SPE 116989
Short-Term and Long-Term Aspects of a Water Injection Strategy
Bruno A. Stenger, Abdulla B. Al-Katheeri, Hafez H. Hafez, Salem H. Al-Kendi, ADCO, SPE
Copyright 2008, Society of Petroleum Engineers
This paper was prepared for presentation at the 2008 Abu Dhabi International Petroleum Exhibition and Conference held in Abu Dhabi, UAE, 3–6 November 2008.
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
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Abstract
This paper reviewed the water injection strategy of a
supergiant carbonate oil field operated by ADCO onshore
Abu Dhabi since 1973. This field was subjected to
peripheral waterflooding in order to maintain reservoir
pressure and provide a mechanism to sweep the oil. In
addition to traditional parameters in waterflooding such as
for instance, reservoir heterogeneity, mobility ratio and
depletion rate that control the waterfont shape, the
presence of three oil-bearing reservoirs juxtaposed across
strike-slip fault planes added a new variable to the
complexity. Fault juxtaposition was interpreted to create
limited pressure communication and fluid crossflow
between reservoirs. The usual way of computing the
voidage replacement ratio based on well production and
injection rates was therefore insufficient to gain a
complete understanding of the water injection strategy.
Two different solutions of the voidage replacement ratio
were computed using a full-field reservoir simulation
model history-matched for both pressure and saturation
changes. After accounting for all surface facilities
constraints and under a certain set of assumptions, results
of this model indicated that crossflow magnitude was
minimized when certain pressure differences were
maintained between these three reservoirs. Alternatively,
there were some indications that higher crossflow could
result in some additional oil recovery. A simple
methodology to manage production and water injection
targets on a quarterly basis while accounting for the
communication between reservoirs was discussed. Finally
implications for an on-going development were reviewed.
Introduction
Field W was located onshore about 110 km southwest of
Abu Dhabi City in the United Arab Emirates. Three major
Lower Cretaceous oil-bearing reservoirs, X, Y and Z,
contained undersaturated oil with reservoirs Y and Z under
commercial production since 1973, and reservoir X
development on-going with plateau production expected
by end of 2012. Reservoirs Y and Z were undergoing
peripheral waterflooding with a mixed wet producing
strategy whereby wet wells were produced until natural
flow ceased. Subsequently, rigless water shutoff
opportunities and revival via artificial lift were deployed.
Reservoir X development called for a peripheral water
injection scheme, targeting the bottom part of the
reservoir, combined with a crestal immiscible WAG line
drive, targeting the upper part of the reservoir.
Waterflooding was clearly the secondary recovery method
of choice for all three reservoirs. The next paragraph
reviewed the field evidence and determined to what extent
all three reservoirs were deemed to be in pressure
communication.
Review of Field Data
Field Structure
Field W was a low-relief anticline with its main axis
trending NE-SW thought to reflect some deep-seated
basement faults regularly reactivated since the
Precambrian (Ayres et al., 1982). Field W structure is
about 30 km long and 10 km wide. Several major fault
corridors trending N110E and some radial extensional
faults in the northern tip of the structure were mapped
from 3D seismic interpretation (Figure 1a). The major
fracture corridors seemed to be regularly spaced every 3 to
4 kilometers along the field main axis. The examination of
the fault pattern (Figure 1b) revealed a typical shearing
system with associated secondary Riedel N135E fractures
confirming a right-lateral (dextral) displacement as
discussed in previous publications (Silva et al., 1996,
Melville et al., 2004). Extensional fractures trending
N15W were also clearly imaged at an angle of 55o to the
main fault trending N110E and occasionally extending to
merge and act as relay between the main strike-slip
fracture corridors. A third fracture system trending NS was
detected at about 70o from the main fault direction,
providing the necessary clockwise rotational component to
accommodate the lateral displacement and release the
shearing stress; this NS fracture direction was interpreted
as being the conjugated left-lateral (sinistral) Riedel
fracture. A schematic interpretation summarized all
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fractures identified for this field (Figure 1c). At first look,
the interpretation pointed to an apparent maximum
horizontal compressive palaeo stress direction of N40W,
not in line with any of the known maximum horizontal
stress directions that affected this region (1) the older
Paleozoic and Mesozoic E-W “Oman” stress regime, and
(2) the more recent Cenozoic N-S “Zagros” stress regime.
A similar conclusion was reached for another oil field in
the same concession with a palaeo stress deemed to trend
N60W (Gomes et al., 2006).
Instead, the authors proposed a new interpretation in
which the sinistral N40-50E fracture direction observed
offshore Abu Dhabi (Marzouk and Sattar, 1994) and the
dextral N110E fracture direction observed onshore Abu
Dhabi are conjugate shearing faults with a maximum
horizontal palaeo compressive stress oriented N70-80E
and consistent in orientation with the E-W “Omani” stress
regime (Figure 1d). It was the authors’ view that in this
field the “Zagros” stress regime re-activated this strike-slip
system with a N110E dextral (opposite) slip. A possible
explanation for the preferential development of N45E
sinistral strike-slip faults in the north of the basin (offshore
Abu Dhabi) and N110E dextral in the south of the basin
(onshore Abu Dhabi) could reside in the existence of an
independent tectonic block bounded to the north by the
Trans-Arabian Gulf sinistral fault (Weijermars, 1998)
(Figure 1e).
In the field under study, fault throw was modest in
general but considering that reservoirs X, Y and Z were
vertically separated by dense limestone beds of 20 to 30
feet only, even a small vertical offset would be enough to
juxtapose reservoirs and create a lateral communication
path (Figure 2). Wrench tectonics created situations with
localized reverse faulting and increased complexity of
juxtaposition between reservoirs. Pull-aparts and
extensional fractures could also open direct vertical
communication between reservoirs. It was therefore
concluded that field W was in a known tectonic setting
and that its interpreted fault pattern indicated the
likelihood of (1) lateral communication between reservoirs
through juxtaposition and (2) vertical communication
through pull-aparts and extensional fractures.
Reservoirs X, Y and Z were vertically separated by
dense limestones that were essentially non-pay intervals.
Stylolites were observed on cores taken across these
intervals (Figure 3) and previously described in the
literature (Koepnick, 1987; Al Sharhan and Sadd, 2000).
Stylolites were considered as playing an important role in
the local restriction of vertical communication between
and within reservoirs; laterally, continuity of stylolites
might be interrupted through faulting and fracturing.
Within each reservoir, denser intervals were used to define
a subzonation of the producing units generally in Upper
and Lower subzones. Intra-reservoir dense sublayers with
sufficient thickness were clearly visible on 3D seismic
cross-sections as thick non-pay intervals downflank that
could thin and disappear on the crest of the field (Figure
4).
Reservoir Oil and Aquifer Brine
SPE 116989
Although pre-production fluid analyses were scarce, it
was verified repeatedly that crude oil properties were very
similar between reservoirs X, Y and Z to a point that
variability in composition between bottomhole samples in
one well was larger than any differences measured
between oil sampled in the three reservoirs. Bubble point
pressure of 2,220 psi at 250 oF, solution gas-oil ratio of
850 scf/stb, molar composition all indicated similar sweet
crude with API of 38 degrees. The only notable difference
was linked to the asphaltene content in the northern part of
the field where core data indicated an increase of bitumen
content in the bottom thirty feet of reservoir Y. This
localized increase in bitumen was not fully understood yet
although its basal structural position within a lower
permeability subzone could indicate a palaeo-OWC and
the consequent formation of a tarmat at the OWC
interface. Aquifer brine was sampled from reservoirs Y
and Z early in the field life with a salinity ranging from
157,000 to 188,000 ppm TDS. Onshore Abu Dhabi, the
salinity of the overlying Umm Er Radhuma (Palaeocene)
and Simsima (Upper Cretaceous) aquifers was 254,000
ppm TDS at reservoir conditions and clearly higher than
the salinity measured in reservoirs X, Y and Z. No
definitive explanation was available for the higher salinity
in Umm Er Radhuma and Simsima aquifers although the
overlying Rus formation (Early Eocene) was known to
contain evaporites.
In summary, known oil and brine properties seemed to
indicate similar fluids in all three reservoirs.
Static Reservoir Pressure and Fluid Contacts
Initial static reservoir pressure of 3,930 psia at -7,700 feet
tvdss indicated hydrostatic and static pressure conditions
across all three reservoirs. Original oil water contacts
(OOWC) were found at similar depths in reservoirs Y and
Z. Indications that the OOWC was shallower in reservoir
X might result from a larger transition zone in a reservoir
of lower permeability. It was generally accepted that all
three reservoirs shared a common free water level of 7,920 feet tvdss.
Early Reservoir Pressure Evolution
From late 1973 to early 1976, reservoirs Y and Z produced
under primary depletion in order to determine the level of
aquifer support and select the appropriate full field
development strategy. The rapid reservoir pressure decline
in reservoirs Y and Z indicated minimal aquifer support
(Figure 5).
The large pressure depletion in reservoir X (red dots)
was explained through commingled production with
reservoir Y in two early producers, a practice that was
discontinued after 1976. As expected in commingled
completions, measured pressure in reservoir X (low
permeability) was tracking reservoir Y (high permeability)
pressure perfectly.
Reservoir Z pressure was obviously higher than
reservoir Y suggesting perhaps a restricted communication
between the two reservoirs. Since both reservoirs were of
a different size and produced at different rates, this plot
was not sufficient to draw a clear conclusion. A material
SPE 116989
balance using the Carter-Tracy water influx function and
the Fanchi polynomial coefficients was applied for both
reservoirs during the primary depletion phase from
December 1973 to December 1975. A good match of the
historical reservoir pressures was obtained using a very
small Carter-Tracy aquifer with reD of 1.5 (large dots on
figure 5). These observations were consistent with a
limited aquifer support as frequently observed in the large
carbonate oil fields of the Arabian Peninsula as reservoir
development and permeability dropped dramatically off
structure.
The apparent reservoir compressibility was equal to the
slope of the trends plotted for each reservoir (Figure 6).
This plot revealed that the reservoir pressure of reservoirs
Y and Z behaved similarly when plotted against the
volumetric depletion of their respective oil in place
volumes. After reaching respectively a cumulative
production of 2.8% and 2.0% of their original oil in place
(OOIP), reservoir Y and reservoir Z pressure declines
were drastically reduced as gravity water injection started
at high rates during the first quarter of 1976 and pressure
maintenance was felt very quickly due to the high
reservoir permeability in reservoirs Y and Z. Peripheral
water injection was implemented in order to maintain
reservoir pressure in the producing reservoirs, first using
gravity water injectors from early 1976 then pumping and
re-injecting aquifer brines after 1984. As it was commonly
noted when gravity water injection was used, there were
some uncertainties in the gravity water injection rate
history as injection rate was not measured on a regular
basis and was generally dropping in proportion to the
building backpressure on the injecting aquifers. By
difference, cumulative gravity water injection for
reservoirs Y and Z was recomputed using the Carter-tracy
material balance equations history matched in the previous
step. In the case of reservoir Y, it was found that the
recalculated gravity water injection rate history could be
somewhat higher in the early times (Figure 7).
Early pressure data were found to be of good quality
for this field, a testimony to the professionals who initiated
the development and did not sacrifice data acquisition. A
material balance analysis of these data showed that no firm
conclusion could be made as far as communication
between reservoirs Y and C was concerned. In particular
the pressure differential of 250-300 psi between reservoirs
Y and Z could apparently result from a lower level of
depletion in reservoir Z when gravity water injection
started and the maintenance of similar voidage
replacement ratios in both reservoirs. On the other hand, a
restricted communication was still compatible with the
available pressure measurements.
Reservoir Pressure Evolution during Powered Water
Injection
Powered water injection was initiated in 1984 in order to
help increase reservoir pressure in the center of the field
and sustain the natural flow of maturing producers in the
periphery. Historical reservoir pressures showed the
typical scattering that was a function of the distance
between the observation point and the row of peripheral
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water injectors, reservoir permeability and level of
production.
Reservoir X had been shut in from 1976 to mid 1990
after two early commingled producers were re-completed
and reservoir X perforations squeezed off. No pressure
measurement was made during the shut-in period because
no wells had opened perforations in reservoir X except for
a RFT acquired in a first-row producer across reservoirs
X, Y and Z in February 1989. Since the well location was
close to the eastern row of water injectors, the pressure
levels in reservoirs Y and Z could be influenced by the
near-by water injectors. This RFT indicated however a
pressure differential of 200 psi between reservoirs X and
Y. Upon resuming production from reservoir X in July
1990, reservoir X pressure was measured in two crestal
wells that had been recompleted and pressure was found to
have declined to 2,900 psia at datum of -7,700’ ft tvdss. A
comparison with near-by wells completed in reservoir Y
showed that a pressure differential of 230-300 psi existed
between reservoirs X and Y in July 1990 (Figure 8). As
production resumed, reservoir X pressure declined and
coincidentally became superimposed with reservoir Y
Lower pressure.
Some firm evidence was therefore indicating that
reservoir X pressure had continued to decline during the
14-year shut-in period although the pressure differential of
230-300 psi at datum showed unequivocally that pressure
communication was only partial.
Fluid Saturation Interpretations
Full suites of conventional openhole logs were routinely
acquired in development wells and were covering
reservoirs X, Y and Z. Several water saturation anomalies
were recorded in reservoir X with two classical cases
shown here as examples (Figure 9). These wells were
drilled in major fracture corridors and openhole logs
identified very high water saturation in the lower part of
reservoir X that should have been oil-bearing since
reservoir X was not being developed or produced at the
time of logging those wells. The presence of water in
reservoir X was linked to the waterflooding of reservoir Y
and vertical gravity slumping through the faulted/fractured
zones with the well under consideration clearly drilled in a
(pull-apart) downthrown block with about 50 feet of throw
(Figure 10). Reservoir Y is made up of two major
subzones with much higher permeability in Y Upper. By
the time the well illustrated in figure 10 was drilled in
2003, injection water had encroached in most of subzone
Y Upper after 30 years of plateau production. The
possibility of water crossflow during drilling was not
considered likely since (1) this situation was observed in a
limited number of wells and (2) all wells were drilled with
same mud overbalance of 250 to 300 psi.
Preliminary Findings
It is concluded that some degree of vertical
communication existed between reservoirs X, Y and Z
especially near the major fault corridors where reservoir
sections could be juxtaposed or pull-apart features were
interpreted from 3D seismic imaging. Communication
4
behind casing was ruled out since existing cement bond
logging data showed that usually, cement bond quality was
good across the inter-reservoir dense layers. The authors
were therefore confident that the analysis of early
reservoir pressure data had produced conclusive evidence
that reservoirs X, Y and Z were experiencing some degree
of pressure communication along fracture corridors. A
pressure threshold of 200-300 psi was deduced from the
analysis presented here and could be used as a calibration
point in reservoir models. Anomalous water encroachment
found in reservoir X was successfully linked to pull-apart
features along major fracture corridors with gravity water
slumping in downthrown blocks as the most likely
mechanism for the water presence in reservoir X.
Reservoir modeling and reservoir simulation were the
tools of choice to further understand the interaction
between the three reservoirs and reproduce the historical
data as discussed in the next section.
Reservoir Modelling
Historically, reservoir simulation models were restricted in
size due to limited computer resources. With the recent
increase of computational power and parallel processing,
previous limitations in grid cell size and number of cells
had been overcome and allowed running routinely models
with a million active cells or more.
In the case under discussion, this translated into
building the first ever high-resolution (finely layered)
reservoir simulation model combining all three reservoirs.
The importance of having fine layers across faultjuxtaposed blocks was therefore critical. Previously, nonneighbour connections had provided a numericallyefficient way of connecting layers through fault planes.
Non-neighbour connections were found however
cumbersome to establish and not very practical to modify
in a consistent manner along 10-km long faults with
variable throw during a history matching process.
Although finer layers did resolve the issue of reservoir
juxtaposition and direct lateral communication across
major faults, subseismic faults had to be invoked in some
cases and only non-neighbour connection could establish
the required communication in the absence of any visible
fault throw.
Previously, a set of three models based on the same
structural framework had been history matched. These
three models consisted of (1) finely layered reservoir X
with coarsely layered reservoir Y, (2) finely layered
reservoir Y with coarsely layered reservoirs X and Z and
(3) finely layered reservoir Z with coarsely layered
reservoir Y. Fine layers were extracted from the three
models with all associated properties and merged into a
single fine resolution model (Figure 11). Main matching
parameter was the adjustment of fault transmissivity and
non-neighbour connections. A very good pressure history
matching was achieved in a few months (Figure 12). The
next step was to leverage the insight from the reservoir
simulation model into the deployment of an efficient water
injection strategy for the three reservoirs.
SPE 116989
Short-Term Management of Water Injection
Highly saline water was produced from Simsima and
Umm Er Radhuma aquifers using electrical submersible
pumps with capacity of 30,000 bwpd. Twenty-three water
injection clusters circled the field periphery with
interconnection to ensure that each water supply well
could share its supply with neighboring clusters as a
backup during maintenance shutdowns (Figure 13). Each
cluster was equipped with a surface injection booster
pump with a capacity of 30,000 bwpd and outlet pressure
of 2000 psi.
Water injection targets were defined on a quarterly
basis to match the water supply availability and distribute
the water between injectors in order to optimize voidage
replacement ratio.
Since this field extended over 280 square kilometers,
water injection allocation needed to be calculated by
sector. The field was therefore divided into eleven regions
for each subdivion of the three reservoirs (Lower and
Upper) yielding a total of 22 regions per reservoir. As
much as possible, region boundaries were based on the
fault system described before. Since the no-flow boundary
assumption between the producing regions was not an
acceptable approximation in this case, interaction
coefficients were derived from the simulation model by
increasing the injection rate in one cluster only and
calculating the pressure differential it created in all regions
after a number of years with all others rate constraints
being held identical; a total of 23 runs were necessary to
obtain all coefficients of influence expressed in psi after
five years of injection. After normalizing by the larger
pressure differential recorded, a matrix of influence was
derived. The matrix of influence was used to distribute the
effect of water injection among different regions rather
than allocating it all to one region only as a classical
approach would dictate, which would be clearly wrong in
case the no-flow boundary assumption between regions
was not fulfilled.
Since reservoirs X, Y and Z have been shown to be in
pressure communication, fluid fluxes between reservoirs
were also extracted region by region from the simulation
model and included in a modified version of the classical
voidage replacement ratio equal to the sum of all fluxes
entering the region divided by the sum of all fluxes
leaving the region. Two ways of calculating the voidage
replacement ratio were therefore available and used to
complement/check each other.
The implementation of this methodology required the
coding of visual basic macros using well-known
spreadsheet software. These macros have permitted to
unify the distribution of oil production and water injection
targets string by string in a very efficient and reliable
manner for a field with several hundreds of producing
strings at different stages of maturity. Results could be
plotted easily as bubble maps to ensure a visual check of a
proper rate distribution by region. Voidage replacement
ratios were remarkably maintained throughout history with
a very good balance between regions.
SPE 116989
Long-Term Management of Water Injection
The authors have demonstrated that reservoirs X, Y and Z
were in communication along major fracture corridors.
The history-matched combined model was used to
estimate the cumulative oil and water volumes exchanged
between reservoirs during the historical period and for the
next fifty years of operation.
Several levels of pressure maintenance in the oil
producing areas were assigned as targets and the reservoir
simulator was instructed to adjust water injection rates in
order to match the reservoir pressure targets while
respecting all surface facilities constraints. Sixteen
production forecasts were run using different reservoir
pressure targets for each reservoir.
Results indicated that maintaining the current pressure
levels in each reservoir (blue dot on figure 14) would
minimize future crossflow between reservoirs as expected
(Figure 14). It was indeed predictable that the current
pressure regime reflected a situation of stable equilibrium
after more than thirty years of balanced powered
peripheral water injection. Higher recovery was obtained
when the pressure differential between reservoirs Y and Z
was 100 psi higher than the pressure differential between
reservoirs X and Y due to differences in cross flow
directions. Compressibility effects (blow down) were also
evident in case pressure was allowed to reduce down to
2900/3100/3400 psi in reservoir X/Y/Z respectively with
little additional crossflow since the pressure differential
between reservoirs was maintained compared to the actual
case. Reducing pressure in all three reservoirs to 3000 psi
would lead to the highest cumulative oil recovered
although it would be at the risk of large additional
crossflow between reservoirs. Care must be exercised in
all cases since any extra recovery would come at time of
high reservoir maturity and high watercut in subzone Y
Upper in particular when reservoir simulation predictions
are highly dependent on the accuracy of low relative
permeability values and residual oil saturation.
Since early 2008, the subsurface development team
used commercial software to apply an experimental design
approach in order to quantify the effect of subsurface
uncertainties on the development plan deliverables such as
plateau production duration and reserves recovered at a
cut-off date. The same software was used to accelerate the
history matching process for the gas and water injection
pilots with interesting conclusions on a likely anisotropy
in the horizontal permeability, possibly linked with the
fracturing pattern described earlier. After populating the
full field model with the modified reservoir properties, the
overall history matching quality of the full field model
improved noticeably. These preliminary results were
found significantly encouraging and warranted further
work.
Reservoir X Development Strategy
Reservoir X full field development plan was recently
approved. The optimum drive mechanism was identified
as a peripheral water injection system coupled with an
immiscible Water Alternate Gas (WAG) sparse line drive
on the crest of the reservoir. With this perspective, the
5
need to properly understand and locate pressure
communication and crossflow between reservoirs X and Y
could not be overstated.
Since 1998 and 2002 respectively, a water injection
and a gas injection pilot had been in operation in reservoir
X to obtain information on the sweep efficiency and
timing of water and gas breakthroughs. Since September
2007, both pilots were converted to WAG with 3-month
cycles and 1:1 ratio having been determined as the most
efficient parameters using reservoir simulation models.
Pressure fall-off tests were regularly acquired at the end of
each cycle to check for gas or water blockage effects.
Since 2004, three pairs of peripheral water injection wells
and first row horizontal producers were put on stream in
order to evaluate the pressure transfer in a low
permeability reservoir.
All pilots were monitored on a quarterly basis and the
results were used to fine tune the development plans. For
instance, declining injectivity in peripheral water injectors
resulted in a combined effort to increase injectivity by
drilling longer horizontal wells, enhancing stimulation
practices and reducing the count and maximum size of
suspended particles in the injected water.
Fine water filtering was believed to have a
significative positive effect on reservoir X water injector
life. This was confirmed in a recent study conducted on
the Ghawar field in Saudi Arabia (Evans et al. 2004). In
the case of reservoir X development, water quality was
identified as a critical parameter to maintain injection
conformance in the the crestal WAG wells that were
targeting the upper subzone of reservoir X. Since fractures
could not be allowed to propagate into the lower subzone,
water quality was essential to avoid plugging the fine
pores of the upper subzone that would inevitably trigger an
increase in downhole pressure and raise the risk of
developing a fracture. By itself, fine water filtering might
not be sufficient to ensure WAG wells did not develop
fractures since lower temperature was playing a key role in
reducing the rock ability to bear tensional stresses at the
wellbore face. Permanent downhole pressure and
temperature gauges were therefore added to the WAG
completion kit in order to keep a firm monitoring of these
complex interactions.
Conclusions
At field level, the N110E dextral strike-slip was shown
to be consistent with a North-South “Zagros” maximum
horizontal stress re-activating a conjugated fault direction
initiated during the N70-80E “Omani” compression phase.
Pull-apart features along major dextral fracture corridors
were identified and explained water saturation anomalies
in the then undeveloped topmost oil-bearing reservoir X.
Pressure communication was successfully linked not only
to lateral communication through reservoir juxtaposition.
Transtensional fractures with no identifiable vertical
displacement were also interpreted and could provide
additional vertical communication in the central part of the
field.
A comprehensive review of the water injection strategy
applied in a supergiant oil field operated onshore Abu
6
Dhabi since 1973 has led to some interesting insights that
were integrated in the next phases of development.
Acknowledgements
The authors wished to thank ADCO and ADNOC
management for permission to prepare, publish and
present this paper. The authors acknowledged the
contributions from Peter Melville who interpreted the 3D
seismic cube, David Sousa who coded the first macro used
to distribute the production targets by region, Pradyumna
R. Chaliha for the derivation of influence coefficients
using the reservoir simulation model and Majid M.
Faskhoodi who combined the first finely-layered reservoir
model covering all three reservoirs and studied the effect
of different pressure maintenance strategies. Their initial
efforts were essential to the work accomplished since and
the current achievements. Thanks were extended to Jorge
S. Gomes and Gerard Bloch for their kind and thorough
review of the manuscript.
References
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