Abnormal decline in gas production rates and predicted ultimate recovery in many intermediate and predicted ultimate recovery in many intermediate and deep artificially stimulated gas reservoirs in South Texas are brought about by a rapid decline in bottom hole flowing pressures. The pressure drops occur due to crushing of sand proppants in the hydraulically created fractures. Additional factors contributing to the failure of the sand proppant are low reservoir permeabilities and high overburden pressures. permeabilities and high overburden pressures. Accelerated production rates intensify near-wellbore pressure drawdowns which induce extreme closure pressure drawdowns which induce extreme closure pressures on the proppants. pressures on the proppants. High-strength sintered bauxite proppants were introduced to the petroleum industry in late 1976 to provide fracture support under high closure pressure provide fracture support under high closure pressure conditions. They have been subsequently applied to fracture design in Vicksburg Sand, Edwards Limestone, Wilcox Sand, Frio Sand, and Sligo Limestone formations of South Texas.
Laboratory tests of the sintered bauxite proppant with formation core samples were conducted that proppant with formation core samples were conducted that demonstrated superior flow capacities to sand under the higher closure pressures existing under producing conditions.
Results as evaluated by various pressure response data and production histories indicate significant improvement in stimulation of these reservoirs due to the sintered bauxite proppant.
Exploration and development of natural gas along the South Texas Gulf Coast area has ventured more and more into deep, low permeability reservoirs in recent years. The increased demand for gas and the improvement of product prices have focused attention on gas reserves historically considered to be uncommercial or non-economical. As a result, completions have been made in formations where matrix permeabilities are in the microdarcy range. In permeabilities are in the microdarcy range. In addition, abnormal pressures are often encountered and have been measured as high as 0.93 psi/ft (21.04 kPa/m), mechanical risk is much greater due to drilling depths required to reach the formations, and drilling costs are extremely high.
One of the primary contributions to increased emphasis of exploration in low permeability reservoirs has been the technological advancements concerning massive hydraulic fracture stimulation. The ability to create and maintain an artificial avenue through which large volumes of reservoir fluid can flow to the wellbore has provided sufficient flow capacity, and in some cases, additional reserves to justify completion in low permeability reservoirs.
Evaluation of the performance of most reservoirs revealed that initial rates after fracturing exhibited significant increases over prestimulation capacity. However, it became evident shortly after going on production that several geopressured zones experienced severe and continuous decline in capacity following fracture stimulation. Consequently, projected estimates of ultimate gas recovery proved projected estimates of ultimate gas recovery proved disappointing in comparision to earlier expectations. Figure 1 is a graphical representation showing production rate versus time. The excessive production production rate versus time. The excessive production decline exemplified on Figure 1 is typical of the responses of many "tight" geopressured reservoirs seen in South Texas.
Analysis of pressure tests of numerous wells demonstrated that despite the fact that a well received a massive fracture stimulation during initial completion, the evidence provided by pressure transient evaluation indicated that severe deterioration of the fracture conductivity had occurred. In fact, some wells exhibited few or none of the characteristics typical of highly stimulated zones, and the more severe cases showed the flow capacity of the well resembled the capacity prior to fracture stimulation.
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