Reservoir Recharacterization and Hydrocarbon Volume Re-estimate of Miocene D10/Ph-02 Sand, Phyl Field, Offshore Niger Delta

Deep beneath the waves of the Gulf of Guinea, in a region known as the Niger Delta, lies a complex underground world where oil and gas are trapped within layers of sand and rock. This area is one of the most productive oil provinces on Earth, yet it presents a unique challenge for geologists: the ground is not a solid, uniform block, but a shifting, fractured landscape shaped by millions of years of tectonic movement and river deposition. To find and extract oil here, scientists must build a mental map of the subsurface, piecing together clues from seismic waves that bounce off rock layers and from measurements taken inside deep boreholes. When a field stops producing, it is often because the map used to guide the drilling was incomplete or inaccurate, leaving valuable resources stranded or causing wells to fail. Understanding how to redraw these maps is essential for extending the life of mature oil fields and ensuring that energy resources are not wasted.

In the Phyl Field, an offshore oil field located in the middle to late Miocene section of the Niger Delta, production came to a halt in 2020. The field had been discovered decades earlier and had produced oil successfully for years, but the existing model of the reservoir had become unreliable. The team of researchers, led by geoscientists from the University of Lagos and engineers from Chevron Nigeria Limited, set out to re-examine the specific sandstone layer known as D-10/Ph-02. Their goal was to understand why the field had stopped working and to determine if there was still oil left to recover. They approached the problem by combining modern, reprocessed seismic data with detailed analysis of well logs, fossil records, and the history of how the field had produced oil in the past. This integrated approach allowed them to see the subsurface with a clarity that was not possible with the older data.

The researchers discovered that the underground architecture of the Phyl Field is far more intricate than previously thought. The reservoir is not a single, continuous pocket of oil but is broken up into separate compartments by a network of faults and ancient river channels. These features, including large, curved faults and deep, mud-filled canyons that formed millions of years ago, act as barriers that trap oil in specific zones. By reinterpreting the seismic images, the team identified a complex structure where the oil is held in a three-sided dip, bounded by faults on two sides and cut off by a canyon on the third. This realization explained why the old model failed; it had not accounted for these barriers, leading to incorrect assumptions about how the oil moved and where it was located.

With this new structural understanding, the team turned their attention to the quality of the rock itself. They analyzed the physical properties of the sandstone, measuring how much space existed between the grains to hold oil and how much of the rock was actually sand versus mud. The results were encouraging: the reservoir is of very high quality, with a high percentage of clean sand and excellent porosity, meaning it can hold a significant amount of fluid. However, the team also found that the boundary between the oil and the water sitting beneath it was not where the old maps said it was. By carefully comparing the electrical resistance of the rock and the density of the fluids in the wells, they determined that the oil-water contact was actually higher up in the formation than previously believed.

This shift in the location of the oil-water boundary had a profound impact on the volume of oil estimated to be in the ground. Because the contact was higher, the column of oil was shorter than the original model suggested, which reduced the total amount of oil initially in place. The revised estimate for the oil in the ground dropped from 18.13 million stock tank barrels to 13.10 million stock tank barrels. While this number is lower, it is considered a more accurate and realistic figure based on the new evidence. Crucially, this correction also changed the outlook for how much of that oil could be recovered. The team calculated that the recovery factor—the percentage of oil that can actually be brought to the surface—could improve significantly, rising from 28.8 percent to 45.4 percent. This means that even though the total amount of oil is less than originally thought, a much larger portion of it is now accessible.

The study also looked at the history of the well that was producing the oil, known as PH-02D. The data showed that the well had experienced sand production, where loose grains of rock were carried up with the oil, and water breakthrough, where water began to mix with the oil, reducing the efficiency of the well. These issues were consistent with the pressure depletion observed in the reservoir over time. Based on the new understanding of the reservoir's structure and fluid contacts, the researchers proposed a phased strategy to bring the field back to life. This plan includes drilling a new pilot well to test the updated model, followed by infill drilling to target the remaining oil pockets, and workovers on existing wells to control sand and manage water production.

The findings of this study demonstrate that even in mature fields where production has ceased, a fresh look at the data can reveal new opportunities. By integrating seismic, geological, and engineering data, the team was able to resolve uncertainties that had plagued the field for years. The work provides a clear path forward for the Phyl Field, suggesting that with the right interventions, production can be revived and the field's life extended. Furthermore, the methodology used here serves as a valuable example for other offshore fields in the Niger Delta and similar geological settings around the world, showing that a detailed, multidisciplinary approach is key to unlocking the remaining potential of complex reservoirs.