X in 2014 based on the following

X field consist four main oil
producing zones (Zone – I, Zone – II, Zone – III & Zone – IIII), however
zone – IIII it is depleted zone and it will have included in capstone – II.

In general X field has become mature
with the reduction in bottom hole flowing pressure (FBHP) and increasing water
production. Oil producing wells, located close to the water injectors areas are
now experiencing increasing water cut in some wells causing the well to decline
and die. At the same time, it’s required from the field, to sustain production capacity of 120 M
bbls/day and an additional 15 M bbls/day by 2020.

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Lift Strategy (ALS) project was recommended to achieve the mentioned additional
oil production target.

Artificial lift (AL) type for
x-field should be selected to fit the main two factors:

production rate and,

deep wells.The
reservoir study for the X field showed that, by implementing of artificial lift
strategy will increase oil recovery and extend the field oil production
plateau. In addition, the project has to meet the following objectives:·        
Recover bypassed oil due to water breakthrough.·        
Reduce the number of inactive wells due to high
water cut and improve well performance.

Extend high water cut wells ‘running life.Due to
cost impact, X field artificial lift strategy was agreed and initiated by pilot
phase before going for full field implementation.  A total of 4 candidate wells were selected to
implement two artificial lift systems namely; ESP and Gas Lift systems.  ESPs
were installed in two wells (I-10 and I-15). In 2012 and Gas Lift systems were
installed in 2 wells (II-6 & II-9) in 2014 based on the following criteria: a)     
Well Location – Utilizing existing X field gas
injection network for Gas Lift and existing overhead lines for ESP.b)    
Well Integrity – Operating pressure should not
exceed 80% of the MAASPc)     
Different Reservoir Pressures and wells

All the wells are inactive due to water
breakthrough from the injectors.X Field
gas lift completions consist of 3-1/2″ tubing completion, equipped with side
pocket mandrels with 1-1/2″ IPO gas lift valves. The production casing is a
combination of 9-5/8″ from surface, follow by 7″ liner and 6″ open hole. In
some cases, 7″ tie-back to surface is utilized if the integrity of 9-5/8″
casing is doubtful. The threads of both tubing and casing must be gas tight.
These wells (II- 6 & II- 9) were commissioned in Jan 2014; as per Figure-9.

Considering that the wells have high GOR and will be producing below bubble
point pressure, gas handlers were installed in all the ESP strings. This is to
handle the free gas that will be produced. In order to have access to the
reservoir, Y-tool is necessary in 9-5/8″ casing completion but not desirable
for 7″ casing due to less clearance and the ESP will be even smaller.
Therefore, reservoir accessibility will be an issue for well completed with 7″
casing. These ESP wells were commissioned in 2014/2015 (I-10 & I-15).Well

completion was installed and commissioned in March 2012 in (Zone – I). This
well was producing about 1,700 bopd against a target of 700 bopd at water cut
of 70%. The ESP had a motor failure in April 2013 due to human error. The
cumulative oil production by ESP was about 22,000 bbls and the production
testing results as in figure-10.Well I-15:

The ESP completion was
installed and commissioned in April 2012 in (zone – I). This well was producing
about 2,000 bopd against a target of 700 bopd at water cut of 75%. The ESP
failed in Jan 2013 due to electrical failure. The cumulative oil production by
ESP was about 18,000 bbls and the production testing results as in figure-11.Well II – 6

The gas
lift system was also installed in 2012 to produce from (Zone – II). It was
commissioned in Jan 2014 with an average rate = 800 BOPD, 80% WC. The well is
currently shut-in due to high GOR constraint at the surface facilities.


Well II – 9

Lift system was installed 2012 to produce from (Zone – II). It was shut-in
during commissioning in 2014 due to SAP-B. In 2015, alternative solutions were
explored to revive the well, but they were abandoned due well integrity/ safety
concerns. ·        
For the ESP pilot stage to be completed the
failed ESPs must be retrieved from the wells and a detailed failure analysis
has to be carried out on them. The outcome of the analysis will help to make
any required changes such as equipment metallurgy or installation procedure
that will improve future installations.

Chemical injection skids should be activated

Well completions must have provision for
chemical injection.

All ESP wells must be completed with an annular
packer that has a minimum temperature rating of 300oF

No gassy effect was observed during the
operation of the ESP due to installed gas handler (Poseidon).

Reduce time between identifying AL candidates
and commissioning. This will enable us to produce the oil before the well
waters out.

To extend the run life of the ESP, only trained
personnel should attempt to troubleshoot ESP wells.

X field operation personnel need to be trained
on ESP/ or GL operations

The selected wells must have the capability to
transmitting real time monitoring & surveillance data remotely.

Wells in high GOR areas should not be selected
for gas lift or ESP candidates in the future.In
the single well system, oil and associated fluids move from the reservoir to
the tank. Energy losses must be overcome in order for fluids to flow through
various interconnected components from the reservoir to the stock tank.

 Figure 12 below shows the locations of
commonly used nodes.The Systems Analysis or NODAL analysis concept:
inflow involves the components (inside the reservoir) = outflow all of the
components (from intake point (6) and up word to point (1)).  In
the gas lifted well, generally the solution node is selected at the mid
perforations depth.

this location, IPR (inflow performance relation) = VLP (vertical lift
performance).as shows in the figure -13 below.