1. OTC 16699
Subsurface Development Challenges in the Ultra Deepwater Na Kika Development
D.T. Rajasingam - Shell E&P Americas, T. P. Freckelton - Shell E&P Americas.
Copyright 2004, Offshore Technology Conference
Introduction
This paper was prepared for presentation at the Offshore Technology Conference held in The ultra-deepwater Na Kika development concept represents
Houston, Texas, U.S.A., 3–6 May 2004.
a new movement in the exploitation of hydrocarbon reservoirs
This paper was selected for presentation by an OTC Program Committee following review of
information contained in an abstract submitted by the author(s). Contents of the paper, as
in deepwater environments – one that does not rely on a single
presented, have not been reviewed by the Offshore Technology Conference and are subject to large accumulation to justify development. Instead, Na Kika
correction by the author(s). The material, as presented, does not necessarily reflect any
position of the Offshore Technology Conference or its officers. Electronic reproduction, utilizes a cluster development concept, leveraging technology
distribution, or storage of any part of this paper for commercial purposes without the written
consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print
and innovative thinking to turn a collection of small to
is restricted to an abstract of not more than 300 words; illustrations may not be copied. The medium sized fields into an economic cluster development
abstract must contain conspicuous acknowledgment of where and by whom the paper was
presented. tied to a floating production and storage vessel with sub-sea
production systems, illustrated in figures 1 and 2.
Abstract
The Na Kika Development is located in water depths ranging As the “big cats” in deepwater environments are
from 5,800 to 7,000 feet in the US Gulf of Mexico. The found and developed, the cluster development concept and
project, a joint effort by Shell and BP (approximately 50% application of exploration and production technology will
each), is a sub-sea development of five small to medium sized, have to become the norm to enable companies to develop
oil and gas fields tied back to a centrally located, permanently- further into the deepwater.
moored floating development and production host facility
located in Mississippi Canyon Block 474. The sub-sea The joint venture arrangements associated with the
infrastructure consists of 10 wells connected via three 25-mile development are as unique as its technical nature. The design
flowline loops, 23 flowline sleds, and 50 miles of umbilicals and construction of the surface and subsurface development
to the semi submersible-shaped host with topsides facilities for infrastructure has been executed by Shell as the ‘pre-
fluid processing, and pipelines for oil and gas export to shore. production operator’, with BP assuming the ‘post production
The Na Kika Host facility has a processing capacity of 110 operator’ role upon start-up of the first well. This unique
mbopd oil and 425 mmscfd gas. First production was endeavor, rooted in the historical ownership arrangements of
achieved in November 2003. The host and sub-sea the various fields, has leveraged the best of both companies to
infrastructure is designed for other tiebacks to enable further the benefit of the partnership as a whole.
development in the area. A sixth field will be tied back in
2004. Exploration and Appraisal History
The first exploration leases for what would become the Na
The Na Kika fields consist of multiple stacks of
Kika area were acquired in 1985 over the Kepler, Ariel,
turbidite reservoirs deposited in an unconfined by-passed
Fourier and Coulomb fields (see figure 3). East Anstey and
slope setting. These reservoirs are characterized by mud-rich
Hershel leases were acquired in 1988. The paradigm at the
depositional environments punctuated by sand rich
time of the first lease acquisitions was the hunt for large
channel/levee systems.
accumulations (“Big Cats”) that could justify the installation
of a stand-alone production system, requiring recoverable
The diversity and complexity of Na Kika's subsurface
volumes in the order of 500 MM boe or more. Prospects were
offered a number of challenges requiring a novel approach to
identified on the basis of 2-D seismic, and were amplitude-
the development and application of well and sub-sea
supported mid-Miocec turbidites. In contrast to the confined
technology. The successful deployment of this technology
basins conventionally developed in the Gulf area containing
together with excellent execution has enabled an economic
massive sheet sands, these prospects were located in
development concept of what would otherwise be five sub-
unconfined, bypass slope settings, and most likely contained
economical developments on a stand-alone basis.
hybrid, thin-bedded laminated sands. As such, the geology
was complex, and well placement to exploit reservoir ‘sweet
The key subsurface development risks and challenges
spots’ and maximum connected volume would be difficult.
included reservoir quality, continuity and connectivity (areally
The biggest challenge to development, however, was the
and vertically), aquifer size and support, well and reservoir
deeper water depths (5800-7600 ft). At the time, the deepest
performance and management, reservoir compaction, and fluid
structure in the Gulf of Mexico was the Bullwinkle platform in
compatibility (ashphaltenes).
1350 ft of water. Despite this, exploration drilling progressed

2. 2 OTC 16699
in order to prove up volumes on the assumption that The five Na Kika fields are retained by an integrated,
deepwater construction and production technology would regional Suspension of Production (SOP) approved by the
evolve within the next decade or so. Mineral Management Service (MMS) in 1995.
Shell drilled the first discovery well in the Na Kika Wells, Sub-sea System & Host Facility. The sub-sea system
area in Mississippi Canyon (MC) 383 in June 1987, finding consists of 10 wells connected via three 25-mile flowline
the high net-to-gross oil-bearing K1 sand at Kepler (5800 ft loops (two oil and one gas), 23 flowline sleds, and 50 miles of
water depth). Additional exploration in the area led to the umbilicals to the semi-submersible shaped host with topsides
discovery of the Coulomb gas field in MC 657 (7600 ft water facilities for fluid processing and pipelines for oil and gas
depth) in November 1987, and the Fourier oil and gas field in export to shore.
MC 522 (7000 ft water depth) in 1989.
The ten wells include two at Kepler (oil), three wells
The Kepler, Fourier and Coulomb fields were not of in each of Ariel (oil) and Fourier (gas/oil), and one well in
sufficient size to merit stand-alone developments, nor did each of Herschel (oil) and East Anstey (gas). The wells and
current technology of the day enable development in these completions campaign was undertaken in a batch mode to
water depths. As such, interest in the area faded, and Shell facilitate the execution efficiencies associated with both
refrained from further exploration in water depths greater than operations. The Kepler field is the largest oil-bearing
5000 ft as the Tension Leg Platform (TLP) era began to reservoir, and has been developed by horizontal gravel-packed
evolve. wells. With the exception of the two horizontal gravel packs
In 1993 an Area of Mutual Interest (AMI) was agreed at Kepler, all remaining wells at Na Kika are vertical or
between Shell and Amoco that would allow both partners to deviated frac and packs. All three of Ariel’s oil wells are
share risk and reward in the further exploration and appraisal multi-zone commingled completions, with two of the three
of the area. The AMI encompassed 96 lease blocks around the wells employing intelligent well technology. The Ariel and
Na Kika area, from Kepler in the northwest down to Coulomb Kepler fields are tied into a sub-sea loop, and are commonly
in the southeast. The AMI required Amoco to shoot 3-D referred to as the northern fields, illustrated in figure 2.
seismic over the whole area, and earn further interest by
drilling exploration wells. As additional prospects emerged The three fields in the South are the Fourier,
from the 3-D seismic, further interest was driven by evolving Herschel, and East Anstey fields. Fourier comprises both oil
sub-sea production technology, and it became evident that and gas reservoirs, with one well developing three stacked oil
sub-sea tiebacks could potentially be economically developed pays with an intelligent well completion. The three remaining
within a 15 mile radius to a central production facility. reservoirs at Fourier are gas-bearing and are developed by a
further two wells, of which one is a dual-zone intelligent well
In 1995, three stacked oil-bearing pays were completion. The remaining gas well at Fourier is a single-
discovered in the Ariel field and a further oil-bearing zone completion. The Hershel field is a single oil-bearing
discovery was made at Herschel in 1996. With the Ariel and reservoir developed by a single-zone completion, and is tied
Herschel discoveries, momentum built towards a potential along with the Fourier oil well into a southern sub-sea oil loop
cluster development and concept selection for the (see figure 2). The East Anstey gas field is developed by a
development began. Exploration drilling activity continued single zone completion. The East Anstey and two Fourier gas
with a gas-bearing discovery at East Anstey in 1997 and wells are tied into a southern sub-sea gas loop, illustrated in
appraisal drilling of Ariel and Fourier into 1999. With figure 2.
concept selection finalized, project sanction was achieved in
September 2000 with first production targeted for 2003. The sub-sea flowline systems are comprised of a
10”x16” pipe-in-pipe (PIP) loop connecting Kepler and Ariel
Development Overview to the Host facility in the north, an 8”x12” PIP south oil
The core Na Kika development is comprised of five small to flowline loop connecting Herschel and Fourier to the Host,
medium sized fields (20 – 100 MM boe recoverable), in water and an 8” uninsulated gas flowline loop connecting East
depths of 5,800 to 7,000 feet. The five fields: Kepler (MC- Anstey and Fourier to the Host. The PIP configuration was
383), Ariel (MC-429 Unit), Fourier and Herschel (MC-522 selected for its thermal benefits to assist in the control of
Unit), and East Anstey (MC-607 unit), have been tied back to hydrate formation and paraffin deposition. Twenty-three sleds
a centrally located (3-12 miles distance), permanently moored have been installed for well jumpers, tie-in umbilicals, and to
floating production facility in a water depth of 6340 ft at MC- provide hubs for future tie-ins. Gas lift risers are connected to
474 (see figures 1 and 2). In total, 10 development wells have the base of the North oil loop risers to assist in production of
been drilled to develop some 300 MM boe. Shell and BP the Kepler and Ariel fields, and the system is designed for
share a 50% interest in all fields except East Anstey where future installation of gas lift risers for the South oil loop, if
Shell has a 37.5% interest, with BP holding the remainder. required. All flowlines are connected to the host via steel
First production was achieved on 26 November 2003 with the catenary risers (SCRs).
opening-up of the East Anstey well. A sixth field, Coulomb, a
gas field owned by Shell, is in a water depth of approximately The Host facility has a processing capacity of 110
7,600 ft and will be tied back to the host facility later in 2004. mbopd of oil and 425 mmscfd of gas. The oil and gas will be
produced back to shore via two 75 mile export lines; an 18”

3. OTC 16699 3
oil export pipeline to Main Pass 69 pump station, and a The Ariel reservoirs are delineated by a combination
20”/24” interconnect/export gas pipeline to Main Pass Bock of structural and stratigraphic trapping elements. The
260. Twenty-six riser baskets have been installed onto the reservoirs south of the Main Fault, with the exception of the
host with eleven baskets currently used for the core Na Kika K1 and A2 Upper Sands, have an associated aquifer and are
development and the remaining for future developments in the expected to exhibit a partial water drive. All the reservoirs to
area. the north of the Main Fault have no associated aquifer and are
pressure depletion. All reservoirs are oil-bearing, with the
Field & Subsurface Overview exception of A1 Reservoir B-west, which has a gas
The Na Kika area was an unconfined slope setting during the accumulation on top of the oil leg. This localized gas
middle to upper Miocene period, characterized by mud - rich accumulation does not appear to extend north across the Main
deposition punctuated by sand-rich channel/levee systems. Fault. The placement of the three development wells was
Individual channel/levee systems typically had very low designed to optimize the exploitation of the reservoirs. All of
sinuosity, suggesting relatively steep depositional gradients the completed zones are Upper Miocene (M2.8) amalgamated
were present. Many of the systems are characterized by a channel sands.
central seismic dim with bright flanking amplitudes,
interpreted to be a mud-filled channel with adjacent sandy The major subsurface uncertainty in Ariel is both the
levee/overbank deposits. lateral and vertical continuity, and connectivity of the
reservoirs. The reservoirs are significantly channelized with a
The Na Kika area consists of scattered salt fining upward sequence. There is a high risk that flow barriers
piercements with intervening salt evacuation sub-basins. may exist within the reservoirs as evident in the dim lineations
Trapping geometries are typically found along highs adjacent from the seismic amplitudes. Other key uncertainties are
to the salt piercements (e.g. Herschel, Kepler Fields) and as aquifer support and reservoir compaction.
drapes over deep inversion (turtle) structures (e.g. Fourier and
Ariel Fields). While all the Na Nika fields are localized along East Anstey. East Anstey field is a dry gas accumulation
major structural elements, every pay horizon has a comprised of a single reservoir EA6 located on lease blocks
stratigraphic trapping element overprint. Vertical migration MC-607 and MC-608 in 6650' of water. EA6 is a well-
and charge of the middle to upper Miocene Na Kika reservoirs defined, downthrown fault block trap with a minor
occurs via deep-seated faults and/or along salt/sediment stratigraphic overprint. Two fault splays bound the reservoir
interfaces. Lateral hydrocarbon migration may be possible to the north and northeast. All three EA6 well penetrations
along the depositional axes of sand - rich Miocene (MC 607 #1 discovery well and sidetrack and MC 608 #-1)
channel/levee systems that cross the area. encountered a high net/gross, massive sand package, which is
interpreted to represent amalgamated sheet sands. The
In total, there are some eighteen oil and gas geological setting is conducive to a large aerial extent and
reservoirs developed, ranging in depth from 12,000 to 16,000 hence potentially strong aquifer support, and good lateral and
feet true vertical relative to Mean Sea Level (water depths vertical connectivity.
5,800-7,000 ft) with average reservoir pressures in the range
of 7000 to 9500 psi. The channel/levee type reservoirs One single-zone development well has been drilled
possess a variety of internal seismic geometries reflecting the high on structure. The lateral extent and connectivity of the
variety of sub-facies that occur: channel cut-and-fill, dissected EA6 reservoir across the field is a key uncertainty due to the
sheets-splays, and subtle to large-scale gullwings- presence of faulting and/or discontinuous sand occurrences.
channel/levee. Hybrid sands of massive sand overlain by a Additional uncertainties are primarily fluid and reservoir
fining and thinning upward laminated sequence are the most related.
commonly encountered reservoir type. Complexes of stacked,
channel/levee systems tend to be highly aggradational with Fourier. The Fourier field is an oil and gas accumulation
possible localized post-depositional erosion alteration of the located over a broad, low relief, four-way closure in block
underlying deposits. The key subsurface development risks MC-522 in a water depth of about 7000 feet. The four-way
include reservoir quality, continuity and connectivity (areal closure is located immediately southeast of the Fourier Salt
and vertically), aquifer size and support, well and reservoir diapir and is related to a deep Jurassic turtle structure. The
performance, reservoir compaction, and fluid compatibility individual reservoirs at Fourier consist of bypass facies
(ashphaltenes). associated with mud-rich turbidite deposition in an unconfined
setting. Cross-sections exhibit a range of channel and levee
Field Descriptions related geometries including classic “gull-wing” profiles. All
Ariel. The Ariel field is an oil accumulation comprised of of the tested objectives have hybrid reservoir architectures.
overlapping, stacked reservoirs located on lease blocks MC- The more massive sands at the base of the reservoirs are
385, MC-429 and MC-430 in a water depth of 6200 feet. The thought to be a combination of turbidite fan lobes, overbank
field is categorized as bypass-turbidites with a large, broad, 4- splays, and amalgamated channels. Typically, these massive
way closure. A prominent, E-W striking Main Fault on block basal units are overlain by a fining-upward, thin-bedded
MC429 bisects the amplitude anomalies and is interpreted to sequence. All of the traps have both structural and
be sealing. stratigraphic components. Post-depositional scouring in some
cases may have resulted in discontinuous reservoir

4. 4 OTC 16699
connectivity. Major subsurface uncertainties include reservoir size
(lack of seismic imaging under salt), areal connectivity,
Three wells with six completions have been drilled to aquifer support, and reservoir compaction.
develop six semi-stacked objectives (F5RA, F7RA, F7.5RA,
F8RA upper, F8RA lower and F8RB upper). Subsurface Risks & Challenges
The wide range of reservoir type and size, and the variability
The key subsurface uncertainties are similar to Ariel in reservoir qualities encountered in each field in conjunction
and also include fluid compatibility and the formation of with the area water depths, made it difficult to justify or
asphaltenes during commingled production of the F8 execute stand-alone economic developments of the individual
reservoirs. fields. It has taken the application of maturing sub-surface
imaging technologies to better understand the size of the prize,
Kepler. The Kepler field consists of the single K1 oil along with the evolution of deepwater construction and
reservoir located on block MC-383 in some 5700 feet of production technology to enable an economic development
water. The late Miocene K1 reservoir is interpreted to be a concept.
massive, high net-to-gross amalgamated sheet sand. The
updip west flank of the K1 is abruptly truncated by a channel The limited size of the average Na Kika field is a
cut that forms part or all of the updip trap of the reservoir. direct function of the geologic setting and nature of the
Seismic is unable to image the sub-salt northern flank of the channel/levee systems encountered. A wide variety of sub-
K1 reservoir, thus the exact sub-salt extent and trap are facies is found in these systems, with an associated wide range
unknown. The accumulation has a column height of 700 feet in reservoir quality and type. Reservoir targets in the Na Kika
and is interpreted to have a partial water drive. area are not limited to "classic" levee thin beds and channel
fill, but also include high net/gross, massive sheet sands as
Seismic indicates the K1 sand thickening from under well.
50 gross feet updip to about 100 gross feet downdip of the
discovery well. In addition to the two horizontal development The major reservoir uncertainties identified during
wells, the K1 reservoir has been penetrated from top to base the field descriptions pose a number of risks and challenges to
by the MC383 #1 and by pilot holes for theK-1 and K-2 the subsurface development and production, summarized as
development wells. Although no oil-water contact has been follows:
penetrated, the seismic amplitude shuts off with structure at
the interpreted oil-water contact. • Inter/intra-reservoir connectivity. Likely drainage area
per well/completion as influenced by the lateral and
The Kepler field is developed by two updip vertical continuity of the reservoir zones. Key risk is to
horizontal open-hole gravel packed oil wells (K-1 and K-2). reserves and production. Believed to be present in all
Major subsurface uncertainties include reservoir size due to fields and in particular may have a major impact to the
lack of seismic imaging under salt, areal connectivity of long-term sustainability of the oil reservoirs (Herschel,
reservoir sands, aquifer support and reservoir compaction. Kepler, Ariel and Fourier).
• Well planning and targeting of multiple reservoir zones
Herschel. The Herschel field is an oil accumulation compounded by imaging uncertainty in sub-salt targets
comprised of the H9 oil reservoir located in block MC-520 in (Ariel & Fourier).
about 6800 feet of water. The Herschel H9 reservoir consists
of high net/gross sheet sands overlain by channel-levee thin • Degree of aquifer support in the oil fields and the
bed deposits in an unconfined bypass slope setting. Trapping sustainability of long-term production and well
occurs by a combination of structural and stratigraphic performance. A risk in all fields, particularly Kepler.
elements with a major down to the NW (radial) fault and base • Requirement for commingled production from multiple
salt providing the updip trap on the north side of the prospect. reservoirs to maximize hydrocarbon recovery per well
Seismically supported channelized/scour features provide the and minimize total well-count (Ariel & Fourier)
stratigraphic trapping elements to the northeast. The reservoir
is limited on the west side by sand pinch-out. The updip • Reservoir and well production management of with
trapping and reservoir extent cannot be mapped due to lack of commingled zones in extreme water depths. Key fields
seismic imaging under the Fourier Salt body. The down-dip are Ariel and Fourier.
oil water contact is defined by the seismic amplitude shut-off.
• Fluid compatibility issues due to the potential formation
of aspartames from commingled reservoir zones
The H9 oil reservoir is developed with a single well
(Fourier).
with a frac & pack completion. The well is optimally placed
in a location far enough updip to prevent an early water • Compaction and sand production due to highly
breakthrough while being far enough from the secondary gas compressible formations. A risk in all fields, in
cap to avoid high gas production early on. particular, Ariel, Fourier and Kepler.

5. OTC 16699 5
Management of Subsurface Risks and Challenges The benefit of developing several reservoirs with one
well bore was supplemented by the incremental benefit
Inter/intra-reservoir connectivity. Reservoir connectivity in afforded by commingling. It was estimated through
these bypass turbidite reservoirs is perhaps the largest simulation that additional reserves could be developed by
uncertainty present at Na Kika. Despite the good coverage of commingling due to the enhanced vertical lift characteristics
3D seismic, it is difficult to see the sub-seismic features that of the well, translating to lower liquid load-up in the well and
can often influence lateral continuity. Although this is a key enabling higher water cut zones to produce longer. Figure 4
uncertainty in all fields, the most exposed are the Ariel, illustrates this for the Fourier field as an example. In this case,
Fourier, and Herschel fields. it is estimated that some 10 – 12% more reserves are produced
through commingling from the start of production, compared
Reservoir static and dynamic simulation models were to a case where successive well re-entries are performed to
rebuilt based on development drilling results in order to complete bottoms-up.
provide tools to history-match and simulate observed
production to supplement material balance approaches. However, commingling of reservoirs is risky due,
Reservoir models were built into an integrated production amongst other things, to the possibility of early or excessive
system model, incorporating sub-sea pipeline and host water breakthrough from one zone killing the well before the
processing equipment. These tools will provide engineers other zones have produced their reserves, the presence of large
with a good basis upon which to scenario plan and history initial pressure gradient differences between zones, and the
match unexpected production behaviour. inability to test individual completions in order to estimate
completion efficiency for well integrity management or
A shared (Shell and BP) well and reservoir allocate production for material balance. In order to address
surveillance plan was developed focused on managing these risks, it was decided to install a form of intelligent well,
identified reservoir management uncertainties. A process was allowing commingling or selective production from completed
used to prioritize uncertainties, and map against available data intervals through hydraulically actuated Interval Control
types, with Value of Information (VOI) justification provided Valves (ICV), akin to sliding sleeves. Figure 5 illustrates a
where necessary. This process helped to identify fluid typical intelligent well completion at Na Kika. These sleeves
sampling and well testing types and frequencies in order to are operated by hydraulic pressure provided through sub-sea
address key uncertainties, and specifically reservoir umbilical from the host facility, allowing the operator to
connectivity. The presence of downhole pressure gauges in all choose which interval to produce from using a series of mouse
wells greatly enhances the ability to perform surveillance in clicks from the Master Control Station (MCS). This type of
this respect. well completion has been key to enabling economic
development at Na Kika.
Production and development contingencies were
worked in parallel with start-up preparation activities in order Aquifer support. The two key efforts to mitigate against
to assess and plan for scenarios that could put early production poor aquifer support (low drive energy) are waterflood and
at risk. This involved assessment of completion, sub-sea, and riser gas lift. In the case of waterflood only the Kepler field
topsides reliability in the context of traits unique to Na Kika, had sufficient reserve exposure to warrant the installation of
as well as potential follow-up development activities to cover water-handling facilities and future water injection capability.
production shortfalls if wells or reservoirs did not behave as Early performance data from Kepler will confirm whether or
expected. not this will be necessary in the near term. The possibility for
water injection capability was included into the original design
Well planning and targeting. In order to intersect multiple of the host facility.
stacked reservoirs at optimal drainage points, targeting the
best possible reservoir quality indicated by seismic, careful Reservoir and well production management. Allocation
well planning was required. Early and close interaction and measurement of volumes back to a source reservoir is
between drilling engineers, geoscientists, and directional critical in order to manage reserves and subsurface risk and
drilling partners was required in order to plan optimal well uncertainty through a field’s lifetime. Although downhole
paths to reach targets fulfilling the well objectives. Well pressure gauges are installed in all Na Kika wells, allocation
planning also involved the use of 3D interactive imaging tools of production volumes to wellheads and to reservoirs
allowing engineers, geoscientists, and directional planners to commingled downhole will be a challenge.
immerse themselves in the subsurface and find the optimal
well path. Despite the ability of intelligent wells to allow
isolation and testing between selective intervals, the Na Kika
Commingled production from multiple reservoirs. In order designs installed in 9 5/8” production casing only allow for the
to reduce well count and minimize the unit technical cost to ability to provide two selective intervals. In the case of three
meet screening threshold, it was recognized early on that of the four intelligent wells installed at Na Kika, which are
developing multiple stacked pays with one wellbore would be triple-zone frac and packs, two distinct completions are
required, utilizing existing exploration or appraisal wells commingled through one ICV. This makes allocation of
where possible. production back to the individual reservoirs difficult in these
cases. In addition to subsurface allocation challenges, the

6. 6 OTC 16699
wells produce into sub-sea flow-loops, where production from Compaction tolerant screens were utilized in Ariel
multiple wells is commingled prior to reaching the host. In and Fourier wells in conjunction with telescoping joints in
the case of the Herschel and Fourier oil wells in the South Oil order to absorb vertical strain expected with depletion.
Loop, and East Anstey gas well in the South Gas Loop, this is
not an issue since they all produce to their own separators. Conclusions
However, the Ariel and Kepler oil wells in the North Oil Na Kika is the first deepwater application of the concept of a
Loop, and Fourier gas wells in the South Gas Loop are dispersed subsea development tied-back to a centrally located
commingled at the wellhead. Therefore, allocation of host that does not depend upon a single large accumulation of
production from separators back to the wellheads without oil and gas.
deferring production to test wells is difficult.
A mix of oil and gas fields in combination with reservoir risks
To address allocation of completion intervals related to inter/intra-reservoir connectivity and continuity,
downhole, geochemical fingerprinting has been identified as multiple stacked reservoirs, limited aquifer support and
the primary means of surveillance where sufficient differences reservoir compaction have made it necessary to design a
between hydrocarbon fingerprints exist. Figure 6 illustrates development plan with maximum flexibility. The economic
where this is the case in well A-3. Regular sampling and development and production of these dispersed, mostly sub-
analysis of commingled flow streams will be carried out in economic fields on a stand-alone basis, has been strongly
order to determine the proportion of contributing fluids, enabled by the application of new technology and novel
accounting for the uncertainty that can be expected using these approaches to well completion and sub-sea design.
methods.
Acknowledgments
In the north oil loop, fluid streams commingled into The authors would like to acknowledge the Na Kika
the sub-sea flowline at Kepler and Arial will be measured subsurface and petroleum engineering teams (past & present)
using sub-sea multi-phase flow meters (MPFM). Two of the at Shell Exploration & Production Company for their input
three Ariel wells are equipped with MPFMs, with the third and contribution to this article, and for their efforts and
well’s production being measured by subtraction. Similarly, perseverance through the 18-year history of Na Kika. Thanks
one of the Kepler wells utilizes a sub-sea MPFM, with the and recognition also goes out to BP America Production Co.
other being measured by subtraction. The use of sub-sea for their active participation and support throughout the
MPFM technology reduces the requirement to test wells subsurface development planning.
directly, drastically reducing production deferment.
Fluid Compatibility. Fluid samples acquired downhole were
subject to compatibility testing in order to determine any flow
assurance concerns with respect to asphaltene or wax
formation.
The mixture of F7.5 and F8RA reservoir fluids
developed by the Fourier-3 well proved to be susceptible to
the formation of asphaletenes under conditions where the
mixture was above bubble point. This led to the requirement
to install downhole chemical injection in the well. In order to
further manage risk, the intelligent well utility of F-3 will be
used to deplete the F8RA reservoir to the same pressure
gradient as the F7.5 reservoir prior to commingling in order to
reduce the risk of cross-flow between reservoirs while both are
above bubble point, and below the reach of downhole
chemical injection.
Compaction and sand production. Many of the reservoirs at
Na Kika are prone to compaction and sand failure. Sand
control completions were required in all wells, and mitigation
against compaction-induced strain failure was a key driver of
well design at Kepler, Ariel, and Fourier.
For the Kepler field, horizontal openhole gravel-
packs were chosen to maximize inflow potential, but primarily
to manage the highly compressible K1 formation. A
horizontal well trajectory was found to be the most tolerant to
vertical compaction strain from a geomechanical perspective.

7. OTC 16699 7
Field Kepler Ariel Fourier East Anstey Herschel
Property
Reservoir Fluid Oil Oil Oil & Gas Gas Oil
Water Depth (ft) 5,700 6100 6940 16,040 6738
Number of Development Wells Two (K-1, K-2) Three (A-3, A-1, A-4) Three (F-2, F-4, F-3) One (EA-2) One (H-1 sidetrack)
Well Completion Types Horizontal openhole gravel 1 dual-zone frac & pack 1 single-zone frac & pack 1 single-zone frac & 1 single-zone frac &
packs (A-3 well), 2 intelligent (F-2 well, gas), 1 dual zone pack pack (H-1 sidetrack)
triple-zone frack & packs intelligent frac & pack (F-4
(A-1 & A-4 wells) well, gas), 1 triple-zone
intelligent frac & pack (F-3
well, oil)
Bottom Hole Pressure (psi) 7230 7380 9253 9500 9530
Completion Interval (ft TVDss) ~12,020-12,070 ~12,00-12,900 ~13,820-16,330 ~16,100-16,200 ~16,470-16,5700
(Horizontal)
Reservoir Type Amalgamated Sheet Sand Bypassed Channel sands Bypased Channels, Amalgamated Sheet Hyprid Chanel/Levee
Amalgamated Levees Sand
Trap Type Base Salt-Stratigraphic Stratigraphic Structural+Stratigraphic Structural Base Salt
Net Reservoir Thickness (ft) 47 64-11 16-103 69 54
Table 1 – Na Kika field characteristics
Kepler
Ariel
HOST
Herschel Fourier
Coulomb
E.Anstey
Figure 1 – Na Kika field locations

8. 8 OTC 16699
Figure 2 – Na Kika host & sub-sea loop layout
Figure 3 – The 18 year history of Na Kika

9. OTC 16699 9
Comparison of Commingled vs. Sequential Production at Fourier
Cum. production (% of
BOE)
120%
100%
F-3 well: F8RA L, F8RAU &
F7.5 on after 3.5 months F-3 well: F8RA U
(Asphaltene) F-4 well: F5
80% F-4 well: F7&F5 F-2 well: F8RB
F-2 well: F8RB
F-3 well: F7.5
F-4 well: F5
60% F-2 well: F8RB
F-3 well: F8RA U
F-4 well: F5
F-2 well: F8RB
40% F-3 well: F8RA L
F-4 well: F5
F-2 well: F8RB
20% F-3 well: F8RA L
F-4 well: F7
F-2 well: F8RB
0%
0 20 40 60 80 100 120 140 160
Time (Months)
Commingled production Sequential production
Figure 4 – At Fourier, commingling helps to produce 10-12% more reserves
Figure 5 – Typical intelligent well at Na Kika

10. 10 OTC 16699
Figure 6 – Geochemical fingerprinting is the only way to allocate between reservoirs in
some cases