Production Response in the Denver-Julesburg Basin
Authors: Carpenter Chris 
Published: April 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 180217, “The Impact of Petrophysical and Completion Parameters on Production in the Denver-Julesberg Basin,” by Fred Miller, Carrizo Oil and Gas; Jon Payne, Eureka Geological Consulting; and Howard Melcher, Jim Reagan, and Leen Weijers, Liberty Oilfield Services, prepared for the 2016 SPE Low Permeability Symposium, Denver, 5–6 May. The paper has not been peer reviewed.

The authors used a high-quality digital-log data set to characterize reservoir quality accurately in the Niobrara and Codell Formations in the Denver-Julesberg (DJ) Basin. A petrophysical work flow was developed, and detailed mapping of the reservoir attributes was completed. The log-derived parameters, along with an aeromagnetic and vitrinite-reflectance data set, provided excellent insight into which geologic parameters could be tied best to well-production response.

Introduction

In 2013, the authors began to evaluate production response in an area where nearly 50 Niobrara wells were completed by a single operator with a similar completion design for all wells. There was a wide variation in production results after 180 days of production, ranging from 4 to 16 BOE/lateral ft. The amount of proppant pumped per lateral foot changed very little and ranged between 800 and approximately 1,000 lbm/ft. The dramatic change in production response in light of the absence of major completion changes led to the early conclusion that geology is of great importance in the the Niobrara and Codell.

In the early days of DJ production, horizontal-well-development operators did not generally make radical changes to completion designs, making it harder to evaluate the effect of these changes. Only since 2014 has a significant change from previous approaches been seen, with a new focus on a reduction in cost per BOE.

Starting in 2009, stage count for mostly short (approximately 4,300-ft) laterals varied between 10 and 20 stages, with average stage intensity of 300 ft/stage. One of the first horizontal wells in the basin started with five stages, after which stage count quickly jumped to 16 to 20 stages in a short lateral. In recent years, stage count has increased significantly, partly because of longer extended-reach laterals and partly because of higher stage intensity. Stage intensity has dropped below 200 ft/stage, with some operators now experimenting with 125 ft/stage. 

Fluid and proppant volumes on a per-lateral-foot basis have not changed as dramatically in the DJ Basin as they have in other major US shale plays. Rate and rate per lateral foot show a similar lack of change over the first few years of DJ horizontal-well development; average rates are relatively low, most likely driven by the early-stage limitations of sliding-sleeve completions. Only recently have higher-rate jobs been seen. 

In response to the initial lack of DJ completion changes and the associated apparent lack of effect on production (resulting from production impact being hidden by larger geological changes), the authors developed a petrophysical work flow in an attempt to capture some of these geological parameters and assign them to every horizontal well. This led to calculation of the hydrocarbon pore volume (HPV), a proxy for bulk rock quality, for each of the wells. The conclusion was reached that any statistical model built only on completion parameters will be insufficient and will have to rely on a combination of completion and petrophysical/geological parameters.