Gas lift is recognized for enhancing well stability – but it has its drawbacks. Camcon’s digital gas lift has begun field testing onshore Oman, with offshore installations anticipated. How does it differ from traditional gas lift technology? Camcon’s Ian Anderson explains.
The growth in artificial lift
From the North Sea, where operators including Statoil look to achieve average recovery rates of up to 60%, to the United Arab Emirates’ Upper Zakum expansion project, to offshore Malaysia, home to the world’s biggest enhanced oil recovery (EOR) project, increasing oil and gas recovery is one of the offshore industry’s greatest challenges.
Image: APOLLO can be deployed in a wide variety of challenging geologies and conditions. Credit: Camcon
At the center of these developments is artificial lift. The artificial lift market’s growth is so substantial that Markets and Markets’ 2013 Artificial Lift Systems Market Report predicted it would be worth as much as US$16 billion by 2018.
Gas lift and its applicability offshore
While techniques including electrical submersible pumps (ESP) and multiphase boosting are more widely known, another artificial technology with significant applications offshore is that of gas lift.
In gas lift, gases such as CO2, natural gas or nitrogen, are injected into the production tubing to reduce the impact of the hydrostatic pressure. This action reduces bottomhole pressure, allowing reservoir liquids to enter the wellbore at higher flow rates.
Today, the side pocket mandrel (SPM) technique in gas lift that makes use of injection-pressure-operated (IPO) lift valves is one of the industry’s most widely recognized products.
Gas lift today remains particularly effective offshore and in countering well instability - something which is becoming increasingly prevalent in older fields.
Such instability can result from a number of factors, including water and gas breakthrough in the wells; slugging; or increased well pressures. In addition, as wells and reservoirs age, liquid rates begin to decrease resulting in wells being more sensitive to flow instabilities.
Image: The APOLLO Digital gas lift solution. Photo: Camcon
In such cases, gas lift can operate effectively in a wide range of well conditions and high-volume high pressure/high temperature (HP/HT) wells. Additionally, gas lift can handle abrasive elements such as sand, and gassy and corrosive fluids in deviated wells. Furthermore, SPM and gas lift injection valves allow for a deeper gas injection in the tubing.
It is these characteristics as well as its flexibility with different production rates that make gas lift more suitable to fluctuating well conditions in offshore operations than ESP and rod pumps. For example, Senergy’s Dr. Rick Lemanczyk recently estimated that gas lift enabled fields can lead to a 2-5% increase in field-wide production.
Technology limitations
Despite its growing popularity, gas lift also comes with limitations.
Making injection rate changes in SPM related gas lift, for example, requires wireline interventions. These types of interventions can damage existing infrastructure (if the wire snaps, for example); choke the gas supply at the surface; and even halt production as a new SPM unit is installed.
SPM tools also have no instrumentation on board; operators have little real-time information on pressures and temperatures at the point of gas injection and limited control and flexibility over altering injection rates. In addition, the fact that these tools are IPO with the SPM functioning at a pre-determined annulus gas pressure can lead to severe restrictions and increase the possibility of unstable wells.
All too often with such limited information, monitoring gas lifted wells is confined to a basic approach, focusing on wellhead pressure and the occasional fluid level or downhole pressure reading rather than consistent real-time data. It is this lack of flexibility which requires operators to make certain assumptions about the field conditions and the perceived characteristics of the well at a given time.
Consider, for example, a field with 50 offshore wells all using lift gas as the preferred artificial lift technique. How can the field operations team optimally produce all the wells when they are interrelated and interact? Making change to optimize the performance of one well might negatively impact the performance of another. Moreover, such limited information can actually increase the chances of well instability, leading to potential surges in liquid and gas flow.
The growth of digital gas lift
It’s with these issues in mind that Camcon is introducing a new digital gas lift solution that enables operators to vary injection rates and depth in real-time without production interruption and well intervention. It eliminates the need for SPMs and wireline intervention, with settings tuned as well-bore conditions change through the life of the installation, giving greater downhole control over gas-usage and preventing well instability.
The solution is based around binary actuation technology (BAT), consisting of a low-energy pulse control which signals to switch an actuator between two stable positions to digitally operate a valve. The need for SPMs is thereby eliminated. The electrically-operated valve; actuation configuration; and six control actuators for injection variation enable the realtime setting of injection rates, which is not possible on traditional artificial gas lift technologies.
Putting it to the test
With such technology, it was essential to produce some real-life data to demonstrate its potential prior to test installations in actual wells. This was achieved through a simulation modeling analysis program, conducted by Laing Engineering & Training Services (LETS).
The example well developed was based on a modern subsea well in moderate water depths, drilled to a total depth of 17,600 ft. measured depth (MD) with a 4.5 ft. by 5.5 ft. production tubing string. The key variables examined during the testing were the well productivity index (PI), reservoir pressure and water cut.
LETS used the analysis software PROSPER to create production system models with a number of well life scenarios developed for early life (one day to three months), mid-life and late-life. The analysis revealed a wide range of possible injection depths from 3,000-17,000 ft. MD, and a wide range of optimal gas injection rates from 1-8 MMSCFD. In order to make the comparative modeling exercise practical in multi-variable scenarios, 2 MMSCFD was selected as the allocated gas injection rate.
The analysis found that the two scenarios deriving most benefit from gas lift are at the early life stage after three months and the mid-life stage with water injection support.
Figure 1, for example, shows the bo/d comparisons at the three month life cycle stage for three PI values with digital gas lift already showing increased bo/d. Figure 2 shows improved bo/d at the mid-life stage with digital gas lift, which can also set higher injection rates at 3 MMSCFD. Furthermore, even without water injection support as demonstrated in Figure 3, the bo/d generated through digital gas lift is significant higher than the alternatives.
The model’s final conclusions were that digital gas lift can deliver as much as 1,000 bo/d more oil production from a typical well and, in one scenario, showed a 110% increase in production compared to traditional gas lift equipment. With this modeling data, the digital gas lift solution is currently being deployed in an onshore well in Oman.
Although a test installation, the equipment has been selected as the chosen method of lifting for the well and is likely to lead to offshore installations in the near future. The deployment is part of a normal work over program for a highlyproductivity well where the intelligent gas lift method will be used to improve its production performance. The tool is currently fully activated in the field. Operators today are looking for greater control over their gas lift operations. It is encouraging to see that technologies such as the emergence of digital lift are rising to the challenge with significant applications for offshore operators. OE
Ian Anderson is chief operating officer of Camcon Oil, part of the Camcon Federation of Companies, where he has been working since 2003. Previous roles include director at management consultancy Thespian Ltd; Business Unit Director at IT services company Unisys; and vice president at Atex Systems, a systems integrator.
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