Factory-Model Approach Improves Performance of Coiled-Tubing Drillout
This paper presents a factory-model approach to improving CT drillout performance that has been used successfully for more than 3 years and has become standard practice.
As drilling and fracturing operations improve, there is a need to adapt current coiled-tubing (CT) drillout processes to a more fit-for-purpose approach applicable in any area, regardless of lateral length, number of plugs, and reservoir target. This paper presents a factory-model approach to improving CT drillout performance that has been used successfully for more than 3 years and has become standard practice. The paper includes detailed discussion of the methodology used to create a successful, repeatable, and operationally safe process; field case studies and results; and engineering, design, and implementation of new technologies to improve the process.
CT practices have become increasingly effective in plug drillout operations by reducing the operational cost, environmental exposure, and time to production. Techniques for no-wiper or short trips and plug milling, added benefits from extended-reach bottomhole assemblies (BHAs), and improved fluid-system monitoring methods have helped enhance overall performance. However, there are still components within each of these techniques that can be evaluated.
Background and Methodology
Results of a thorough evaluation of the CT drillout process revealed that the factors with the greatest influence on improving performance included the following:
- Wellbore trajectory
- Plug type
- CT size
- BHA selection
- Fluid-rheology quality assurance/quality control (QA/QC)
- Real-time modeling
Wellbore trajectory is an important factor because it has a major effect on the ability of a CT unit to reach plug-back total depth. High tortuosity in the lateral section can cause plug parts and sand to settle on the low side of the wellbore, making adequate cleaning of the hole by increasing overall friction difficult.
Proper plug type and design serve two purposes: to provide a barrier between stages during hydraulic-fracturing operations and to be easily removed from the wellbore during drillout. Ideally, a fully composite plug should be selected because the lower specific gravity of the material aids in removal.
The proper CT size can lead to a more-successful drillout because it allows for higher pump rates, leading to better hole cleaning. Additionally, larger outer-diameter CT (2⅜ in. or greater) ensures sufficient weight on bit (WOB) in the toe of longer laterals to reduce friction pressure and protect against helical buckling.
Integrating a proper fluid rheology QA/QC system with small plug parts makes hole cleaning far more efficient and effective. With a better understanding of the fluid rheology, hole cleaning can be maximized by focusing on two critical aspects: monitoring the viscosity of the gel sweeps going in and coming out and developing an appropriate sweep schedule. Monitoring the fluid viscosity allows for determination of whether the fluid has adequate gel loading to carry debris and sand out of the wellbore. Measuring and understanding the fluid viscosity helps determine whether the drillout fluid is in turbulent flow. This is critical in CT drillout operations because it allows or increases hole cleaning in the eccentric part of the wellbore, which is the low side of the wellbore or CT annulus.
Real-time modeling, implemented for the factory-model approach, has been able to help determine whether to perform a condition-based short trip. Real-time modeling also has improved communication between engineers, managers, and all service providers during CT drillout. Communication among all parties involved helps them understand their role in the process and increases the likelihood of success (Fig. 1).
Rather than instituting and optimizing the critical factors at one time, a step-by-step road map was created so improvements could be measured easily. During a 5-month trial period, the factors were implemented and analyzed fully. Once the methodology was validated with predictable, repeatable, and successful consistent outcomes, it became the new standard for CT drillouts.
Field-Trial Case Study
The first steps in the factory-model approach were implemented in April 2015 on a multiwell pad. These consisted of CT-size optimization, BHA selection, and real-time modeling. Wellbore trajectory and plug type were considered in every phase. The lessons learned and best practices from the initial rollout were captured and transferred to the next pads. The next two multiwell pad installations took place in June and July 2015. This rollout consisted of the new fluid-rheology QA/QC process and an engineered sweep pumping schedule. The integration of these new factors, in addition to improvements from past pads, allowed for the reduction of the number of short trips per well. On the second pad, the advancement consisted of drilling out five plugs before a short trip to drilling out seven plugs. The third pad started with drilling out seven plugs and increased to nine plugs without any issues. The real-time modeling and fluid rheology QA/QC data from Pads 2 and 3 revealed that the wellbore was being cleaned effectively. This confirmed that the planned and prescheduled short trips performed in the past were providing no additional benefit. This new realization allowed the team to move toward the next step—performing CT drillouts with only condition-based short trips, meaning no planned short trips unless hole conditions, equipment failures, or other abnormalities required them.
On the fourth pad, in September 2015, two wells were drilled out successfully at 19 plugs per well without performing a short trip. The other two wells on the pad, also at 19 plugs per well, required only one prescheduled short trip. These advances in CT drillouts culminated on Pad 5 in October 2015, when the entire process was implemented using only condition-based short trips. On this pad, 30 plugs were drilled out without a short trip for three out of the four wells on the pad, while the fourth well required one condition-based short trip because of third-party nonproductive-time (NPT) issues. The new methodology for CT drillouts became the operator’s standard across the Permian Basin.
The complete paper includes a comprehensive discussion of the primary factors influencing CT drillouts and how these factors were implemented in the field trial. The authors also discuss how completion-design changes, such as longer laterals and tighter cluster spacing that resulted in more plugs needing to be drilled out, provided an opportunity to use new technologies to drive performance improvements. Specific topics include polycrystalline diamond bits, downhole memory-tool data analytics and results, WOB, and removal of dedicated drilling flowback and completions flowback from the CT drillout process.
Some areas of the Permian Basin had seen a standard practice of performing flowback operations immediately after CT drillout was completed to clean up any excess sand, solids, debris, or fracturing fluids that had not been cleaned up during CT drillout. After the flowback was completed, the wells were connected to the battery through the production flowlines. Depending on the area, this process could take an additional 7 to 14 days of time and associated cost, which delayed well put-on-production (POP) time. After the factory-model CT-drillout process had been in place for some time, the wellbores were seen to have been cleaned successfully. Thus, a crossfunctional initiative was established to move away from flowback. Sand separators were used to mitigate any damage to the central tank battery. Considering the additional cost for extra surface equipment for an expected number of days, the savings associated with not performing the flowback equated to approximately $90,000 per well. However, the most influential benefit from this change was the ability to put the wells on production immediately after CT drillout—10 days sooner on average.
Full implementation of the factory-model CT-drillout methodology has been used successfully for more than 3 years and continues to be the standard process. The well-performance effect realized by optimizing the main factors has been substantial, as have technological advancements.
Appropriate engineering design led to better understanding of the fluid-rheology system and optimal chemical usage and dosage during drillouts. These, plus proper CT size and BHA optimization, have optimized pump-rate capability and annular velocity while minimizing plug-debris size to improve hole-cleaning efficiency. Using real-time data and data analytics to identify trends in downhole tool data has optimized procedures.
Since the inception of this methodology, more than 320 horizontal wells have been completed successfully across the Permian Basin, regardless of reservoir target, well type, or wellhead pressure. Lateral lengths have ranged from 5,000 to more than 10,000 ft, and well plug counts ranged from 19 to 102. Average time savings is shown to be 66%, and average cost savings is 61%. In addition, the process has eliminated large NPT events, provided additional cost savings, and reduced POP-cycle times.
According to the authors, the factory-model CT-drillout methodology can be reproduced and successfully applied with minimal or no modifications in any unconventional basin across the world.
This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 191689, “Factory-Model Approach for Successful Coil-Tubing-Unit Drillout Operations in Unconventional Wells,” by Jesus Barraza, SPE, and Chris Champeaux, SPE, Chevron; Heath Myatt, SPE, and Kyle Lamon, C&J Energy Services; Ryan Bowland, Spartan Energy Services; Troy Bishop, SPE, and Jerry Noles, SPE, Coil Chem; and Rocky Garlow, RGC Consulting, prepared for presentation at the 2019 SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, Texas, USA, 5–7 February. The paper has not been peer reviewed.