1. Intelligent Gas Lift Cameron Laing, LETS Limited
Peter Watson, Camcon Oil Limited
I should say a couple of things up front. I am actually an independent consultant and have happily specified Schlumberger, Weatherford and PTC kit to customers in the past year. I am presenting under the Camcon banner simply because I am excited about what they are attempting to deliver. It is exactly what I was looking for when I was made a presentation here almost 25 years ago related to the need for flexible gas lift design.
The second thing I should say is that the opinions I express may not necessarily agree with those of the management and staff of Camcon – so….
37th Gas-Lift Workshop, Houston
February 5th - 6th, 2014
This presentation is the property of the author(s) and his/her/their company(ies).
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2. Intelligent Gas Lift – Why?
Current “1950s Technology” is no longer fit for purpose
Weak equipment design
Weak & inflexible operational design
Requires intervention
Frequent wire-line problems
OK for depletion drive reservoirs
How’s that statement for getting your attention?
I see a lot of new and superbly engineered equipment out there but it still has 1950’s DNA. We had a problem with conventional valves in that we could not change the port size or the depth of injection without a work-over so we invented retrievable side-pocket mandrels and retrievable valves. It was inspirational at the time but what if we went back to that decision point and solved the problem a different way with the benefit of 21st century technology and more effectively maximise production rate and reserve recovery.
It is often said that: Hey, “most of the time” gas lift equipment works really well and does a great job. Well if Macdonalds serve their hamburgers hot “most of the time” I can live with that but If I’m flying from Aberdeen to Houston and they tell me that the planes get there safely “most of the time” – the planes are “not fit for purpose” – and you could buy a plane for the cost of some of the wells that I deal with.
I’ll look at the equipment and gas lift design more closely in a minute or two but just for an example of how crazy we are - we now commonly run valves pre-installed in completion sub-assemblies. Then we apply higher pressure to the valves during completion tests than they have been tested to in the workshop!
The intervention tools & techniques we use were designed for small tubing sizes in onshore wells where the wireline crew could hand-jar the valve in and out of the pocket – now we have tools for big tubing sizes being run in deep, deviated wells from a semi-submersible rig in 1000ft of water and expect it to work just the same --- is it any surprise that we have problems?
Gas lift works well in reservoirs where pressure is falling ---but most operators I know expect to water flood and often drive up the pressure higher than it was originally.
Feb. 3rd – 7th, 2014
2014 Gas Lift Workshop

3. North Sea sub-sea wells - example data
13 valves pulled from 4 wells, < 3 years old
~$15m per intervention (semi-sub)
1 well lost completely
90+% valves failed combined TRO
re-test and reverse flow check test
Only 1 passed TRO test
Well fluids in dome / de-pressured dome / cracked mandrel / bent latches / loose latches / one field installed latch not locked in mandrel
Hard data on gas lift equipment performance & reliability in the field is hard to come by but here is some I gathered myself.
It is perhaps exceptionally bad experience. It is not important to know the operator or the equipment supplier. I don’t have the time to put it in context or discuss all the contributing factors, but the point is that it real data and it cost the operator a lot of money in intervention costs and lost cash flow. The interventions were primarily driven by integrity problems but they revealed chronic production problems.
The point I’d like to make is that gas lift valves are put in the well to deliver production – integrity is actually a secondary design requirement. The TRO tests and valve failure modes suggest that production was being compromised.
The experts among you will recognise that the 1-1/2” RK latch shown is not actually locked in place. The valve was run as a replacement in the field and later when the well was worked over we brought the mandrel to town and cut it open. In an adjacent well a valve had earlier been replaced at great cost only for us to later discover that it had popped out of the pocket during production – another $15mm down the drain!
The 1” orifice valve at the bottom has absolutely no integrity – the check valve being cemented open by scale – a common sight, well known to the labourers at the local scale de-contamination facility in Aberdeen.
Feb. 3rd – 7th, 2014
2014 Gas Lift Workshop

4. Conventional Valve Operating Limits
Max CHP
IPO Re-Opening
One of the barriers to life cycle optimisation is that, in situations where intervention is unlikely to happen, we are stuck with one port size for the life of the well.
It is not often recognised that each port size has a distinct range associated with it. Wim der Kinderen, recently retired from Shell, has shown that a lower stability limit can be identified by performing a nodal analysis of how pressure changes with rate at a point in the casing just outside of the gas lift mandrel.
The gas flowing into the node comes down the annulus from surface – typically with little frictional pressure loss so that the performance curve is a straight line, perhaps dipping slightly to the right as rate increases The outflow from the node flows though the valve and joins the produced fluid ending up back at surface. This relationship is very rate dependent reflecting both the pressure drop across the valve and the pressure losses in the multi-phase flow from the valve to surface. The outflow performance is shown by the blue line on this plot of pressure on the right hand y axis versus gas injection rate on the x axis. Consider the analogy of nodal analysis of produced fluid flow in the tubing at the depth of the perforations. If the inflow and outflow curves intersect to the left of the minimum pressure point, in the head dominated region, on the outflow curve the well is considered unstable. So too with the gas flow analysis and we can therefore identify the stable limit on this outflow curve in the same way.
If we want to get more gas into the well we can increase the casing pressure but a maximum limit is imposed by the pressure that would re-open the adjacent unloading valve. This pressure may itself be well below the maximum casing pressure available due to the pressure drops taken in the design process to ensure upper valves remain closed.
We now have a minimum and maximum gas injection rate – and a corresponding minimum and maximum operating casing pressure – for that particular port size in that well.
The green curve simply plots the ratio of actual flow rate divided by the critical flow rate, 10 – 110% on the left hand axis, and demonstrates as we might expect that with this port size we are not in critical flow over the range of gas injection rates identified for this port size.
Stability Limit
Feb. 3rd – 7th, 2014
2014 Gas Lift Workshop

5. Injection Rate Flexibility
3mm Port
4.5mm Port
In this plot we see the gas lift performance curve for the well in blue showing how production on the right hand axis increases with increased gas injection on the x axis. We also see the gas pressure at depth on the left hand axis changes with v gas injection rate for two of the 6 different valves available in the Camcon unit .
If we have the 3mm port open, the minimum stable rate is around 4 Km3 per day and the maximum is 7.5 ksm3 per day. If this valve were closed and a 4.5 mm valve opened, the range would be 7 – 17.5 ksm3 per day. If the gas is available, opening the 4.5 mm valve has extended the upper end of the range by 17 ksm3 and increased production by 40m3/d. Conversely, if gas is in short supply because one of the compressors is down, closing this valve and re-opening the 3 mm valve would extend the lower end by 3 ksm3 per day – so we could keep the well flowing at a stable lower rate rather than have to shut it down completely. And that just covers 2 valves operated sequentially. The range is enormous if we consider valves opened up simultaneously in various combinations.
Feb. 3rd – 7th, 2014
2014 Gas Lift Workshop

6. Intelligent Gas Lift – Flexibility
Well Inflow Performance
changes over time
Ideal depth of injection changes
Optimum gas allocation changes
Recognised in the original 1954 retrievable valve patent
Continuous injection through IPO valve not “recommended” by vendors but “implied” in designs for many sub-sea wells
Flexible designs produce more oil
When designing a gaslift well, we live with the uncertainty of what the well may actually produce. We also live with the certainty that well performance will change over time! That is why we need flexibility in gas injection depth and port size that does not depend on well intervention.
This need for flexibility was recognised in the text of the patent for one of the first retrievable gas lift valves, submitted in – you may recognise the back-check that is still used in a popular 1” valve still being installed in some high cost 2014 wells.
With current equipment we end up being forced to say one thing and do another. Opportunities for intervention are rare and expensive in offshore platform and subsea wells. Operators want flexible designs that produce the most oil that the well can deliver at any given period in its life cycle.
Feb. 3rd – 7th, 2014
2014 Gas Lift Workshop

7. What now ? Are there alternatives? Further development
of the old ideas?
High Pressure Gas Lift?
Casing integrity
Cost
Hydraulic Gas Lift Valves?
For single point gas cap lift
Out dated technology?
As an independent consultant, I have to look at alternatives. More of the same is not an option. Putting racing handlebars on the bike is no good when I need a car.
I have a lot of respect for the many excellent engineers assembled in this room so I hope that you are not offended by my introduction of a little bit of a light hearted analogue from the industry that gave us the Darcy equation.
You may recognise that it is based on the familiar French device – and we have a lot of data on this from the Valve Performance Cleaning House. Added to it is the new Norwegian Barrier device – it looks deceptively simple on the outside but on the inside, a well known British boffin has installed a venturi profile to make things move faster. And finally we have added the Oklahoma Flapper – deliberately located at a distance from the fluid interface to minimise the risk of plugging! I think we can do better than incremental technology in the 21st Century.
High pressure is theoretically ideal, although very expensive, but it places significant extra demand on the casing connections. We do not have a great record on sustained casing pressures and the Elgin G4 blow-out – in part due to the unexpected failure of a casing connection in an HP HT well, was some-thing of a wake-up call in this regard. I like the high pressure rated X-lift and PTC valves – but I think of them as fit for standard sevice
Hydraulic control of gas lift valves has been around for a few years now. It is used successfully, I believe, for controlling gas cap gas lift but it has yet to be proven successful for multi-valve operation – although PTC may have cracked that one now. That would give me variable depth of injection but leaves me with a fixed port size and still no downhole data to help me keep the well optimised. In the end, it still relies on the old intervention technology to change port size.
Feb. 3rd – 7th, 2014
2014 Gas Lift Workshop

8. What is the solution? What the experts said !
Th ASME/ALRDC International Gas Lift Workshop
Remote control
Variable rates of injection
Without using injection pressure control
Data acquisition
Retrievable Annular Safety Valves
Last year, at this workshop in Stavanger, a break-out group came back with 5 requirements for gas lift in the future. Neither myself not any Camcon employee participated in that group. It is remarkable that Camcon are has already developed a gas lift device that satisfies 4 out of the 5 demands.
Feb. 3rd – 7th, 2014
2014 Gas Lift Workshop

9. Camcon “Apollo” Gas Lift Unit
The solution
¼” control line for remote control
6 independent, electrically actuated, valves for variable injection rate
Not injection pressure controlled
No temperature sensitivity
Real time pressure and temperature
Real time well and field optimisation
Without intervention
Feb. 3rd – 7th, 2014
2014 Gas Lift Workshop

10. First Installation

11. Apollo Gas Lift: Oman Installation
First unit installed and operational
Brought “on line”: in October 2013
Valves run closed on installation
Valves actuated remotely
Electrical connections secure
Data transmission ongoing in real time
Operator testing ongoing.
Field challenges experienced and addressed
Feb. 3rd – 7th, 2014
2014 Gas Lift Workshop

12. Apollo Gas Lift: Oman Installation
Original Data Plot
Downhole Temperature and Pressure
Pick up re-start of gas injection and
unloading valve closure

13. Chart clearly shows impact of intervention activity
Apollo Gas Lift: Oman Installation
Chart clearly shows impact of intervention activity
Well intervention in progress

14. Apollo Gas Lift: Oman Installation
Tubing Pressure Shows “Unloading Valve Action” & Temperature Tracks Production.
Unloading valve action seen here

15. Apollo Gas Lift: Oman Installation

16. Apollo Gas Lift: Oman Installation
Plans going forward
Expand reference base of users
On Shore
Off Shore
Flow testing
Higher P & T, Longer Reach
Multiple Unit Installation
Intelligent Well and Field Optimisation
Feb. 3rd – 7th, 2014
2014 Gas Lift Workshop

17. What are the applications?
Onshore and Offshore deployments
Intervention limitations: subsea / high angle / bed space / wireline crew scheduling or skillset
Dual Gas Lift Completions
Multi well start-up & optimisation acceleration
Liquids removal from gas wells
Unloading control to protect surface separators
Deepwater flow control (fibre optic line built in)
Feb. 3rd – 7th, 2014
2014 Gas Lift Workshop

18. Intelligence in the Upper Wellbore
Move to the 21st century with intelligent gas lift
Surface controlled
Electrically actuated valves
Multi Ported
Real time well and field optimisation
Without intervention
THANK YOU
Feb. 3rd – 7th, 2014
2014 Gas Lift Workshop

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Feb , 2012
2012 Gas Lift Workshop

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Feb , 2012
2012 Gas Lift Workshop