The objective of this study was to evaluate treatment distribution and fracture geometry in a multi-stage, multi-cluster fracture completion performed in a horizontal Eagle Ford well. Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS) data were acquired on the subject well. The DAS/DTS-observed fracture treatment distributions were then modeled in a three-dimensional fracture model in an effort to visually represent resultant fracture geometries. This process was used to evaluate the impacts on the resulting treatment distributions that occurred as a result of stress-shadowing between fractures. The ultimate goal was to understand the influence that adjacent fractures within a stage and adjacent stages have on fracture distribution, fracture geometry, and completion effectiveness. DAS/DTS data suggest a high level of interference between adjacent fractures. Interference between adjacent fractures within a given stage, and from adjacent fracture stages, results in a consistent geometric predominance for fracture growth in the most heel-ward perforation cluster. DAS/DTS results also indicate that an excessive number of perforation clusters, spaced closely together, magnify the negative effects of stress shadowing, and potentially diminish completion effectiveness. Operationally, the DAS/DTS data showed that the surface pressure response originally attributed to downhole diversion from particulate diverters was in fact not due to diversion. Once a dominate fracture was established in a given stage, it remained dominate throughout the entire stage even though two diverter drops per stage were incorporated into the treatment. Finally, the DAS/DTS data indicated that a significant portion (71%) of the stages experienced intra-stage communication. The large majority of this communication was due to plug leakage.

No abstract

The Anadarko Basin is located within a strike-slip faulting regime (SHMax>Sv>Shmin) which results in large, planar fracture geometries created during the hydraulic stimulation of low permeability formations. The Meramec formation is dominated by siltstones as part of a series of prograding, stacked clinoforms. The geomechanical properties and the regional stress regime are first order drivers in controlling fracture growth rates, size, and ultimately the drainage area. Net pressure and stress shadowing play a significant role in the design of cluster spacing, proppant selection, fluid selection, and resulting fracture geometry. This paper will review an operator’s case study designed to quantify stress shadowing and fracture net pressure using multiple bottomhole pressure gauges (BHPGs) in a horizontal, multi-stage stimulation in the Meramec formation of the Anadarko Basin. The case study will review the measurements taken from two permanently installed BHPGs placed along a horizontal wellbore during a hydraulic stimulation. The first BHPG is located at the toe of a horizontal wellbore being stimulated and is in communication with hydraulic fractures created during the first stage; the second BHPG is located near the heel of the same well being stimulated. The BHPG at the toe of the well is used to measure the poroelastic pressure responses generated as stages are completed uphole from the first stage. Optical fiber is analyzed to evaluate Near Wellbore (NWB) and far-field fracture interactions. The measurements have been integrated into a fracture simulator to calibrate the far-field stress during hydraulic fracture growth. Measured stress shadowing in this pilot allowed the authors to develop an equation that can be solved to estimate net pressure. The results are aligned with measurements obtained from DFITs in the area. Historically, net pressure and stress shadow values have been difficult to measure with high confidence due to various pressure losses between the wellhead and formation. Net pressure is a key for optimal cluster spacing design, and a critical matching parameter for hydraulic stimulation models, small errors in net pressure matches can have significant impacts in the resulting simulated fracture geometry. This paper will detail the integration of empirical data to advance an analytical model that quantifies net pressure and poroelastic stress transfer from a hydraulic fracture.

In development of the Bakken/Three Forks play, it is crucial to obtain a strong understanding of not just the hydraulic fracture geometry, but also what portion of those hydraulic fractures are conductive. If both parameters and their interactions are not fully understood, then development of the play could be severely compromised due to unoptimized well spacing and completion design. This study represents a two-pronged approach to better understand this interaction. The first step was to perform a Sealed Wellbore Pressure Monitoring (SWPM) test to gain an understanding of hydraulic half-length (Haustveit. et al. 2020). Then, a conductive interference test was performed to utilize Chow Pressure Group (CPG) to understand the conductive half-length (Chu et al. 2018). This paper will address the results from these two tests and how they can be coupled together to optimize the unique relationship between well spacing and completion design to maximize the value in development of the Bakken/Three Forks play or any play both new and mature. The SWPM test was successfully completed on a nine well zipper frac operation consisting of two pads (four well pad/five well pad) where four Middle Bakken and five Three Forks wells were stimulated. The SWPM results provided insight into the hydraulic fracture geometry of the stimulation in multiple scenarios of vertical and lateral separation, as well as various amounts of offsetting depletion. The next step in the analysis was performing a CPG interference test on the five well zipper pad. The CPG results provided insight into not just the initial conductive geometry, but a three month follow up test also showed how the conductivity of the fractures rapidly degrade over time. By coupling the SWPM and CPG analysis together, an operator can learn where hydraulic fractures are growing and what portion of those fractures are conductive. This project design of coupled SWPM and CPG provided multiple learnings: Hydraulic fractures for a well in either the Middle Bakken or Three Forks grow through the Lower Bakken Shale and create large geometries in both the landing and staggered zone Hydraulic growth is faster and geometry larger growing towards modern completion parents versus vintage completion parents A relatively small portion of the hydraulic geometry is conductive, and although early time wells communicate through the Lower Bakken Shale, a 3-month interference test shows closure between the Three Forks and Middle Bakken. From these learnings, an optimized development is being developed for the Bakken/Three Forks play and a similar workflow can be applied to any play both new or mature to maximize value and returns for operators.

Until recently, microseismic has been the primary diagnostic for estimating "bulk" or stage-level fracture geometry, including asymmetry due to parent-child interactions, for modern multi-cluster plug-and-perf completions. However, microseismic cannot provide details on individual fractures or cluster-level measurements. With the continued advances in fiber optic technologies, we can now measure cluster level fracture behavior at the wellbore and in the far-field. Characterizing the relationship between wellbore and far-field fracture geometry, referred to as fracture morphology, is important when simultaneously optimizing completion design and well spacing. Microseismic and fiber optics are very robust, but expensive, technologies and this limits the frequency of their application. Recently developed low-cost pressure-based technologies enable high-volume data acquisition but may not provide the same level of detail compared to microseismic and fiber optic measurements. This paper presents a case history that details the application of deployable fiber optics to characterize fracture geometry and morphology using microseismic and strain data. The paper also presents results from Sealed Wellbore Pressure Monitoring (SWPM) (Haustveit et al. 2020), comparing the lower-cost SWPM technology to the higher-cost deployable fiber. Wireline-fiber was deployed in the inner two wells, one Middle Bakken (MB) and one Three Forks (TF), of a four-well pad. Surface pressures were recorded on all wells on the pad and nearby parent wells. The outer two wells, one MB and one TF, were completed first, using zipper operations. Fiber-based microseismic and strain measurements were used to characterize fracture geometry and morphology, and parent-child interactions. Pressure measurements on the two inner wells were used for SWPM, providing estimates of completion effectiveness and fracture geometry using Volume to First Response (VFR) measurements. The microseismic data showed asymmetric growth from the eastern well to the parent well pad, with fractures covering the entire parent well pad. More symmetric fracture growth was measured for the western well, as the parent well pad was farther away. The microseismic data provided fracture geometry measurements consistent with previous measurements in the same area using a geophone array. The SWPM results compared favorably to the fiber measurements using the high confidence data. However, there were data acquisition complexities with both technologies that will be detailed in the paper. Fiber strain measurements provided detailed information on fracture morphology, showing significant decreases in the number of far-field hydraulics as distance increases from the completion well. The advancements in Low Frequency Distributed Acoustic Sensing (Ugueto et al. 2019) provides the ability to monitor hydraulic fractures approaching, passing above/under, and intersecting the monitoring location. Both fiber and SWPM showed much faster fracture growth within the same formation compared to fracture growth between formations. The integration of the fiber optic measurements and SWPM results have provided important insights into fracture geometry and morphology, leading to improved hydraulic fracture models.