No abstract

Summary Lost circulation during the drilling of fractured formations is one of the most challenging engineering problems. Shape memory polymers (SMPs) have been used as lost circulation materials, but most of them are not resistant to high temperatures. In this study, a high-temperature-resistant thermal shape memory epoxy resin (SME) was synthesized by conducting an orthogonal experiment using the glass transition temperature (Tg) as an index. The Tg of the SME synthesized by using the optimum formula was 124℃. This SME had good thermal stability, and its compression and tension stresses were 94.2 and 58.8 MPa, respectively. In addition, the thickness swelling ratio (Rrc) of the SME was optimized by performing another orthogonal experiment, and the Rrc of the SME prepared by using the optimized formulation (OSME) was 78.8%. The OSME did not swell at 25–150℃ in water, brine, or base fluid. The total size reduction percentage of the OSME was 1.7% after aging at 150℃, whereas that of a nutshell was 10.7%, indicating that OSME particles had better compression and temperature-resistance performance. The shape memory ratio (Rc) of the OSME was 6, 70, and 100% at 80, 120, and 125℃ after being heated for 50 minutes, respectively, and it was fully activated in 5 minutes at 150℃. The breakthrough pressure of the plugging mud with or without the OSME was 15 MPa at 25, 80, 120, and 150℃ when plugging the wedge fracture model with an inlet/outlet width of 3/1 mm. However, when plugging the wedge fracture model with an inlet/outlet width of 5/2 mm, the plugging slurry with the OSME could withstand a pressure of 3, 5, and 15 MPa at 80, 120, and 150℃, respectively, and the plugging mud with conventional lost circulation materials could bear a pressure of below 3 MPa at 80, 120, and 150℃. These results indicated that the OSME had good plugging and thermosensitive performance. OSME particles matched better with the fracture size, owing to their elastic and shape memory performance at above Tg. They migrated and bridged in fractures, aggregated and filled the pore space with other lost circulation materials, and formed a dense plugging layer at above Tg. Thus, the synthesized SME is a promising material for plugging high-temperature fracture formations while drilling.

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^

The candidate wells are tight oil wells and most of the wells in the area have a low recovery rate of fracturing fluid after fracturing treatment. The lithology is glutenite with weak cementation and a high sensitivity tendency. This paper presents the process of sensitivity evaluation and fracturing fluid evaluation. Also, this paper introduces a customized and optimized clay control fracturing fluid wells in a highly sensitive reservoir. Per local national standard, traditional methods of swelling test (ST) and x-ray diffraction (XRD) were employed for qualitative formation cutting analysis. An innovative trial was then developed to evaluate cores quantitatively by water sensitivity. A clay stabilizer was then chosen to be used for the highly sensitive cores and regain permeability testing of the broken fracturing fluid was performed. Based on the analysis and evaluation, a customized treatment design was initiated for the hydraulic fracturing treatment. The qualitative evaluation showed the rock is highly water sensitive and the cores easily collapse because of weak cementation. No flow could be established during traditional core flow tests with brine. The newly developed method used kerosene as the working fluid to prevent the cores from contact with water or brine. The core flow tests resulted in a velocity sensitivity damage rate of 92%, which is considered as highly velocity sensitive. Accordingly, a special clay stabilizer was chosen to be used in the fracturing fluid and the permeability damage of the broken fracturing fluid is only 26.9%(Table 16). Field results have shown that the fracturing fluid recovery rate in treated wells is higher than the area average level and treated wells have significant oil production increase. The innovative clay control fracturing fluid and its field application reduces the influence of water and velocity sensitivity. The customized treatment with special clay stabilizer helps increase the recovery rate of fracturing fluid in reservoirs with severe clay stability and weak cementation issues.