Multiple-Source Data Provide Insight Into Hydraulic Fracture Geometries
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Using planar fracture models to match treatment pressure and improve understanding of fracture-geometry generation is not a new concept. At some point during the progression from vertical to horizontal wellbores, however, many within the industry forgot about the learnings that still can be gained from current fracture models. The complete paper demonstrates the benefits of honoring data measurements from a multitude of potential sources to help engineers do a better job of including more diagnostics into routine operations to provide additional insight and result in improved models and completion designs.
Many sources of reservoir, drilling, and completion data and measurements are available to well operators. However, in nearly all cases, a balance must be achieved of what can be captured at a reasonable cost and the associated value of the information gained. It is unrealistic to acquire high-density data sets for every well in an entire field because of the prohibitive costs, but understanding what is available and knowing what questions need to be answered can enable a more-cost-efficient means of acquiring the correct information to address specific challenges.
Diagnostic Data and Measurements
The complete paper contains a summary of some relevant tools and technologies and a short description of the information that can be captured, the importance of this information, and how it can be used; examples are discussed wherein some of these tools are combined to provide useful completion-design information.
Gathering Production Information
Production-logging tools are useful for characterizing and better understanding reservoir performance and optimizing production. The production logs are typically run after the completion of a well, either in a cased or open hole. The logs are used to determine the allocation of wellbore inflow to different zones and to identify areas of production problems such as crossflows and leaks. In low- and ultralow-permeability reservoirs with horizontal drilling and increases in the number of fracturing stages, understanding the production rate of each fracturing stage is important. Therefore, a post-fracturing evaluation might be necessary for optimization of multistage fracture design. Artificial-lift installations on post-fracture completions can be an obstacle to acquiring good production-log data in unconventional wellbores.
Multiple tracer technologies are available for fracture diagnostics, and, while all such methods provide useful information, the results can be misleading when the methods are used independently. Conditions within the reservoir are changed significantly during the completion process and again during production. While wells can be in communication during hydraulic fracturing operations, that does not mean that the same wells will be in communication during production, because not all of the created fractures will remain open and conductive when production and reservoir depletion has begun.
Radioactive Tracing. In horizontal well developments in which multiple wellbores are fractured in close proximity, there is potential for radioactive tracers used to fracture one well being detected in one or more of the neighboring wells. This would clearly signal that proppant communication between the two wellbores exists.
Water-Soluble Chemical Tracers. A multitude of different water-soluble tracer materials are available for hydraulic fracturing operations. The benefit of this approach is that different materials can be used for different multiple wells and then produced-water samples from each of the wells can be analyzed to determine which tracers are present. This provides a positive indication of which hydraulic fracturing treatments from multiple wells were in communication during the completion process.
Oil-Soluble Tracers. Oil-soluble tracers have proved beneficial in providing post-fracture production information over time. Oil-based tracers were added to a water-based fracturing fluid during the beginning of the proppant-laden portion of each stimulation stage of a horizontal completion. The tracers are insoluble in water and are pushed into the fractures by the fracture fluid; there, they bind with the in-situ hydrocarbon. The nonradioactive oil tracer will bind upon contact with the in-situ oil encountered in the reservoir. Samples of produced oil are tested to determine the presence of each unique tracer, which is subsequently correlated to the volume of oil production starting at first production to produce a pseudoproduction log.
Pressure Interference Testing. In a multiwell pad, this process can be a significantly complex procedure, requiring high-quality bottomhole pressure gauges so that sudden rate changes (shut-in or restarts) can be deployed on selected wells and the other wells can be observed for pressure responses caused by these events. The delay of pressure interference, or the response time observed between wells, and the magnitude of the interference provide information corresponding to the extent of pressure communication between the given wellbores.
The complete paper includes case histories in which (a) tracer and pressure interference testing were performed in a joint industry study completed in the Midland Basin and (b) pressure buildup/pressure interference between wellbores was tested in the Marcellus Shale.
Diagnostic Fracture Injection Test (DFIT) Before Fracture Treatment. DFIT is a cost-effective way to obtain in-situ measurements of the reservoir. This technique can provide values for the minimum stress, reservoir pressure, and the effective system reservoir permeability. The pressure required to open natural fissures and a pressure-dependent leakoff coefficient also can be determined from this test. A stepdown-rate test at the end of the DFIT can determine the near-wellbore restrictions (tortuosity), which often can impede proppant placement during the fracturing treatment. The instant shut-in pressure (ISIP) from the DFIT also can be used to make relative comparisons to early-time ISIP treatment values along the horizontal wellbore to help ensure proper wellbore placement.
Complex Fracture Model (CFM) Can Enhance Current Fracture Model Design. The development of complex fracture models that move beyond modeling planar fracture growth are being developed currently by both industry and academia.
Fracture-design inputs such as injection rate, fluid volume, proppant volume, and perforation design are controlled by the user. Nature controls input parameters, such as the deviatoric stress, bedding planes, and the natural fracture network. Variation in the input parameters can be used in a sensitivity analysis to determine which parameters are significant. One should aim to generate complex fracture geometry from these inputs and then iterate the results back into the planar fracture model to assist in the calibration.
Fig. 1 is an example of the output from a CFM for a single fracture stage in a horizontal wellbore, which varied the number of entry points (perforation clusters) between three and five. The injection rate (60 bbl/min), fluid and proppant volume (7,500 bbl), deviatoric stress (150 psi), and natural fracture network were the same for both simulations.
Several observations from this analysis under the given model conditions include the following:
- A more-complex hydraulic fracture network is generated with more entry points (five).
- More hydraulic fracture length is generated with fewer entry points (three).
- More fracture surface area is generated with three perforation clusters than with five.
- Fracture area with proppant is approximately the same for both cases.
- If perforation efficiency is high, a larger treatment volume may be needed for the five-perforation cluster design than for the three-perforation cluster design.
- Iteration of a larger treatment volume is observed in the 3D poroelastic planar fracturing model.
Production Model History Matching. In the drilling of complex trajectories—specifically, long laterals through heterogeneous reservoirs with multiple stages of fracturing—the information gained from the production analysis improves reservoir understanding. Through history-matching solutions, the effective permeabilities are estimated along with other key reservoir parameters. However, it is important to realize that the solutions derived from the reservoir simulation and production history matching are not unique.
Sensitivity analysis of hydraulic fracture design integrated with reservoir simulation can provide significant insight into changes in well productivity in response to reservoir characteristics and completion technologies. Numerical simulation of low-permeability reservoirs with complex configurations, however, has the following specific challenges that cannot be addressed with conventional tools:
- Gridding challenges for horizontal wells with multiple stages of hydraulic fractures
- Heterogeneity of the rock (vertical and lateral)
- Very low effective permeability
- Inclusion of natural fractures in the model, thus increasing the complexity of the model
- Selection of optimal stimulation design
Multiple-Source Data Provide Insight Into Hydraulic Fracture Geometries
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