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The Colombian Caribbean region has become an important exploratory target, and recent discoveries confirm its potential as a gas province to overcome the expected near-future gas deficit. A petrophysical and dynamic characterization workflow was implemented for this challenging deepwater play, where the depositional environment is the result of turbidity current processes. The reservoirs consist mostly of thin to very thin sand layers, corresponding mainly to the Ta, Tb, and Tc divisions of the Bouma sequence as observed in the cored intervals. Bouma divisions Td and Te are related with the lowest rock quality and represent the nonreservoir intervals. The greatest challenge in the characterization of this particular reservoir is the vertical resolution, given the very low thickness of the layers, which becomes very difficult to detect using standard resolution logs. Thus, tomography images, resultant CT-scan curves, and their integration with routine and special core analyses were used to reveal the true nature of this complex reservoir. The proposed methodology focuses on the integration of routine and special core analysis for the petrophysical and dynamic characterization of the reservoir, where the pore-throat-radius distribution from high-pressure mercury injection becomes the basis of the differentiation between what is considered reservoir and what is not. Pore-throat radius estimated from high-pressure mercury injection (R35) correlates extremely well with textural features and clay content in the rock; therefore, this parameter (R35) was used to define the different classes for rock typing. The approach taken was to develop a multilinear regression model of R35 as a function of very high-resolution tomography outputs in the cored zones and then see how it may be extrapolated to the uncored zones using available high-resolution logs. Special petrophysical analyses, such as NMR low field, porous-plate capillary pressure, electrical properties, and relative permeability curves (steady state), showed correlation with the defined rock types and, in turn, allowed for a determination of the gas accumulation potential of the area. Finally, rock and fluid (dry-gas) properties have been used to build a single-well radial model to design initial well tests (DST) and predict production performance from each interval (selective tests). The simulation model represents the lateral and vertical heterogeneity related to the geological environment (turbidites). The final results have defined the flow and shut-in times during tests to optimize the budget.
Hou, Yanan (China University of Petroleum (Beijing)) | Peng, Yan (China University of Petroleum (Beijing) (Corresponding author) | Chen, Zhangxin (email: email@example.com)) | Liu, Yishan (University of Calgary and China University of Petroleum (Beijing) (Corresponding author) | Zhang, Guangqing (email: firstname.lastname@example.org)) | Ma, Zhixiao (China University of Petroleum (Beijing)) | Tian, Weibing (China University of Petroleum (Beijing))
Summary Pulsating hydraulic fracturing (PHF) is a promising fracturing technology for unconventional reservoirs because it could improve the hydraulic fracturing efficiency through inducing the fatigue failure of reservoir rocks. Understanding of the pressure wave propagation behavior in wellbores and fractures plays an important role in PHF optimization. In this paper, a transient flow model (TFM) was used to describe the physical process of pressure wave propagation induced by PHF, and this model was solved by the method of characteristics (MOC). Combination of the TFM and MOC was validated with experimental data. The impacts of controlling factors on the pressure wave propagation behavior were fully discussed, and these factors include the frequency of input loading, an injection mode, an injection position, and friction. More than 10,000 sets of pressure wave propagation behaviors in different scenarios were simulated, and their differences were illustrated. In addition, the generation mechanisms of different pressure wave propagation behaviors were explained by the Fourier transform theory and the vibration theory. The important finding is that there is resonance phenomenon in the propagation of the pressure wave, and the resonance frequencies are almost equal to the natural frequencies of a fluid column. As a consequence of resonance phenomenon, the amplitudes of bottomhole pressure (BHP) and fracture tip pressure will increase sharply when the input loading frequency is close to the resonance frequency and less than 5 Hz; otherwise, the resonance phenomenon will disappear. Furthermore, an injection mode can alter the resonance frequency and the amplitude and frequency of the induced pressure wave. In addition, a friction effect can significantly decrease both the resonance frequency and the resonance amplitude. These findings indicate that the optimized input loading frequency should be close to the natural frequency of a fracturing fluid in a wellbore to enhance its BHP.
Summary Decline curve analysis (DCA) has been the mainstay in unconventional reservoir evaluation. Because of the extremely low matrix permeability, each well is evaluated economically for ultimate recovery as if it were its own reservoir. Classification and normalization of well potential is difficult because of ever-changing stimulation total contact area and a hyperbolic curve fit parameter that is disconnected from any traditional reservoir characterization descriptor. A new discrete fracture model approach allows direct modeling of inflow performance in terms of fracture geometry, drainage volume shape, and matrix permeability. Running such a model with variable geometrical input to match the data in lieu of standard regression techniques allows extraction of a meaningful parameter set for reservoir characterization, an expected outcome from all conventional well testing. Because the entirety of unconventional well operation is in transient mode, the discrete fractured well solution to the diffusivity equation is used to model temporal well performance. The analytical solution to the diffusivity equation for a line source or a 2D fracture operating under constrained bottomhole pressure consists of a sum of terms, each with exponential damping with time. Each of these terms has a relationship with the constant rate, semisteady-state solution for inflow, although the well is not operated with constant rate, nor will this flow regime ever be realized. The new model is compared with known literature models, and sensitivity analyses are presented for variable geometry to illustrate the depiction of different time regimes naturally falling out of the unified diffusivity equation solution for discrete fractures. We demonstrate that apparent hyperbolic character transitioning to exponential decline can be modeled directly with this new methodology without the need to define any crossover point. The mathematical solution to the physical problem captures the rate transient functionality and any and all transitions. Each exponential term in the model is related to the various possible interferences that may develop, each occurring at a different time, thus yielding geometrical information about the drainage pattern or development of fracture interference within the context of ultralow matrix permeability. Previous results analyzed by traditional DCA can be reinterpreted with this model to yield an alternate set of descriptors. The approach can be used to characterize the efficacy of evolving stimulation practices in terms of geometry within the same field and thus contribute to the current type curve analyses subject to binning. It enables the possibility of intermixing of vertical and horizontal well performance information as simply gathering systems of different geometry operating in the same reservoir. The new method will assist in reservoir characterization and evaluation of evolving stimulation technologies in the same field and allow classification of new type curves.