The oil and gas sector always finds ways to save money, increase productivity and discover new source system reserves. To secure its future transfer functions, the global community is expanding on deeper ocean seismic data.
Permanent reservoir monitoring (PRM) is a seafloor-based technique that is increasingly becoming a component of a reservoir engineer’s toolset for effectively managing oil and gas operations.
The most frequent implementation of PRM systems is performing 3-dimensional earthquake velocity surveys at regular intervals, often six months to two years.
The length of time between seismic source surveys is flexible and determined by the signal-to-noise ratio characteristics of the reservoir under observation.
Since the seismic data monitoring system is updated in response to reservoir changes, this method has been proven technically successful when fluids are injected or generated from a field.
Using acoustic sensing PRM in the field has evolved into a vital geoscience and engineering endeavor with measurable outcomes. Whether this geothermal PRM market growth is sustainable is an open question. Many factors have prompted PRM seismic technology use.
Advanced Approach
For elevated wells operating under tougher conditions, such as higher temperatures and pressures, the operator may implement a permanent monitoring source system with better accuracy.
In these pore pressure situations, quartz gauges and optical sensors are utilized; the decision to supply service equipment depends on the nature of the signal propagation measurement and the quantity of data to be collected.
Due to their superior temporal variation measurement precision, quartz gauges are widely used in offshore subsea operations. Quartz gauges have always been trusted to provide accurate readings in high-pressure/high-temperature environments up to 150 °C.
Similarly, optical sensing systems are one of a kind because they allow for the dependable deployment of several point sensors and dispersed sensors over a single cable downhole.
During the circulation phase of an operation, when temperatures reach up to 300°C, these dependable sensors can be monitored nonstop to track any shifts in the reservoir’s heat.
Using this data, the operator may see how the well’s thermal profile develops over time. This offers information about the uniformity and efficiency with which steam is dispersed down the lateral.
Similarly, an optics-based pad system with many gauges spread out along a lateral and over multiple wells, all connected to a centralized data-gathering system on the pad, would be the best option for seismic surveys.
Combining distributed sensing with optical gauges in a single cable enables unprecedented high-resolution, in-situ downhole inspection. A system like this acts as a guardian for the reservoir, keeping tabs on how much each zone or well contributes to the overall output.
Cost and Trust
When considering a long-term solution for reservoir monitoring, operators do so in the same way they consider any other potential investment like fiber-optic cable in the field.
Expenses associated with the initial setup of the monitoring system include the purchase and installation of hardware and software. In addition, they include any necessary training for staff to get familiar with the system and effectively use the collected data.
Although data-gathering devices placed permanently at an established site are usually trustworthy, they might rack up maintenance and repair bills if they are not properly maintained and protected from the elements.
A robust vertical source motion data collecting system, data historian, and data visualization and analysis software tools make it feasible to handle and analyze continuous real-time well data.
Two-phase downhole flowmeters offer critical real-time, precise hourly well production allocation, while pressure/temperature gauges facilitate crucial drawdown management and sand control.
DTS sensors confirm leaks and detect other qualitative issues. The system gathers critical information for fuel lift tracking and handling to verify injection sites.
It also gathers thermal profiling for validation and flow connections for performance modeling.
Software
With remote seismic monitoring capabilities, users may operate and monitor permanent gauges from remote locations. This Windows PC program relies heavily on generic data transfer functions and user-friendly interface elements like menus and icons.
This program lets users see downhole gauge readings in real-time or examine previously saved data. Moreover, the data may be disseminated through seismic cable networks so that more people can use it.
These victories are crucial in breaking down the obstacles to wider industry adoption, especially as we go from the early adopter stage of the technology’s development to the mature stage.
These hurdles will continue to erode as new technological enhancements, such as smart travel time visualization and analysis systems, become available. Eventually, permanent tracking will be standard practice for most high-value wells.
