Stratigraphic Characterization of the Eagle Ford Shale to Identify the Best Landing Zone: A Semi-analytical Workflow

Placement of the horizontal well within the best landing zone is critical to maximize well productivity, thus identification of the best landing zone is important. This paper illustrates an integrated semi-analytical workflow to carry out the stratigraphic characterization of the Eagle Ford shale to identify the best landing zone. The objective of this work is twofold: 1) to establish a workflow for stratigraphic characterization and 2) to understand the local level variability in the well performance.To establish the workflow, we have used the production data, petrophysical information and regional reservoir property maps. As a first step of the workflow, we subdivided the Eagle Ford shale into nine smaller stratigraphic units using the wireline signatures and outcrop study. In the second step, we have used statistical methods such as linear regression, fuzzy groups and theory of granularity to capture the relationship between the geological parameters and the well performances. In this step, we identified volume of clay (Vclay), hydrocarbon filled porosity (HCFP) and total organic carbon (TOC) as key drivers of the well performance. In the third step, we characterized the nine smaller units and identified four stratigraphic units as good reservoirs with two being the best due to their low Vclay, high HCFP and high TOC content.Finally, we reviewed the well paths of four horizontal wells with respect to the best stratigraphic units. We observed that production behavior of these wells is possibly driven by their lateral placement. The better producing wells are placed within the middle of the best stratigraphic units whereas the poor wells are going out the best stratigraphic units. This investigation provides a case study that demonstrates the importance of integrating datasets to identify best landing zones and the suggested workflow can be applied to other areas and reservoirs to better identify targetable zones.

Unloading Frac Hits in Gas Wells: How Does the Nitrogen Injection Rate and Pressure Affect the Unloading Process?

The unconventional resources development has grown tremendously as a result of the advancement in horizontal drilling technology coupled with hydraulic fracturing. However, as more wells are drilled and fractured close to each other, frac hits have become a major challenge in these wells. The aim of this work is to investigate the effect of nitrogen injection flow rate and pressure on unloading frac hits gas wells in transient multiphase flow. A numerical simulation model was created using a transient multiphase flow simulator to mimic the unloading process of frac hits by injecting nitrogen from the surface through the annulus section of the well. Many simulation cases were created and analyzed to comprehend the effect of the nitrogen injection rate and pressure on the unloading of frac hits. The model mimicked real field data from currently active well in the Eagle Ford Shale. The results showed that as the nitrogen injection pressure increases, the nitrogen volume and the time to unload the frac hits decrease. On the other hand, increasing the injection rate of nitrogen will increase the nitrogen volume required to unload the frac hits. In addition, the time to unload frac hits will be decreased as the nitrogen injection rate increases. These results indicate that the time required to unload frac hits will be minimized if higher flow rates of nitrogen were utilized. Nonetheless, the volume of nitrogen required to unload the frac hits will be maximized. An important observation to highlight is that the operators can save money by reducing the time for injecting nitrogen. This observation was verified when increasing the injection pressure in the frac hit well in the Eagle Ford Shale, the time of injection was reduced 20%. This study presents the effects of nitrogen injection flow rate and injection pressure for unloading frac hits in gas wells. Due to the lack of published studies about this topic, this work can serve as a practical guideline for unloading frac hits in gas wells.

Characteristics of Seismicity in the Eagle Ford Shale Play, Southern Texas, Constrained by Earthquake Relocation and Centroid Moment Tensor Inversion

Analysis of earthquake locations and centroid moment tensors (CMTs) is critical in assessing seismogenic structures and connecting earthquakes to anthropogenic activities. The objective of this study was to gain insights into the seismotectonics of the Eagle Ford Shale play (EF), southern Texas, through relative relocation of earthquakes, assessment of CMT solutions, and investigation of the background stress field. Using Texas Seismological Network (TexNet) data from 2017 through 2019, we were able to relocate 326 earthquakes and obtain CMT solutions for 37 ML≥2.0 earthquakes. These earthquakes are located in the sedimentary basin and uppermost crust, with depths ranging from 2 to 10 km. The earthquake groups in the northeastern EF are linearly distributed along the Karnes fault zone, whereas the southern and western groups are spatially scattered around mapped or unmapped faults. CMT solutions identified 32 normal fault earthquakes and five strike-slip earthquakes. The orientation of the fault plane of most normal fault earthquakes is southwest–northeast, whereas the possible fault plane of the strike-slip fault is from north-northwest to south-southeast, which is roughly perpendicular to the normal faults. Normal and strike-slip faults in the EF are of high dip angles, with the dip angles of the most faults ranging from 60° to 80°. Stress inversion results show that the major orientation of maximum horizontal stress (SHmax) is southwest–northeast, with minor local stress-field rotations. We further estimated earthquake energy release in the EF region using moment magnitude from the CMT solutions, and the cumulative earthquake energy release curve reveals three notable increases in cumulative seismic moment, which occurred in January–July 2018 and January–March 2019, and May–August 2019. Whether these energy releases were caused by anthropogenic activities is a matter for further investigation.