Increasing Oil Production by Hydraulic Fracturing in the Hassi Messaoud Cambrian Formation, Algeria

Abstract Since 1990, over 100 hydraulic fracturing treatments have been performed in the Hassi Messaoud (HMD) field in the northeastern part of central Algeria, resulting in an average production increase per well of 700 BOPD. The success of the stimulation program in this 11,150 ft deep, Cambrian-age sandstone formation depended on overcoming the combination of the following treating conditions.–slotted liner and openhole completions in most wells–reservoir thickness of 200 to 500 ft–Young's moduli of 8 to 12E6 psi–fracturing pressures of 0.8 to 1.2 psi/ft–low reservoir pressures of 0.15 to 0.45 psi/ft–formation permeabilities of 0.5 to 50 md–moderately high temperature of 245 F–underlying low-stress saltwater formations Prefrac injection tests and temperature logs were run on almost every well to allow treatment optimization. Proppant amounts range from 10,000 to 300,000 lb of 20/40 and 12/20 sintered bauxite at concentrations up to 15 lb/gal; tip-screenout designs were used on most treatments to maximize fracture conductivity. The collection of comprehensive data in uncommon formation characteristics has led to a much better understanding of the controlling factors in predicting treatment performance. Descriptions of fracturing behavior, well preparation, and production results are presented. Introduction Since the first field operations in the late 1940's, hydraulic fracturing treatments have become key factors in the development of many fields throughout the world. By the late 1980's over 1 million treatments had been performed. Most were performed in the United States, where fracturing has made many low-permeability, hard formations economically feasible to develop. In the last 15 years, there has been significant extension of hydraulic fracturing into softer, moderate- to high-permeability formations. The recent expansion of Frac and Pack techniques in international locations, as well as in the USA Gulf Coast, has further extended fracturing technology to unconsolidated, high-permeability formations. The fracturing treatments performed in the HMD field differ significantly from previous fracturing experience because of a rare combination of hard formation characteristics, low reservoir pressure, and moderate formation permeability. Fracturing pressures in this 11,150-ft deep Cambrian sandstone formation average 0.9 psi/ft, attributable to Young's moduli that vary from 8 to 12E6 psi. With formation permeability averaging up to 50 md and pore pressure gradients that vary between 0.15 to 0.45 psi/ft (resulting from 35 years of field production), fluid loss is often great. Fluid efficiency (percentage of fluid remaining in the fracture at shut-in of a prefrac injection test) averages only 15%, even with the use of large polymer loadings and fluid-loss additives. Complicating matters further are mechanical limitations inherent to treating a mature field, coupled with slotted liner and openhole completions methods. These difficult treating situations make treatment design challenging and stress the importance of well preparation and prefrac data collection. The importance of prefracturing injection testing and understanding the role of fluid loss at large pressure differentials have been significant factors in the success experienced in HMD. Knowledge obtained under these conditions of high pressure differential as well as the experiences gained from fracturing slotted-liner and openhole completions should be of considerable interest as fracturing is extended into nontypical arenas. To best describe the field and fracturing history, subject content will be separated into the following areas: P. 303