For all the technological developments in the oil and gas industry over the last few years, the challenges for smaller players in confronting what is often a risk-averse culture – when it comes to adopting and introducing new technologies – remains.

Whether it is access to financing, tapping into existing industry knowledge and support, or gaining widespread industry confidence, the oil and gas sector remains a highly challenging environment.

However, for all of the technologies and companies that do not make it, there also are many examples of companies that do. Our experiences in bringing a digital gas-lift solution to market, the challenges we faced and how they were overcome, and the reams of new information operators will now be able to access when conducting their digital lift operations is shared below.

The gas-lift market today: benefits and limitations

Artificial lift remains one of the most important EOR technologies in the US and beyond. Today, according the SPE, the number of wells requiring artificial lift is 80% worldwide, with operators such as Shell responsible for over 4,000 artificially lifted wells.

While techniques such as electric submersible pumps (ESPs) and multiphase boosting have tended to receive most attention, gas lift also is receiving recognition as a means of improving recovery rates. In gas lift, gases such as carbon dioxide, 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.

The advantages of gas lift over other alternatives include its effectiveness offshore and in a wide range of well conditions; its ability to handle high volume and HT/HP wells as well as abrasive elements such as sand; and the side pocket mandrel and gas-lift injection valves, which allow a deeper gas injection in the tubing. It is this flexibility with different production rates that makes gas lift more suited to fluctuating well conditions than ESP and rod pumps.

For all these benefits, however, there are significant limitations to gas lift as well – limitations that the industry has lived with for many years and particularly in relation to side pocket mandrels.

Side pocket mandrel-related gas lift requires wireline interventions to change the operating valve when injection rate changes are necessary. Such interventions can be a long and cumbersome process, leading to damage to existing infrastructure (if the wire snaps, for example) and the halting of production as a new side mandrel unit is installed.

Side mandrel tools also have no instrumentation on board. The result is that operators have little to no information on pressures and temperatures at the point of gas injection and limited control and flexibility over altering injection rates in real time.

In addition, the fact that these tools are injection pressure operated (IPO) with the side pocket mandrel functioning at a predetermined annulus gas pressure can lead to severe restrictions and increase the possibility of unstable wells. Annulus pressure fluctuations can often create multipointing injections and can require resources to travel to the wellhead to choke the annulus gas supply to compensate.

All too often with such limitations, monitoring gas-lifted wells is confined to being a basic tick-box approach, focusing on wellhead pressure and the occasional fluid level or downhole pressure reading rather than any consistent real-time data.

It is this lack of flexibility in gas-lift operations that requires operators to make certain assumptions about the field conditions in which they operate and which then determine the gas-lift design. For example, operators have to make an assumption that the well will operate at a specific reservoir pressure and flow at a specific rate and with a specific water cut. With fast-changing reservoir and well characteristics, such assumptions are becoming increasingly unfeasible.

Finally, the changing of side mandrels also requires personnel to be working in remote areas where they are often vulnerable to security issues. Operators such as Shell have already identified this as a key benefit in regions such as Nigeria, and with the recent tragedies in Algeria improved security and remote operations are gaining considerable favor with operators.

Digital gas lift

Whereas in the past, incremental changes might have been suggested to meet these limitations, it is clear that there is a genuine industry need for greater operator control over gas-lift operations. Operators need to have access to variable operating valve combinations, where decisions and modifications can be made in real time without intervention and without threats to well instability.

This is what we believe to be the compelling market case against which Camcon has developed a new digital solution for gas lift under the name APOLLO.

The solution is based on what is called binary actuation technology, consisting of a low-energy pulse control that signals to switch an actuator between two stable positions to digitally operate a valve, eliminating the need for side pocket mandrels. The result is that operators can vary injection rates and depth in real time without production interruption and well intervention and generate pressure and temperature information throughout the gas injection process. Electronically actuated valves do not face the restriction of being IPO.

In this way, the solution not only gives operators greater downhole control over gas usage but also delivers increased recovery rates. Recent modeling analysis conducted by a third party showed increased incremental production of over 1,000 b/d of oil and in one scenario, up to 110% more production.

Field trials

Camcon’s digital gas-lift solution is currently being deployed in an onshore well in Oman, with well results of the trials expected to be published shortly.

The deployment of APOLLO is part of a normal workover program for a high productivity well where the new 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.

Ian Anderson, Camcon Oil