Thru-the-bit logging delivers unconventional insights

Summary

ThruBit™ through-the-bit logging services helped create high-resolution image logs for analyzing natural fracture patterns and structural dip changes. Multiple stimulation scenarios were conducted to determine the best proppant concentration to achieve the desired results.

Objective

A US operator was having issues matching production in adjacent wells. The reservoir area was tectonically complicated, with high variation in the formation facies. To gain better insights, the operator wanted to examine the impact of natural fractures on the intended hydraulic stimulation design and determine whether to avoid these fractures—or target them to improve conductivity and producibility while lowering water production.

Results

Using the ThruBit Quanta Geo service, the operator was able to create high-resolution borehole image logs that provided direct observation of the natural fracture distribution. Structural dips measured precisely from the borehole image enabled a robust structural model to be built that showed local structural dip changes throughout the lateral. 3D far-field events mapped using ThruBit Dipole™ through-the-bit acoustic service helped identify another key attribute of natural fractures: their extension away from the wellbore in length and height.

$Image log showing different fracture types: conductive (blue) and resistive (cyan).$

ThruBit Quanta Geo™ through-the-bit photorealistic reservoir geology service provided imaging of different fracture types, with conductive fractures shown in blue and resistive fractures traced in the lighter cyan color.

A 3D discrete fracture network (DFN) model was built using input from the borehole images and acoustic far-field maps. A more realistic picture was obtained, honoring the true subsurface complexity.

$A snapshot from the 3D DFN model based on two principal natural fracture systems.$

A snapshot from the 3D DFN model based on two principal natural fracture systems, honoring the actual orientation and density distributions observed directly from the borehole images. Natural fracture length is constrained in the model based on the 3D far-field mapping of fracture extension along the lateral. Fractures were observed up to 90 ft away from the wellbore.

Finally, through the Kinetix Frac™ integrated fracturing stimulation software, multiple stimulation scenarios were used to examine which job size and proppant concentration would achieve the designed stimulated reservoir volume (SRV) and half-length at optimum cost.

The figure below shows the full interaction of the hydraulic fractures (pink color) and the natural fractures from the DFN model, with different colors representing the combined 2D multilayer. In this figure, two different scenarios are displayed representing the base pump schedule (left) versus an upsized pump schedule (right) using an extra 20% proppant and a higher overall rate of 7 bbl/min per cluster. The result shows that the upsized pump schedule creates more fracture area from stage 10 toward the toe of the well due to enhanced interaction of the slurry with the conjugate natural fractures as modeled, based on the image and 3D far-field data.

Analysis shows the base design (left) versus an upsized pump schedule (right).

Results of the analysis from the ThruBit FMI microimager showing the base design (left) versus an upsized pump schedule (right) using an extra 20% proppant and a higher overall pumping rate.