The oil and gas industry has operated in Denver Julesburg (DJ) basin for many decades. Currently in the basin, increasing population density and wellbore complexity have resulted in a heightened visibility of long-term well integrity. Failure can lead to future liabilities, loss of public trust, and a revoked right to operate. Operators must demonstrate commitment to well integrity to continue operating in the basin, yet many still report sustained casing pressure (SCP) on a significant portion of wells. Because SCP corresponds to the open communication of fluids to surface, it is a direct metric of well integrity failure. Regulations require operators to report and remediate instances of SCP on all wells. On average, clients experience one well with SCP for every five drilled. As a primary well barrier element, the cement sheath is vital to well integrity improvement. Enhanced placement techniques of conventional cements failed to prevent SCP, confirming that failure is derived from post-placement dynamic conditions. The solution must account for pressure and temperature stresses, preventing and mitigating mechanical failures throughout the well life cycle. A flexible and self-healing cement design provides a twofold response that is ideal for wells in areas, such as the DJ basin, with SCP risk. Mechanical properties are optimized based on the results of a mathematical stress model. Although Portland-based cement systems can be optimized to sustain higher levels of dynamic stresses, it is impossible to avoid a mechanical failure entirely. Therefore, a self-healing function is a critical secondary feature. The self-healing mechanism is designed to activate upon contact with an invading hydrocarbon and can be formulated for any type of hydrocarbon, from high gravity oil to dry gas. Flexible and self-healing cement has been successfully designed and implemented on approximately 250 wells in the DJ basin with a reduction to 2% instances of SCP. Elimination of SCP provides confidence in long-term well integrity, which is essential to continued operation in the basin.

One of the primary challenges of cementing and achieving effective zonal isolation is removing nonaqueous drilling fluid from the wellbore. Microdebonding of the cement sheath is a significant risk to overall well integrity, potentially leading to sustained casing pressure and health, safety, and environment (HSE) hazards. Field applications of a new fiber technology, designed with an optimized surfactant and mutual solvent package, have provided improved cement evaluation logs. Such trials also reduced or eliminated sustained casing pressure. This novel application of fiber technology in weighted spacers ahead of cement placement has been tested and evaluated with success. Modified rheometer rotors were among several new techniques developed to identify the efficacy of these cement spacer packages. These tests provide greater insight into fiber, surfactant, and mutual solvent performance, and have been validated in the field with ultrasonic and acoustic cement evaluation log results. Detailed laboratory analysis suggests superior effectiveness of the fiber, surfactant, and mutual solvent design. These preliminary results established the confidence to pursue a field trial on a number of development wells in an unconventional liquids play. Cement evaluation logs confirmed that the new technique successfully reduced microdebonding. Additionally, sustained casing pressure was significantly reduced, indicating that the log response correlates to a tangible improvement in well integrity. The novel use of fiber technology considerably improves the surface cleaning effectiveness of cement spacer package. Additionally, new laboratory testing procedures enhance our understanding of surfactant package function. Successful laboratory results were validated by field applications that reduced the microannulus in sample wells and minimized sustained casing pressure.

Industry-wide cement plug failures account for more than 1,000 hours of lost time and USD 20 million in nonproductive time (NPT) costs each year, including individual failures responsible for up to 350 hours of lost time and USD 3 million in NPT costs. These failures include unset or soft cement that cannot meet the plug requirements, top of cement not at the designed depth, loss of cement plug, and stuck pipe. The causes of cement plug failures include incorrect temperatures, slurry contamination, cement falling in the wellbore, and inadequate displacement methods.Best practices applied during a new process include temperature mapping of major fields, evaluation of the plug base, implementation of mechanical fluid separation, optimization of balancing fluids while pulling out of hole, and mathematical modeling of fluid contamination. The peer-review process for the design answers four simple questions: Is the design documentation complete and accurate? Does the design meet a clearly defined client objective? Does the design adhere to plug cementing best practices? Is the cementing crew prepared to properly execute the job?In 2012, nine western US cement plug failures resulted in over 200 hours of lost time and USD 500,000 in NPT costs. The lack of technical design criteria and accountability process demonstrated the need for improvement. In response, a regional investigation and quality initiative were launched. The investigation found regional failures related to cement contamination, incorrect displacement, poor slurry design, and incorrect well data. As a result, a specific process for handling all plug cement jobs was implemented. This process included adherence to a number of plug cementing best practices and a peer-review of all plug cement designs.Approximately 500 cement plug jobs have been executed within the last 27 months in the western US region since the implementation of the plug cementing process. In this time, there have been no plug failures, no NPT, and no rig costs from failed cement plug operations.