Success Story Zistersdorf
Zistersdorf plays a unique role in RAGs 80 year history. Due to its limited options, this field was always at the brink of being closed. First plans of Shell and Mobil (RAGs shareholders at the time) were to end production in 1999.
More than 6,900 days later, Zistersdorf is still in production today and will most likely produce another 20 years. Therefore, RAGs biggest achievement is and was to keep producing feasibly and save an oil field including its employees, suppliers and valuable resources from liquidation. Over the decades RAGs employees were able to find smart solutions to combine new digital ways with the existing analogue measures to reduce operating costs and increase the lifetime of their field.
Zistersdorf on a Glance
The two fields, “Gaiselberg” and “Zistersdorf” were discovered in 1935. Since that time we produced 150 wells, 44 of those wells are still in operation today. This includes our pride and oldest well, Gaiselberg 1, which is in production since 1937. The daily oil production is now as little as 50 m³ with an average watercut of 96.5%.
- Miocene, Eocene to Paleocene sandstones in a structural trap
- Porosity: 17–24 %
- Permeability: 50–870 mD
- More than 50 reservoir horizons
- Initial oil in place: 18.1mm to
- Total production (1935–2018): 6.8mm to (54mmboe)
- Ultimate recovery rate 37.6%
- Oil gravity: 27–33 API
The brownfield Zistersdorf has its own processing facilities, pipeline network, storage tanks and a mid- stream pipeline to the refinery in Schwechat.
Zistersdorf’s Challenges and How We Mastered Them
Due its supermature state, Zistersdorf is facing various challenges, which need to be solved and most importantly remain solved.
Continuously declining production…
…and at the same time an ever increasing watercut. The average oil production rate per well is now less than 1.7m³/d (less than 12bbl/d).
Since RAG is not able to change that fact, we monitor, analyze, adjust production and artificial lift equipment of each well. This is done by using new approaches like artificial intelligence and machine learning.
This helps us to avoid
- uneconomic production of high watercut wells (production monitoring)
- reduce downtime (performance and reservoir monitoring)
- equipment failures, workover and repair work (visualization and AI analysis)
The harsh downhole conditions are and ever present challenge for the requirements on artificial lift equipment.
Corrosion rates of more than 4.00 mm per year, waxing, a CO2 content of 10 % and sand have to be dealt with. To master those challenges, RAG introduced several measures:
Corrosion monitoring and treatment program
• corrosion rate is now below 0.005mm per year
Wax monitoring and treatment program
• waxing reduced by 90%
Artificial lift optimization program
- Material management to reduce mechanical wear
- Increase mean time between failure (MTBF) to 7 years
- Reduce downtime
- Increase production by 6 %
Other facts which cannot be changed are surging energy and labour costs.
RAG has managed to implement an automation program. This has helped us to achieve several benefits for all employees and optimize our energy efficiency.
This automation program is utilizing:
- fully automated operations with artificial intelligence applications
- autonomous fail safe functionalities
- prolonged lifetime of equipment
These benefits helped us to use personnel to improve reliability and efficiency of equipment even further. The automation program decreases HSE risks and improves work life. Reduced maintenance represents free budgets and free employee capacities for more important tasks. We reduced energy costs by implementing new materials and material combinations. Our pumps performance is monitored permanent and is adjusted automatically as required.
What have we got out of it?
First and foremost cost savings. RAG was able to reduce the unit operating costs by 25-40 % to 29 USD/bbl in 2018. This includes technical staff from headquarter and depreciation.
Secondly RAG has now an average runtime of artificial lift systems of 7 years. Starting in 2005 with 6 months to 2 years in 2007 and 4 years in 2010, we are now experts in facing adverse conditions. Cost wise this increased runtime means savings of 80,000 USD/year at each well on workover and maintenance.
The extended field lifetime and reduced downtime brought a production increase of 6 %. The now free budgets helped us to enhance inflow performance with alternative workovers. Free capacities of our employees are used to increase ultimate recovery by drilling sidetracks or investigating production enhancement options.