Acid Stimulation of High-Temperature Sandstones in Eastern Venezuela
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 98318, "Effective Stimulation of High-Temperature Sandstone Formations in East Venezuela With a New Sandstone-Acidizing System," by S.A. Ali, SPE, and C.W. Pardo, SPE, Chevron Energy Technology Co., and Z. Xiao, SPE, F.E. Tuedor, SPE, A. Boucher, SPE, S.A. Al-Harthy, B. Lecerf, and G. Salamat, SPE, Schlumberger, prepared for the 2006 SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 15–17 February.
Wells in this eastern Venezuela oil field have a bottomhole temperature of approximately 230°F and varied mineralogical composition from interval to interval. Near-wellbore fines damage and carbonate-scale damage have been reported. A novel chemical system was developed to stimulate these high-temperature sandstone reservoirs.

Introduction
Most of the wells in this field in Maracaibo, Venezuela, have several perforated intervals covering up to 1,000 ft, with a net perforated interval of up to 500 ft. The mineralogy varies from interval to interval, with 4 to 16% calcium carbonate (CaCO3), 6 to 18% clays (mainly kaolinite), 5 to 10% feldspars, and 2 to 5% siderites in some wells. Reservoir pressures range from 800 to 2,500 psi, and skin values vary across the zones. Permeability varies from 1 to 200 md among the zones. The main formation-damage mechanisms were identified as fines migration (80 to 90% production decline after treatment) and CaCO3 scales, mainly from loss of workover fluids. Various formulations of mud acid, organic-clay acid, and solvents are used to treat these wells, with mixed results.
The new sandstone-acidizing system was developed to treat multilayered high-temperature (200 to 375°F) reservoirs with long production intervals and complex mineralogy. The new sandstone-acidizing fluid uses a single-stage placement process, has less precipitation tendency and reduced tubular and production-equipment corrosion, and reduces exposure of hazardous fluids to wellsite personnel and the environment. A comprehensive laboratory study, which included acid-solubility tests, X-ray diffraction (XRD) analysis, batch reaction kinetics, fines-migration tests, and core-flow tests, was conducted on field cores to evaluate the performance of this sandstone-acidizing system and compare it with currently used systems.

Experiment
Twelve core plugs were used from the formation sand in the oil field. Six plugs were from the 7,951- to 7,953-ft interval, five from the 7,723- to 7,727-ft interval, and one from the 7,757- to 7,758-ft interval. All samples were 1 in. in diameter and approximately 2 to 3 in. long. These core samples were classified into groups of high- and low-permeability sands, although a slight difference in physical appearance was observed in the laboratory.
Acid solubility tests were run on 10 samples. Mineralogical information is very important in sandstone-acidizing treatments. XRD was used to quantify the mineralogical composition of the core samples. Typical minerals in sandstone rock include silica (quartz), feldspars (plagioclase, K-feldspar), clays (kaolinite, illite, chlorite, smectite, and mixed-layered illite and smectite), zeolites, micas, carbonates (dolomite, calcite), sulfides, and sulfates (gypsum, anhydrite, and barite).