End of Linear Flow Time Picking in Long Transient Hydraulically Fractured Wells to Correctly Estimate the Permeability, Fracture Half-Length and Original Gas in Place in Liquid Rich Shales

Abstract

Formation permeability (k) and fracture half-length (Xf) determination provides the ability to economically optimize well and fracture spacing. For wellbores completed in the gas-condensate and oil window (producing below saturation pressure) two-phase flow occurs from the fracture face increasing in distance until it reaches the no flow boundary from the adjacent fracture face along a horizontal wellbore. Thereafter the flow becomes boundary dominated. It becomes challenging to precisely pick the end of linear flow time and the start of boundary dominated flow regime due to long transient region in shales (low permeability nature). End of linear flow time is used to calculate both the permeability and original gas in place (OGIP) using production data. Existing practices in the literature suggest to pick the end of linear flow time implicitly from the plot of reciprocal rate vs cumulative production. The deviation on the line is termed as typically the time at which linear flow has ended. However, considering the lengthy transition regions in shales, this involves a great deal of error as the end of linear flow time is not calculated mathematically but picked on the analyst's eyeballing practices. Thus, a small mispick of end of linear flow time could result in substantially misleading permeability and OGIP. The primary work presented in this paper resolves the selection of end of linear flow time by proposing a technique which involves production data analysis equations and statistical methods along with graphical techniques to calculate and rightly pick the end of linear flow time. Since gas condensate ratio (GCR) remains constant during the linear flow regime, our methodology also involves reverification of the end of linear flow time. This is done by picking the increase in GCR which happens at the end of linear flow on the plot of cumulative production versus the GCR. While the procedure involved laboratory fluids, special core analysis, and numerical simulation, the methodology lends to a wide range of liquid-rich reservoirs where linear flow analysis is appropriate.

Effect of Cryogenic Liquid Nitrogen on the Morphological and Petrophysical Characteristics of Tight Gas Sandstone Rocks from Kirthar Fold Belt, Indus Basin, Pakistan

“…It is pertinent to measure the conventional petrophysics and rock properties via reservoir characterization in order to quantify hydrocarbon potential. − This can be achieved by proper characterization of the porous media and its lithology. − Our results for petrophysical experiments depict bright difference in properties of tight sandstone rock samples before and after LN 2 treatment, Figure and Table . Liquid nitrogen treatment from 30 to 90 min has enhanced the porosity and permeability of tight sandstone rocks due to induced fractures.…”

Nanomaterial-Based Drilling Fluids for Exploitation of Unconventional Reservoirs: A Review

“…Energies 2020, 13, x FOR PEER REVIEW 3 of 30 nano-silica polymer grafted polymer [61], ZnO polymer nanocomposite [43], TiO2/polymer nanocomposite [62], TiO2/clay nanocomposite [63], and several others [64]. Nanomaterials are widely used for different purposes, including enhanced oil recovery [65][66][67][68], wettability alteration [69][70][71][72], IFT reduction [73][74][75], surface adsorption [76], and CO2 storage applications [77][78][79][80][81]. They have a potential to augment rheological properties and shale inhibition of unconventional HPHT wells, but this has not been reported in a review work to date.…”

Cryogenic Liquid Nitrogen Fracking Effects on Petro-Physical and Morphological Characteristics of the Sembar Shale Gas Formation in the Lower Indus Basin, Pakistan

“…The conventional methods of exploitation and development of such resources have limited applicability in their extraction. ,,,, Additionally, the economical production from such reservoirs cannot be achieved by conventional means due to their complex pore system and lesser connectivity, complex pore geometry, extremely low porosity, and permeability. − Hence, this requires innovative technologies to enhance the productivity of shale gas reservoirs. , Such techniques include carbon dioxide (CO 2 ) injection, − acidizing, hydrofracking, − drilling optimization, − , and liquid nitrogen (LN 2 ) fracturing (a recently developed technique). ,,,,,, …”