Hydraulic Frac Stimulations in a Libyan Oilfield B A Case History

Abstract

Abstract Wintershall started in 1994 with the preparation of frac treatments. Between 1995 and 2004 eight wells were fractured. Only one frac was conducted in Libya in the mid 1970s and the challenge was to introduce this technology. Firstly, a service company had to be encouraged to provide the equipment, the service and logistics for chemicals and proppant. Secondly, the National Oil Corporation had to be convinced that application of this kind of technology would be feasible and beneficial for the development of a low-permeable reservoir. All wells in the subject field produce from a heterogeneous Lower Cretaceous Sandstone at a depth of about 12,000 ft. The drive mechanism is solution gas drive since the underlying aquifer was found to be inactive. Low porosities of 10 to 14 % and poor permeability ranging from 0.1 to 20 mD allow only a low to moderate production, which hampers the economics of a field development. Today, 80% of the production wells in this field have been successfully stimulated by hydraulic frac treatments. State-of-the-art real-time analysis was performed to evaluate and optimize the frac operation on the fly. Hydraulic frac simulation findings were compared to post-frac well test results obtained from pressure buildup analysis in order to crosscheck the outcome. About half of the cumulative oil produced to date can be assigned to the frac stimulations. However, they did not only help to improve the productivity of each well, but allowed us to produce longer above the bubble point and even permitted an optimization of production with bottomhole flowing pressures below the bubble point. Hydraulic prop fracs have successfully shown to be an appropriate means of reservoir management in this oilfield. Overview Geology. The subject field is located in the Hameimat Trough in the Southeast of the Sirte Basin (Fig. 1), and was discovered in 1970. The development started in 1993. The main productive formation is the so-called Upper Sarir Sandstone, which forms the uppermost layer of the Sarir Group. The Sarir Group consists of two sandstones layers (Upper and Lower Sarir Sandstone), separated by the Sarir Shale Member. The Upper Sarir Sandstones is well-consolidated sandstone, which can be described as deposits of an ephemeral fluvial system, with channels, sheet flood and interchannel sand flats (Fig 2). Thus, clean sandstone layers alternate with shale streaks. It was deposited in the Early Cretaceous (eventually Late Jurassic) age. The Field structure is a WNW - ESE trending Sarir arm (Fig 3). Its northwestern end is in contact with the Amal/Nafoora-Augila Basement High via a broad saddle. Reservoir Parameters. The Upper Sarir Sandstone in the oilfield is at a depth of 11,700 to 12,500 ft. The net pay is in the range of 130 to 400 ft; the porosity is 10 % to 14 %. Reservoir parameters and especially average permeability are improving from NW to SE, while higher pay heights have been drilled in the Northwest compared to Southeast. The permeability range is from tight (0.1 md) to fair (20 md). The main reservoir parameters are summarized in Table 1. Oil Properties. The oil is a light oil API gravity of about 42°. Due to paraffin and wax the pour point is high with about 100°F. Live oil viscosity is low, 0.35 cp at initial reservoir conditions. The oil properties are summarized in Table 2.