Technical & operational integrity issues and their resolutions are dealt with leading to the concept selection for a high H2S (33% H2S) gas development in Abu Dhabi. Two strategic principles underpinned the concept selection and field development plan:
minimise Health, Safety and Environment (HSE) risks and
employ field proven technology and practices as far as practicable.
Sulphur production instead of acid gas injection was rejected as a viable development option due to its environmental impact and the poor prospects for sulphur marketing. Developmental technical issues included sulphur precipitation in the production tubing and pipelines, and material selection for the sour gas well completions and the gathering & injection pipelines. Materials selection was based on designing out all catastrophic failures and corrosion mitigation & monitoring of progressive corrosion failure mechanisms. Operational issues were related to minimal facility manning and competence assurance of sour gas operatives.
Technical and operational integrity is achieved when, under specified operating conditions, there is no foreseeable risk of failure endangering the safety of the people, environment or asset value. A joint Abu Dhabi National Oil Company (ADNOC) and Shell team completed a field development plan (FDP) for an onshore sour gas field containing high H2S in Abu Dhabi. The objective of this paper is to highlight and share some of the main technical & operational integrity issues, and their resolution leading to concept selection for field development.
In a nutshell, the FDP calls for the production of sour gas using horizontal well completions & sweetening the gas using the Shell proprietary Sulfinol-M process. Additionally, the FDP advocates the injection of the effluent acid gas (80% H2S & 20% CO2) into an oil reservoir for miscible flood/enhanced oil recovery. Sulphur production instead of acid gas injection was discarded as a viable development option due to its environmental impact and the poor prospects for sulphur marketing due to its worldwide oversupply.
The raw produced gas is dry (i.e. no hydrocarbon condensate) and highly sour with 33% mol H2S and 10% mol CO2. The produced gas also contains dissolved elemental sulphur at reservoir conditions, which will precipitate upon pressure and temperature reduction of the reservoir fluid during production. If elemental sulphur were allowed to deposit on the tubing wall or any part of the facility made of carbon or low alloy steel, it would cause rapid corrosion (>25 mm/year) in the presence of water containing chlorides (e.g. produced water, completion brine etc.).
In addition, at temperatures below the freezing point of sulphur at 110°C, the precipitated sulphur would form solid deposits, plugging the tubing and downstream facilities, and restricting the production flow. Two extreme examples of the latter are the high H2S Bearberry wells located in Alberta and Zakum in Abu Dhabi where the wells completely plugged the tubing with solid sulphur within 3–4 hours of production.
The sour gas production system is therefore subject to particularly aggressive corrosion conditions due to high H2S and CO2, presence of produced water containing chlorides, potential for elemental sulphur deposition and high production temperatures.
Besides the handling of highly toxic and corrosive fluids at relatively high pressures (160–276 bar), the most challenging feature of the development is upscaling existing technology to sour gas production of up to 910 MMscf/d and acid gas injection of up to 320 MMscf/d. Major facilities for the full scope of field development from upstream to downstream comprise:
36 sour gas-gathering wells (horizontal completions)
4 sour gas gathering satellite stations