The Jurassic carbonate reservoirs in Kuwait are deep, characterized with extremely low porosity and permeability. The temperature of these reservoirs ranges between 250–300ºF. High production from these types of reservoirs will be possible if the oil filled fractures can discharge into large connected fractures during drawdown. Hence, these reservoirs are well sited for fracture stimulation to be exploited properly.
Fracture acidization of a deep HTHP exploratory well producing from limestone reservoir was performed successfully without any operational problem. The well was drilled to a depth of above 16,000 ft using high density oil-based mud (OBM). The well was tested in three intervals out of which the middle section produced high API gravity oil with gas. Initially, the well flowed at low rates but little increase in production was observed after matrix stimulation with emulsified acid. Lack of flow channels in the matrix was indicated by the continuous increase in bottomhole pressure during long shut-in period with a consistent drawdown pressure of 8,000 psi.
The low production of the well was investigated using borehole image logs, mud logs, daily drilling reports and core examination study. The findings of the study combined with data of the offset wells prompted fracture acidizing treatment. The well was fracture acidized using emulsified acid due to which the oil and gas production increased by several folds. Prior to the main fracturing treatment a step rate test, using 2 wt% KCl brine with surfactant, was conducted to determine reservoir parameters such as fracture extension pressure, fracture closure pressure and instantaneous shut-in pressure.
The paper highlights the usefulness of old data in deciding and designing the fracturing treatment to enhance reservoir deliverability. Additionally, a procedural mechanism for the selection of stimulation techniques, acid or proppant, in deep limestone reservoirs is discussed in this paper.
Introduction
Massive exploratory activities are in progress in Jurassic carbonate formations in north Kuwait at a depth of above 16,000 ft. Drilling in deep reservoirs has always been a challenge with operational considerations. If the reservoir quality is low the challenge will be compounded with the uncertainty of flow of reservoir fluids to surface.
Drilling in deep reservoirs necessitates the use of high density muds. Usually, when mud densities go high, the choices of least damaging drill-in fluids will become narrow. Achieving high mud densities without increasing solid content will be almost impossible unless high cost clear brines are used. The use of high cost formate or halide brines in fractured reservoirs will be a concern due to the risk of potential losses of these brines into the formation. In such scenarios drilling fluids with barite as a weighting material are typically used to maintain the required density to control downhole pressures. Some other weighting materials, heavier than barite, such as manganese tetroxide and ilmenite are also reported to be used in high density drilling fluids (Nicora et al. 2001).
Drilling fluids exert great influence on well productivity in terms of induced formation damage (Goode and Stacy 1984). For drilling the pay/target zone, selection of appropriate drilling fluid is most important and this becomes highly significant in HTHP drilling and completion (Svela and Wennberg 2006). Drilling in HTHP environment with increased depths at temperatures above 250oF poses several challenges on the selection of mud type. Normal water-based muds (WBM) and OBM or emulsion muds cannot be simply used in these applications as the stability of fluid loss control polymers and other ingredients will be at stake, wheras the increased quantity of barite potentially leads to sagging.
