Channel vs. Matrix Sandstone Acidizing of a HT/HP Reservoir in Saudi Arabia
Authors: Thomas R.L. , Nasr-El-Din H.A. , Lynn J.D. , Mehta S. , Muhareb M. , Ginest N. 
Published: December 2007

The Jauf reservoir, a deep, high temperature illitic sandstone, was reported to be sensitive to conventional mud acid treatments based on field results. An extensive study was performed to better understand the response of the reservoir to a matrix acidizing treatment incorporating mud acid (HCl-HF). A description of the mineralogy of cores prior to and following treatment is presented with emphasis on the matrix flow pattern and potential damage mechanisms. Interpretations of the core tests results are supported by SEM, and thin section analyses. This study highlights a misconception we have about sandstone matrix acidizing with mud acid and discusses the impact on matrix acidizing models and well performance results.

Core flow tests were performed using HCl and acetic acid preflushes to HCl-HF systems to determine their effect on Jauf cores at 300°F. Acetic acid was used rather than the conventional HCl preflush in several core tests since it did not severely degrade the formation clays nor create core damage as was observed with HCl. It was discovered that HCl - HF when preceded by HCl or acetic acid created channels through Jauf reservoir cores. Channeling normally occurred in 1–2 pore volumes of acid when using the 12 wt% HCl - 3 wt% HF. However, channeling was delayed when using weaker acid systems and pseudo-matrix flow was observed. The tendency of the HCl - HF to channel was found to be a function of the heterogeneity of the core, the acid composition and permeability.

SEM and thin section evaluation of core plug samples prior to the injection of acid indicated the presences of significant amounts of hairy illite, and pore-lining illite/montmorillonite mixed layer clays. Examination of cores treated with 15 wt% HCl followed by 12 wt% HCl - 3 wt% HF (12–3) mud acid indicated microcline and clay remained in the core. Coarse-grain laminations in the cores normally resulted in high permeability channels going through the core to yield excellent stimulation. The channels contained relatively clean sand grains and large pores. Although the channeling flow pattern dominated in cores treated with 12 wt% HCl - 3 wt% HF, transition from a channeling to matrix flow pattern was observed when 9 wt% HCl - 1 wt% HF systems were used. Although all matrix sandstone acidizing models assume uniform radial flow occurs in a matrix treatment, this was not the case in the linear flow tests using cores from the Jauf reservoir. Similar to wormholing in carbonate reservoirs, channeling of acid in HT/HP sandstone reservoirs should improve stimulation results due to a near zero or slightly negative skin.

Introduction

Matrix acidizing treatments are designed to remove or bypass formation damage by injecting the acidizing fluid into the reservoir below fracturing pressure. The classical goal of sandstone matrix acidizing is to restore the natural permeability of the reservoir by removing the formation damage.1,2 This implies the formation damage that is plugging the pores is dissolved to yield improved matrix flow that approaches the natural flow capacity of the un-damaged well. On the other hand, carbonate matrix acidizing treatments are designed to bypass the damage via creation of wormholes to yield a high permeability region radially around the wellbore that exceeds the natural permeability of the reservoir. This is true reservoir stimulation i.e., a negative skin is created to yield higher injection or production than that obtained from an undamaged well at the same conditions.