No abstract

In the Permian basin, Spraberry Trend is one of the formations that markedly contribute to the unconventional shale production in the U.S. lately. Unusual shale reactivity was encountered while drilling several horizontal wells, leading to wellbore instability issues. Consequently, shakers’ screens blockage increased the mud losses and drilling time, leading to an increased non-productive time (NPT). This paper addresses the challenges and causes of the formation instability issues resulted from shale interaction with the used drilling fluid and presents the timely actions taken to mitigate such problems. During the drilling operation, several rock samples were collected at different depth intervals from the shale shaker. Rock samples were analyzed to identify the clay and minerals contents in the formations. The collected samples were first cleaned to remove the mud, dried, ground, and then characterized by an X-ray diffraction test (XRD) and microscopic imaging. After identifying the possible reasons for the wellbore instability, several timely actions were taken to mitigate this issue. These actions include: 1) increasing the emulsion stability, 2) increasing the water phase salinity (WPS), 3) decreasing the water phase volume, 4) adding wetting agent, 5) using wider screens for the shaker, and 6) controlling drilling parameters such as weight on bit and rotational speed. Afterward, wellbore stability, well control problem indicators, and drilling fluid properties, especially rheology, were closely monitored to identify any subsequent or unusual events. The geological and mineralogy studies show that the drilled formation contains high smectite and illite clay content, up to 49%, which was believed to be the main reason for the unusual shale reactivity. Replacing the existing screens (200 API) with wider screens (160 and 140 API) showed an insignificant effect in mitigating the screens blockage. The adopted method of reducing the rate of penetration (ROP) and increasing the circulation time helped significantly alleviate the screens blockage by reducing the cuttings production and giving more time for hole cleaning. Furthermore, the optimal hole cleaning successfully increased the formation's stability. Adding a wetting agent to the drilling mud did not impact the cuttings aggregations; however, it led to a decrease in the rheological properties; thus, adding more concentration of the viscosifier was required to maintain the fluid rheology. Increasing the water phase salinity (WPS) to over 230k ppm and the emulsion stability to over 700 mV was considered the backbone of the treatment plan that significantly resolved the issue by inhibiting the clay. Eventually, the critical considerations were pointed out.

The conventional rock physics models used for interpretation of resistivity measurements (e.g., Archie’s model) need to be calibrated using core measurements. This becomes challenging when core measurements are not available or significant vertical variation in rock types and pore structure is commonplace. Conventional models also assume homogeneous pore structure and uni-modal pore-size distribution. To overcome these challenges, we introduce a new workflow for water/hydrocarbon saturation assessment, in which model parameters are geometry related and can be estimated from analysis of the pore structure. Such workflow enables reliable interpretation of resistivity measurements in the presence of complex multi-modal pore structure. Furthermore, we investigate the consistency of the estimated model parameters (i.e., electrical constriction factor and tortuosity) in the pore-scale domain through the same rock types, for the purpose of developing a workflow for field applications. We first obtain high-resolution pore-scale computerized tomography (CT) images from rock samples in the same rock type and quantify pore-network characteristics (e.g., constriction factor, pore- and throat-size distributions) of the samples at different water saturation levels. Image analysis is used to obtain geometrical constriction factor. We obtain electrical resistivity of the samples through numerically solving Maxwell’s equations, which is used as an input in the introduced model. We successfully applied the introduced method to pore-scale images from three carbonate formations. We verified the consistency of the obtained parameters in the pore-scale domain by applying the method in other rock samples of the same rock type. Results demonstrated consistency in estimated electrical constriction factors and tortuosity values in each rock type. We observed variation of model parameters in different rock types. The introduced method successfully captured the variation of the pore structure within the formation and honored the geometrical heterogeneity of the complex carbonate rocks. Finally, we used the new workflow and Archie’s model to estimate water saturation. The new workflow enhanced water saturation estimates by 30% compared to Archie’s model with default parameters (i.e., a=1 and m=n=2). The outcomes of this paper can potentially minimize core-based calibration efforts for well-log-based water saturation assessment in rocks with complex pore structures such as carbonates. The introduced rock physics model captures the complexity of pore-network geometry and rock fabric and converged toward a more mechanistic model where most parameters have physical and geometrical meaning. The results are promising for enhanced assessment of water saturation in carbonate formations with minimal calibration efforts.