Challenge: Develop marginal field with fewer wells to reduce capex and opex, and comply with local regulations requiring back allocation for individual reservoir zones
Solution: Use a modular intelligent well completion to maximize production monitoring and control
Results: Completed three-zone well faster, within budget, without incident or NPT, and with less HSE exposure; improved reservoir management; and met regulatory requirements for joint production and back allocation from multiple zones
Seplat Petroleum Development Company was developing a marginal onshore oil field in Nigeria’s Niger Delta, where the reserves are distributed over 14 stacked reservoirs. The marginal reserves and the field’s limited area made the project uneconomical unless the number of wells could be minimized. The goal, therefore, was to develop the field with fewer wells to reduce capex and opex. Because of the location’s poor accessibility and increased HSE risks, remote zonal monitoring was a necessity. In addition, Seplat had to meet local regulations requiring that back allocation be reported for individual reservoir zones.
Seplat and SLB took into consideration the reservoir parameters, sand control measures, production targets, and governmental regulations for back allocation of jointly produced zones before deciding on an intelligent completion using modular downhole equipment. This solution enables operators to optimize production control and commingling through remote downhole monitoring and control. For each zone, the completion integrates variable-choke flow control valves, an optional pressure and temperature monitoring system with valve position sensing, an optional multidrop module, and a packer. The module allows more flow control valves to be actuated on fewer hydraulic control lines compared with traditional flow control completions and to be controlled from the surface in real time without intervention.
Using a modular solution enhances design flexibility, reduces onsite preparation requirements, and enables improved inventory management, reducing the operational planning challenges imposed by long lead times.
Design. In the first well, the production objective was to drain the three lower layers simultaneously. The single upper layer would be produced using a conventional sliding sleeve. To design the multizone completion, the SLB domain support team compiled and studied PVT and nodal analysis data to determine the optimal size of the flow control valves, which are available with multiple choke sizes. Each zone was also equipped with tubing and annular pressure and temperature gauges, for a total of six gauges.
Operation. During the startup period, a surface multiphase flowmeter and surface test separator were used to directly measure flow rates from individual and commingled zones. These rates along with the downhole zonal pressure readings enabled creation of inflow performance relationship (IPR) curves for the individual zones and the joint production. This analysis was carried out for the various downhole choke settings. The presence of a flow control valve and annular pressure gauge in each zone allowed Seplat to monitor pressure buildup while the flow control valve was closed, enabling determination of reservoir pressure, formation damage, and contributing permeability from each zone.
The commingled testing results were used to evaluate the performance predicted by the original simulation model. No flow domination or crossflow was observed during static conditions. At the conclusion of the well test, a new calibrated simulation model was developed that was suitable for the new flow conditions. The difference between measured and estimated production was within 5%, confirming that the required daily production allocation could be performed from the updated simulation model. This model would remain valid as long as no significant changes occurred to fluid composition and gas/oil ratio.
Using SLB reservoir monitoring and control systems resulted in several significant benefits for Seplat. Because of the equipment’s modularity, completion lead time was reduced and commissioning was accelerated. Installation in the three zones was completed within budget, without incident or NPT, and with less HSE exposure. Remote monitoring and control of zonal production greatly improved reservoir management. Finally, the real-time flow measurements showed that zonal production met regulatory requirements for joint production and back allocation from multiple zones.
