Results of Stress-Oriented and Aligned Perforating in Fracturing Deviated Wells
Authors: Pearson C.M. , Bond A.J. , Eck M.E. , Schmidt J.H. 
Published: December 2007

Summary
This paper reports the first results of stress-oriented and aligned perforating of deviated wells at the Kuparuk River field, Alaska. Preferred perforation alignment and Preferred perforation alignment and spacing are calculated for each well so the fractures from individual perforations link to produce a single perforations link to produce a single "zipper" fracture plane along the deviated wellbore. Results of the first application of this technique are presented from the 26-well development presented from the 26-well development of Drillsite 2K. The results from use of three different oriented casinggun systems and pertinent data from Drillsite 2K fracture stimulation treatments are discussed. Comparisons to drillsites where nonaligned perforating strategies were used show a perforating strategies were used show a significant reduction in perforation friction, enabling the placement of larger, more productive fracture treatments. Application of this technique to deviated and vertical wells and its use at Kuparuk on developments after Drillsite 2K are discussed.

Introduction
Perforation design for a well that will be Perforation design for a well that will be hydraulically fractured is usually controlled by the requirements to place the stimulation treatment. Key parameters are the number, size, orientation, and phasing of perforations. Typically, the objective is either perforations. Typically, the objective is either to minimize or, in the case of limited entry treatments, to control the amount of perforation friction during the stimulation perforation friction during the stimulation treatmeat. No uniform criteria exist within the industry for defining perforation phasing or shot density. Different operators use different techniques. However, the pumping of a fluid stage to break down the well and to calculate the perforation friction loss is routine to verify that sufficient communication exists between the wellbore and the formation to place the fracture treatment. Often, a ballout treatment is pumped before the main stimulation to force additional perforations to breakdown. Although it is perforations to breakdown. Although it is generally acknowledged that the optimal placemeat of perforations in a vertical well is placemeat of perforations in a vertical well is 180 phasing in the fracture plane, which is perpendicular to the far-field minimum stress, there are, to the best of our knowledge, no reported efforts of routinely practicing such a technique. Laboratory practicing such a technique. Laboratory investigations into fracture initiation from deviated wells showed the importance of perforation placement on the length of perforation placement on the length of wellbore intersecting the fracture.
During the past 7 years, more than 600 new development wells have been fracture -stimulated in the Kuparuk River field. The large number of treatments has provided the opportunity for significant advances in the technical and operational aspects of hydraulically fracturing deviated wells that are not aligned colinear to a direction of principal stress. The success of this stimulation principal stress. The success of this stimulation program was documented in Refs. 4 and 5. program was documented in Refs. 4 and 5.
Perforation strategy during the initial development consisted primarily of perforating the net pay intervals in the Kuparuk A sand. Depending on the drillsite, this would result in the perforating of two or three separate zones. Before the wellbore tubulars and completion equipment were run, casing guns (4 1/2-in.) were shot with a typical shot density of 4 shots/ft and a phasing of either 90 or 120. We often used largehole shots every fifth hole. Most initial fracture treatments pumped in wells where this strategy was used had relatively high perforation friction drops ranging from 500 to perforation friction drops ranging from 500 to 1,500 psi. Post-treatment temperature and tracer logging often showed fluid entry into a few discreet points along the perforated interval, with the lowest zone of the A sand often showing no evidence of fracture stimulation. The poor communication at the wellbore is thought to have caused many treatment screenouts in the field.