Embedment and Fracture Conductivity in Soft Formations Associated with HEC, Borate and Water-Based Fracture Designs
Authors: Lacy Lewis L. , Rickards Allan R. , Ali Syed A. 
Published: December 2007

Embedment and Fracture Conductivity in Soft Formations Associated with HEC, Borate and Water-Based Fracture Designs Lewis L. Lacy, SPE, Allan R. Rickards, SPE, BJ Services Company, Syed A. Ali, SPE Chevron U.S.A. Production Company Copyright 1997, Society of Petroleum Engineers, Inc.

Multigrain proppant embedment in to soft formations reduces the propped fracture width by 40% and damages the proppant pack conductivity by formation fines. Embedment and fracture width are measured for 20/40 and 40/60 mesh Ottawa gravel and 20/40 mesh sintered bauxite at proppant placement densities of 4 lb/ft2. The simulated formation consist of prepacked unconsolidated sand to reservoir conditions with Brinell hardness values less than 140 psi and static compaction modulus (i.e. Young's modulus) of 200 thousand psi. The carrier fluids investigated in the embedment tests were crosslinked borate gels, linear HEC gel and high rate water packs. One to four monolayers of proppant embedment were measured at two leakoff rates corresponding 0.01 and 0.03 ft/root-min. The embedment test results were measured with a sensitive electronic micrometer and confirmed by microphotography.

Introduction

In a previous paper, fracture width and embedment were investigated for four soft sandstone reservoirs with Brinell hardness values less than 20 kg/mm2 (24000 psi) and static Young's moduli less than 2 million psi. In the present paper, fracture width and embedment are studied using unconsolidated sands pre-packed to reservoir conditions where the Brinell hardness value is only 0.1 kg/mm2 (120 psi) and static Young's moduli less than 250 thousand psi. Multigrain proppant embedment in soft formations reduces the designed fracture width in frac and pack completions and significantly damages the pack with formation fines. The embedment process takes place during fluid leakoff to the formation and continues as closure stress increases on the proppant pack. The embedment depends on the fluid viscosity, grain size of the proppant, closure stress and leakoff rate. Testing indicates that the embedment process in unconsolidated sands consist of both micro-embedment of individual proppant grains into the formation and macro-invasion of a collection of proppant grains and carrier fluid. The initial random distribution of suspended proppant grains in the carrier fluid facilitates the embedment process into the simulated fracture face.

Proppant pack conductivity tests were also performed to determine the damage associated with formation fines at two closure stresses of 2000 and 5000 psi. At 5000 psi closure stress, 10% formation fines can reduce pack conductivity to only 18% of the original pack conductivity at 2000 psi. Embedment increases with increased proppant size (i.e. embedment 20/40&gt;40/60 mesh), closure stress (i.e. embedment 5000 psi &gt;1000 psi) and fluid viscosity (i.e. embedment borate &gt;HEC). To maintain fracture width and conductivity, stimulation treatments should be designed for a minimum of 4 lb/ft2. Fractures with propped widths of 2 lb/ft2 are essentially closed and have very low conductivity due to formation fines damage.

This paper will compare embedment of two proppants sizes, 20/40 and 40/60 mesh gravel pack sands (Ottawa), and three fracturing fluids (i.e. crosslinked borate gels, 80 pound HEC linear gels and high-rate water packs). Multigrain embedment is measured as a function of closure stresses from 500 psi to 5000 psi under computer controlled leakoff conditions from 2 minutes to 10 minutes. The propped fracture widths of the packs were measured at 4 lb/ft2, using slurries equivalent to 10 lb/gal, and are compared to propped fracture widths with no embedment.

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