As fracturing materials, fracturing fluid and proppant are two very important parameters in doing hydraulic fracturing design. The combination of fractuirng fluid and proppant selection is the main focus and determinant of success in the hydraulic fracturing process. The high viscosity of the fracturing fluid will make it easier for the proppant to enter to fill the fractured parts, so that the conductivity of the fractured well will be better and can increase the folds of increase (FOI) compared to fracturing fluid with lower viscosity (Economides, 2000). This research was conducted by using the sensitivity test method on the selection of fracturing fluid combinations carried out at the TX-01 well with various sizes of proppants (namely; 12/18, 16/20, and 20/40 mesh) with the proppant selected being ceramic proppant type carbolite performed using the FracCADE simulator. Fracturing fluid was selected based on its viscosity, namely YF240OD and PrimeFRAC20 fluids with viscosity value of 4.123 cp and 171.1 cp, with a fixed pump rate of 14 bpm. The results showed that the combination of high-viscosity fluids (PrimeFRAC20) and 16/20 mesh proppant size resulted in a greater incremental fold (FOI) between the choice of another combination fracturing fluids and proppant sizes, namely 6.25.
Predictability and consequential safety of jackup rigs during installation and removal remain non-trivial issues for the industry despite larger deployment of jackup rigs and operations in emerging frontier regions with more complex soil conditions. Jackup foundation hazards such as unpredicted leg penetration, rapid leg penetration, punch-through, spudcan-footprint interaction and leg extraction difficulties continue to occur in spite of the industry stepping up efforts to better control of the risks. Apart from improvements of the installation guideline and practice within the industry as well as implementation of proper site specific assessments, safer performance of jackup rigs may be achieved through advancement in jackup instrumentation technology. In the present paper, a new instrumentation technology integrated with jackup rigs is proposed to assist the jackup operators in making decision and taking measures to prevent or mitigate potential geotechnical hazards, particularly punch-through.
Drilling of Well X-1 in the North Sumatra Basin at a depth of 2887-3186 m TVD occurred partial loss, and caving at a depth of 500-1650m TVD. To overcome this problem, it is necessary to use the safe mud window concept. Drilling mud density planning must be greater than the pore pressure and shear failure gradient but not more than the minimum horizontal stress and fracture pressure. The purpose of this paper is to make an accurate subsurface pressure analysis and to overcome problems caused by the mud weight planning errors used based on the safe mud window, and can be used as a reference for further drilling of wells that have field conditions and stratigraphy such as the Well X-1. In conducting safe mud window analysis, there are several parameters that need to be estimated in order to make a safe mud window, namely formation pressure, formation fracture pressure, minimum horizontal stress, maximum horizontal stress, vertical stress / overburden pressure, and shear failure gradient. From the results of the safe mud window on Well X-1, the actual mud weight data used during drilling is entered. After being analyzed, at a depth of 500-1050 m TVD caving occurs because the density value used is smaller than the shear failure gradient, while at a depth of 1050-1600m there is kaolinite mineral which causes caving. At a depth of 2829-3281 m TVD the density value is greater than minimum horizontal stress (SHmin). Here, caving occurs if the density value used is smaller than shear failure gradient and partial loss occurs if the density used is greater than SHmin. Based on the safe mud window, the optimal mud weight for drilling at a depth of 36-354.2 meter on a 20” route is 9.2-9.4 ppg. At a depth of 354.2-948 meter on a 16” route is 14.49-15.33ppg. At a depth of 948-1619 meter on a 13 3/8” route is 15.45-17.65ppg. At a depth of 1619-2829 meter on a 9 5/8” route is 17.36-17.76ppg. At a depth of 2829-3281 meter on a 7” route is 16.57-16,7ppg. And at a depth of 3281-3796.1 meter is 13.49-13.74ppg in order to avoid partial loss and caving problems.
The “CJ” field is a gas field located in the South Sumatra Basin with a reservoir located in the Basalt Telisa Limestone (BTL) formation. This gas field consists of 3 wells namely Well GTA-1, GTA-2, and GTA-3 which produced from 1951 to 1991. In 1991 the three wells were suspended and will be reopened in 2021 due to requests from buyers for 10 years. The research method used is to collect data consisting of data on reservoir, production, and physical properties of the gas. The next step is to calculate the value of the gas formation volume factor and Z-factor with various pressures. Next, determine the type of drive mechanism using the Cole Plot method. After knowing the type of drive mechanism, you can determine the current OGIP value using the material balance method. If the OGIP value is known, the next calculation is the Recovery Factor (RF), Ultimate Recovery (UR) and finally the value of Remaining Reserve (RR). Based on the calculation, the current OGIP value obtained by the material balance method with P / Z vs GP plots is 83.46 BSCF, Recovery Factor of 80.223%, Ultimate Recovery of 66.96 BSCF, and remaining gas reserve 15.45 BSCF. From these results, the maximum reserve value that can be produced to the surface for 10 years is 4.2325 MMSCFD. So that "CJ" Field is able to supply gas every day of 4.2325 MMSCFD or less than 4.2325 MMSCFD for 10 years.
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