Optimization of Infill Well Placement in Clastic Reservoirs of Toma South Oilfield

Deep beneath the surface of the Earth, oil does not always sit in a single, uniform pool waiting to be pumped out. Instead, it often resides in layers of sandstone, a type of rock formed from ancient grains of sand that were transported by rivers and wind and then cemented together over millions of years. These rock layers are rarely perfect; they are full of variations in how tightly the grains are packed and how easily fluids can move through them. In many oil fields, the initial drilling and pumping methods leave behind pockets of oil that the original wells cannot reach, trapped in these complex, uneven layers. This is particularly true in the Muglad Basin of South Sudan, where the Toma South oilfield has been producing since 1999. While the field has been productive, the natural variations in the rock have left a significant amount of oil untouched, hidden behind barriers of less permeable rock or in thin layers that standard vertical wells simply cannot touch effectively.

The challenge for engineers is to find a way to reach this remaining oil without wasting money on wells that might fail or produce too much water. In mature fields like Toma South, the pressure that pushes oil to the surface has naturally declined, and water has begun to rise, making it harder to extract the valuable black gold. To solve this, a researcher named J. Junior Rier Mayek from Heriot-Watt University set out to find the best way to place new wells, known as infill wells, into the ground. These are not the first wells drilled in a field, but rather additional ones placed strategically between the existing ones to drain the oil that was previously missed. The goal was to determine not just where to drill, but what kind of well to drill—vertical, horizontal, or directional—and whether the extra cost of these advanced techniques would be worth the extra oil they could produce.

To answer these questions, the researcher built a detailed digital twin of the entire oilfield. Using specialized computer software, they combined geological maps, seismic data that acts like an X-ray of the ground, and decades of production history from the existing wells. This virtual model allowed them to simulate how the oil and water move through the rock over time. Before trusting the model, they tested it against real-world data from the past, checking to see if the computer's predictions of pressure and water levels matched what actually happened in the ground. Once the model proved accurate, the researcher used it to run several different scenarios. They simulated what would happen if they did nothing and simply let the existing wells continue to produce until they stopped being profitable. They also simulated drilling new vertical wells, which go straight down, as well as horizontal wells, which turn and run sideways through the rock layers, and directional wells, which angle toward specific targets.

The results of these simulations revealed a clear winner. While doing nothing would eventually yield a recovery of about 50.2% of the oil in place, adding new wells could significantly improve that number. The study found that drilling vertical wells would help, recovering an additional 3.5% of the oil, but they were most effective only in the thicker, simpler layers of the reservoir. Directional wells offered a middle ground, recovering 4.2% more oil by reaching around faults and structural edges where oil had been trapped. However, the most successful strategy involved drilling horizontal wells. By running these wells sideways through the thin, complex layers of rock, the researchers found they could recover an additional 4.8% of the total oil, bringing the total recovery factor up to nearly 55%. This approach was predicted to add 17.3 million stock tank barrels of oil to the field's production by the year 2028.

Beyond just the amount of oil, the study also looked at the financial reality of these options. Drilling horizontal wells is more expensive upfront than drilling straight down, but the simulation showed that the extra oil they produce makes them the most profitable choice. The analysis calculated that this strategy would generate a net present value of $215.46 million, with a return on investment of 29% and a payback period of just 2.5 years. In contrast, simply trying to pump more water out of the existing wells to get more oil out was found to be less efficient, as the cost of handling the extra water would eat into the profits. The study also highlighted that the best spacing between these new wells is about 750 meters, which allows them to drain the oil effectively without interfering with each other.

The final recommendation from this research is to proceed with drilling six horizontal wells in the most promising areas of the Toma South field, specifically targeting the thin, oil-rich layers that have been missed so far. This should be paired with optimizing the pumps in the existing wells to handle the water better. While the study acknowledges that drilling these complex wells carries risks and requires precise technology to guide the drill bit underground, the simulations suggest that the reward is substantial. By using advanced computer modeling to guide these decisions, the operating company can maximize the amount of oil recovered from the field, ensuring that the resource is used efficiently and contributing to the economic growth of South Sudan. The work demonstrates that even in an aging oil field, careful planning and the right technology can unlock significant value that was previously out of reach.