As known the first application experiment for lifting fluids was conducted in Germany in 1797. Then the idea was developed in 1846 utilized compressed air to lift oil from wells. In year 1900 the lifting done by compressed air injected through the annulus or tubing where numerous patents were applied for and issued, but it took nearly 20 years before gas lift became an acceptable lifting method. In 1945 nearly 25,000 different flow conventional valves were patented. Later the pressure operated valve has practically replaced all other types of gas lift valves. The first WL retrievable gas lift valve was introduced in 1957. This pressure with the introduction of the bellows charged gas lift valve in 1940, gas lifting of low pressure wells with a controlled change in the surface injection pressure was achieved. As all the above types is required heavily and costly facility in addition to losing energy, big oil companies such as ADCO started digging for innovative and creative ideas to overcome the disadvantage of the surface injection valves such as corrosion, well control and upstream risk. Although the conventional gas lift system still required but due to harsh environment especially in SOUR fields the Auto-Gas Lift Smart well completion become one of the innovative solutions. Recently ADCO investigated and has successfully installed the first Auto-Gas Lift Smart completion in the UAE. The concept of this completion is to use the gas cap energy from different reservoirs to lift the heavy and high water cut wells. This will eliminate conventional gas lift approach as well as intervention cost meanwhile extends the well life. Candidate selection for this new approach was considered as the main challenge as step one to avoid the project failure. Second main challenge of Auto-Gas Lift was nonstandard completion material and accessories which required special design. As case study this paper will introduce challenges starting from well planning, designing, material selection, and execution. This paper also will demonstrate different problems such as reservoir pressure regime, Slickline line up normal operation through high deviated hole hence it wasn't easy at a high angle to retrieve the plugs, and finally controlling the higher differential pressure of upper formation was also a big challenge. A smart well head was finally installed and tested for the integrity.

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During a tubing depressurizing operation in a sour gas producer, the Sub-Surface Safety Valve dislodged from the nipple profile, broke and stuck inside the tubing hanger, restricting accessibility to the well. Multiple attempts to recover the stuck fish via slick line in combination with a permanent magnet resulted in recovering a few broken pieces and revealed a limited clearance of 1.85" through the fish. The well was killed and attempts to secure the well by installing through tubing inflatable bridge plugs using coil tubing were unsuccessful. It was then decided to exclude the coiled tubing operation for well integrity purposes due to limited clearance as the coil tubing had to pass through broken fish and could get stuck compromising the X-tree valves operation and it was decided to carry out work over operation to recover the broken fish. The cost for well work over was estimated at $ 3.0 MM. An innovative approach to secure this gas well riglessly using through Inflatable bridge plugs setting with electric line was introduced and the job was conducted successfully after completing all the risk assessments saving the significant costs associated with rig intervention. Two 1-11/16" through tubing inflatable retrievable bridge plugs (TTIRBP) were set with electric line passing thru the limited access hole of the broken fish. Plugs were set inside 4-1/2" and 3-1/2" tubing and pressure tested to 3000 PSI. The well was secured and the fish was successfully retrieved. Both bridge plugs were retrieved using 0.108 inches slickline and the well was put back into production. This great achievement was recognized as a 1st trial to carry out securing a sour gas well in the Middle East using a combination of electric line and slick line for setting and retrieving TTRPB Inflatable packers and plugs run on coiled tubing and wireline through production tubing for water & gas shut-off applications were introduced in late 1980s. This has brought substantial cost savings by eliminating the workover rig and all ancillary operations required by conventional workover in additional to bringing wells back to production in significantly less time. Expanding the use of thru-tubing retrievable beyond their usual scope, to secure wells where maintenance work was required on x-mas trees, tubing hangers and in this example to retrieve and replace the sub surface safety valve stuck in the tubing hanger in a rigless environment sheds light on a whole new range of applications. The rigless program designed and executed successfully to secure the sour gas well utilizing through tubing retrievable bridge plugs.

Completion fluids, typically chloride or bromide brines, based on density requirements are used to control the well during some operations and remain either in the tubing until well is put on production or in the annulus above the packer for the duration of well life. Under normal conditions, the well casing is a closed system where the brine is protected from ingress of H2S/CO2 and oxygen. However, brines may be exposed to oxygen ingress from the surface through a leak at the wellhead, and /or to H2S / CO2 ingress through a potential leak through the packer, their dissolution in the brine, affecting significantly the corrosion resistance of the steel. In spite of its proven efficiency with martensitic stainless steels, sodium bromide based completion brines are quite expensive. To explore possible less expensive alternatives, without compromising corrosion resistance of the tubing, ADNOC Onshore conducted a comprehensive testing program to identify suitable, less expensive alternative brine systems with the same or improved corrosion behavior in well conditions. In the study, the general and pitting corrosion, and the Sulphide Stress Cracking (SSC) resistance of 13Cr and S13Cr samples in NaCl, NaBr and CaCl2 brines were assessed. Samples were tested for a period of 30 days in three brine systems, under inert conditions, under 1.6psi (6.5psi) H2S / 165psi CO2, at 120°C and under oxygen ingress conditions at 49°C, in an autoclave. Pitting and general corrosion were assessed using weight loss coupons, whereas the susceptibility to SSC was tested using C-ring specimens in accordance with NACE TM0177 - Method C, at stress levels of 0,2% of the material proof stresses. Relative pitting susceptibility of the steels under oxygen contamination of the different brine systems was also assessed by electrochemical polarisation tests, at 49°C. The most significant results obtained is that none of the steels presented SSC under all conditions and brine systems. For both alloys, in all test conditions, the general corrosion rates decreased in the order CaCl2 > NaBr > NaCl brines, the exposure to H2S/CO2 presenting 2 to 5 times higher corrosion rates as compared to the inert gas conditions, with the 13Cr alloy presenting higher rates in all conditions, as expected. Pitting was inexistent / negligible in all testing conditions for S13Cr. In sour environment and in oxygen ingress conditions, 13Cr showed relevant pitting in all brines. Under oxygen contamination, deeper and broader pits were observed in the NaCl as compared to the CaCl2 brine, while no pitting was found on NaBr brine specimens. Electrochemical polarisation tests showed that the pitting onset and the repassivation potentials were shifting towards the cathodic direction in the order NaCl, NaBr and CaCl2. The conclusions of the study is that chloride brine systems are a technically viable option for application with S13Cr, without introducing additional corrosion or HSE risks, leading to cost saving of $81MM over five years whereas for 13Cr, the use of bromide based brines cannot be avoided.

Enhancing hydrocarbon recovery is the ultimate goal in the oil and gas business; nowadays there are many technologies that can be applied effectively to reach that goal; Maximum reservoir contact (MRC) wells, Under-balanced drilling (UBD), Multi-laterals (ML), fishbone. etc. However, still the preferable, economical option is to improve the well production by stimulation which is applied easily and riglessly in existing or newly drilled wells. In many horizontal or long pay zone wells; the optimum results cannot be achieved through conventional stimulation techniques because it is difficult to ensure even stimulation fluid distribution (i.e. acid in the case of carbonate stimulation) across the entire lateral hole unless some sort of selective stimulation can be performed. This is a prerequisite for successful result. It becomes more challenging in heterogeneous open hole completions which have natural fractures. Even more challenging is trying to achieve selective stimulation in such complex geological environment when specific reservoir compartments need to be treated specifically. A tight gas carbonate reservoir with no oil rim in a super-giant onshore gas field in Abu Dhabi was particularly targeted for stimulation during a field review to increase field production. Conventional stimulation treatments performed to restore well productivity resulted in rapid performance decline as a result of undesired worm-holing throughout the existing bore hole and uneven flow contributions. PLTs’ were run in three wells to understand the well productivity. The results showed that most of the gas production (approximately 95%) was from upper zones while the remaining production came from the lower zones which were of poor reservoir quality. It became necessary to look at selective fracturing stimulation techniques that could be applied riglessly and allow contribution from the non-producing zones. This paper describes a unique engineering approach, the Hydrajet Fracturing (HJF) technique that was successfully executed for this purpose. The objective was to apply an economically feasible, rigless, selective fracturing technique with efficient placement approach that would lead to proper reservoir drainage. Pin-point stimulation at selected points was considered an important factor for the development of this field. After the unique stimulation treatment, a new technology based on spectral noise logging and temperature distribution survey was used to evaluate the contribution of the targeted fractured zones in conjunction with pressure buildup well test analysis. Several lessons were learnt from the first use of this technology and some interesting conclusions were reached from these investigations.