Treating-Pressure Analysis in the Bakken Formation
Authors: Cramer David D. 
Published: December 2007

The Bakken formation is an oil-producing interval in the Williston basin. Usually, commercial Bakken wells are linked to an anisotropic natural fracture network. Hydraulic fracturing treatments have been used extensively in vertical wells and to a limited extent in horizontal wells. In this paper, bottomhole treating pressures (BHTP's) are analyzed to improve understanding of hydraulic fracture propagation in the Bakken.

Introduction

The Bakken formation produces oil over a wide area in the Williston basin. Bakken sediments were deposited in the early Mississippian/late Devonian and consist of upper and lower black shales and a middle carbonate/siltstone interval.1 The Bakken formation is confined by the carbonates, shales, and sands of the Lodgepole (upper) and Three Forks (lower) formations. These bounding zones are productive locally.

In most areas of the Williston basin, matrix permeability in Bakken reservoirs in very low (&lt;0.1 md). Oil is produced through an anisotropic natural fracture set, and the fractures seem to trend normal to the minimum horizontal stress.2

Hydraulic fracturing treatments are used extensively in vertical Bakken wells to improve well productivity.3 Normally, 50,000 to 150,000 gal of gelled Bakken lease oil is used as the fracturing fluid.4 A variety of proppant types and concentrations have been used, in volumes ranging from 80,000 to 500,000 lbm. Usually post-treatment well-test analysis shows that the apparent conductive (propped) fracture half-length is &lt;100 ft,5 regardless of the fracturing technique used. A hydraulic fracture simulator6 indicates that propped half-lengths range from 300 to 600 ft. The discrepancy between well-test and simulator results suggests that hydraulic fractures trend in the Bakken.2 When this happens, a propped fracture affects well productivity by circumventing formation damage (e.g., plugged natural fractures) and by linking into on-trend natural fractures missed by the wellbore. In horizontal wells, fracture treatments may improve well productivity of bypassing wellbore damage and by mitigating vertical permeability anisotropy (i.e., layering effects).2,7

Analyzing bottomhole pressure (BHP) during a fracture treatment helps to determine how the hydraulic fracture is propagating. Analyzing surface pressure or BHP immediately after a fracture treatments helps to determine the fracturing fluid-loss rate and the dimensions of the hydraulic fracture.8-15 This information can be used to refine the job design for future treatments in the evaluated zone. The principles of BHTP analysis are based on the relationship between fracturing fluid pressure and the elastic deformation of rock at the fracture walls; formation rock properties must be known to use this technique.

The primary focus of this paper is to analyze BHTP and supplementary data from a variety of wells in an effort to understand the nature of fracture propagation in the Bakken formation. Topics covered in this paper include the mechanical properties of the gross Bakken interval, the fracture-height growth, the effect of fracturing fluid viscosity and proppant addition on net treating pressure, the use of the G-function plot to estimate the fracturing fluid-loss rate, and the effect of perforation restriction on BHTP and how to remove this restriction.

Rock Properties and Fracture-Height Growth

The elastic properties of rock (i.e., Young's modulus, E, and Poisson's ratio, µ) affect hydraulic fracture propagation. Young's modulus is the stress/strain ratio for uniaxial stress16; it is a measure of rock stiffness that affects hydraulic fracture width and net fracture pressure (i.e., BHTP minus fracture closure pressure). Poisson's ratio is the ratio of lateral expansion to longitudinal contraction for uniaxial stress. This property, along with pore pressure, determines the amount of vertical overburden stress that is applied horizontally to rock layers. Poisson's ratio is directly proportional to the minimum in-situ horizontal stress, sHmin, as expressed by17

Equation 1

where sV=vertical or overburden stress, a=poroelastic constant that varies between 0 and 1, pp=pore pressure, and s=tectonic stress.