Eductors, also known as ejectors or jet pumps, are used to boost low pressure (LP) flows by utilizing energy from high pressure (HP) streams. An application can use gas from an HP well to boost production from an LP well. Historically, vendors only provide the performance expectations of an eductor for initial conditions. However, as reservoirs decline, the pressure and flow regimes change making the future performance of an eductor difficult to predict.
Water reduction techniques were applied in the openhole gravel pack (OHGP) completions of four wells in Field C. Field C is operated by BP Trinidad and Tobago LLC (bpTT) and is located offshore Trinidad in the Columbus Basin. During the first phase of field development, six wells encountered economically recoverable reserves and first gas was achieved in 2007. The field produced at peak rates wells became liquid loaded due to aquifer influx, and production declined by~80%.The second phase of field development was scheduled to commence in 2016, and hence the bpTT field team began to investigate ways to revive the four liquid loaded wells and return them to production. Using experiences from BP Global Operations, and based on the assumption that the reservoir drive mechanism was bottom and/or edge water drive, the team decided to install zonal isolation devices. Also known as water shut off plugs; these devices are usually used in oil well casing applications and had never before been tested in gas well openhole gravel packs in Trinidad and Tobago. Each plug was set within an interbedded shale in the reservoir and screen joint of the completion to provide a vertical flow barrier. Due to uncertainty on the lateral extent of the shale and its ability to act as a barrier to water encroachment, an additional step of dynamic wellbore modelling was implemented. This was used to modify well bean up in order to minimize drawdown while maintaining the critical rate.The well intervention campaign to install the plugs began in December 2013 and was executed using both slickline and e-line tools. One of the key considerations during job execution was depth control, to prevent setting the plugs too high in the wellbore and isolating gas bearing sands. This was achieved by correlating the gamma ray (GR) and Casing Collar Locator (CCL) logs with the original openhole logs. The plugs were installed by July 2014 and 75% of the wells were successfully offloaded with an average reduced WGR of 40%. This prolonged the producing life of the wells and improved the recovery factor by an average of 2%.
Over the past 18 months energy prices have declined more than 50%. This has placed significant constraints on energy companies who are experiencing major declines in operating cash flow while maintaining shareholder distributions. Increasingly, the response has been to cancel or delay capital-intensive projects while attempting to materially improve efficiency and reduce operating costs. Improving the efficiency of Base Production, defined as production from existing wells and fields, has been a particularly effective way for BP to improve or maintain production levels at relatively low cost. This is not without major challenges as Base Production includes fields/wells which are heavily depleted and/or liquid loaded. Offloading these types of wells requires specialized skills and simulation tools one of which is described below. OLGA or Oil and Gas Simulator is a dynamic multiphase modelling tool which is used to simulate flow behavior of petroleum fluids from the reservoir to onshore gathering systems. It utilizes finite element analysis to divide the well or production system into elements which together create a mesh intersecting at nodes. After boundary conditions are introduced the simulation is completed in a series of several thousand time steps by solving system equations for each element with the outputs from one time step used as the input for the next one. With this powerful calculation method, engineers are able to investigate the behavior of complex and irregular shaped systems, such as wells and networks, to determine the optimum range of pressures and temperatures to optimize production. For well offloading, dynamic modelling is used to evaluate the offload against various platform, well and reservoir parameters to understand and mitigate risks. Simulations are also completed to ensure new wells either have enough pressure energy to remove completion fluids and flow into the gathering system or to determine if a depressurized volume or reduced system pressures are required. This approach has positively impacted wedge production delivery for the company as the Subsurface Team is able to better influence well offloading strategy at the early stages of planning therefore reducing instances of production downtime.
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