Experimental Tight Rock Characterization and Surfactant Screening for Hydraulic Fracturing Operations

• Author / Creator

  Yousefi, Mohammad

• Recently, unconventional resources, especially tight and shale reservoirs, have developed rapidly because of advances in horizontal drilling technologies and hydraulic fracturing technique. Based on the annual energy outlook of the Energy Information Administration, tight oil production in the US will increase from 8.2 million bbl/day in 2022 to 9.1 million bbl/day in 2050 ,and it will form more than 70% of all the US oil production. The tight and shale gas production in the US will also increase from 31.7 Tcf in 2022 to 39.2 Tcf in 2050, forming more than 92% of all the US natural gas production. Despite the great extent of unconventional resources, the recovery factor of those reservoirs is typically less than 10%, which shows the importance of enhanced oil/gas recovery methods. The first step in this path is to characterize rock/fluid properties to better understand fluid flow through such tight porous media.
  Measuring tight-rock properties, particularly permeability, is important in a wide range of engineering applications, from radioactive waste disposal and CO2 storage to production from unconventional hydrocarbon reservoirs. The steady-state method of permeability measurement is currently considered impractical for tight rocks due to the long time needed to reach stabilized pressure and flowrate. In contrast to experimental results, the diffusivity equation shows the steady state to happen much faster when a constant injection flowrate is used as a boundary condition. In this study, we investigate the reason behind the inconsistency between the modeled and measured equilibrium time. We modify the boundary condition of the diffusivity equation based on an analogy from the well-testing models. We propose a semi-analytical solution for a more general diffusivity equation with a modified boundary condition. The results show that the main reason that makes the steady-state method time-consuming is the accumulator “storage effect”. We modify the conventional coreflooding device to reduce the time of permeability measurement, making the steady-state method practical for tight-rock samples.
  During hydraulic fracturing operation, a huge volume of fracturing fluid is pumped into the well to create a network of fractures and propagate the fractures away from the wellbore. Some part of the injected fluid remains in the fracture system, and some part of it leaks off into the rock matrix. During flowback and post flowback periods, only a small portion (5-50%) of the injected fluid will be recovered. The remaining leaked-off fracturing fluid will form a water-loaded zone near the fracture face that hinder oil production during flowback. On the other hand, the imbibition of fracturing fluid into the rock matrix can be considered as a production mechanism that forces oil out of the rock matrix. This dual behavior of fracturing fluid led researchers to find an optimized situation where imbibition oil recovery is maximum, and water blockage near the fracture face is minimum. Chemical additives such as surfactant solutions and microemulsions have been introduced to serve this purpose. Screening such additives for field applications requires evaluating their impacts on regained permeability and post-flowback well performance. In this study, we are using our developed method to measure liquid permeability before leak-off and after flowback to investigate the effects of different surfactant solutions on regained permeability of tight plugs.
  Relative permeability (kr) is one of the constitutional relationships in the general equation governing immiscible displacement that needs to be determined. Due to the complexity and nonlinear nature of the governing equations of the problem, there is no unique model for the relative permeability. The modified Brooks and Corey (MBC) model is the most common model for kr prediction. Here, a practical technique is presented to measure kr for low-permeability tight rocks. We use this experimental data to tune the empirical constants of the MBC model. The proposed method is based on a simple mathematical technique that uses assumptions of frontal advance theory to model the pressure drop along the core plug during two-phase immiscible displacement at constant-injection flowrate.

• Subjects / Keywords

  • Diffusivity Equation
  • Tight Rocks
  • Pressure Profile
  • Relative Permeability
  • Leak-off
  • Flowback
  • Surfactant Screening

• Graduation date

  Spring 2023

• Type of Item

  Thesis

• Degree

  Doctor of Philosophy

• DOI

  https://doi.org/10.7939/r3-eawa-r694

• License

  This thesis is made available by the University of Alberta Libraries with permission of the copyright owner solely for non-commercial purposes. This thesis, or any portion thereof, may not otherwise be copied or reproduced without the written consent of the copyright owner, except to the extent permitted by Canadian copyright law.