SPE-213974-MS
Mahmoud Koriesh, Dragon Oil; Mahmoud El Sheikh and Ahmed Maher, GUPCO; Mahmoud Elwan, Dragon Oil;
Ahmed El Bohoty, GUPCO; Hisham Mousa, Dragon Oil
Copyright 2023, Society of Petroleum Engineers DOI 10.2118/213974-MS
This paper was prepared for presentation at the Gas & Oil Technology Showcase and Conference held in Dubai, UAE, 13 - 15 March, 2023.
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
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Abstract
Gas Lift has been applied in the oil field for more than 70 years, despite the new technology and
developments there is always more optimization that can be done. In this paper we are giving a leading
example of one of the oldest gas lift projects in gulf of Suez that has been running for more than 50
years where 540 MMSCFD being pumped on daily basis to produce more than 200 wells as of today. the
experience in this field is quite historical but the question is always persisting are we making best use of
lift gas volumes and pressure, does every well have the optimum design and receives the optimum gas lift
rate. One more important question will be how to prioritize interventions and optimization operations to
target wells with highest value.
In order to assess the overall gas lift performance of the field an innovative dashboard was created
including Key performance indicators that reflect benchmarking of Lift Gas Consumption compared with
historical Performance of the field. This should spot the light to the field with lowest efficiency and most
probably it is expected higher return of production if we dedicate efforts to this field.
Moreover creating wells dashboard has valued new Key Performance indicators with New Diagnostic
Graphs that was not given attention by the industry before. Having these diagnostic Plots allowed
benchmarking performance of wells for similar reservoir, completion type, gas lift design and sand face
completion. Using this technique, it became easy to detect wells with higher potential of production with
proper gas lift intervention.
Although Analytics can give some guidance on the required actions to enhance production of wells
knowing the basic design, having the analytics coupled with Integarated Network modelling and well models
added more value to the project.
Data Driven Gas Lift Optimization approach was applied since Oct. 2021 in an extensive approach over
GOS, the approach succeeded to define more than 74 Optimization and Intervention Opportunities 45 of
them were actually intervened in less than a year and added more than 4000 BOPD to production capacity. It
was not a surprise that some of historically known underperforming wells were interpreted underperforming
for other reasons than gas lift in-efficiency but using Gas lift Analytics re-analysis of the system showed
huge value for gas lift intervention in these wells and succeeded to revive them.
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Data Analytics Drives Production Optimization for Gas Lift Wells to the
Peak, Case Study from Gulf of Suez.
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Data Analytics and Data driven gas lift optimization is proved a huge leap in managing gas lift fields and
keeping the system running closer to optimum.
Introduction
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Gas injection rate : increasing lift gas injection rate increases the volume fraction of gas in wellbore
and hence decrease the density of the mixture result in less bottomhole flowing pressure, more
drawdown over formation. Fig.1 shows a typical performance curve. Production increases with
more injection gas untill reaches a peak where infliction takes place. At this point the friction
impact of incremental gas flow rate equals or overweight the impact of decreasing density resulting
on stabilized or increasing flowing pressure and hence less production. From this graph we may
come up with two definitions:
∘ Well Maximum Production Point: it represents the injection gas rate that achieves maximum
production from well perspective. Represented on graph by gas injection rate at infliction point.
∘ Optimum injection Point: this point is more related to the gas injection rate value that achieves
the benefit for the whole production system. For example assuming maximum production point
for the well of 2.5 MMSCFD, you may decide to operate the well at 2.5 MMSCFD and produce
300 BOPD. Or to operate the well at 1.5 MMSCFD to produce 250 BOPD and open one well
with 1 MMSCFD for 100 BOPD or to operate the well at 2 MMSCFD, produce 280 BOPD and
increase 0.5 MMSCFD to one of the low watercut high productivity wells and get incremental
100 BOPD. Ideal way to determine the optimum gas lift injection rate is by integrated asset
model where every well has a calibrated model.
Gas Lift Injection Depth: having said that maximum available injection pressure is actually
the discharge pressure of compressors, which is pre-designed before installation. The remaining
engineered factor is to make the best use of available injection pressure by utilizing this energy to
inject lift gas as deep as possible through proper location of gas lift mandrels and gas lift valves.
Comparing injection of same amount of gas at different depths.
∘ The deeper injection the better since gas will be allowed to lighten produced fluids for
longer section of tubing, as a result less hydrostatic head and lower flowing pressure and more
production, Fig.2 shows example of impact of deeper injection on flowing pressure.
∘ In order to produce same liquid flow rate you would either use shallow point of injection at
high lift gas injection rate and you may exceed maximum production point before you achieve
the target rate or you can inject from deeper point and less injection gas and saving more gas
for other wells in the field.
∘ Deepest allowable injection point is function of available injection gas pressure, well
production rate that govern the tubing pressure with depth, gas lift mandrel spacing and setting
pressure of unloading valves.
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Gas Lift operation consists of gas compression of produced gas to a pre-designed value of pressure that
allows deep injection of this gas to oil producers through gas lift mandrels that result in less hydrostatic
head inside wellbore and allows well to prolific production by the natural pressure of the reservoir. The
concept of gas lift is to decrease resistance against natural reservoir energy.
Looking at well performance in terms of gas lift efficiency, it is mainly a function of two engineered
parameters:
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Figure 2—Example pressure traverse showing static pressure gradient &
superimposed production traverses assuming gas injection from different mandrels
Based on the basic concepts of gas lift operations, objective of gas lift optimization can be stated as
achievement of maximum oil production rate by considering two main pillars. The first is to maximize
possible production at well level by design to inject as deep as possible. The second is proper allocation
of available high pressure gas to different wells in the field. That would achieve highest net present value
and maximize recovery from the field.
Field Background
The subject study included data from more than 200 well from 18 different fields offshore gulf of suez
all of them are operated by gas lift system as artificial lift method and below is data ranges coming from
these wells :
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Lift Gas Injection pressure: 1000 – 1500 PSI.
Reservoir Depth: 4000 – 12000 Ft TVD.
Production Rates : 150 – 7000 BFPD per well
Productivity Index : 0.2 – 20 BFPD/PSI
Reservoir Pressure 900 – 5000 PSI
Crude API : 17 – 36 API
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Figure 1—Typical Gas lift performance curve
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Formation GOR: 240 – 860 SCF/BBL.
Water Cut : 0 – 95%
Reservoir Drive : Depletion, Water Aquifer & Water Injection
Figure 3—Gulf Of Suez Fields
Gas Lift Optimization
Gas lift optimization comprises a range of activities related to measuring of operating parameters and
production indicators, analyzing well data, modeling well performance to compare current status of wells
with modelled well capacity, prioritizing optimization activities, and implementing actions to enhance gas
lift efficiency and increase production.
Gas lift optimization is a dynamic process. That means optimum distribution of lift gas between wells
may differ over time. It is not a definite gas injection rate value for each well that is engineered during the
design phase and kept constant during well / field lifetime and here comes the challenging field dynamics
that requires a very dynamic optimization process.
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Operating Dynamics : factors related to day to day operations that would impact strategy of lift
gas distribution
∘ Lift Gas Outage: having one compressor down for any reason implies less lift gas availability
and hence what was optimum distribution before is no more optimum. At this point a contingent
optimization strategy should be applied, either to shut in producers with equivalent lift gas
utilization to the compressor output or to redistribute the available lift gas over all wells or to
shut in low value wells and redistribute lift gas to remaining wells.
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Typical field challenges: like any offshore field, operations are so dependent on weather conditions and
availability of logistics that results in competition of priorities between all field activities between day-today production operations support, wells & machinery maintenance activities, construction activities, well
intervention and surveillance activities. This kind of competition will imply some challenges on gas lift
operations as well.
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∘ Production Bottlenecks: temporary or permanent outage of production vessels or pipelines
would result in production bottlenecks that result in increasing flowing pressure of producers,
resulting in shallower Point of injection and hence different lift gas distribution and system
design should be considered.
∘ Water injection outage: water injection is key for reservoir pressure maintenance, having
injection plant down for moderate or long run results in decrease of reservoir pressure and
hence keeping injection gas depth shallow as per old design results in suboptimal production
rates and hence deeper injection can be achieved and requires redesign. Similarly maintaining
production levels with decreasing reservoir pressure requires increase in injection gas rate.
Reservoir Dynamics: factors related to reservoir performance over time that affect optimum gas
lift injection depth or rate.
∘ Water cut : inflow of more water to wellbore results in higher hydrostatic head in tubing side
hence limited pressure difference across the operating valve that larger valve should be installed
to maintain enough gas entry. High wc also results in shallower point of injection and hence
requires more gas to maintain production rates at the well level.
∘ Reservoir pressure: in ideal gas lift system as reservoir pressure decrease point of gas lift
injection moves to a deeper valve, however the impact of reservoir pressure drop is always
doubled by keeping fixed point of injection in this case will be shallow POI. So a redesign of
GL system may be needed.
Well Dynamics: factors related to specific well performance over time and may affect optimum
gas lift injection rate of depth.
∘ Productivity impairment: productivity index of certain well is rarely constant over productive
time, it is impacted by changes in produced phases fraction of oil, water & gas, skin damage
due to organic & inorganic deposits or fines migration,.. etc. changes in productivity index,
change the well response to gas injection rates and gas injection depth as well.
∘ Well Mechanical Issues: tubing deformations or malfunctioning gas lift valves imply change
in well performance and response to lift gas injection rates.
∘ Organic & Inorganic deposits: it is common to see scale deposition inside production tubing
and resulting in changes in tubing pressure traverse, production rates or results in gas lift
mandrel plugging and operating from shallower valves.
Industry practices for gas lift optimization mostly focus on well models and integrated network models
where different sensitivities are applied to consider different operating scenarios and different sensitivities
on well inputs. Although integrated asset models are ideal optimizers, the inputs update for the models can’t
be as dynamic as the actual field dynamics. It is mainly due to logistics limitations in offshore environment
along with aging well facilities that result in competition of priorities that may impact surveillance frequency
of well testing, flowing surveys, optimization tests,.. Etc.
Here comes the role of making use of available high frequency well data to Measure & Analyze well
performance, define priorities for surveillance and intervention and come up with best execution plan.
Data Analytics Approach
Data reflect the operational reality of gas lifted wells. Which builds the experience sense of the field to
production engineers. The objective of analytics is to put the available high frequency data in a format where
some conclusions can be made. Such data includes simple wellhead parameters like injection gas rate, last
production rate or can be replaced with wellhead temperature, operating Gas injection pressure.
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Process starts with creating key performance indicator charts that allow benchmarking of wells
performance in comparison with historical well performance or with similar wells producing from same
reservoir quality, similar completion design, similar gas lift design, similar reservoir pressure and depth.
Such benchmarking tool can be useful to :
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Injection Gas Rate Benchmarking:
First diagnostic plot included in the study is a cross plot between gas injection rate on the x axis and last
production rate on the y axis, in case of scarcity of production data well head flowing temperature can be
used with caution.
Kind of plot can be made at field scale; however it is best interpreted combining wells producing from
same reservoir, sharing same depth, pressure, PVT and similar Gas lift design.
Using this plot, it becomes easy to capture wells off trends and hence can set priority list for optimization,
out of 24 wells need optimization detected in an example field 22 of them performed in accordance with
the optimum lift gas injection rate got from benchmarking chart without using a model. Resulting in 90%
efficiency of the gas lift injection benchmarking as optimization tool.
Lift Gas Outage Example: benchmarking optimization is quite easy and quick to conclude specially in
case of emergency gas lift outage due to failure of one of the compressors, figure 6 shows example results
on field scale production during outage of lift gas due to compressor down time during emergency repair
that resulted in 12% drop in gas availability. Optimizing wells to values driven from benchmarking chart
resulted in sustainable field production rate and least impact of lift gas outage.
Figure 4—Field Scale Cross plot for Gas injection rate vs well production rate
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Spot odd performance wells, some of these wells may be overlooked for a while or interpreted
underperforming for other reasons by mistake.
Define maximum capacity wells, what we call benchmarking wells a type well with ideal
production and ideal lift gas consumption and ideal gas lift system. Such wells are the example
that we need to follow In other wells in same field.
Give indications about potential well problem. Using field benchmarking charts may give
indications about shallow point of injections or Mandrel Plugging, etc.
Define Potential Redesign to enhance gas lift system efficiency, for example definition of number
of excess unloading valves that are no more needed for operating a well.
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Figure 6—Field results of using Benchmarking optimization during lift gas outage.
Performance Benchmarking:
The second diagnostic plot is a cross plot between lift gas injection pressure on the y axis versus the
production rate on the x axis. Similarly it is best interpreted when using data from well producing from
same reservoir. The concept of the plot is derived from the fact that in ideal gas lift system - where deepest
point of injection is achieved and it is orifice valve that it is not active valve-higher production rate wells
tend to show higher gas injection pressure due to higher tubing pressure against injection gas lift valve.
Benchmarking of performance of wells of same reservoir as shown in Figure 7 most of wells follows
general trend represented by green dashed line. Such line can be generated by trending or engineering
calculations using well models. Using this cross plot it becomes easy to detect wells with odd performance
and may need intervention or gas lift redesign and can be divided in two categories:
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Low Rate & High gas injection pressure wells: such wells are to the left of the green dashed line
that show high gas injection pressure despite the low production rate and typically the reason is
one of the following :
∘ Partial Plugged gas lift mandrel: scale deposits or any dirts in lift gas can plug ports of gas lift
mandrel. Plugging results in higher differential pressure across the valve / mandrel to achieve
same gas injection rates across the plugging. This may result in suboptimal gas injection rate
due to plugging or reopening of shallower valve and in turn less efficiency of gas utilization.
∘ Completely plugged gas lift mandrel : sometimes pots of gas lift mandrel is completely
plugged at point of injection and resulting high pressure in annulus side causes opening
shallower valve and then suboptimal injection depth.
∘ Incomplete unloading : during unloading sequence of gas lift wells, gas injection starts at
shallower valves and moves to deeper valves as unloading continues, in rare cases suboptimal
gas rates cause high pressure gradient between valves and inability to move from valve to the
next, shallower valve is kept open and due to the high setting pressure annulus pressure remains
high.
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Figure 5—Example Cross plot for gas lift consumption vs production of wells producing from same reservoir
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Figure 7—Example Cross plot of lift gas injection pressure and production rate for wells producing from same reservoir
Example well with High Injection Pressure. Well was detected underperforming through performance
cross plot high gas injection pressure 1000 PSI while production rate is 300 BFPD using model assuming
offsets productivity index it was expected that 2nd valve is the current point of injection which was confirmed
by flowing survey in 2021 and below mandrels are likely plugged.
Based on the survey data changed top two valves with dummies pulled V#6 and cleaned gas lift mandrel
with injecting gas at high rate then set another new orifice valve.
Following job well was testing 700 BOPD and gas injection pressure decreased to 730 PSI, which matches
the normal trend in the field.
Figure 8—Example well with high injection pressure and low production rate
Shallow Orifice Benchmarking
The basic gas lift design in the field is to keep deepest valve in the design is kept orifice to keep a way
of communication in case of future work over. Typically after flow back of the well the point of injection
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Low Injection pressure and moderate rate: such wells are to the right of the average trend of green
dashed line showing low injection pressure despite moderate or high rate and typically the reason
is one of the following :
∘ Shallow Orifice valve: during early life of well, production rate is quite high and then point
of injection is shallow and is set to be orifice valve and left since then.
∘ Shallow malfunction valve: shallow injection may happen in active valves due to stuck open
valve or broken bellow that resulted in leak of nitrogen pressure so the valve will be kept open.
∘ Tubing hole : due to corrosion taking place over time tubing leak may take place at shallow
depth and result in inefficient gas utilization.
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is changed to orifice with production and depletion sometimes depth of orifice need to be changed to a
deeper valve.
Figure 9 shows example of shallow orifice benchmarking includes well name, gas injection pressure and
number of orifice valves is color coded. Wells with potential deepening of orifice would show multiple
orifice and low annulus pressure.
Example well with shallow orifice. Figure 10 shows example of well with multiple orifices well was
detected by shallow orifice benchmarking showing lower gas injection pressure than analog wells and design
includes multiple orifice. Analysis shown available injection gas pressure can reach 5400 Ft instead of 4200
Ft.
Figure 10—example well with shallow orifice
Following the diagnostics both valves #3 & 4 were changed with active valves and resulted in 200 BOPD
incremental production.
System Reliability Benchmarking:
field practice shows that worst enemy to gas lift efficiency is muli-point of injection. Numerous reasons
may lead to multi-pointing. So in order to have a reliable gas lift system it is important to keep the number
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Figure 9—example shallow orifice benchmarking
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of unloading valves as low as reasonably practical. And here comes the idea for benchmarking system
reliability.
Figure 11 shows an example graph showing load in feet that needs to be unloaded by unloading gas lift
valves and color code shows the number of excess unloading valves installed in the existing gas lift system
design. Such valves may reopen with orifice valve dissipating the value of gas lift injection or it may stuck
in the open position and act as shallow point of injection.
Following these statistics current field practice is to minimize the number of unloading valves to minimize
the risk of shallow or multiple point of injection and decrease the need of slickline interventions in the future
having to replace malfunctioning valves.
Results
Establishing data analytics database and dashboard for every field categorized by reservoir allowed quick
detection of wells with odd performance different from the average trends. These analytics came in service
in sep. 2021 and out of these dashboards a list of more than 74 optimization opportunity was detected and
more than 60% of these wells were intervened accordingly and resulted in great cumulative gain. Figure 12
shows clear enhancement of gas lift optimization activities following the application of gas lift analytics.
The improvement comes from early detection of underperforming wells and the efficient of analytics tool
to generate optimization opportunities and apply new concepts for gas lift system efficiency and reliability.
Figure 12—Gas lift optimization Activities trends following application of gas lift data analytics
Conclusion
Gas lift analytics can be a useful tool for gas lift optimization, early detection of underperforming wells,
diagnosing them and setting up proper intervention plan for recovery. The tool can be used as key
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Figure 11—Example System Reliability Benchmarking
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performance indicator for gas lift system benchmarking at field scale. And can be used as a machine for
generating gas lift optimization opportunities.
References
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