intelligent gas lift

8/3/2019 Intelligent Gas Lift

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www.letstrain.co.uk Page 1 of17 27/4/2011

INTELLIGENT GAS LIFT

Cameron Laing, Production Technology Consultant, LETS

Summary & Conclusions

This paper demonstrates the significant increases in oil production that can result from the

deployment of Camcon DIAL units instead of conventional wireline retrievable valves and side-

pocket mandrels in a gas lifted production well. A subsea well in a small field development, with

limited - if not zero - intervention opportunities, was evaluated over a number of scenarios in its

productive life cycle. The Camcon DIAL units were seen to offer much greater flexibility than

conventional equipment, as the achievable depth of injection could change in response to the

inevitable changes in reservoir pressure and water cut over the life of the well and with the initial

uncertainty over Productivity Index.

Incremental production delivered in this example was in some cases over 1,000 bopd greater thanthat of conventional equipment and represented up to 110% more production in one scenario. The

ability to open and close the DIAL units at will, and to vary the equivalent port size meant that even

greater production increments could be delivered in the scenarios where additional casing pressure

or additional gas lift gas became available, since there was no concern over re-opening unloading

valves or finding valves stuck closed due to temperature effects on nitrogen charged bellows.

Introduction

Gas lift is one of the most common artificial lift technologies, lifting reservoir fluids to surface at

rates which wells are not able to sustain naturally. Its popularity is related to its inherent ability tohandle gassy; sandy; corrosive fluids in deviated wells and its applicability to a wide range of

production rates. When gas sales, and therefore gas compression, facilities already exist, the

incremental cost of downhole equipment is relatively low and that equipment, once installed, does

not present any barrier to reservoir access for investigation, treatment, repair or sand-face

production management. Superficially, the equipment also offers the option of adjustment to

accommodate changes in well performance.

These are the implicit assumptions that have been associated with gas lift for the last half century or

more. But in that time period the oil industry has undergone significant transformation; moving

geographically from its original land base to deepwater offshore provinces; and moving technicallyfrom slick wire intervention to remote real time management of digital intelligent completions. Gas

lift technology, however, has virtually stood still the technology that time forgot.

My understanding of the direction being taken by the API in drafting RP 19G13 High Pressure and

Subsea Gas Lift, is that the use of high pressure gas and a single orifice is the recommended way

forward for subsea wells. This amounts to an implicit admission by the industry that the

conventional system of unloading valves is not fit for purpose for subsea wells. In my view, it also

brings with it additional risks associated with higher inventories of flammable hydrocarbons on host

platform topsides, higher cost in subsea distribution systems and higher specifications for casing

connections to prevent well integrity threats due to annular pressure migration.


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Taking a closer, more critical, look at gas lift design assumptions clearly shows that it is not just

subsea wells that have a problem. The textbooks; recommended practices; and service company

procedures all make the same implicit design assumption that the well will operate with a specific

reservoir pressure; flow at a specific rate and with a specific water cut. This is a patently naive

assumption in many fields being developed and produced today particularly offshore, where

fewer, higher cost wells probe fault blocks where sands have uncertain connection to areas already

developed; to aquifers or to injection support.

Uncertainty over initial well performance is high yet completion equipment, such as mandrel sub-

assemblies, must be made up, tested and shipped before the bit has even entered the reservoir.

Ironically, the one certainty is that reservoir pressure, production rate and water cut (not to mention

gas lift gas supply volumes and pressure) will surely change over the life of the well. With water

injection for pressure maintenance and/or flooding, reservoir pressure may even rise to higher than

initial values.

Ideally, gas lift gas should only be injected continuously through the orifice normally located in the

deepest side-pocket mandrel. Personal communications with service sector companies providing

downhole gas lift equipment has confirmed that it is not recommended that injection take place

continuously through an unloading valve. This entails a significant risk of destroying the seat

through chattering of the ball on the seat of the valve. This would compromise well integrity where

the well retains the potential to flow naturally to surface (the standard back check in the nose cone

is neither designed nor qualified as a well barrier). It would also compromise any gas lifting of the

well at any deeper point as this valve would not be able to close, so gas would always be injected

through it. Yet, despite this warning, they are regularly delivering designs to operators where,

inevitably, injection will take place through an unloading valve.

The next gas lift assumption is that circumstances different to those used in the design exercise can

easily be accommodated by simple wireline intervention to change out gas lift valves. This implies

that we have ready access to the wellhead. This is not necessarily so for platforms where the rig is

involved in a drilling programme and its footprint covers the well bay, or for subsea wells. The cost

of operations and the time-lag during which production is lost can both be very significant.

Finally it is assumed that intervention will be a simple, trouble free operation. (I should pause here

while field engineers stop laughing and pick themselves off the floor.) For many this is in fact true,

but for many others with wax, asphaltene, inorganic scale, sand, corrosion, depth and deviation to

deal with, this is not a risk free business. For subsea wells, with interventions costing potentially

tens of millions of dollars, there are additional operational risks to consider along with the possibility

that a high value well could be junked, production actually diminished or the well have to be worked

over at further great expense.

This paper looks at the options for addressing the challenge of uncertain well performance and

highlights, in particular, the potential advantages of the new technology being brought to the

industry by Camcon Oil with their Digital Intelligent Artificial Lift (DIAL) unit. Over the past couple of

decades we have come to accept intelligent completion equipment that optimises the well Inflow

Performance Relationship (IPR) between bottomhole pressure and rate. We are now seeing the

possibility of full production system optimisation through incorporating intelligence in the


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production tubing that allows us to optimise the Vertical Lift Performance (VLP) relationship

between bottomhole pressure and rate.

Example Well

Every reservoir rock has a unique set of attributes. Similarly, each oil is also a unique multi-component hydrocarbon mixture. Wells also have many different depths and trajectories and, while

production tubing comes in standard sizes, sizes can be combined in many ways and the string

adorned with jewellery that gives it unique attributes providing specific functionality. The

example selected as a basis for comparison of gas lift design options may not match every readers

idea of a typical well but it is based on a real well that I believe is indeed typical of modern day

subsea wells in moderate water depths.

The well trajectory is approximated by being virtually vertical down to around 6,000ft MD RKB, then

building angle to 66 by 7,000ft MD and holding down to a total depth of 17 ,600ft MD (11,300ft

TVD). The well was completed using a 7liner with a 4.5 by 5.5 production tubing string with thepacker and end of the tubing at 17400ft MD and the x-over at 1,100ft MD and the wellhead on the

seabed at 600ft MD. The maximum depth for a gas lift mandrel is 17,200ft MD (11,100ft TVD).

The reservoir temperature is 260f and the overall heat transfer coefficient (OHTC) assumed for

temperature modelling was 5 Btu/hr/ft2/F. A detailed enthalpy balance temperature model

reflecting well construction materials; and rock properties; and time on production would be

required to predict flowing well temperature gradients for the initial development well in a field but

this detail has been omitted here. For simplicity it has been assumed that the OHTC is obtained by

matching measured temperatures to a well model for other wells in the field. The oil is a light 38API

fluid with a solution GOR of 360 scf/stb and a saturation pressure of 1200psig. The tubing headpressure of the well is assumed to be 500psig. As this is a subsea well, this pressure is, in reality, a

variable rather than the fixed value assumed here for simplicity. Subsea wells typically feed into a

flowline that is shared with other producing wells and which extends over a significant distance to

the host platform. Tubing head pressure will depend on the frictional pressure losses in that line,

which in turn depends on the production rate, gas lift rate and water cut etc. associated with the

well in question and with the other wells in the gathering system. The completion/packer fluid for

gas lift design is taken as treated, filtered Seawater with a weight of 8.6ppg.

The key variables that are examined are the well Productivity Index (PI), the Reservoir Pressure and

the Water Cut (WC). Each of these parameters can be expected to change over the life of the well.A Reservoir pressure, PI and WC data set can effectively be used to describe a life cycle service load

case for the gas lift system (see table below). The use of PI in place of a full blown IPR model is

justified in reducing the complexity here in order to meet the objective of this particular exercise but

also because the low bubble point pressure of the oil means that gas will not evolve in the near

wellbore rock and diminish PI correspondingly. PI is therefore only impacted by two phenomena: a)

Completion & Production uncertainty due to, for example: damage caused by ineffective

perforating; or by fluid incompatibility between formation water and completion or treatment fluids,

such as scale inhibitor squeeze treatments; fines invasion from the completion fluid or migration

from deeper in the reservoir; scale formation with injection water breakthrough; cross-flow between

differentially pressured zones etc. and b) Relative Permeability effects in the near wellbore rock due

to increasing water saturation. The former is taken into account by the use of specific PI sensitivity


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values and the latter by specific relationship derived from special core analysis tests that are built

into the base PI model. In general, the only way is down, relative to the initial PI estimate, unless

some specific stimulation treatment is planned as part of the completion or as a remedial treatment

at a later date.

Analysis Software

There are numerous steady state Production System Models on the market and a few transient

models. The gas lift unloading operation is a transient phenomenon i.e. pressures and temperatures

change over time, as is unstable performance misbehaviour, but continuous gas lift can be

adequately modelled as a steady state process. The model used here is a leading software product;

PROSPER from Petroleum Experts (www.petex.com), which many petroleum engineers in most

leading international E&P companies will be familiar with. Ideally, this kind of comparison would be

carried out with linked material balance reservoir models and network gathering system models that

link the performance of multiple wells in a common system but for simplicity this has been omitted.

Production system analysis can be used to determine many features of a well completion design,

from perforating shot density to production tubing size. In this example, the tubing size and other

attributes are taken as already fixed.

Analysis Workflow

The focus of this analysis is to inform the selection of artificial lift equipment that will balance the

desire for optimal oil production with the requirement for maintaining well integrity and gas lift

equipment functionality over the life of the well. The workflow involves the following 3 basic steps:

1. Conceptual Gas Lift Design:a. Develop a set of scenarios that will encompass the likely well performance over the

life of the well

b. Review the Base Case reservoir model. This reflected the possibility that a WaterInjection well could be added to the reservoir several months after 1

stoil and that it

would be justified by the initial performance of the lone producer. The following life

of well scenarios were established as being representative of a realistic range of

possibilities with and without water injection:

i. Early Life (1 day): High Reservoir Pressure 7000psig / no water cutii. Early Life (3 months): Moderate Reservoir Pressure 4700psig / no water

cut

iii. Mid Life (1 year) Water Injection: Lower Reservoir Pressure 4150psig / lowwater cut 15%

iv. Mid Life (1 year) No Water Injection: Lowest Reservoir Pressure- 3000psig /no water cut

v. Late Life (3 years) Water Injection: Moderate Reservoir Pressure- 4700psig /high water cut 90%

vi. Late Life (3 years) No Water Injection: Lowest Reservoir Pressure - 3000psig/ low water cut- 15%

c. Establish appropriate sensitivity variablesi. Reservoir Pressure (psig): 7,000; 4,700; 4,150; 3,000.

ii. Water Cut (%): 0; 15; 90.iii. PI (barrels per day per psi reduction in bottom hole pressure): 21; 14; 7iv. Gas Injection Rate (MMSCFD): 0; 0.5; 1.0; 2.0; 3.0; 4.0; 5.0 6.0; 8.0; 10.0
http://www.petex.com/http://www.petex.com/http://www.petex.com/http://www.petex.com/


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d. Run PROSPER in Optimum Depth of Injection Gas Lift Mode, assuming no pressureloss in annulus, to find for each life cycle case:

i. Production Rate Rangeii. Depth of Injection Range

iii. Gas Injection Rate Range2. Detailed Gas Lift Design:a. Evaluate results from the sensitivities above to determine the best compromise

choice of variables on which to build a base case detailed gas lift design:

i. Tubing Sizeii. Reservoir Pressure

iii. Water Cutiv. PIv. Gas Injection Rate

vi. Production Rateb. Perform Enthalpy Balance temperature prediction calculations using the design

production and gas injection rate configuration in order to better predict

temperatures at valve depths so that nitrogen dome charges can be properlycalculated. [This is not discussed in this paper but it should be emphasised that

conventional gas lift valve performance is critically related to temperature at valve

depth a parameter that is not always established with any great confidence.]

c. Establish the specific mandrel spacing, valve port sizes and valve dome pressuresettings for the conventional gas lift equipment to be installed in the well. In this

case, for expediency the design facility within PROSPER was used.

i. Caution should be exercised in using production system modelling softwarefor gas lift design by those who are not experienced gas lift design

practitioners. Specialist gas lift service company engineers should be

consulted. Many design techniques are available, some of which may blend

traditional graphical methods which offer more direct control of the detailedprocess and the multitude of design safety factors, with the power of

software that can quickly generate multi-phase flow tubing pressure

gradients.

d. Establish the DIAL unit spacing based on the absence of any drop in casing pressurebeing required between stations

3. Design Comparison:a. Using the range of potential life of well scenarios discussed above, compare the

performance of a standard multi-mandrel design with:

i. Single point injection at the top mandrelii. Multiple Camcon DIAL units

b. This comparison should:i. Identify where injection via orifice is not possible.

ii. Identify both the optimum and maximum practically achievable productionrates

iii. Identify optimum and maximum practically achievable gas injection rates

Conceptual Design Results

1900 psig casing head pressure is available for gas lift but 1800 psig casing head pressure was used in

the conceptual analysis as the actual operating casing head pressure. This was to take into account

pressure drops taken from maximum available casing pressure to close unloading valves prior to

reaching the operating depth (orifice). 500psi DP across the orifice at the point of injection was


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assumed for conceptual design (the actual DP depends in reality on both the orifice port size and the

rate of gas injection through that port since neither are know at this stage a starting assumption,

based on experience, must be made).

Table 1 Life Cycle Stage 1a: Early Life 1 day

ProductivityIndex

bpd/psi

OptimumDepth of

Injection, ft

MD RKB

OptimumGas Lift

Injection

MMSCFD

NaturalFlow

Production

bopd

Gas LiftedOil

Production

bopd

Gas LiftedTotal Liquid

Production

blpd

Gas LiftedIncremental

Oil

bopd

7 3,790 5.0 15,695 16,105 16,105 410

14 3,160 3.0 20,635 20,730 20,730 95

21 2,930 1.0 22,855 22,865 22,865 10

Table 2 Life Cycle Stage 1b: Early Life 3 Months

Productivity

Index

bpd/psi

Optimum

Depth of

Injection, ftMD RKB

Optimum

Gas Lift

InjectionMMSCFD

Natural

Flow

Productionbopd

Gas Lifted

Oil

Productionbopd

Gas Lifted

Total Liquid

Productionblpd

Gas Lifted

Incremental

Oilbopd

7 6,275 8.0 5,545 8,950 8,950 3,405

14 5,030 8.0 8,835 11,330 11,330 2,495

21 4,635 6.0 10,545 12,545 12,545 2,000

Table 3 Life Cycle Stage 2a: Mid Life Water Injection Support

Productivity

Index

bpd/psi

Optimum

Depth of

Injection, ft

MD RKB

Optimum

Gas Lift

Injection

MMSCFD

Natural

Flow

Production

bopd

Gas Lifted

Oil

Production

bopd

Gas Lifted

Total Liquid

Production

blpd

Gas Lifted

Incremental

Oil

bopd

7 15,525 6.0 - 3,275 3,855 3,27514 10,350 8.0 - 4,677 5,505 4,677

21 8,250 8.0 - 5,670 6,670 5,670

Table 4 Life Cycle Stage 2b: Mid Life No Water Injection Support

Productivity

Index

bpd/psi

Optimum

Depth of

Injection, ft

MD RKB

Optimum

Gas Lift

Injection

MMSCFD

Natural

Flow

Production

bopd

Gas Lifted

Oil

Production

bopd

Gas Lifted

Total Liquid

Production

blpd

Gas Lifted

Incremental

Oil

bopd

7 17,200 6.0 - 1,990 2,340 1,990

14 16,605 6.0 - 3,045 3,585 3,045

21 14,485 6.0 - 3,495 4,115 3,495

Table 5 Life Cycle Stage 3a: Late Life Water Injection Support

Productivity

Index

bpd/psi

Optimum

Depth of

Injection, ft

MD RKB

Optimum

Gas Lift

Injection

MMSCFD

Natural

Flow

Production

bopd

Gas Lifted

Oil

Production

bopd

Gas Lifted

Total Liquid

Production

blpd

Gas Lifted

Incremental

Oil

bopd

7 9,780 8.0 - 452 4,525 452

14 7,150 8.0 - 634 6,340 634

21 6,310 8.0 - 743 7,435 743


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Table 6 Life Cycle Stage 3b: Mid Life No Water Injection Support

Productivity

Index

bpd/psi

Optimum

Depth of

Injection, ft

MD RKB

Optimum

Gas Lift

Injection

MMSCFD

Natural

Flow

Production

bopd

Gas Lifted

Oil

Production

bopd

Gas Lifted

Total Liquid

Production

blpd

Gas Lifted

Incremental

Oil

bopd

7 17,200 6.0 - 1,990 2,340 1,99014 16,605 6.0 - 3,045 3,585 3,045

21 14,485 6.0 - 3,495 4,115 3,495

Conceptual Design Results Comparison

From the tabulated conceptual design results it can be seen that, over the life of this well, there is

extremely wide potential range of injection depths --- anywhere from 3,000 17,000ft MD and a

similarly wide range of optimal gas injection rates, anywhere from 1.0-8.0 MMSCFD. Welcome to

the real world, rather than the textbook world, of gas lift design!

Some engineers propose rationalising this dilemma by using a probabilistic approach, based on a

particular distribution of key parameter values, similar to that used in determining actual oil reserves

in place, to establishing the target injection depth and injection rate as a basis for detailed gas lift

design. In my opinion, it is better to consider this a strategic decision that will be influenced by the

operators business drivers. There will be different answers in different situations. The right

answer is not necessarily a technical one.

Is it more important to gain quick payback on a risky investment through maximising early time

production rates than to maximise the full life cycle reserve recovery by lifting as deep as possible

over the longer period of tail end production, or vice versa?

Table 1 shows that the benefit of gas lift on day 1 is relatively trivial and so can reasonably be

ignored. Similarly, Table 6 is, in this example, identical to Table 4 and so we can combine these two

cases in one for analysis. Both are low reservoir pressure consistent with no water injection support

(limited aquifer support assumed).

The two scenarios that demonstrate most benefit from gas lift are in Table 2 and Table 3. Table 2

might be more important if early payback is important. On the other hand, with the reservoir

pressure that table 2 is based upon, the well is capable of sustaining natural flow meaning that gas

lift is not essential for significant production rates to be achieved. For Table 3 and all subsequent

tables, the reservoir pressure has fallen to a level where it cannot support natural production gas

lift is essential for any production to take place.

For this example it was decided that the detailed design would be based on the maximum oil

production rate seen in a situation where gas lift was essential for production i.e. the Table 3 case

with a PI of 21. This targets a mid depth range ofpoints of injection. If well performance is poorer

than expected, or reservoir pressure falls lower, we will be assured of injecting at this depth. PI is

considered to be unlikely to be higher and, if it were, we could probably still get by with injecting at

this depth with a lower gas injection rate. If we had chosen a case from Table 2, while we would

have benefited under the conditions assumed for that table, we would have lost production in every

other case as the depth of injection would be significantly higher and production consequently lower

than would have been possible with a deeper point of injection.


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The theoretical optimum gas injection rate indicated for all tables, apart from Table 1, is in the range

of 6.0 8.0 MMSCFD. This is, however, a luxury that is unlikely to be available since it is probable

that the host production facility will have a limited total amount of gas to distribute between many

wells. This must be allocated optimally between wells of different potential. It is probable that we

will operate much further to the right on the oil production v gas injection curve. Examining the

chart for Table 3, it can be seen that most of the benefit of gas lift can be obtained with a muchlower rate of around 2.0 MMSCFD. It is also considered prudent to size the conventional gas lift

orifice for a lower gas injection rate, and live with that limitation, rather than assume a higher

injection rate that ultimately may not be available leading to potentially unsustainable instability in

the well casing and tubing pressures due to the marginal DP across the injection valve that results.

One of the great advantages of the Camcon DIAL unit is that the orifice size is not fixed it can

effectively be varied on demand. 2.0MMSCFD was selected as the injection rate for each of the

systems being compared thus providing a level playing field for comparison. It should be noted,

however, that there are three options available for varying the gas injection rate using the DIAL

units. Firstly, since each DIAL unit incorporates multiple valves, it may be that additional valves in

that unit can be opened. Secondly, if the DIAL unit is already has all valves open, the casing pressurecould be raised (should that option be available) in order to increase the rate through the unit. This

would not be feasible with conventional equipment as the upper unloading valves would start to

open (with potentially damaging results). Finally, if the casing pressure cannot be raised and the

DIAL unit at the point of injection is operating at capacity, one or more valves in a second DIAL unit

located higher in the wellbore can be opened, creating a limited form of multi-point injection, to

maintain the required gas injection rate in a controlled and stable manner.

Detailed Gas Lift Design

A typical gas lift design technique built in to the PROSPER program similar to those used by gas lift

service companies - was selected to determine mandrel spacing and valve port size. The depthestablished for the top mandrel was subsequently used as the single orifice design. The mandrel

spacing for the Camcon units was based on the same design technique but without taking any casing

pressure drops (as needed to close conventional unloading valves). The fixed port sizes and dome

pressures calculated are of course irrelevant for the DIAL unit. Only minor use of safety factors was

made for all designs. The transfer tubing pressure was taken as the objective fluid gradient. The gas

passage calculation, which is based on the Thornhill-Craver equation, was de-rated by 75% to reflect

gas lift service company data (i.e. a larger port size will be required to pass the specified gas injection

rate than would be the case without de-rating the calculation).

In a conventional design it is prudent to install mandrels beneath the design injection depth to

permit a deeper point of injection to be established if well performance allows. Dummy valves are

installed in these mandrels, as having additional valves that would in effect be holes in the tubing

beneath the orifice (which cannot close) would be a recipe for instability. Changing out those

dummies requires wireline intervention and is unlikely to happen in a subsea well. For the Camcon

DIAL units, injection can take place through any unit at any time and when the unit is not in service

the valve ports can be closed off by a signal from surface. No well intervention is required. The

location of these additional units lies outside the envelope created by the design tubing pressure

gradient, so they cannot be spaced in the conventional manner. A couple of extra DIAL units were

installed arbitrarily at approximately 2000ft TVD intervals to cover virtually the full range of injection

depth possibilities over the life of the well


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Table 7 Gas Lift Equipment: Basis of Design

Productivity

Index

bpd/psi

Reservoir

Pressure

psig

Water Cut

%

Target Gas

Injection

Rate

MMSCFD

Load Fluid

Gradient

psi/ft

Flowing

Tubing

Head

Pressure

psig

Gas

Injection

Casing Head

Pressure

psig21 4125 15 2.0 0.45 500 1900

Having performed the design exercise, the mandrels were spaced as shown in Table 8. Using the gas

injection rate of 2.0 MMSCFD discussed previously, the port size for the orifice was set at 20/64

(5/16) and the port for the unloading valve was set at 12/64 (3/16) . The unloading valve was set

with a Test Rack Opening Pressure (TRO) of 1650 psig.

Examining the plot of gas pressure vs. gas injection rate at the valve, 2.0 MMSCFD is just to the right

of the curve minima. This means that 2.0MMSCFD is close to the minimum injection rate for stable

injection. The dp across the valve for 2.0MMSCFD is found to be 205 psi. These figures were used in

establishing production rates under the different reservoir pressure, PI & water cut scenariosestablished previously, using a Valve Depths Specified calculation in PROSPER. The calculation

determines whether or not injection can take place at that depth. Since injection is only allowed via

the orifice, only the orifice depth is specified for the conventional design. The operating casing head

pressure is 1850 psig as a 50 psi drop has been taken to close the unloading valve.

For the Camcon design all DIAL unit depths are specified and the calculation indicates at which depth

gas will be injected at. For simplicity, the multiple ports in the Camcon DIAL unit are approximated

by the same 5/16 port and dp assumed for the conventional design. The casing head pressure for

this case is 1900psig as no drops are ever taken.

For the Single Orifice option only the depth of the top valve is considered but a 16/64 (1/4) portsize with an 800psi dp was chosen. The injection of 2.0MMSCFD trough this size of orifice is further

away from potential instability (in this case ~1.0MMSCFD) as we have the luxury of a high dp to work

with. Injection pressure is 1900psig in this case.

Table 8 Gas Lift Mandrel Spacing, ft MD / TVD RKB

Conventional Single Orifice Camcon DIAL

4,190 / 4,190 4,190 /4,190 4,190 / 4,190

6,770 / 6,585 6,970 / 6,730

10,555 / 8,500

15,615 / 10,500

Table 9 Life Cycle Stage 1a: Early Life 1 day

PI

bpd/psi

Conventional Design

Orifice @ 6770 ft

Single Orifice

Orifice @ 4190 ftCamcon DIAL Units

Oil

bopd

Gas Lift

MMSCFD

Oil

bopd

Gas Lift

MMSCFD

Oil

bopd

Gas Lift

MMSCFD

Depth of

Injection

ft MD

7 16,105 0.0 16,105 0.0 16,105 0.0 -

14 20,730 0.0 20,730 0.0 20,730 0.0 -

21 22,865 0.0 22,865 0.0 22,865 0.0 -


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Table 10 Life Cycle Stage 1b: Early Life 3 Months

PI

bpd/psi

Conventional Design

Orifice @ 6770 ft

Single Orifice


Oil

bopd

Gas Lift

MMSCFD

Oil

bopd

Gas Lift

MMSCFD

Oil

bopd

Gas Lift

MMSCFD

Depth of

Injection

ft MD7 2,865 2.0 2,360 2.0 3,125 2.0 10,555

14 4,625 2.0 4,060 2.0 4,650 2.0 6,970

21 5,895 2.0 5,330 2.0 5,920 2.0 6,970

Table 11a Life Cycle Stage 2a: Mid Life Water Injection Support

PI

bpd/psi

Conventional Design

Orifice @ 6770 ft

Single Orifice


Oil

bopd

Gas Lift

MMSCFD

Oil

bopd

Gas Lift

MMSCFD

Oil

bopd

Gas Lift

MMSCFD

Depth of

Injection

ft MD

7 2,165 2.0 1,550 2.0 2,710 2.0 15,61514 3,455 2.0 2,715 2.0 3,800 2.0 10,555

21 4,360 2.0 3,575 2.0 4,400 2.0 6,970

Table 11b Life Cycle Stage 2a: Mid Life Water Injection Support & Higher CHP

PI

bpd/psi

Conventional Design

Orifice @ 6770 ft

Single Orifice


Oil

bopd

Gas Lift

MMSCFD

Oil

bopd

Gas Lift

MMSCFD

Oil

bopd

Gas Lift

MMSCFD

Depth of

Injection

ft MD

7 2,165 2.0 1,550 2.0 3,005 3.0 15,615

14 3,455 2.0 2,715 2.0 4,245 3.0 10,555

21 4,360 2.0 3,575 2.0 5,240 3.0 10,555

Table 12a Life Cycle Stage 2b: Mid Life No Water Injection Support

PI

bpd/psi

Conventional Design

Orifice @ 6770 ft

Single Orifice


Oil

bopd

Gas Lift

MMSCFD

Oil

bopd

Gas Lift

MMSCFD

Oil

bopd

Gas Lift

MMSCFD

Depth of

Injection

ft MD

7 750 2.0 - 2.0 1,570 2.0 15,615

14 1,205 2.0 - 2.0 2,210 2.0 15,615

21 1,500 2.0 - 2.0 2,595 2.0 15,615

Table 12b Life Cycle Stage 2b: Mid Life No Water Injection Support & Higher CHP

PI

bpd/psi

Conventional Design

Orifice @ 6770 ft

Single Orifice


Oil

bopd

Gas Lift

MMSCFD

Oil

bopd

Gas Lift

MMSCFD

Oil

bopd

Gas Lift

MMSCFD

Depth of

Injection

ft MD

7 750 2.0 - 2.0 1,750 3.0 15,615

14 1,205 2.0 - 2.0 2,595 3.0 15,615

21 1,500 2.0 - 2.0 3,095 3.0 15,615


11/17


Table 13 Life Cycle Stage 3a: Late Life Water Injection Support

PI

bpd/psi

Conventional Design

Orifice @ 6770 ft

Single Orifice


Oil

bopd

Gas Lift

MMSCFD

Oil

bopd

Gas Lift

MMSCFD

Oil

bopd

Gas Lift

MMSCFD

Depth of

Injectionft MD

7 325 2.0 220 2.0 375 2.0 10,555

14 480 2.0 365 2.0 485 2.0 6,970

21 - - 460 2.0 575 2.0 6,970

Table 14 Life Cycle Stage 3b: Late Life No Water Injection Support

PI

bpd/psi

Conventional Design

Orifice @ 6770 ft

Single Orifice


Oil

bopd

Gas Lift

MMSCFD

Oil

bopd

Gas Lift

MMSCFD

Oil

bopd

Gas Lift

MMSCFD

Depth of

Injectionft MD

7 750 2.0 - 2.0 1,570 2.0 15,615

14 1,205 2.0 - 2.0 2,210 2.0 15,615

21 1,500 2.0 - 2.0 2,595 2.0 15,615

Table 15 Incremental Oil Production from Camcon DIAL Units

Life CycleCase

PI

bpd/psi

Increment vs.

Single Orifice

bopd

Increment vs.

Conventional

Multi-MandrelDesign

bopd

Increment vs.

Conventional

Multi-MandrelDesign

%

Increment vs.

Conventional

Multi-MandrelDesign

(3.0 MMSCFD)

bopd

1a 7 0 0 0

14 0 0 0

21 0 0 0

1b 7 765 260 9

14 590 25 0.5

21 590 25 0.4

2a 7 1160 545 25 840

14 1085 345 10 790

21 825 40 1 880

2b 7 1570 820 110 1000

14 2210 1005 83 1,390

21 2595 1095 73 1,595

3a 7 155 50 15

14 120 5 1

21 115 575

3b 7 1570 820 110

14 2210 1005 83

21 2595 1095 73


12/17


Discussion

For Life Cycle Stage 1a, the early life (1-day) scenario, injection of 2.0 MMSCFD at the depth of the

top mandrel is not possible, so the well will be left to flow naturally without any gas lift assistance.

For Life Cycle Stages 2b & 3b, which are in fact identical and represent the lowest value of reservoir

pressure, there is no stable solution as the VLP and IPR curves do not intersect. It is not possible by

injecting gas only at the depth of the top mandrel to reduce bottomhole pressure sufficiently to get

the well flowing.

For Life Cycle Stage 3a, with a strong reservoir pressure and the strongest PI it is not possible to

inject 2.0 MMSCFD at the depth of the orifice in mandrel number 2 in the conventional gas lift

design. Since there is a risk that injecting through the unloading valve may damage the valve, no

injection takes place. Since the well is not capable of natural flow with this high water cut, the well

must remain shut in until either the reservoir pressure falls to the point that gas can be injected at

the depth of the orifice or, conversely, reservoir pressure rises high enough to deliver natural flow.

There is no such problem with the Camcon DIAL unit. In this case 2.0 MMSCFD can be injected at

mandrel 2 since there is greater casing pressure available at depth (no pressure drop is necessary to

close the unloading valve above. Alternatively, if the pressure difference across the DIAL unit was

not available, the unit could be closed by a remote instruction and the DIAL unit above opened up to

continue lifting the well and maintain oil production.

For each of the Life Cycle Stages (apart from Day 1 when the well is too strong for any gas lifting

regardless of the equipment) it can be clearly seen that the flexibility of the DIAL unit to move

injection depth up and down the well in response to the changes in well production characteristics

yields additional production. At times this incremental production is worth over 1,000 bopd,yielding significant extra cash flow. The relative benefit varies over time but is always positive and

reaches up to 110% in one case. (The relative benefit is truly massive in the case where the well

must be shut in, given a conventional design, but the relative % measurement of infinity is not

particularly meaningful!)

In order to make this comparative modelling exercise practical in a multi-variable scenario, some

simplifying assumptions were made, such as the selection of 2.0 MMSCFD as the allocated gas

injection rate. This does not enable a full appreciation of the potential of the DIAL units, which

provide the option of changing the effective port size by selectively opening a number of valves in an

individual unit.

In order to capture this, a scenario was created where higher casing head pressure becomes

available (perhaps through re-wheeling the compressor or perhaps as a result of less pressure drop

in the distribution lines) and more gas lift gas also becomes available (perhaps as other wells are

shut in). A casing head pressure of 2000psig and a gas injection rate of 3.0 MMSCFD were modelled

for the two mid life Life Cycle Stages. The conventional design cannot take advantage of this as

higher casing head pressure will re-open the unloading valve. Furthermore, the port size was based

on the lower injection rate and cannot be changed without accepting the cost and risk of well

intervention.

With higher casing head pressure and higher gas injection rates, the DIAL unit delivers even greater

incremental production and without any well intervention.


13/17


Appendix 1: Graphical Illustrations from Petroleum Experts PROSPER Software (www.petex,com)

Figure 1: VLP/IPR Curves for Late Life Scenario 4700psig / 90% WC; No production solution

(intersection of curves) for zero gas lift.

Figure 2: Oil Production vs. Gas Lift Gas for Early Life Scenario 4700psig / 0% WC; Well capable of

natural flow (zero Gas Lift) regardless of PI.
http://www.petex%2Ccom/http://www.petex%2Ccom/http://www.petex%2Ccom/http://www.petex%2Ccom/


14/17


Figure 3: Depth of Injection vs. Gas Lift Gas for Mid-Life Scenario with Water Injection; uncertainty

over PI yields a wide depth range

Figure 4: Detailed Gas Lift Design Plot of TVD vs Pressure & Temperature; Conventional Equipment


15/17


Figure 5: Gas Lift Orifice Performance Curves for the downhole pressure, temperature and gas lift

gas gravity used in this example

Figure 6: Annulus Pressure at Valve Depth vs. Gas injection rate showing curve minima


16/17


Figure 7: DP across valve vs. gas lift gas injection rate

Figure 8: VLP/IPR curves for the Late Life / High Pressure / High Water Cut Scenario with

Conventional Equipment injection at the orifice in mandrel 2 is possible with PIs of 7 and 14 but

not for a PI of 21. The VLp then defaults to the natural flow VLP for which there is no solution

(VLP/IPR intersection)


17/17


Figure 9: Mid-life Scenarios with Conventional Equipment Injection at the orifice in mandrel 2 is

possible for both reservoir pressures and each PI.

Figure 10: Mid-life Scenarios with Camcon DIAL Units Injection takes place deeper for the lower

reservoir pressure and each PI but for the higher reservoir pressure the injection depth is raised for

each value of PI. The stair step in the VLP reflects the lifting of the depth of injection resulting in

higher bottomhole pressures for a given production rate.

END

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