Case study: Offshore, Malaysia

Integrated Well Services, alliancepartner rejuvenate brownfield, extend
field economic life by 20 years
Discovered in the early 1980s, Field-D
reached its peak production in theearly 1990s, topping 19,000 BOPD
(3020 m3/d). By the late 1990s,
however, production began a steadydecline, bottoming out at 4,000 BOPD
(635 m3/d) in the early 2010s. The
sharp decline is attributed to thereservoir depletion mechanism
without any support.
The field is a complex, compressionalextensional structure with varying fluid
contacts. The field is laced with morethan 800 interpreted faults, making
block-to-block transmission morechallenging. Small compartments
contribute to rapid pressure and rate
decline while the thinly laminatedsands are easy to miss in seismic
studies—increasing the risk of
bypassed hydrocarbons.
Various service companies attempted
to mitigate the declining production
over the years but the depletedpressures kept dwindling theproduction and the decline could not
be arrested. At the lowest production
rate, only about 30% of the dual
conventional strings with straddled
zones in the field remained active andthe artificial lift systems were under
optimized for sustainable recovery.
Based on declining baseline
production and increased facilities
operating costs, the field was expected
to become uneconomical by 2020.
Faced with declining production andno plan for increased oil recovery, theoperator established a contract with
Baker Hughes for a solution that would
rejuvenate the field and enhancerecoverable reserves and productionof hydrocarbons to extend Field-D’seconomic life.
Aligning the well plan
Baker Hughes, drawing on its extensive
production portfolio and expertise,assigned responsibility of the projectto the Baker Hughes Integrated Well
Services (IWS) team. Combining
project management expertise, acomprehensive technology portfolio,and superior service delivery, IWS wastasked to optimize the project
performance and extend the field’s
productive life.
IWS and the operator created analliance comprised of integrated
multi-disciplinary teams, emphasizing
a collaborative work environment that
followed an upstream process
management system and aligned thevarious business drivers through arisk-reward model between
both companies.
Additionally, the alliance members
agreed that:Challenges• 30-year-old depleted reservoir
without any IOR/EOR• Conventional well were limiting thelife of the well
• Insufficient artificial lift
• Excessive and unplanned deferments
due to aging facilities• High operating cost per barrelResults• Extended field economic life by>20 years• Delivered incremental reserves >50%
compared to total reserves drained• Increased incremental oil production>90% of total production• Improved active strings from
30% to 60%• Upgraded facilities to reduce
unplanned production downtime
from >10% to <5%• The plan must fully exploit all the• Reduced field operating costs, withnew oil coming in at lower costs andreducing unit production cost

• An integrated solution was required• Achieved a perfect health, safety andenvironmental (HSE) performance(more than 6 million safe man-hours
and counting)conductor slots on the platforms,
thereby adding more wells per slot toenhance recoverable reserves.
to develop the multiple, stacked
reservoirs with variable pressuresand saturation profiles to avoid early
inactivation and extend the field’sproductive life.

Designing the solution
In order to boost production, theoperator first needed to zero in on
where the recoverable reserves werebakerhughes.com

located in the compartmentalized
formations, and drew on the robust
reservoir modeling portfolio of Baker
Hughes. This portfolio provided indepth subsurface intelligence that
reduced uncertainty and clarified thefield planning.
The teams also emphasized specificdesign areas of concentration toachieve success:• Facilities—All facilities would receive
an upgrade to enhance the fluidhandling and lifting capability.

• Reservoir—Water injection would becommissioned to improve therecovery through pressure
maintenance and sweep.

• Chemicals—Tailored chemicalsolutions would be developed toaddress deliquification, enhanced oil
recovery (EOR), and stimulation.

With a better understanding of thereservoir and a modified well design,
the consolidated teams developed amulti-phase approach to re-energize
the field.
Executing predictable performance
The first step towards field reactivation
was to stop the production decline
and improve marginal recovery. Phase
1 of the project consisted of nine wells,
including oil producers and water
injectors that were being used toinitiate secondary recovery. This
segment of the plan incorporated asmart completion concept with apermanent downhole monitoring
system and hydraulically controlled
flow control valves.
Phase 1 successfully managed toarrest the production decline but it
was just the beginning. With Phase 2 insight, the target was to reverse it backto the 1990’s peak.
Drawing on the lessons learned inPhase 1, Phase 2 was conducted withthe goal of maximizing the existingproduction and recovery via eight new
infill drilling wells. In four out of theeight oil producers, the team opted todeploy the electrical inflow control
valves (ICV) to address the formation
complexity, pressure, andproduction challenges.

intervals added more than 50 MMSTB
of oil in a 35-year-old brownfield—
providing production flow expected tolast for at least 30 years.

Reaching new reservoirs
with technology

Revitalizing a brownfield

Historically, Field-D has produced fromthe primary oil-bearing reservoirs
located at a shallower depth while thepotential of the deeper formations
remained untapped due to limited
data availability. Exploration at thisdepth was considered unfeasible
because of its associated higher risks,such as tight reservoirs, watered-outsands in deeper reservoirs, and more
complex geology.
IWS and the operator took the initiative
to drill deeper along the trajectory ofwells planned for the shallower
prospects to appraise new deeperhorizons. Phase 2 quantified thefuture production potential of the
deeper horizons.
Comprehensive formation evaluation
was vital prior to developing thedeeper plays and appraising/developing the existing sands. TheFASTrak™ fluid analysis sampling andtesting service and the RCX™ Sentinel
focused sampling service are just two
examples of services used to provide
fluid characterization and pressuredata. In addition, an alternative
geological model was proposed fromthe geological analysis carried out
from the facies and log expression.
This geological model showed where
additional healthy reserves werelocated and enabled high-pressure
gas in deeper sands to support thelifting of wells. Remote Operations
Services (ROS) teams performedmuch of the data analysis to avoid
delays due to travel restrictions during
the COVID-19 pandemic.
As a result, six out of the eight wells in
Phase 2 were drilled to the middle ofthe deeper horizon where significant
oil and gas reserves were discovered.
The hydrocarbons flowing from these

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As of 2021, the alliance has
implemented more than 30 new
technologies and initiatives to help
deliver on the project’s goals andcontinues to innovate as newchallenges present themselves—
driving efficiencies and increasing
production. At each stage, both Baker
Hughes and the operator reaped thereward of a continuous improvement
curve, applying new lessons learned toexisting and future segments.
Today, the tangible results speak forthemselves as the incremental oil
production constitutes more than 90%of the total production. The active
strings percentage has improved from
30% to 60% with a plan to reach 80%
within ten years. Through facilities
rehabilitation, unplanned field
deferments were cut in half. Field
operating costs were substantiallyreduced as well, with new oil coming in
at lower costs, to further reduce theunit production cost. And, through thecombination of new wells andproduction enhancement campaigns,
the team more than doubled theoperator’s incremental reserves.
When the collaboration began, the real
threat was that the economic limit ofField-D would be reached in 2017. Bycollaborating with the Baker Hughes
Integrated Well Services team andtapping their technology andexpertise, the field’s life has been
extended by at least 20 years and, withthe prospects of new, deeper wells
producing at virgin pressures, theoperator can expect new phases ofdevelopment even beyond the life of
the contract.

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