The Maari oil field, the first OMV operated offshore oil field development, has showcased OMV's impressive technical skills. Following the completion of a field re-development drilling campaign in August 2015, the well configuration currently consists of 10 producers and 1 water injector (with the option to convert a producer into a water injector in the future). Electric Submersible Pumps (ESPs) are installed on all 10 producing wells to provide lift of reservoir fluids to surface. A SCADA system and associated Production Historian Database (PHD) was included in order to capture the high frequency data for well & reservoir surveillance and daily production optimisation of the field. However, there were many challenges in utilising this live data stream from the offshore facility. In particular, it was vital to continuously and effectively monitor and optimise ESP performance in order to improve run life, reduce downtime and ultimately increase production. An integrated decision support system was therefore required for real-time data collection, production monitoring, ESP health check and KPI analysis for proactive decision making and limiting the number of manual processes involved. This paper describes how these challenges were overcome by creating an integrated workflow and aligning the existing system architecture in order to meet the business needs. The system is based on full workflow automation, and has been deployed for data acquisition, validation and analysis by optimising the components of integrated asset management. The system includes an integrated framework connected to various live data sources with different time increments, allowing data aggregation to a reliable intra-day hub. Automated job scheduling has also been built in with a decision support dashboard setup for production analysis and ESP performance monitoring. Based on historical trends, an optimum operating envelope was defined and automatic rules were configured for anomaly detection. The system has provided standardized data access throughout the asset team, streamlining their entire process and resulting in improved efficiency, which has optimised the engineers time for core operational activities. With a secure and automated workflow, and the ability for multiple users to work simultaneously, the system has minimised their downtime, thus improving overall productivity. Utilizing the live data feed for updating of simulation models has allowed quicker comparisons of numerical predictions with analytical forecasts, hence helping to streamline the overall reservoir management of the field. The system has not only assisted the team in meeting their production reporting deadlines, but has also alleviated bottlenecks in their decision-making processes helping to boost overall asset productivity.

The Maari Field in the offshore Taranaki Basin, New Zealand was discovered in 1983 by the Moki-1 exploration well (figure 1). Appraisal activities and development studies undertaken by various oil companies over the subsequent two decades failed to identify a viable development concept with an acceptable risk profile. Key factors delaying development were distance from existing infrastructure, field size in association with oil price and critically the high wax / low pour point nature of the oil. The Maari Joint Venture identified a strategy to develop the field and produce the previously stranded oil by means of innovative technology applications.The self-installing wellhead platform and the FPSO were installed in April and May 2008, respectively but the jack-up rig to drill the five horizontal production and three deviated water injection wells was delayed by three months due to winter weather. First Oil from the field was on 25 th February 2009, a milestone achieved some 25 years after its discovery.A number of new technologies and pioneering applications were put into practice with the Maari field development:• The self installing wellhead platform. At the time Maari WHP was the largest self-installing platform of its kind.• The production wells have a thermal design with both passive (thermal gel and thermal cement in the annuli) and active (electric down hole heating system) elements. • Drilling while casing.• The electric submersible pump assemblies were designed to handle free gas conditions down hole in the horizontal section due to the reservoir fluid being close to its bubble point. • The injection water is heated to reservoir temperature to avoid wax precipitation in the reservoir and injected above the 'fracture pressure'.Two smaller near field satellite oil accumulations were also drilled and completed, including a ~8,000m horizontal ERD production well targeting a deeper reservoir in separate structure to the south of Maari. Numerous challenges, such as scale, hydrogen sulphide, corrosion, completion designs and wax, have been encountered and largely overcome during the production phase.The paper will detail the innovations, new technologies, major learnings and experiences from the development concepts to production of this originally 'stranded' asset.

Coiled tubing is utilized to enter horizontal wells for the purpose of performing general remedial well operations. Common operations performed include but are not limited to stimulation treatments, solvent treatments, cleanouts and water shut-off. In today's oilfield, many horizontal well plans incorporate the drilling of multiple laterals. Entering multiple laterals, in one well, using coiled tubing, requires guidance. Advanced completion designs may facilitate such guidance. However, in the case of open hole multi-lateral wells a guidance system is not incorporated in the completion design. This paper will discuss a reliable commercially available technology, developed for the purpose of entering open hole multilateral wells using coiled tubing. The paper will review bottom hole assembly functionality, development of this technology and applications. In addition, offshore case histories of wells entered using multi-lateral entry guidance technology will be summarized. Introduction Open hole, horizontal multilaterals exist in a number of fields throughout the world and have proved cost-effective to drill, delivering high rate wells in the short term. However, longer term, as the production declines and the water cut increases in the well, typical intervention operations are required: water conformance, stimulation, production logging and water shutoff to mention only a few. Open hole, horizontal multi-laterals are typically not designed for enabling interventions into the laterals during the lifecycle of the well. The usual method of intervention would require a drilling or workover rig to pull the completion and then use jointed pipe to guide the tools into the desired lateral, typically using a bent piece of pipe. However, the high rig rates, long workover times, limited rig availability, the inherent operational risks and the high potential for formation damage make workovers with a rig very costly. Alternatively, well interventions could be done through-tubing with coiled tubing, a much cheaper method of conveyance than jointed pipe. However, for coiled tubing to enter all the laterals in a open hole, horizontal multilateral well, a guidance system would be required as coiled tubing has no inherent steering capability. Presently today there is a reliable commercially available solution to enter multilateral wells using coiled tubing, the Lateral Entry Guidance System. Lateral Entry Guidance System: Solution to enter multilaterals Using Coiled Tubing The challenge of entering open hole multilateral wells is not a simple problem. Consideration was given to the problem with respect to how complex should the tool string be. Effective tool design should be "simple is best". For this reason, a tool was designed to ensure that laterals may be entered without electronic telemetry systems. Simple tools are easily introduced and implemented on a global basis thereby enabling access of this important technology to all operating regions. The lateral entry guidance system is a fluid activated tool. This enables the tool to be run on virtually any coiled tubing unit. In fact, the tool may also be run on jointed pipe if required.

Wax buildup that would restrict the flow of the oil from the reservoir to the offshore platform was expected in several wells offshore New Zealand. Alternatives such as hot oiling, scraping and chemical injection were rejected, since electric downhole heating was the most efficient, economical, reliable, and environmentally friendly solution. The use of a unique, skin-effect electrical heat tracing system inside the production tubing was selected as the most efficient and cost-effective method. This heat tracing system involved a sealed coiled tubing, with an internal cable and filled with di-electric oil, that was installed in the production tubing. This created a skin-effect heater with maximum heat transfer and also ease of installation. The use of heaters inside the production tubing provide a more effective and efficient system for flow assurance than external heaters on the tubing would. The heaters, called skin-effect heat tracers, covered the length from the reservoir to the topsides, some 1,700–2,000 meters (5,577–6,562 ft.). The reservoir temperature was only 50 0C (122 0F) and the crude had a Wax Appearance Temperature of 48 oC (118.4 0F), so even minor cooling could potentially cause wax buildup problems. Typically well flows were heated effectively during operations to ensure that the tubing head temperatures were 60-65 0C (140- 149 0 F) so that wax was never deposited on the tubing. The heaters can easily be adjusted at the surface to provide the required heat under varying operating conditions. Skin-effect heating is an efficient, reliable, and easily adjustable method to prevent flow assurance issues that can be retrofitted to existing offshore or onshore wells The total system is very space efficient both downhole and on the platform. Some of the conclusions include that the flow assurance issues of wax buildup and the resulting restricted oil flow were resolved in an economical and efficient manner. Also, this unique, first application of skin-effect heat tracing downhole for a deep offshore well provided reliability and economic returns on investment. Finally, this method can also be used to prevent other flow assurance issues such as viscous oils and to prevent hydrate formation.