A Case Study of Using a Specially Formulated Fracturing Fluid to Hydraulically Fracture Ultra Deep Wells to Improve Water Injectivity

Abstract

Abstract A specially formulated fracturing fluid was selected to meet the operational requirement for hydraulically fracturing high temperature, ultra deep water injection wells in Tarim Basin in China. This fracturing fluid is composed mainly of a low residue, low friction loss gelling agent XD, a high temperature zirconium-borate complex crosslinker, GCL, that is easy to break, and a non-damaging degradable particulate filtration control agent, MS-5. Application of the fluid system in wells that are among the deepest (5910 meters) hydraulically fractured wells in the world was successful, and significant improvement in water injectivity was obtained. The evaluation of the fracturing fluid system was conducted in the laboratory by using a dynamic filtration hydraulic fracturing fluid formation damage tester with cores taken from the formation to be fractured. Test results showed that a) MS-5 gives very effective filtration control; b) the friction loss of XD gels is only 20% of that of water; c) GCL can give more that 6 minutes of delayed crosslinking time; d) the variation of fluid viscosity at 170 s-1 for 120 minutes at 140 C is between 90 and 100 mPa-s; e) the fluid is shear healing; and f) the low residue of MS-5 after degradation gives the minimum damage to the target formation. All these characteristics contributed to the success of the fracturing operation, and to the improvement in water injectivity. Introduction A deep reservoir in Tarim Basin, China needed waterflooding to increase the formation pressure. However, difficulty was met in the water injection; no water could be injected, even at wellhead pressures up to 37 MPa. Hydraulic fracturing was necessary to improve water injectivity. It was a challenge to select a fracturing fluid system since there was no successful fracture of water injection wells in a depth of near 6000 m. Conditions in ultra deep well treatment usually include high formation pressure and temperature, small diameter tubings, high closure pressures, and low permeability of the formation. The high treatment pressure requires the use of a fluid system that has a minimum pumping friction pressure. The high closure pressures often require high strength proppants which are more difficult to transport than sand. Low formation permeability indicates the need for long propped fractures that have a high conductivity to achieve the desired production rate or injection rate. For water injection wells, the length of the propped fractures is limited by the fracture azimuth. If the azimuth is not in the desired direction, the longer the fracture, the faster the water will break through. Considering the formation characteristics, the operational characteristics, and the special requirements for water injection wells, the criteria for the selection of a fracturing fluid system were to have a fluid system that has low friction loss leading to a low pumping pressure, low fluid loss, and low damage to the formation. Also, a fracture that has high conductivity is essential. In the past, in the selection of temperature resistant, low friction hydraulic fracturing fluid systems, a water based, organometallically crosslinked fracturing fluid system was usually chosen. A high temperature borate crosslinked fluid system has also been reported. But those systems that can withstand temperatures above 140 C usually require a pH value of above 13. This high pH value will damage the formation of the reservoir. It is well known that an organometallically crosslinked fluid causes more damage to the conductivity of the propped fracture than a borate crosslinked fluid. Several methods have been recommended to improve the fracture conductivity of high temperature wells such as the use of unique breakers, and injecting multiple fluids (incorporate an organometallic crosslinked fluid followed by a borate crosslinked fluid). P. 271^