First Application of High Density Fracturing Fluid to Stimulate a High Pressure and High Temperature Tight Gas Producer Sandstone Formation of Saudi Arabia

Abstract

Abstract Recently Saudi Aramco and international companies started an aggressive gas exploration campaign in tight gas sandstone formations. In most of the cases the prospective tight gas producing zones were discovered at a depth below 20,000 feet where the stress and temperature are extremely high and the reservoir permeability conditions are low; being necessary in all cases to fracture stimulate each horizon to define the fluid and evaluate productivity. The extreme stress and temperature conditions are actually one of the main challenges to perform fracture stimulations on this type of formation, this because the fracturing fluid needs to be stable, induce minimum damage and have good proppant transport capabilities at high temperature conditions. As a part of the referenced exploration activity in the first quarter of 2008 Saudi Aramco has the challenge to perform a proppant fracture stimulation in a deep tight gas on shore sandstone formation where the temperature and stress conditions (375° F and 1.1 psi/ft at 20,000 feet) exceeded the working pressure capability of the available equipment and the existing fracturing fluids application limits. To answer the referenced challenges and knowing that 20,000 psi fracturing equipment is not available in the area an extensive laboratory evaluation was done to design a new high density fracturing fluid. After a lengthy laboratory evaluation, we were able to select a regional supplier for the 1.48 specific gravity (12.3 lb/gal) heavy brine used as the base fluid and prepare a user friendly cross linked fluid for the referenced field application. The new fluid system was successfully mixed and pumped in the field enabled the treatment of the well through lower surface treating pressure with conventional 15,000 psi equipment, lower horsepower requirements, and a safer work environment. The paper summarizes the well conditions, extensive fluid qualification testing, procedures, and specially learned lessons during the referenced first field application of the new fracturing fluid system. Introduction As Saudi Arabia increases their demand for natural gas inside the Kingdom, ongoing reservoir targets are moving increasingly to more challenging reservoirs which exhibit low permeability of <0.01 md. Reservoir pressure ranges from low or can be extremely high (11–13,000 psi) and the high temperature makes obtaining reservoir data increasingly difficult due to tool limitations. Two particular formations which have recently received attention is the Sarah and Mid Qusaiba formation. These two reservoirs have been penetrated over 25 times in Ghawar and western Rub' Al Khali areas by Saudi Aramco and the International Oil Companies. Reservoir quality is typically moderate to poor (5–15% porosity); natural fractures are thought to significantly enhance deliverability in wells. Recently hydraulic fracturing was included in the testing of these formations which resulted in short term rates of 3–5 mmscfd. Hydraulic fracturing these formations are increasingly challenging due to mechanical limitations on the completion assembly and surface equipment. Maximum surface pressure limitations of 15,000 psi with a maximum bottom hole pressure limitation required the use of 12.3 lb/gal sodium bromide (Nabr) brine. Heavy brines have been successful in the deep Gulf of Mexico frac packing however they have never been applied to a tight gas reservoir. Development of this fluid was targeted to local material resources, fluid stability at 375º F temperature, proppant transport capability, and minimal formation damage. The new fluid was extensively tested to ensure it would perform as required in the field.