducing the time required for this operation, since the
rest of the tools would be left in the wellbore allowing it to have
a pressure build-up. (Figure 13)
Well D Objectives: Reservoir evaluation in unconsolidated sand
at a very low temperature and in deep water using an horizontal
well. A very detailed operations program, Hazop/Hazid meetings, and
quality assurance of all the involved service companys equipment
was organized by the operator to evaluate all the possible causes
of failure.
A sand control completion in a horizontal well was performed;
the completion included a fluid-loss-control valve. A large-bore
tool string (3.5-in. ID) with an encapsulated pump was run. It
should be noted that the entire test tool string and ESP where set
in the horizontal section of the well. The operator decided to run
injection mandrels also for diluent and chemical injection below
the sea bed. Cable powered gauges for pressure and temperature real
time data acquisition (PDG) were also installed in the pump. Fluid
solidification during the pressure build-up was prevented by
circulating oil, while the tester valve was closed. (Figures 14a,
b, and c)
Tester valve
OMNI Circ. valveRD reversing valve
Gauge CarrierssamplerTST
No -goSeals
ESP
Expansion Joint
SubSea
Figure 14a " DST Tool String used in Well D
Figure 13 " DST Tool String used in Well C
Sand Control Equipment
Sub
Sea
eq
uipm
ent
SS
ESP
CI lines
PDG TEC line
Sea bed tools umbilicals
PDG line
ESP Cable
DST
Cas
ing
xx
Mot
or
SE
ALS
PU
MP,
ENCAPSULATED PUMP
Figure 14b " DST Tool String used in Well D showing cables for
data acquisition.
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8 SPE 150495
Conclusions As demonstrated in this paper, heavy-oil operations
are complex and must be carefully planned. Consequently, test
designs will change with reservoir conditions, water depth and well
conditions. However, in all cases the following items must be
considered:
Wellbore temperature profile must be modelled to evaluate flow
assurance and fluid or chemical injection points Similar procedures
must applied for surface equipment to provide enough heat or
improve blending operations Volume to be tested must balance
reservoir evaluation goals, and consider blending-fluid volumes,
hydrocarbon
storage, and different disposal methods ! Fluid disposal, !
burning ! fluid transference to a tank barge.
Artificial-lift methodology to evaluate the reservoir Should the
artifitial lift system itself be evaluated? Surface measurement
devices for hydrocarbon rates and viscosities Surface equipment
modifications to provide heat, reduce footprint, and isolate heat
from personnel and other
equipment. Surface measuring instruments, such as multi-phase
flow meters, viscosity meters, and mass meters Injection lines for
diluents or chemical viscosity reducers Evaluate use of coiled
tubing, considering all the possible risks Umbilical lines
installation procedures and protective devices, especially in light
of potentially unfavorable weather
conditions Position of the pump in relation to the tester valve:
the ESP above the Tester will avoid a ram effect when
shutting in the well, but real-time data acquisition during this
period would be more difficult to accomplish versus the opportunity
to collect this data when installing the pump below the tester
valve.
Acknowledgments The authors wish to thank Halliburton TSS and
GBTS management for their encouragement and support in the
publishing of this document and for providing all the relevant
information. References Ehlig-Economides, C.A. et al;Recipe for
Succes in Ultradeep Water Paper SPE 77625 presented at the 2002
SPE, San Antonio , Texas
Conference and Exhibition Salguero, Alejandro et al; Well-Test
planning in deepwater wells in high pressure, high temperature
environments The Brazil
experience Paper OTC 18734 presented at OTC, Houston , Texas
2008 Salguero, A. et al.: New Reservoir Testing and Sampling System
Reduces Costs and Provides Improved Real-Time Data Acquisition
in
Deep Water and Environmentally Sensitive Wells Gulf of Mexico
and Brazil Case. Paper OTC 19623 presented at the Offshore
Technology Conference, Houston, Texas, May, 2008
Spottingcushion Flow Shut-in
Reversecirculating
Testing Valve
Circulating valve
FlowSpottingcushion
Figure 14c " Sequence of testing valve operations in Well D.
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SPE 150495 9
Wendler, C., and Mansilla, C.; Deep Water Well Testing for
Heavy- and Low-Pour-Point Oils Issues, Options, Successful
Methodology: Case Histories Paper OTC 15279, presented at the 2003
otc, Houston, Texas, U.S.A., 58 May 2003.
SI Metric Conversion Factors gal x 3.785 412 E - 03 = m3 ft x
3.048* E - 01 = m in x 2.54* E + 00 = cm psi x 6.894 757 E + 00 =
kPa md x 9.869 233 E - 04 = m3
bbl x 1.589 873 E - 01 = m3 F (F - 32)/1.8 =C
