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June 2009 SPE Projects, Facilities & Construction 19
The Cliff Head Field Development—Flow 
Assurance and Production Chemistry 
Challenges in a Marginal Field Context
Simon Daniel, ROC Oil Company Limited, and Jon Roberts, Advantage Energy Limited
Copyright © 2009 Society of Petroleum Engineers
This paper (SPE 115612) was accepted for presentation at the 2008 SPE Annual Technical 
Conference and Exhibition, Denver, 21–24 September, and revised for publication. Original 
manuscript received for review 7 July 2008. Revised manuscript received for review 
30 December 2008. Paper peer approved 13 January 2009.
Summary
The Cliff Head Field, offshore Western Australia, faced signifi-
cant development challenges because of its location and reservoir 
fluid properties. The influence of these challenges is apparent in 
the development solution adopted from sandface to market. The 
modest reserve size required the application of a number of firsts, 
including coiled tubing (CT), deployed electric submersible pumps 
(ESPs) combined with intelligent completion technology, a novel 
water “spike” approach to waxy crude transportation, a distrib-
uted chemical injection system, a remote-controlled, normally 
unmanned production platform, produced water re-injection, and 
“hydrofrac” water-injection capacity.
This paper describes the flow assurance and production chem-
istry challenges facing the development, the resulting development 
solution, and the production history to date.
Introduction
The Cliff Head field is located in Commonwealth hydrocarbon 
exploration permit WA-286-P in the offshore Northern Perth Basin, 
Western Australia. Cliff Head is the first offshore development 
within the region. The facilities consist of the following compo-
nents (Fig. 1):
• A minimum facilities, unmanned wellhead platform, Cliff 
Head Alpha (CHA) approximately 7 miles offshore, to accom-
modate the dry well heads and support equipment.
• Six production wells with coiled tubing deployed ESPs and 
two water injection wells on CHA.
• Arrowsmith Stabilization Plant (ASP) located approximately 
two miles inland.
• A nine-mile insulated sub-sea production pipeline, crossing 
beneath the shoreline and the dune system by means of an hori-
zontal directionally drilled (HDD) hole.
• A nine-mile insulated subsea water injection pipeline from 
ASP to CHA, also using an HDD shore crossing.
• Onshore source water well to supply make-up water for 
injection.
• A subsea umbilical power, control and chemical supply cable 
running from ASP to CHA.
The field was discovered in December 2001 when Brent crude 
prices were at USD $20 per barrel. The field contains 15.7 million 
barrels of estimated ultimate oil recovery.
The offshore area is host to a variety of marine flora and fauna, 
including important seagrass meadows and cetaceans. It is also a 
major rock lobster fishing ground. For these reasons, the offshore 
facilities have been designed to ensure that no waste will be dis-
charged into the marine environment. The onshore plant area is 
located in a Class C nature reserve.
The low energy reservoir is normally pressured with a low 
solution gas to oil ratio, (GOR, see crude properties, Table 1) and 
therefore requires water injection for pressure support and artificial 
lift to achieve economic production rates. Studies indicated that the 
most appropriate method of artificial lift was ESPs. Considerations 
such as the remote location, unavailability of drilling rigs, and 
minimalist production platform, however, meant that the ESP 
deployment system had to allow for rapid, low-cost, and rigless 
work-over interventions. These requirements led to the selection 
of CT-deployed ESPs.
Flow Assurance Challenges
Initial Well Data. The drilling of the fi eld discovery well Cliff 
Head 1 in late 2001 yielded formation tester samples providing 
early indications that the fl uid properties were likely to be prob-
lematic for any development. The Cliff Head 3 well test, carried out 
in January 2003, established that artifi cial lift would be required 
and confi rmed that the crude was waxy in nature (see Table 1), 
and contained signifi cant levels of nitrogen, sulphur, and oxygen-
bearing (NSO) compounds. The initial fl ow assurance study on 
Cliff Head stock-tank crude following the fi rst samples reported 
a wax content of 27%, a pour point of 34ºC, and a wax appear-
ance temperature (WAT) of >90ºC. The cooldown viscosity data 
compared unfavorably with those of the waxiest crudes in the Asia 
Pacifi c region. Furthermore, testing with pour point depressants 
(PPDs), known to effectively treat similar crudes, indicated that 
dose rates of near 3,000 ppm would be required to achieve suit-
able rheological properties. It was clear from these early results 
that pipeline fl ow assurance would be a critical component of the 
development success.
Following additional appraisal wells, a significant sample inven-
tory, including low draw-down PVT and atmospheric samples, were 
recovered from the appraisal wells for ongoing fluid studies.
Water Disposal Requirement. Because of the highly undersatu-
rated nature of the Cliff Head reservoir, the low GOR, and uncertain 
aquifer influx, reservoir pressure was likely to fall rapidly upon 
commencement of production. Therefore, pressure maintenance 
was considered a prerequisite from day one. Further complications 
included the high pour point of the waxy crude and the associated 
thermal issues.
The opportunity to avoid discharge of produced water to the sea 
was afforded by the potential utilization of closed-loop-produced 
water for water injection supplemented by initial make-up water 
from an onshore water well. The Phase 1 feasibility study prior to 
declaration of commerciality defined a water-injection concept and 
provided refined costs. A second phase of work was then conducted 
to provide data for the FEED and detail design.
The Phase 1 water injection study determined that produced 
water re-injection (PWRI) was feasible. Water injection up-time 
was considered critical because of limited water storage onshore, 
low field GOR, and an assumed negligible aquifer support, re-
sulting in rapidly falling reservoir pressure. Therefore, complete 
and reliable voidage replacement would be required from first 
oil production.
Following literature reviews (for example Cassinat 2002) and 
because of the high potential for near-wellbore wax deposition 
and emulsion blocks, it was further determined, following more 
detailed laboratory studies (discussed next), that heating of in-
jection water to a minimum of 55°C at the injection wellheads 
would be required, at least during initial production. The Phase 2 
study showed that fracture injection (hydro-fraccing) to maintain 
injectivity in spite of fluctuations in injection water quality offered 
project capital cost savings of up to USD $4 million by removing 
20 June 2009 SPE Projects, Facilities & Construction
the requirement for high specification filters. Furthermore, deleting 
operator intensive filtration equipment resulted in significant op-
erating-cost reduction. A possible drawback to fracture injection 
is conformance: the potential for vertical and horizontal fracture 
growth leading to bypassed oil and nonoptimal waterflood man-
agement. However, with detailed modeling of the formation pore 
throat-size distribution and detailed reservoir geomechanics stud-
ies, it was possible to specify the allowable operating limits for 
injection water solids content and confirm with a high degree of 
certainty where fractures would propagate.
Injection Water Source. An onshore aquifer at a depth of 
1000 m capable of providing water at approximately 65°C was 
selected as the most suitable initial source water. Following a 
source water well test, it was possible to precisely determine the 
source water composition and flowing tubing head temperature 
(FTHT). The FTHT of 65°C was capable of providing some 
4 MW of heat-flowinto the production system—a significant 
low-cost heat source.
Flow Assurance Studies
Workfl ow and Strategy. The criticality of fl ow assurance at Cliff 
Head was recognized early, and management of this key project 
risk was assigned to a single individual. A phased approach was 
adopted to allow project engineering to progress in parallel with 
laboratory studies (see Fig. 2).
Phase 1 was undertaken pre-FEED and consisted of:
• Steady state thermo-hydraulic modeling of the wells and 
pipeline to provide preliminary assessments of Cliff Head flow 
assurance issues, particular relating to wax deposition.
• Laboratory flow-assurance studies aimed at confirming key 
flow assurance parameters and providing data to aid in assessing 
piping and pump size requirements, pipeline restart pressures, and 
pipeline displacement options. 
Phase 2 consisted of more focused steady-state and dynamic 
thermal and hydraulic modeling to remove uncertainty and provide 
clear design parameters or ranges for the basis of design and opera-
tions input. The influence of the key flow-assurance parameters on 
the facility design are set out in Fig. 3.
Phase 1 Flow-Assurance Laboratory Studies. There was a dispari-
ty between initial fl ow-assurance results (specifi cally wax appearance 
Onshore
facilities
Crude
stabilization
Export via
truck transport
HDD Offshore
facilities
Coastline
Development
wells
Reservoir
• Pipeline to shore
• Water injection to CHA
• Power to CHA
• Chemical injection to CHA
• Fiber optics
Fig. 1—Cliff Head facilities overview.
Flow Assurance Studies Project Phases
Initial PVT analysis
Laboratory FA study
numerical analysis
Chemical selection
Reality check
Concept
FEED
Detailed design
Commissioning
and operations
Fig. 2—Flow assurance studies and relationship to key project 
phases.
TABLE 1—PVT AND FA PROPERTIES 
Well CH1 CH3 CH3 CH3ch1 CH3ch1 
Sample MPSR-192 MPSR-494 11489-QA 11478-QA 
Depth (m RT) 1280 1276.2 1297.9 DST 1 DST 1 
Bo (rb/stb) 1.037 1.047 – 1.053 1.058 
GOR (scf/stb) 9 32 – 35 38 
Pb (psia) 123 371 – 378 433 
Viscosity at 73°C (cp) 6.88 6.25 – 5.53 5.49 
Compressibility (10^6/psi) 5.73 5.69 – 5.92 6.67 
API gravity 31.4 30.7 33.2 33.0 33.1 
Pour point (°C) 36 36 33 33 33 
Wax (wt%) 30.2 20.4 20.6 23.7 20.4 
Asphaltene (wt%) 0.67 0.59 0.67 0.22 0.25 
June 2009 SPE Projects, Facilities & Construction 21
Pour Point. ASTM D5853 is conventionally used to determine 
the pour point of crude oil. The test is conducted at atmospheric 
pressure and the method provides maximum and minimum read-
ings, depending on the thermal history of the crude. Because of 
concerns about the usefulness of “dead crude” pour points gener-
ated by Labs A and B, an alternative approach was undertaken by 
Lab C. A “live” crude sample was heated in a pressure cell (held 
at pressure), to minimize the loss of light ends which may result in 
an unnecessarily pessimistic result. Once liquid and fully homog-
enized, the standard procedure was followed to determine the pour 
point under atmospheric pressure. Table 3 presents the impact of 
this procedure modification on the crude’s pour point. A conserva-
tive pour point of 32°C was assumed for the pipeline design.
Asphaltene Studies. Early examination of Cliff Head crude 
identified significant levels of black noncrystalline material, rais-
ing concerns about asphaltene precipitation. As gas lift was not 
planned, the major impacts on asphaltene stability would be the 
pressure drop from initial reservoir conditions. Laboratory testing 
utilized filter plugging and spectroscopic analysis to assess the 
asphaltene stability of Cliff Head crude at 73°C and through the 
expected range of production pressures in 200-psi steps.
Slight variations in absorbance and filter pressure drop suggested 
slight asphaltene instability at 1400–1600 psig (Fig. 4). However, 
the results generally indicated good asphaltene stability, agreeing 
with observations made during the well test and comparative data 
(Jamaluddin et al. 2001), from the high resin to asphaltene ratio 
(34:1) reported following saturates, aromatics, resin and asphaltene 
(SARA) benchmarking.
Based on the WAT and asphaltene studies, the black noncrystal-
line material identified in early testing was assessed as unlikely to 
present a flow-assurance risk to the development, and further work 
to characterize it was considered unwarranted.
Crude Viscosity. Viscosity measurements at various shear rates 
were made on fully restored, stabilized, crude under dynamic cool-
ing conditions. As with the pour-point work, crude beneficiation 
was conducted in sealed containers to minimise loss of lightends. 
Results are plotted in Fig. 5. The key finding was that viscosities 
remained relatively low until 35°C, indicating that dry crude was 
unlikely to gel until quite close to the pour point.
Pipeline Restart. Environmental conditions for all modeling 
and laboratory work were worst-case (minimum seabed tempera-
ture of 14.5°C). Stabilized dry crude was used for the restart test-
ing, again with the aim of representing the worst case due to no 
beneficial impact of dissolved gas. A model pipeline was utilized 
as follows:
• Test pressure 15 psig confined initially (to prevent light ends 
losses and counteract shrinkage).
Key FEED Design Numbers
• Wax content
• Asphaltene precipitation envelope
• Crude viscosity
• Wax deposition rates
• Pipeline restart tests
• Pour point
• Wax appearance temperature “WAT”
• SARA and high temperature GC benchmarking
• Wet crude/emulsion studies
Influence of Parameter
→ Heating/insulation/pigging
→ Well/pipeline management/mitigation
→ ESP specs/pipeline/storage/export
→ Pipeline/heating/pigging/export
→ Pipeline/mitigation/pigging/pump sizing
→ Restart/cool-down timing/pigging/export
→ Heating/insulation/pigging
→ Design options/mitigations
→ ESP specs/chem. inj./pipeline/pigging/vessels
 /heating/storage 
Fig. 3—Influence of flow assurance parameters on facilities design.
TABLE 2—WAX APPEARANCE TEMPERATURE AT 
VARYING PRESSURES USING MODIFIED CFPPT 
Wax Appearance 
Temperature (°C) Pressure (psig) 
55 0 
45 150 
48.5 1900 
10
8
6
4
2
0
2000 1500 1000 500 0
0.3
0.25
0.2
0.15
0.1
In
c
re
a
s
e
 A
c
ro
s
s
 F
il
te
r,
 p
s
i/
h
o
u
r
A
b
s
o
rb
a
n
c
e
Pressure, psig
Filter pressure increase Crude absorbance
Fig. 4—Asphaltene precipitation run.
temperature) and the observed performance of the crude, as refer-
enced in the following. Therefore a new fully integrated study, uti-
lizing alternative procedures, was commissioned as part of Phase 1. 
The differing test methods and results are discussed next.
Wax Appearance Temperature. As stated previously, in the 
initial post-discovery work a wax appearance temperature (WAT) 
of >90°C was determined. The viscometry method was used for 
this work. This defines the WAT as the temperature at which the 
viscosity of crude cooled at a controlled rate deviated from a 
straight line (i.e., shows non Newtonian behavior owing to the 
presence of solids).
The subsequent well test and laboratory work presented no 
evidence of wax deposition or crystallization at temperatures of 
40°C and less. Therefore an alternative method, based on the cold 
filter plugging point test (CFPPT), was used to further explore 
the potential for wax deposition in the Cliff Head process. In this 
method, fully restored crude is flowed through a 0.5-micron filter 
at a controlled cooling rate, while the differential pressure across 
the filter is monitored. In this experiment, the WAT is defined as 
temperature at which irreversible plugging of the filter commences 
and a deviation from Newtonian behavior occurs.
The method presented a significantly lower WAT (see Table 2) 
more in line with field and laboratory observations.
TABLE 3—POUR POINT BYLABORATORY 
Laboratory Pour Point (°C) Source Sample 
Lab A 33-36 CH3 dead crude 
Lab B 34 CH3 dead crude 
Lab C 26 CH3 live crude 
22 June 2009 SPE Projects, Facilities & Construction
• Coil dimensions 160-in. length by 0.18-in. internal diameter.
• Applied restart wall shear rate of 1 sec-1.
Two shutdown conditions were considered aimed at represent-
ing the following cases:
1. A sudden shutdown from normal operating conditions—
pipeline bulk fluid temperature assumed to be 60°C
2. A slow turn down from operating conditions to just above 
the pour point (35°C) before shut-down.
The sudden shut-in case resulted in a higher restart pressure 
because of the development of a gel/solid phase with a relatively 
high yield stress. Static cooling from a higher temperature allowed 
more effective crosslinking of the wax crystals. Shearing during 
cooling inhibited crystal growth, resulting in correspondingly 
lower apparent gel strengths.
Upscaling the results indicated that pumping requirements for 
displacing the offshore nine-mile product pipeline of dead crude 
should be sized to provide start-up differential pressures of at least 
1,230 psig across the pipeline (Table 4).
It is important to note that the crude does not become liquid 
once the restart pressure has been reached. The pressure indicated 
is the “breakaway yield stress” of the crude plug. Handling of the 
solids associated with the mobile plug following a cold restart 
required consideration within the facilities design.
Wax Deposition Rate. Predicting deposition rates from labo-
ratory testing is somewhat qualitative despite best efforts to 
mimic expected field conditions. Furthermore, there are numerous 
laboratory procedures that purport to provide the most accurate 
approximation. The method used involves pumping suitably con-
ditioned crude at a constant shear rate through a calibrated test 
loop (1/4-in. OD × 12-in. tubing) held at a specified temperature 
while continuously monitoring pressure differential across the 
test loop. The estimated wax deposition rate for that temperature 
is then calculated using the test loop data. The approach allows 
for detailed measurement of deposition rates at various points in 
the modeled pipeline based on the thermal gradient. To ensure 
that shear-related factors (shear stripping) are considered, flow at 
several shear rates is modeled. Again, the fluid tested is dry, dead 
oil as the worst case.
Deposition rates were consistently very low for this crude. The 
worst case, when upscaled for the offshore product pipeline, gave 
a deposition rate of only 1.0 × 10–3 in. per month, adjacent to the 
location in the pipeline where the temperature fell below the WAT.
Low deposition rates reported in this testing agreed with the 
well-test results, in which no signs of wax deposition were detected 
in the tubing or flowlines, despite known periods of bulk liquid 
flow below the WAT. Furthermore, the crude viscosity results 
reported previously implied a relatively low degree of wax precipi-
tation in the crude sample below the WAT and down to 35°C. As 
noted previously, anecdotal laboratory evidence during handling 
and observing the crude under various cold surface conditions 
directionally supports these results.
Emulsion Characterization. Shearing with differing ratios of 
Cliff Head crude and synthetic formation water showed the emul-
sions formed readily and remained stable up to approximately 60% 
water cut following conditioning at high shear rates to simulate 
ESP production conditions. Viscosities of the emulsions were 
significantly higher than those of dry crude, and increased with 
increasing watercuts, particularly at low test shear rates.
Bottle testing by several laboratories and with a range of de-
mulsifiers failed to identify any product that significantly resolved 
high shear emulsions within the specified (1-hour) test period. 
In combination with the emulsion viscosity data, these results 
indicated that use of ESPs would produce stable, high-viscosity 
emulsions that would seriously impact pump sizing, hydraulic 
design, and operating practices. Experience elsewhere had shown 
that dosing demulsifier to the ESP suction provided excellent 
dispersion of the chemical and could result in rapid emulsion 
resolution. Laboratory testing confirmed that this was also effective 
with Cliff Head crude.
Pour Point Depressant (PPD) Assessment. PPDs (or wax 
crystal modifiers) work by precipitating with waxes in the treated 
crude, distorting their crystals and inhibiting deposition. To be 
effective, a PPD should ideally be dosed to the crude before there 
has been any crystal growth. PPDs themselves generally require 
significant preconditioning facilities and can provide handling is-
sues in an offshore, normally unmanned environment.
Initial testing with Cliff Head crude indicated that very high 
treatment rates (3,000 ppm) would be required to achieve the de-
sired rheological properties. More detailed screening of the four 
main families of PPD chemicals also failed to find an effective 
product. Poor lab results, handling difficulties with the product, and 
the requirement to dose above the WAT of the crude ruled out PPD 
treatment as an effective flow assurance option for Cliff Head.
Core Annular Flow Assessment. Core annular flow (CAF) was 
identified as a potential transportation method for waxy crudes at 
temperatures below their pour point (Joseph 1997). This form of 
transport relies on establishing water as the external liquid phase 
(in contact with the pipeline wall) and carrying the crude as an 
internal slurry.
The stimulus for investigating CAF at Cliff Head was an export 
option that involved transporting crude from ASP by an onshore 
pipeline approximately 60 miles to the nearest port for storage and 
export by marine tankers.
The testing method utilized drilling mud aging cells rolled at 
decreasing temperatures and then held static at 4°C, the anticipated 
minimum onshore air temperature. A range of dispersants and 
water-wetting surfactants were tested. Results were promising, 
with several of the surfactants maintaining water as the external 
phase with little crude deposition on the cell walls at dose rates of 
200 ppm and temperatures near 20°C. Subsequent tests by another 
laboratory were also encouraging but indicated that higher chemi-
cal treatment rates (1,000 ppm) may be required.
The marine export option, and hence requirement for the onshore 
pipeline, was dropped during FEED in favor of road tanker trans-
portation, eliminating a major flow-assurance challenge. Therefore, 
1000
100
10
1
20 30 40 50 60 70 80
V
is
c
o
s
it
y
, 
c
p
Temperature, °C
340 sec-1 170 sec-1 132 sec-1 66 sec-1 13.2 sec-1
Fig. 5—Dry crude viscosity at varying shear.
TABLE 4—PIPELINE RESTART RESULTS 
Conditions 
Restart Pressure (psig) 
Across 9 Mile Pipeline 
Restart Pressure (psig) 
Across 60 Mile Pipeline 
Sudden shut-in 1230 7380 
Slow turn-down 870 5220 
June 2009 SPE Projects, Facilities & Construction 23
the CAF option, despite providing promising results, was not 
pursued further.
Phase 2 Flow Assurance Steady-State and Dynamic Modeling. 
Numerical Simulation and Transportation Considerations. The 
full life cycle crude rheology results from the Phase 1 fl ow assur-
ance laboratory studies were incorporated into a steady-state mod-
el, including the envisaged pipeline route and elevation changes. 
A constant U value of 1 W/m2K was assumed for all cases for 
the onshore section of the pipeline, which was to be trenched and 
buried in dry sand. The nine-mile product pipeline from the off-
shore platform to the onshore plant was modeled, given a required 
arrival temperature above the defi ned WAT of 45°C. The following 
was to be determined:
• Insulation requirements (type, thickness, and so on).
• Pipeline pressuredrops (c.f., ESP deliverability
• Operational considerations of start-up/shut-down.
Pipeline Insulation Requirements and Water Spike. The mod-
eling strategy for the production pipeline was such that if the arrival 
temperature could not be met, alternative insulation options, plus a 
novel hot water spike approach, would be applied. Other pipeline 
developments have utilized hot steam spikes to add thermal mass 
to the bulk fluid in an attempt to maintain flow properties (Tang Y. 
et al. 2003). In this case, an option for consideration was spiking 
the 55°C hot water available offshore through the insulated a hot 
water injection pipeline for water injection with the produced 
fluids. The benefits of this approach are as follows:
1. Thermal mass of bulk fluids would be increased and a com-
mensurate reduction in insulation possible.
2. Above the emulsion inversion point (here, circa 60%), bulk 
liquid viscosity would reduce.
3. Adding water to a dry crude pipeline would reduce the gelled 
pipeline restart pressures.
4. Providing the ability to add agents to the offshore produced 
fluid in the aqueous phase as a mitigation option should insulation 
prove ineffective (e.g., slurrification additives for CAF).
Initial simulations demonstrated that at low water cuts, insulation 
was indeed necessary to prevent the stream falling below 45°C before 
arrival at the plant. With inlet temperatures of 65–70°C and the most 
optimistic field water rate, all cases without insulation fell below the 
pour point before reaching the pipeline halfway point. Even with 
35,000 B/D gross liquid, 97% water cut, and an inlet temperature at 
100°C, the model showed pipeline fluid temperature reaching the pour 
point some four miles before the end of the nine-mile pipeline.
The next stage of testing was aimed at assessing insulation 
requirements in early field life with low water cuts, and com-
mensurate low thermal mass, but including the option to use the 
thermal water spike. Table 5 illustrates these results for a fixed 
inlet temperature of 50°C, a realistic low rate case.
These results indicate that for a U value of 3 W/m2K, hot water 
injection was required to meet an onshore arrival temperature of 
45°C. Hot water at 55°C would need to be “spiked” into the line 
at the offshore platform to provide an additional temperature boost 
and greater thermal mass. As expected, the greatest demand for hot 
water was when the field water cut was lowest.
To study the impact of reduced insulation on the heated water 
requirement, a case of U = 11 W/m2K was considered with a 65°C 
inflow temperature. Results showed that hot water of 60,000 B/D 
at 55°C would be required for an early field life case of 20,000 
BOPD. For only 5,000 BOPD, the heated water requirement was 
still 55,000 B/D. Therefore, U = 11 W/m2K was not feasible for 
these cases.
Steady-state results indicated that, with the expected minimum 
seawater temperature, cooling of the offshore pipeline system would 
be significant. Insulation of U = 3 W/m2K plus a 55°C hot water spike 
was required to meet the onshore arrival temperature of 45°C for 
expected field oil and water production rates. It was further expected 
that pipeline insulation and the use of thermal spike water would help 
minimize the potential for wax deposition in the pipeline.
Production Pipeline Pressure Drop Requirements. To real-
istically imitate expected field conditions, including the impact 
of untreated emulsions, a number of cases were run with varying 
viscosity profiles. The set arrival pressure at the onshore facilities 
was 150 psig. Viscosities were selected from the laboratory data, 
based on the field water-cut, prevailing pipeline temperature, and 
expected pipeline shear rate.
The worst-case inlet pressure of 280 psia was within the capa-
bilities of the downhole ESPs (Table 6). However, power require-
ments and well productivity would be improved if demulsifiers 
were injected as deep as possible in the well-bore, but at least 
upstream (downhole) of the submersible pumps.
Further Numerical Modeling Work. To provide robust data for 
input into the detailed facilities and pipeline design, further numer-
ical modeling addressing the transient behavior of the entire well, 
gathering, and pipeline system was commissioned. This phase of 
work was concerned specifically with detailed steady state/dy-
namic thermal and hydraulic analysis. Output from this work was 
incorporated into more detailed project risk assessments.
Flow Assurance Solutions
Description of Facilities. The laboratory testing and modeling 
programs described previously identifi ed fl ow-assurance-based 
design, equipment, and treatment criteria essential for the develop-
ment of the Cliff Head fi eld. These are listed in the following:
TABLE 5—STEADY-STATE MODEL ING RESULTS (50°C INLET, HOT WATER SPIKE) 
Oil Rate (stb/d) Field Water Cut (%) U (W/m
2
K) Hot Water (bbls/d) 
18250* 27 3 0 
18250 27 3 7500 
10440 64 3 3000 
6000 80 3 2000 
* case failed to meet specified onshore inlet temperature 
TABLE 6—STEADY-STATE MODEL ING RESULTS, PRODUCTION 
PIPELINE PRESSURE DROPS 
Case Inlet Pressure (psia) Pressure Drop (psi) 
190 cp 
 No demulsifier, high water cut 
280 116 
50 cp 
 No demulsifier, early field life case 
260 96 
12 cp 
 Demulsifier added, high water cut 
213 49 
24 June 2009 SPE Projects, Facilities & Construction
Wells: 6 producers and 2 water injectors.
• Downhole demulsifier injection into the suction of the ESP.
• Downhole combined corrosion and scale-inhibitor injection.
• Ability to circulate the wells with hot injection water to re-
move waxy oil from the production string and deliver or displace 
treatment chemicals if required; the completion details have been 
reported elsewhere (Way et al. 2007).
• Production tubing to casing annulus vacuum from mud line 
to platform tree to help prevent cold spots in the production tubing 
through the water and air gap.
• Crude produced above the saturation pressure upstream of 
the choke to mitigate solids (asphaltenes, etc.) and allow simple 
surface remediation.
• Downhole monitoring and flow-line metering to allow ESP health 
and performance tracking and monitoring of pump scale and fouling.
Platform: (not normally manned).
• Insulation and heat tracing of all surface production piping 
and instrumentation.
• Distributed chemical injection system fed through a subsea 
umbilical.
• Offshore injection water quality monitoring (online turbidity 
meter).
• Hot water injection water spike to add thermal mass to fluids 
in the production pipeline.
Pipelines: (1 × production, 1 × injection).
• Identical 10-in. injection water and production pipelines on 
piggable loop.
• 0.563-in. wall thickness, (1500# ANSI), sized for hydrofrac 
and gelled pipeline restarts.
• Polyurethane foam insulation and concrete weight coated 
(0.984 in./1.575 in.).
• U Offshore =3.0W/m2K.
• U Onshore =1.0W/m2K.
Onshore Plant.
• Heat tracing of all production piping and instrumentation.
• Lagging and heating medium circuit through all vessels and 
storage tanks.
• Onshore source water well to provide heat flow into the system.
• Downhole combined corrosion and scale inhibitor injection 
to source water well.
• Capability to reroute gelled pipeline contents to settling tank.
Water Injection Facilities.
• High-pressure onshore positive displacement pumps for hy-
drofrac produced water-reinjection scheme.
• Induced gas flotation for oil and solids removal (hydrocy-
clones may be problematic with waxy crudes).
• Water injection pumps sized to allow displacement of cold, 
gelled pipeline.
Operational Flow-Assurance Summary
There have been a number of flow-assurance challenges since the 
field was commissioned in mid-2006; however, none were related 
to crude gelation, wax deposition, emulsion stability/viscosity, or 
pipeline re-start pressures. Facility uptimes have been excellent, 
with only 5 hours of downtime in 2007. Flow-assuranceparam-
eters investigated in laboratory testing and modeling and mitigated 
against in field planning are addressed in the following:
• The crude is waxy with an ASTM 5853 pour point of 32°C.
• Production pipeline temperatures are maintained at >55°C, 
and weekly pig runs have never recovered hard wax deposits, 
confirming that the WAT is below this temperature.
• Pressures in producing wells are maintained above the bubble 
point of the crude, and there are no indications that asphaltene 
deposition is occurring downhole or anywhere in the process.
• At least 50% of the production pipeline volume is made up of hot 
water and it is displaced with hot water prior to planned shutdowns, so 
the pipeline restart calculations have never been challenged
• Crude is exported hot (>55°C) and loses very little temperature 
in the 5–6-hour journey to the refinery. High dry crude viscosities 
have, therefore, never had an adverse impact on field operations.
• Emulsions generated by the ESPs are extremely stable. Centri-
fuged at 1,600 rpm and 70°C for 30 minutes, an untreated wellhead 
sample with >40% water cut will typically drop only 1–2% water. 
However, effective demulsifier treatment followed by 4 hours in 
laminar flow in the production pipeline containing >50% hot water 
produces emulsion-free near dry oil in the production separator.
• Because of the effectiveness of the production system, no 
additional PPD or CAF testing has been undertaken.
Facilities heat flows (Fig. 6) were generally within expectation 
and the pipeline insulation has performed well (Table 7), despite 
M
/T
HDD
Onshore
- buriedSubsea
Platform
1
3
4
5
6
7
9
2
8
11
33
44
55
66
77
99
22
88
Steady-State Relative Heat Flow 
In 1 4000 kW 
 2 2200 kW 
 3 2500 kW 
Out 4 Negligible kW 
 5 1000 kW 
 6 4600 kW 
 7 1000 kW 
 8 2100 kW 
Transfer 9 350 kW 
Fig. 6—Cliff Head facilities steady-state heat flows.
June 2009 SPE Projects, Facilities & Construction 25
TABLE 7—OPERATIONAL PIPELINE INSULATION PERFORMANCE 
Parameter Detailed Design Estimate Field Experience 
U Overall 2.5 W/m
2
Kcompounds present—possibly Greigite 
(see above). There were also some iron oxide compounds present, 
perhaps owing to oxygen attack.
A detailed survey of the onshore plant failed to detect signifi-
cant levels of oxygen in either produced or injection water. Howev-
er, visual inspection during the Year 1 shutdown found significant 
pitting and oxygen corrosion product on pump discharge lines on 
the injection water system. Finally, recording gauges mounted on 
several of the standby pumps showed them regularly going into 
vacuum, indicating that air ingress was likely through mechanical 
seals. Continuous oxygen scavenger injection was initiated imme-
diately, and high sensitivity corrosion monitoring probes recently 
installed in the injection water system indicate that negligible metal 
loss is occurring. Alternative seal options and the mothballing of 
possible air ingress sources (such as the IGF) are under review.
Conclusions
Cliff Head field is small oilfield (30°C and 
high emulsion forming tendencies. The field is located in highly 
environmentally and economically sensitive, shallow (20 m) ma-
rine environment seven miles off a predominantly lee shore. The 
field was successfully developed because:
1. Flow assurance challenges were recognized early.
2. Appropriate resources were assigned to investigate and develop 
potential solutions to these challenges.
26 June 2009 SPE Projects, Facilities & Construction
3. The development team was willing to integrate flow-assurance so-
lutions into the field development plan and adopt innovative well 
completion design and pipeline thermal management systems.
The development plan has proven robust with respect to waxy 
crude flow assurance, with cumulative production passing 6 mil-
lion barrels in April 2008.
Acknowledgments
The authors would like to thank the Cliff Head joint venture for its 
willingness to publish these data and operational history. We would 
also like to thank David Brankling of Oil Field Chemical Technol-
ogy Limited, Chris Payne of Plexal, and Chin The and Jason Jordan 
of Advanced Well Technology for the significant contribution they 
and their associates made to the project.
References
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Simon Daniel has over 17 years of geographically diverse oil 
and gas experience with operating oil companies, field service 
companies, and consultants in west Africa, the Middle East, the 
North Sea, and Australasia. His field development exposure 
includes mature field regeneration in the North Sea, three FPSO 
developments in west Africa, and both onshore and offshore 
marginal fields in western Australia. He is currently manger of 
production and development for ROC Oil Company. Daniel 
holds a BEng degree in mechanical engineering, an MSc 
degree in exploration geophysics, and an MSc degree in 
petroleum engineering, all from Imperial College in London. 
Jon Roberts started working as a mud engineer in 1974 and 
became increasing involved in production chemicals over 
the following decade. He set up a consultancy in the early 
1990s and has worked on flow assurance and integrity issues 
on numerous developments and facilities in the Asia Pacific 
region since.