Water flooding is performed in unconsolidated sand reservoirs for pressure support, improved oil recovery, or for produced water disposal. Injection in these formations leads to “fracture” propagation due to formation plugging by solid impurities in water, even in multi-Darcy sand. This paper addresses the questions of soft sand injectivity and fracturing in the context of a study carried out for a particular field in offshore Nigeria. Water flooding has been performed in this field since late 2005 for pressure support and productivity improvement. Through the analyses of pressure falloff (PFO) data from a number of injectors we have established that indeed long “fractures”, in the order of 10's or possibly over 100 meters, could be induced in the multi-Darcy sand. These conclusions have been verified through injectivity analyses and fracture propagation modeling. Nevertheless, the available data suggest that for some wells sand production, wellbore fill and near-wellbore plugging contribute to severe injectivity decline.
Many oil reservoirs both onshore and offshore comprise unconsolidated or poorly consolidated sand. These are typically characterized by high permeability, in the order of several Darcies. Producing these formations requires water or polymer injection to support the pressure, displace the oil towards the producers, avoid or reduce compaction, and in some cases to dispose of the produced water. Depending on the water source, the injection fluid could contain significant quantities of suspended solids, in the order of several parts per million to 10's of ppm by volume, which tend to plug the sand face and reduce injectivity. The particle sizes could be in the order of 1 to 10 µm. While the water might be filtered to remove the larger particles, fine filtering is both expensive and not always effective due to equipment performance. To maintain injectivity in the presence of sand face plugging and formation damage, the injection pressure must be in excess of the formation parting pressure in order to induce fractures. Under this scenario as the existing fracture face is plugged by solid impurities, new fracture surfaces would be generated at the tip to facilitate further injection. Injecting under fracturing conditions could have a number of drawbacks, which include possible loss of containment and of flow conformance. Fractures propagating into the caprock or into the underburden could connect to other reservoirs and, in extreme cases, even connect to the surface. From a production perspective, the fracture length should be limited to onethird of the distance between the injector and producer for good conformance. From these discussions it is clear that knowing the fracture geometry and the injection pressure is paramount to optimizing the injectivity. During the last couple of decades a number of research projects have been carried out to address the issues of injectivity and “fracturing” in unconsolidated sand [1-6]. Although the investigations have focused on several types of field activities, including cuttings re-injection, frac-packing, produced water re-injection, and water and chemical flooding for EOR, several common observations and conclusions are reached that we summarized in [7].
