Al-Garadi, Karem (King Fahd University of Petroleum and Minerals) | Aldughaither, Abdulaziz (King Fahd University of Petroleum and Minerals) | Ba alawi, Mustafa (King Fahd University of Petroleum and Minerals) | Al-Hashim, Hasan (King Fahd University of Petroleum and Minerals) | Sibaweihi, Najmudeen (King Fahd University of Petroleum and Minerals) | Said, Mohamed (King Fahd University of Petroleum and Minerals)
Condensate banking has been identified to cause significant drop in gas relative permeability and consequently reduction of the productivity of gas condensate wells. To overcome this problem, hydraulic fracturing has been used as a mean to minimize or eliminate this phenomenon. Furthermore multistage hydraulic fracturing techniques have been used to enhance the productivity of horizontal gas condensate wells especially in low permeability formation. Even though multistage hydraulic fracturing has provided an effective solution for condensate blockage to some extent as it promotes linear flow modes which will minimize the pressure drops and consequently improves the inflow performance considerably. However, this technique is very costly, and has to be optimized to get the best long-term performance of the multistage fractured horizontal gas condensate wells.
In this paper, multiple sensitivity analyses were conducted in order to come up with an optimum multistage hydraulic fracturing scenario. In these analyses, our manipulations were focused mainly on the operational parameters such as fractures half length, fractures conductivity using compositional commercial simulator. CMG-GEM simulator was used to investigate the different cases proposed for applying multistage hydraulic fracturing of horizontal gas condensate wells. The investigation began with a base case scenario where the fractures half-length were fixed for all stages with equal spacing between them. Then, six more fractures half-length patterns were created by introducing new approach where the well performance was studied if they are in increasing trend away from the wellbore (coning-up), or in a decreasing trend (coning-down). Well performance is furtherly addressed when the fractures half-length arrangements formed parabolic shapes including both occasions of concaving upward and downward. Finally, the last two patterns illustrated the effect of having the fractures half-length arrangements both skewed to the left and right on well productivity.
The investigation of the effect of changing the multistage hydraulic fractures half-length distribution patterns on the performance of a gas condensate well was conducted and resulted in parabolic up distribution pattern to be the optimum pattern amongst the other tested ones. It results in the highest cumulative both gas and condensate production. It also maintains the gas flow rate and bottom hole pressure more efficiently. The parabolic up distribution pattern confirms that the majority of gas production was fed by the fractures at the heel and at the toe of the horizontal drainhole which is in agreement with the flux distribution along the horizontal well.
Abouzaid, Ahmed (Baker Hughes) | Thern, Holger (Baker Hughes) | Said, Mohamed (Baker Hughes) | ElSaqqa, Mohammad (Khalda Petroleum Company) | Elbastawesy, Mohamed (Khalda Petroleum Company) | Ghozlan, Sherin (Khalda Petroleum Company)
The evaluation of logging data in shaly sand reservoirs can be a challenging task, particularly in the presence of accessory minerals such as glauconite. Accessory minerals affect the measurements of conventional logging tools, thus, introducing large uncertainties for estimated petrophysical properties and reservoir characterization. The application of traditional Gamma Ray and Density-Neutron crossover methods can become unreliable even for the simple objective of differentiating reservoir from non-reservoir zones.
This was the situation for many years in the glauconite-rich Upper Bahariya formation, Western Desert, Egypt. Formation evaluation was challenging and the results often questionable. Adding Nuclear Magnetic Resonance (NMR) Logging While Drilling (LWD) data in three wells changed the situation radically. The NMR data unambiguously indicate pay zones and simplify the interpretation for accurate porosity and fluid saturation dramatically. Key to success is NMR total porosity being unaffected by the presence of accessory minerals. NMR moveable fluid directly points to the pay zones in the reservoir, while clay-bound and capillary-bound water volumes reflect variations in rock quality and lithology.
Although the NMR total porosity is lithology independent, the presence of glauconite affects the NMR T2 distribution by shifting the water T2 response to shorter T2 times. This requires an adjustment of the T2 cutoff position for separating bound water from movable hydrocarbons. A varying T2 cutoff was computed by comparing NMR bound water to resistivity-based water saturation. The calibrated T2 cutoff exhibits an increase with depth indicating a decreasing amount of glauconite with depth throughout the Upper Bahariya formation. Based on these volumetrics, an improved NMR permeability log was calculated, now accurately delineating variations in rock quality throughout the different pay zones. In addition, viscosity was estimated from the oil NMR signal. The estimated values match the expected values very well and illustrate the potential of NMR to indicate viscosity variations.
Many of these results are available today already in real-time by transmitting NMR T2 distributions to surface while drilling. Besides the application for formation evaluation, the data can be used to initiate optimized side-tracking and completion decisions directly after finishing the drilling operations.