More than 90% of the world's producing wells currently use some form of artificial lift technology, according to Schlumberger.

Spears & Associates' October 2009 "Oilfield Market Report" estimated that the global artificial lift market was worth US $5.8 billion in 2009 – a figure that is likely to have increased over the last few years. In addition, according to the "OPEC Annual Statistical Bulletin 2009," there are 1.48 million producing oil wells, of which only 30,000 are free-flowing.

While electric submersible pumping (ESP) techniques have tended to lead the way, there also has been an increase in popularity for gas lift, where gases such as CO, natural gas, or nitrogen are injected into the production tubing to reduce the impact of the hydrostatic pressure where reservoir pressures are not sufficient to lift the hydrocarbons to the surface.

By reducing the density of the produced fluid column and drawing down flowing bottomhole pressure, thus encouraging reservoir liquids to enter the well bore at higher flow rates, operators can enjoy improved well performance. Gas lift's popularity also is often related to its ability to handle gassy, sandy, and corrosive fluids in deviated wells and its applicability to a wide range of production rates.

The APOLLO solution is in direct response to operators’ needs to have access to variable operating valve combinations and make decisions and modifications in real time without the need for intervention. (Images courtesy of Camcon Oil)

Solution limitations

Today's solutions for gas lift come with limitations, however, particularly in regard to the information generated and the often crude forms of intervention required. Monitoring gas-lifted wells, for example, is often limited to a basic tick-box approach, focusing on wellhead pressure or the occasional fluid level or downhole pressure reading.

The primary method of gas lift well completion still depends on the use of side pocket mandrels, where wire-line interventions are used to change injection depth and make significant rate changes possible. Operators have little information on pressures and temperatures at the point of gas injection and limited control and flexibility over altering injection rates in real time.

The side pocket mandrels host either temperature-sensitive injection pressure-operated devices or a simple orifice with fixed port size, both of which are prone to unstable operation when annulus and/or tubing pressures change. This can lead to unloading valves higher up the production tubing opening and injecting gas. It also can lead to gas injection at the wrong point and potential valve failure as most unloading valves are not designed for continuous injection.

The lack of flexibility and control in gas lift has paved the way for ESPs to grow in popularity in recent years, and it is a real challenge for the gas lift community. It also comes at a time where there is a wide range of conditions and fluctuating flow rates and pressures in many fields, especially those linked by complex gathering system networks. The wider range of process conditions increases the need for greater control over injection rates.

Remote field locations, growing water cuts, and fast-changing reservoir and well characteristics are increasingly common in reservoir operations, and the previous assumption that a well will operate with a specific reservoir pressure and flow at a specific rate and water cut is simply not sustainable. The lack of information and difficulties over intervention also have the potential to result in well instability, leading to chronically suboptimal production rates; dramatic surges in liquid and gas flow, which can shut down production separators and degrade field production uptime; and concerns over the integrity of the casing and tubing.

Need for greater innovation and flexibility

Camcon recently developed a digital solution for gas lift called APOLLO. At the core of the technology is an extremely low energy pulse control, which signals to switch an actuator between two stable positions to digitally operate a valve. The six electrically actuated valves, opened individually or in specific combinations, allow for real-time setting of injection rates not possible on traditional gas lift technologies.

This eliminates the need for side pocket mandrels and wireline intervention, with settings tuned as well-bore conditions change throughout the life of the installation, providing downhole control of gas usage and preventing instability.

The solution also provides operators with continuous real-time information on pressure and temperature within the annulus and the production tubing at the point of gas injection. Having live information allows operators to optimize operating parameters and minimize gas usage without expensive and potentially risky slickline intervention, resulting in higher oil production rates.

A comparison is shown between a side pocket mandrel gas lift completion and the digital solution in regard to reduced intervention times and improved recovery.

Putting the system to the test

The digital solution has been deployed in an onshore well in Oman, and Camcon expects to publish well results shortly. The deployment is part of a normal workover program for a high-productivity well where the intelligent gas lift method will be used to improve the production performance of the well. Although a test installation, the equipment has been selected as the chosen method of lifting for the well.

Aside from this deployment, a recent simulation modeling analysis comparing the new solution to traditional side pocket mandrel units already has provided the company with positive results. The analysis demonstrates that Camcon's digital solution can deliver as much as 1,000 b/d more oil from a typical well compared to traditional gas lift equipment.

The simulation modeling was carried out by production technology consultants Laing Engineering & Training Services (LETS).

LETS developed an example subsea well in moderate water depths, drilled to 5,365 m (17,600 ft) measured depth (MD) and with a 4.5-in. by 5.5-in. production tubing string inside a 7-in. liner and 9 5/ 8 -in. production casing. The oil was a light 38°API fluid with a reservoir temperature of 127°C (260°F). The key variables examined were the well productivity index, reservoir pressure, and water cut, all expected to change over the lifetime of the well.

LETS used the analysis software PROSPER to create production system models with a number of well life scenarios developed. These included early life cases of one day and three months, where there would be high, dropping to moderate, pressures and no water cut; through to mid-life at one year, where there would be water injection for reservoir pressure maintenance and low water cut; and late life at three years, where the reservoir is repressured and there would be a higher water cut.

Using this range of potential life-of-well scenarios, the test compared the performance of a standard, multi-mandrel gas lift design with Camcon's digital artificial lift solution to identify the maximum practically achievable production rates alongside the maximum practically achievable gas injection rates.

The analysis revealed a wide range of possible injection depths from 914 m to 5,182 m (3,000 ft to 17,000 ft) MD and a wide range of optimal gas injection rates from 1 MMcf/d to 8 MMcf/d. To make the comparative modeling exercise practical in multivariable scenarios, however, 2 MMcf/d was selected as the allocated gas injection rate for comparison. When going through the different well scenarios, the analysis revealed that the benefits of gas lift on day one are relatively trivial and the well would be left to flow naturally without any gas lift assistance.

The two scenarios that derive most benefit from gas lift are at the early life stage after three months and the mid-life stage with water injection support. Table 1 shows the b/d of oil comparisons at the three-month stage for three potential PI values, with APOLLO starting to show increased b/d. The mid-life stage is considered to be particularly

important where reservoir pressure has fallen to the extent that it cannot support natural production. As Table 2 illustrates, the b/d comparisons are significantly in favor of the new digital solution.

The ability to open and close the APOLLO 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. For example, a gas injection rate of 3 MMcf/d was modeled for the mid-life liftcycle stage as illustrated in Table 2 with a higher casinghead pressure as well. As can be seen, the digital solution continued to deliver greater incremental production. The conventional solution would have required wireline intervention to increase the port size.

At the late lifecycle stage with water injection support and higher water cut, it was not possible to inject 2 MMcf/d with conventional gas lift design. This was due to the concern that injecting through the unloading valve might damage the valve. Subsequently, no injection took place. There was no such problem with the digital gas lift solution with 2 MMcf/d being injected.

When LETS assessed the APOLLO units under these lifecycle well scenarios and compared against single point injection gas lift solutions, APOLLO's ability to move injection depth up and down the well in response to changes in well production characteristics such as reservoir pressure and water cut was seen to yield increased production. At times this incremental production was worth more than 1,000 b/d of oil and in one scenario represented up to 110% more production.

There is a genuine industry need for greater operator control over gas lift operations – a future where gas lift operating parameters can be adjusted over a wide range of variables without intervention to reflect changing field characteristics.

The result for operators will be, as the simulation models demonstrate, much greater flexibility and improved recovery rates in comparison to conventional gas lift equipment.

Comments