Use of Frac-Pack Pressure Data to Determine Breakdown Conditions and Reservoir Properties

Abstract

Abstract Frac-Pack completions are becoming common in high permeability, poorly consolidated formations in the U. S. Gulf Coast and other areas. In many attempted frac-pack completions fracture breakdown conditions have not been achieved, resulting in immediate screenouts at low sand concentration. Several conditions determine whether breakdown can be achieved in a particular zone including depth, rock properties, zone thickness, skin factor, permeability, maximum achievable pump rate, fluid viscosity, and fluid leakoff behavior. This paper presents methods for determining critical reservoir properties including kh and skin from short duration pressure falloff tests conducted during the frac-pack operation, and for using these properties to determine fracture breakdown conditions including initiation and extension pressures and required pump rate. This information can be used to select the fluid type required for fracturing or to decide between a frac-pack and conventional gravel pack (or water-pack) completion. The data can also be used to predict the maximum surface treating pressure which must be sustained during fracturing, and the maximum casing pressure which will be reached if the treatment is conducted with the service tool in the circulating position. Introduction More than 600 frac-pack treatments have been completed in the Gulf of Mexico alone as of mid-year 1995. The overwhelming success of the completion method ensures that it will be a preferred practice in the future. However, procedures must be developed to improve candidate and material selection to broaden the future application of frac packing. Several authors have discussed the characteristics which define good candidates for frac packing. They include high permeability formations which are susceptible to deep damage, low resistivity laminated pay zones, and formations which are prone to fines migration. The problems associated with frac pack design in each of these situations vary. A particular problem with thick, high permeability formations is that matrix injection rates can be so high, once perforation damage is bypassed, that fracture initiation or breakdown can be difficult to achieve. This problem can be addressed either by using a wall-building fluid rather than a clean, high leakoff fluid, or by limiting the perforated interval. To correctly assess these choices, information concerning the formation flow capacity (kh/u, skin, etc.) must be obtained. These data, when combined with the near wellbore stress state, determine the injection rate, and bottomhole pressure at which breakdown will occur and may suggest what type of fluid must be used, or the maximum zone thickness which can be successfully treated. A series of 17 completions was carried out in an offshore Gulf Coast reservoir in producing intervals ranging from 18 feet to 160 feet in true thickness. Effective permeabilities from post-completion pressure transient tests ranged from 190 md to 1690 md. True vertical depths (TVD) of the zones ranged from 9800 feet to 12900 feet. Data from these treatments are used to illustrate the wide range of treating conditions which can be encountered, and to show how a proper analysis of available data can be used to design an efficient completion process. Estimation of Fracturing Conditions Fracturing is generally assumed to occur in a nearly cohesionless material when the net tangential stress at some point around the wellbore is reduced to zero. The net stresses around the wellbore can be estimated as a function of distance from the well, for conditions of equal horizontal stress in all directions, using the following equations: P. 75