OTC-30851-MS
Flow Assurance Risks Impact on Kuwait Offshore Field Development Plans
Eissa M. Al Safran, Kuwait University; Sara I. Al Ansari, Kuwait Oil Company
Copyright 2020, Offshore Technology Conference
This paper was prepared for presentation at the Offshore Technology Conference originally scheduled to be held in Houston, TX, USA, 4-7 May 2020. Due to COVID-19
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Abstract
Kuwait Oil Company (KOC) offshore exploration and development plans are underway to boost its
production capacity to the future target rate. However, the selection of offshore field development
scheme is critical due to the associated flow assurance risks, which impact project economics, safety,
and sustainability. The objective of this study is to simulate and evaluate two offshore field development
schemes, namely subsea multiphase flow, and platform schemes. The evaluation is based on the associated
flow assurance risks, project economics, and environmental impact of each development schemes. The
analysis covers simulation of each scheme, prediction of flow assurance risks, and prevention/mitigation
of the risks during the entire life of the field. Results revealed that although the flow assurance risks in the
subsea multiphase flow scheme are significant, it eliminates the large investment cost of platform, which
improves the project economics significantly, and minimize environmental impact. Conversely, although the
platform development scheme has low flow assurance risk, platform capital investment cost may impair the
project economics, safety, and environmental impact. This study investigates each scheme by simulating,
economically evaluating, and environmental impact assessing both schemes, to enable the right decision
and selection of field development plan.
Introduction
Kuwait Oil Company recently expanded its exploration to cover its offshore oil fields, which requires an
optimum integrated development plan to, economically, increase production capacity while maintaining
human and environmental safety. Several offshore oil field (Fig. 1) were explored, but none was developed.
While no offshore development in Kuwait fields, other countries in the Arabian Gulf have developed their
offshore fields. For example, Qatar is producing large volumes of oil and gas from PEARL gas to liquid
offshore project located in North of Qatar (Pit and Unsal, 2018). The produced and processed gas is being
transported from two platforms to the onshore gas-processing plant through main pipelines. As the produced
gas is sour with high mole fraction of CO2and H2S, a continuous corrosion inhibitor injection is applied as
well as kinetic hydrate inhibitor due to the low sea temperatures, which reaches below hydrate formation
temperature. Furthermore, the Arabiyah and Hasbah fields in Saudi Arabia offshore are challenging offshore
fields due to complex flow assurance risk related to elemental sulfur, hydration, large slug volumes, high
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corrosion rate, and HPHT environment (Al-Tunisi et al., 2015). The field was developed using sixteen
platforms, where heavy diesel oil and MEG injection were used to control corrosion and hydrates.
Figure 1—Kuwait offshore field location map showing Medina field investigated in this study (Ibrahim, and Cristoffersen, 2019)
This study compares and contrast two different offshore development schemes, namely multiphase subsea
and platform developments that differ from each other mainly in the schemes’ layout and fluid separation
and processing location with reference to the producing wells and the final onshore production facility. In
this study, six deviated, HPHT, volatile, and sour oil producing wells are simulated and optimized. The
optimization is done by adjusting the choke size of each well with the objective of maximizing the flow rate.
In the subsea development scheme, the separation and processing of the produced fluid is simulated to be
at the onshore production facility, which is expected to increase the flow assurance risks along the oil-andgas-subsea pipeline transportation system. On the other hand, in the platform scheme, the production from
the six producing wells is separated and processed at the platform, which minimizes the flow assurance
risks along the pipeline transportation system from platform to the onshore surface production facility. The
objective of the study is to simulate and evaluate the two field development schemes based on the associated
flow assurance risks, economics, and environmental impact using a state-of-the-art commercial steady-state
flow simulator. Several flow assurance mitigation strategies are investigated to optimize the total production
rate through enhancing the system design and operability.
Field, Fluid, and Production System Description
This study carries out steady-state multiphase flow analyses to simulation subsea and platform development
schemes located in offshore Kuwait. The simulated Medina field is approximately 90 meters deep and
located approximately 16 km from the Northern shore as shown in Fig. 2.
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Figure 2—The simulated Medina field location
The sea floor profile is rugged with a sharp elevation close to the shore as shown in Fig. 3. The two
field development schemes were constructed and simulated, from which the optimal total flow rate and
flow assurance risks were predicted. The six deep and deviated wells have a maximum depth and deviation
of 16,570ft and 50°, respectively as shown in Fig. 4, which are drilled and completed in the HPHT
Middle Marrat, Jurassic formation. The initial reservoir pressure and temperature of Middle Marrat are
approximately 11,000 psia and 270°F, respectively. The flow from the six wells is comingled at a joint to
and delivered to the facility through a main multiphase flowline in the subsea multiphase scheme. In the
platform scheme, the flow is comingled at the riser base and flowed upward through the riser to the twophase separator, the separated fluids are delivered to the shore through two single-phase down comers and
two main pipelines.
Figure 3—Sea floor profile
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Figure 4—Simulated wells profile and geometry
The simulated volatile oil has an API gravity and GOR of 38° and 2900 scf/STB, respectively, with sour
gases of 1.1% CO2 and 2.1% H2S mole fractions. Fig. 5 shows the phase envelop of the produced fluid as
well as the hydrates and water lines, indicating the potential of hydrates and ice formation and deposition
along pipeline system.
Figure 5—Produced fluid phase envelope
The reservoir pressure depletion is predicted using material balance on the same reservoir located
onshore, which is fitted in Eq. 1 as follows:
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(1)
where Np is the cumulative produced oil in STB and pr is the reservoir pressure in psia.
Simulation Description
In this study, a commercial industry standard steady-state multiphase flow simulator is used. Fig. 6 shows
the network simulation schematics of the subsea scheme and platform scheme. A compositional model
with 3-Parameter Peng Robinson Equation of State (EoS) is used to characterize the volatile sour crude
oil simulated in this study by advanced thermodynamic commercial software package incorporated in the
standard industry multiphase flow simulator. Furthermore, comprehensive mechanistic models of Xiao et
al. (1990), Ansari et al. (1994), and Kaya et al. (1999) where selected to predict the multiphase behavior and
characteristics, including the flow pattern, pressure gradient and liquid holdup along the entire production
system. The investigated flow assurance phenomena in this study are pipe erosion and corrosion, formation
and deposition of gas hydrate, hydrodynamic and terrain slugging, and severe slugging in the platform
system.
Figure 6—Network simulation schematic. Subsea scheme (top) and platform scheme (bottom)
Pipe erosion is predicted by calculating the erosional velocity ratio (EVR) defined as the ratio of fluid
velocity to the maximum allowable erosional velocity using API RP14 model. To control erosion, a proper
pipe size is selected that allows producing the optimum designed flow rate, while keeping erosional velocity
ratio less than unity. Corrosion is predicted by calculating the corrosion rate, i.e. pipe material loss per year
due to the presence of CO2 dissolved in water, using de waard (1995) corrosion model.
The analysis of gas hydrate formation and deposition in the flowlines covers different sensitivities
based on the controlling parameters of this phenomenon such as sea temperature gradient and pressure
and temperature profile throughout the pipelines. The objective of this analysis is to predict the critical
temperature below which gas hydrate forms with ±10% uncertainty, which indicate that the system thermal
management is crucial to prevent hydrates formation. Consequently, heat transfer management is carried
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out to prevent hydrates formation using different type and thickness of pipeline insulation material. In
addition, chemical inhibitors to mitigate hydrates are investigated by predicting the inhibitor injection rates
and economics (Al-Safran and Brill, 2017).
Terrain and hydrodynamic slugging are predicted and mitigated by early phase separation and pipelining
as single-phase gas and single-phase liquid, or pipeline re-routing to minimize the inclination angle effect.
Severe slugging is predicted using Boe (1981) criterial and is mitigated by preventing liquid accumulation
at the riser base, increasing system pressure by topside choking, riser gas lift, or riser self-gas lifting (AlSafran and Brill, 2017).
Economic Analysis
A detailed economic analysis based on the optimum designs of the subsea multiphase development scheme
and platform development schemes is carried out to evaluate all the simulated alternatives of flow assurance
mitigation and prevention scenarios. The net present value (NPV) is used as the main economic indicator
in this study to, economically, evaluate the alternatives, and compare the two schemes. In addition,
the discounted cash flow rate of return (DCFROR) is used as a second indicator for further detailed
comparison. Different factors are included in the cash flow calculation to determine the NPV such as
depreciation, tax, and present value factor. The investment cost cover in each scheme the capital cost of
drilling and completion, platform installation, pipeline material, insulation and coating, fluid separation,
chemical injection, pump and compressor stations, SCADA and metering system, environmental and
permitting, engineering and construction management and contingency cost represented as allowance for
funds used during construction. Furthermore, the operating cost includes the annual expenses related to
personnel salaries, data acquisitions and operations, pump and compressor fuel and maintenance cost,
required chemical injection, station maintenance, SCADA operating cost, produced water treating cost,
transportation and accommodation cost in case of platform scheme, workover and other field maintenance
costs. Based on the economic analysis results, as well other factors, the evaluation of both production
schemes is determined.
Results and discussion
Both scheme designs were optimized to meet this study objective. Table 1 shows the properties of the main
designed flowlines. The multiphase flowline represents the main flowline of the subsea scheme, while liquid
and gas flowlines are the main flowlines in the platform scheme that carries liquid and gas after separation
to the shore.
Table 1—Flowline characteristics
Flow line
Type- Schedule
Nominal
Diameter (in.)
Inner
Diameter (in.)
Thickness (in.)
Weight (lbm/ft)
Roughness (in.)
Multiphase
API-60
10
9.75
0.5
54.74
0.0018
Liquid
API-80
8
7.625
0.5
43.39
0.0018
Gas
API-140
10
8.75
1.0
104.13
0.0018
In the platform scheme, the separator is located at the platform with a separator pressure of 700 psia,
a pump and compressor are added to boost the flow to the onshore receiving facility from year 1-12, and
14. Based on the designed pipeline size and optimized flow rate, the EVR along the multiphase and single
phase pipelines did not exceeded 0.9, eliminating the risk of pipe erosion as shown in Fig. 7.
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Figure 7—Erosional velocity ratio vs. time
Pipeline corrosion is significant and severe in this simulation study due to the sour gas and water,
which when combined forms carbonic acid. This was observed in the multiphase and gas flowlines in
year one as shown in Fig. 8. Corrosion can be mitigated in several ways, for example using corrosion
resistance alloys (CRA) instead of carbon steel, gas-sweetening processing, cathodic protection, and
corrosion inhibitors. However, the efficiency of the chemical inhibitor is related to the flow pattern and
the pipe wall-wetting phase. Because the flow pattern predicted along the pipeline is mainly stratified and
slug flow, it is recommended in this study using CRA and Cathodic protection over continues corrosion
inhibitors injection.
Figure 8—Corrosion rate and cumulative corrosion for gas, liquid, and multiphase flowlines
The hydrates phase envelop and flowlines pressure/temperature profiles are predicted and plotted in Fig.
9 to assess the risk of hydrates formation and possible deposition. In this paper, we only show the results
of hydrates prediction and mitigation in the multiphase flowline of the subsea scheme. Similar results were
obtained for the gas flowline in the platform scheme, but almost no hydrate was predicted in the liquid
flowline of the platform scheme. The analysis shows that the fluid temperature drops below the hydrates
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formation temperature seven months of the year due to sea water temperature drop and increase in heat
transfer rate from produced fluids to surrounding sea water.
Figure 9—Hydrates phase envelop and fluid PT profile at different sea temperatures
Multiple sensitivities analyses were carried out on pipeline insulation thickness and insulation material
to minimize heat loss and prevent hydrates formation. Polyethylene, polypropylene, and polyurethane are
three different insulation materials with thermal conductivity of 0.20, 0.13 and 0.07 Btu/h-ft-°F, respectively,
were investigated with multiple thicknesses of 0.2, 0.3 and 0.5 in. Fig. 10 shows the produced fluid and
hydrates formation temperature profiles with insulation, which indicates fluid temperature drops below the
hydrates formation temperature for most of the flowline. On the other hand, Fig. 11 shows the fluid and
hydrates formation temperature profiles with 0.3 in. of Polypropylene insulation in which the temperature
of the fluid above the hydrates formation temperature due to reduction in heat transfer rate. Similar analysis
was carried for different insulation material and thicknesses.
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Figure 10—Hydrates and fluid temperature profiles without insulation or chemical injection
Figure 11—Hydrates formation and fluid temperature profiles with 0.3 in. polypropylene insulation
In addition, sensitivity analyses on methanol injection rate to obtain the optimum value to mitigate
hydrates formation is carried out. Fig. 12 shows the effect of methanol on shifting the hydrates formation
temperature line below the fluid temperature line. Further analysis was carried out to obtain the optimal
injection volume. Table 2 lists all the optimal insulation thicknesses and material, and methanol injection
rates for the multiphase, gas, and liquid flow line in both subsea and platform schemes at the lowest sea
temperature of 63 °F.
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Figure 12—Hydrates formation and fluid temperature profiles with Methanol
Table 2—Gas hydrate simulated prevention and mitigation methods
Methanol (bbl/d)
Polyethylene (in.)
Polypropylene (in.)
Polyurethane (in.)
Multiphase flowline
270
0.5
0.3
0.2
Liquid flowline
70
0.7
0.5
0.3
Gas flowline
90
2.1
1.4
0.7
Severe slugging in platform riser is predicted for the base case in this study according to the severe
slugging indicator being less than one. Sensitivity analysis on topside choking and decreasing of riser ID was
carried, but showed a no effect on mitigating severe slugging. However, increasing the separator pressure
2200 psia increased the system pressure and decreased the flowrate, resulting in complete mitigation of
severe slugging. Results show that this resulted a reduction of 6.6 MMscf/d (7%) of gas flow rate, and
3,255 STB/d (9%) of oil flowrate in the first year. In addition, this eliminated the need of fluid boosting
downstream of the separator. This severe slugging mitigation was only obtained when selecting Zhang et
al. (2003) unified model as the hydrodynamic model, which predicts dispersed bubbly flow pattern in the
vertical riser. On the other hand, when Ansari et al. (1994) model is used, severe slugging persists. This
indicates the large uncertainty in modeling severe slugging phenomenon and flow pattern, and may require
careful model tuning with field data to ensure accuracy.
Terrain slugging prediction is a transient phenomenon, which requires slug tracking modeling. In future
work of this study, an industry standard transient multiphase flow simulator will be used, which includes slug
tracking modeling to simulate terrain slugging along the multiphase flowline. At this stage of the study, the
average multiphase flow parameters along the multiphase flowline of the subsea development scheme are
presented using industry standard commercial steady-state simulator. Figs. 13 and 14 show the flow pattern
and average liquid holdup along the multiphase flowline, indicating that intermittent flow is the dominant
flow pattern, especially in the uphill sections of the flowline. The flow pattern not only affects flow assurance
phenomena such as hydrates and wax deposition behavior and characteristics, but also the efficiency of
chemical injections such as Methanol and MEG. Fig. 15 shows an important slug flow characteristics, i.e.
mean slug length along the flowline. Results reveals that average slug length increases up approximately
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300 ft at 11 km horizontal distance, then sharply decreases as the flow pattern becomes segregated flow in
the downhill sections of the flowline. This sharp increase in mean slug length results in the generation of
very long slugs when calculating the 99% probability (P99), which indicates the slug length that exceeds
99% of the slugs. Al-Safran et al. (2005) proposed a probabilistic modeling of the maximum slug length
as a function of mean slug length and standard deviation of normally transformed slug length distribution
as given in Eq. 2.
Figure 13—Flow pattern prediction along multiphase flowline of subsea scheme
Figure 14—Liquid holdup prediction along multiphase flowline of subsea scheme
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Figure 15—Mean slug prediction along multiphase flowline of subsea scheme
(2)
where μN and σN are the mean and standard deviation of normal transformed slug length distribution,
respectively. The value of 2.58 in Eq. 2 is the t-statistic that corresponds to 99% confidence interval of tdistribution.
Incorporating the flow assurance prevention and mitigation scenarios, both development schemes
maintain continuous production for entire project life of 20 years. Figs. 16 and 17 show the reservoir pressure
depletion, and the production rates of oil, gas and water along the life of the project for both schemes.
Figure 16—Platform scheme production and pessure forecast
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Figure 17—Subsea multiphase scheme production and pressure forecast
Based on simulation results, detailed economic analyses were carried out for four alternative scenarios
under the subsea multiphase scheme and 16 alternative scenarios under the platform scheme based on the
proposed flow assurance mitigation methods. Table 3 describes each alternative plan.
Each of the above alternatives have its capital cost, operating costs and revenues. For example, separator
pressure of 2200 psia option eliminated the capital cost of installing the boosting stations as well as station
annual maintenance cost and operating cost; however, increased system pressure, which resulted in less
oil and gas production, which will directly affect the revenues and cash flow. Considering 35% tax rate
and 20% depreciation rate, the two economic indicators (NPV profile and DCFROR) were obtained to
evaluate the above alternatives given in Table 3. Results revealed that all subsea scheme alternatives showed
approximately equal DCFRAR of around 128.6% with slightly higher NPV profile for the AA alternative
as shown in Table 4.
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Table 3—Design alternative
Alternatives
Description
AA
Subsea scheme with corrosion resistance
alloy and polypropylene insulation
AB
Subsea scheme with corrosion resistance alloy and polyethylene insulation
AC
Subsea scheme with corrosion resistance alloy and polyurethane insulation
AD
Subsea scheme with corrosion resistance alloy and methanol injection
BAAA
Platform scheme with corrosion resistance alloy,
separator pressure 700 psia and polypropylene insulation
BAAB
Platform scheme with corrosion resistance alloy,
separator pressure 700 psia and polyethylene insulation
BAAC
Platform scheme with corrosion resistance alloy,
separator pressure 700 psia and polyurethane insulation
BAAD
Platform scheme with corrosion resistance alloy,
separator pressure 700 psia and methanol injection
BABA
Platform scheme with corrosion resistance alloy,
separator pressure 2200 psia and polypropylene insulation
BABB
Platform scheme with corrosion resistance alloy,
separator pressure 2200 psia and polyethylene insulation
BABC
Platform scheme with corrosion resistance alloy,
separator pressure 2200 psia and polyurethane insulation
BABD
Platform scheme with corrosion resistance alloy,
separator pressure 2200 psia and methanol injection
BBAA
Platform scheme with gas sweetening processing,
separator pressure 700 psia and polypropylene insulation
BBAB
Platform scheme with gas sweetening processing,
separator pressure 700 psia and polyethylene insulation
BBAC
Platform scheme with gas sweetening processing,
separator pressure 700 psia and polyurethane insulation
BBAD
Platform scheme with gas sweetening processing,
separator pressure 700 psia and methanol injection
BBBA
Platform scheme with gas sweetening processing,
separator pressure 2200 psia and polypropylene insulation
BBBB
Platform scheme with gas sweetening processing,
separator pressure 2200 psia and polyethylene insulation
BBBC
Platform scheme with gas sweetening processing,
separator pressure 2200 psia and polyurethane insulation
BBBD
Platform scheme with gas sweetening processing,
separator pressure 2200 psia and methanol injection
For platform alternatives, both indicators proposed BBAA alternative over the 15 other alternatives as
shown in Fig. 18 with DCFRAR of 61.2%.
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Figure 18—Platform scheme alternative NPV as a function of discount rate
Table 4—NPV of subsea scheme selected alternatives
NPV, USD million
Discount Rate %
AA
AB
AC
AD
0
4633.984
4633.953
4633.969
4632.489
10
2223.691
2223.66
2223.676
2222.33
20
1308.17
1308.139
1308.155
1306.92
30
861.5549
861.5242
861.54
860.4
40
604.2724
604.2417
604.2574
603.1984
50
438.7447
438.714
438.7297
437.7409
60
323.8401
323.8094
323.8251
322.8978
70
239.6026
239.5719
239.5876
238.7144
80
175.2772
175.2465
175.2622
174.4372
90
124.5851
124.5543
124.5701
123.7882
100
83.62483
83.5941
83.60986
82.86676
The best economic selected scenario from each scheme were to determine which scheme is economically
better. Fig. 19 shows the comparison results between the two best-selected scenarios of both schemes based
on two selected economic indicators.
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Figure 19—NPV and discounted rate of best scenarios from each scheme
Conclusion
The results showed that flow assurance risks such as hydrates and corrosion are high in both production
schemes, which impact not only the wells flow rate, but also system integrity and safety. Using industry
standard steady-state multiphase flow simulator, 20 different field development designs were simulated with
manageable flow assurance risks. These designs were economically evaluated based on two economical
indicators, NPV and DCFROR. As a result, a subsea multiphase development scheme with 10 in. ID
corrosion resistance alloy multiphase flowline with 0.3 in. thick polypropylene insulation is selected as
the optimum design and most profitable economic option with assured flow scenario. Therefore, compared
with platform field development scheme, subsea development is better option due to its manageable
flow assurance issues, and high NPV. This study should enable KOC to evaluate different offshore
development schemes by predicting flow assurance risks, investigating different flow assurance mitigation
and management strategies, evaluating the economics for each scheme, and assessing the environmental
impact. This should ensure sustainable production with safe operation and protected environment.
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