The BL Vintage Pad project, located in the Denver-Julesburg (DJ) Basin, consisted of seven Buckley wells and two Barr Lake wells.
The initiative aimed to optimize drilling performance, reduce cost per foot, improve lateral efficiency, and consistently hit geological targets.
With well depths nearing 23,000 measured feet and average well costs around $2 million, the pad served as a testing ground for strategic improvements in rig selection, wellsite coordination, solids control, and power sourcing.
By analyzing drilling KPIs, non-productive time (NPT), and cost variances, the team identified key inefficiencies and implemented best practices to improve future well operations and maximize financial returns across the basin.
The Challenge
Operational hurdles significantly impacted both efficiency and cost throughout the project.
High Non-Productive Time (NPT)
A total of 171 NPT hours, representing 9% of total operational time, were recorded. The worst-performing well reached 24% NPT due to drilling rig equipment failures, including traction motor breakdowns.
Increased Mud Weight and Costs
Common DJ Basin formation challenges resulted in increased mud weights, requiring an additional 298 tons of barite and significantly increasing material costs.
Vibration and Well Flow Complications
Drilling vibrations reduced rate of penetration (ROP), while near-total-depth well flow conditions increased fluid consumption and treatment frequency.
Unexpected Power Cost Inefficiencies
The original well plan called for a highline power rig with diesel engine backup. Due to scheduling conflicts, a rig with compressed natural gas (CNG) backup was used instead. This introduced recurring costs of approximately $30,000 per month for on-site CNG trailer rentals, demonstrating how scheduling-driven rig selection can create significant cost variability.
The Approach
To mitigate these operational challenges, the team implemented several targeted strategies.
Power Optimization
The team conducted cost comparisons between highline/CNG hybrid rigs and alternative power systems to identify opportunities for reducing monthly operational power costs.
Solids Control Enhancements
A second centrifuge was recommended to manage increased solids generated by anticipated well flows near total depth.
Managed Pressure Drilling (MPD)
Managed Pressure Drilling (MPD) was evaluated as a method for controlling mud weight and wellbore pressure while reducing barite and additive usage.
Drilling Vibration Mitigation
The team adopted longer gauge bits and high-frequency torsional oscillation tools to reduce drilling vibration and improve rate of penetration.
Improved Cementing Performance
Engineering planning and precise on-site execution, supported by strong project management, resulted in superior cement jobs. Halliburton followed planned pump schedules, accounted for Equivalent Circulating Density (ECD) adjustments, and increased spacer volume, producing high-quality bond logs.
The Results
The nine-well program delivered measurable operational improvements and cost-saving results.
Lateral Efficiency
All nine wells achieved 100% completable lateral lengths, with the Buckley wells reaching peak lateral utilization of 91%.
Drilling Time Reduction
Average drilling time was reduced to just over five days per well, with “clean time” operations accounting for 91% of total activity.
Cementing Quality
Bond logs confirmed excellent wellbore integrity, validating the effectiveness of the cementing strategy.
Power Cost Savings
Analysis demonstrated that using rigs that did not require on-site CNG trailers could reduce operational power costs by more than $30,000 per month.
These findings contributed to the development of a replicable best-practices playbook, helping ensure future DJ Basin wells are executed with greater cost efficiency, reduced operational risk, and optimized performance.