The work presented in this paper analyzes surface and downhole microseismic data for a horizontal well in the Woodford Shale in Oklahoma and compares those results with calibrated hydraulic fracture modeling. Hydraulic fracture models were created for each of five stages with a three-dimensional modeling software, incorporating available petrophysical data in order to match the recorded treatment pressure and the fracture geometry obtained from the microseismic data. Further analysis investigated the congruency of the downhole and the surface microseismic data, what differences they produced in a match if used exclusively, the influence of the number of events on the fracture geometry obtained from the microseismic data, the error of event location, the degree of complexity of the created fracture network, and the relationship between the magnitude of events and the time and location of their occurrence.
The fracture models produced good matches for both pressure and fracture geometry but showed problems matching the fracture height due to cross-stage fracturing into parts of the reservoir that were already stimulated in a previous stage. Surface and downhole microseismic data overlapped in certain regions and picked up on different occurrences in others, giving a more complete picture of microseismic activity and fracture growth if used together. However, they deviated in terms of vertical event location with surface data showing more upward growth and downhole data showing more downward growth. In general, the downhole microseismic data showed that the stimulation treatment was successful in creating a fairly complex hydraulic fracture network for all stages, with microseismic recordings making flow paths visible governed by both paleo and present day stresses. Plots showing the speed of event generation, the cumulative seismic moment, and the event magnitude versus the event-to-receiver-distance identified interaction with pre-existing fault structures during Stages III and V.
Although a stimulation technique, the hydraulic fracturing process can also cause damage to the reservoir in a variety of ways. These damage mechanisms cannot be completely eliminated, but by careful examination of their individual characteristics and effects on production, focus can be placed on minimizing the most critical factors. This paper presents the results of a sensitivity study of numerous reservoir properties and operational control variables on fracture effectiveness and production from a fractured gas well. Simulations are based on a newly developed mathematical model for hydraulic fracture propagation and cleanup processes, combined with reservoir simulation.
The numerical simulation model considers a three-dimensional reservoir which can either be homogenous or heterogeneous. The created fracture is extended with time and the corresponding leak-off effects on the near wellbore and far-field area are assessed. Two-phase flow equations, both in the fracture and in the surrounding matrix, are used to evaluate behavior during the fracture propagation and production/clean-up periods.
The developed simulation model is validated by history matching with actual field performance from a fractured gas well. The history matched results are used as a base case for the study. The sensitivity results show the creation of different leak-off profiles and the effectiveness of corresponding cleanup processes. Results indicate that shut-in time between end of fracture propagation and beginning of flowback is critical due to imbibition of fracturing fluids. Additionally, heterogeneity of the reservoir has a significant effect on cleanup profiles.
Not only does that this study provide significant insight into phenomena happening on the fracture face and inside the reservoir, it and the developed simulator can also be used as a tool for hydraulic fracturing design or post-stimulation evaluation.
Ramirez, Kelly (Colorado School of Mines) | Cuba, Patricia Helena (Anadarko Petroleum Corporation) | Miskimins, Jennifer Lynne (Colorado School of Mines) | Anderson, Donna Schmidt (EOG Resources Inc.) | Carr, Mary
Hydrocarbon resources such as tight sands have become one of the most sought after types of unconventional plays, given the extensive amounts of gas they contain. In order to access these reserves, the industry is focused on improving hydraulic fracturing techniques with the purpose of increasing gas recovery. However, proper reservoir management practices, in conjunction with improved completion processes, are also key factors for maximizing these gas reserves. Additionally, reservoir understanding becomes even more relevant when dealing with reservoirs deposited in complex fluvial environments.
This paper discusses a study that integrates the accurate stratigraphy and detailed reservoir characterization of a 160-acre 3D fluvial geologic outcrop model populated with analog producing field reservoir properties with detailed hydraulic fracturing modeling to better understand the effects that fluvial depositional environments have on hydraulic fracture growth.
Subsequently, the detailed hydraulic fracturing growth parameters are implemented in a robust 3D reservoir simulation model, representing the heterogeneous geologic environment. Reservoir simulation is then used to determine the dynamic flow conditions associated with the fluvial geologic model with the ultimate goal of determining optimum reserve recovery practices such as well spacing and placement, hydraulic fracture design components, etc.
The methodology applied in this study, which starts with the 3D outcrop mapping and characterization, followed by the development of a geostatistical model, hydraulic fracturing modeling, and reservoir simulation is presented. Three different cases, consisting of various well locations and spacing, are described. Results show that the continuity of sand bodies in the near wellbore vicinity, whether part of the completion interval or not, is critical to the ultimate reserve recovery and is a
function of the hydraulic fracture growth pattern. Additionally, amalgamation of the sandstone bodies, which also affects the hydraulic fracture growth patterns, has a strong effect on gas recoveries. Finally, for the cases reviewed, the benefits of infill drilling were mainly obvious in reserve acceleration versus reserve addition.
Charoenwongsa, Sarinya (Colorado School of Mines) | Kazemi, Hossein (Colorado School of Mines) | Fakcharoenphol, Perapon (Colorado School of Mines) | Miskimins, Jennifer Lynne (Colorado School of Mines)
Polymer and gel damage is a major issue in the cleanup of hydraulically fractured gas wells. This paper addresses this issue by using a gas-water flow model which simulates fracture propagation with gel filter cake formation as mechanical trapping of polymer molecules on the fracture face and filtrate transport into the adjacent matrix. The model accounts for polymer as a chemical component. This approach is different than treating polymer as a highly viscous gel phase, which is the common method in most literature. In this model, the gel filter cake thickness is calculated based on experimental data. For leakoff, the model allows only the sheared polymer molecules, which are the major cause of formation permeability reduction, to cross the fracture face into the formation and adsorb on the matrix. Other features of the model include water blockage, non-Newtonian flow, non-Darcy flow, and proppant and reservoir compaction.
"Stress shadowing," where the stress field around an induced hydraulic fracture reorients from its far field directions by up to 90 degrees, is a major factor in designing and executing multiple hydraulically fractured, horizontal well completions. This is especially true as the number of hydraulic fractures increase for a given lateral length. Often the number of fracture stages is determined by well analogues without considering how stress shadows alter fracture properties. In this paper, the main objective is to determine what properties are most important in determining the minimum distance needed between hydraulic fractures to avoid stress interference. A finite element model of a horizontal wellbore with a transverse hydraulic fracture is constructed in order to perform numerical simulations of the stress around the fracture. The model is used to perform sensitivities on various mechanical and reservoir properties to investigate how and why the stress field changed.
The simulation results show that the ratio of minimum to maximum horizontal stress is the most important parameter to know in order to determine the optimal fracture spacing. Changes in this ratio show an exponential change in fracture spacing, affecting spacing requirements by up to 81%. Poisson's ratio, Biot's parameter, and net fracture pressure were also important.
It can be concluded that fracture spacing cannot be determined by looking only at one or two properties. The fracture spacing must be determined by looking at all the important variables and identifying those that are most variable for the reservoir in question. The sensitivity of the "stress shadow" to various properties is an indication that obtaining good data is key to proper completion design.