Drilling and Completions operations optimization requires as starting point the building of an alive database that sustains the benchmark for a list of defined KPIs. The KPIs will represent main well construction activities conducted in different well types in a specific field. Once the data is captured and processed, the operations efficiency is obtained with the computation of the Invisible Lost Time (ILT). Computations are defined in different ways by different operators with different margins. The purpose of this paper is to probe that operational efficiency that can be tracked better when the percentiles lead the targets and not the Composite Best as a target. The continuous monitoring of the performance and the daily distribution of KPI's tracking dashboard has changed the mindset of the entire team, engaging the rig personnel in the identification of specific limiters that affect the performance and defining specific actions to take to revert the trend. The year to year comparisons showed a significant performance improvement in all the rigs but not at the same rate. The expected learning curve has deferred from one rig to another. A forecast tool has been created to generate an automatic AFE that delivers automatically TvD curves for the different percentiles and it is aligned to the latest rig's performance and the well architecture. This tool will help the drilling engineers to estimate, quick and more accurate, the well duration time, especially when the rig allocation is crucial for the yearly objectives of the project.
This paper is focus on the performance benefits when drilling data is streamed from rig sensors (high-frequency) and is integrated with daily drilling reports and well plans (low-frequency). The purpose is to systematically monitor and evaluate the performance of the entire rig fleet across the well construction process in the 20 land rigs drilling and completing oil and gas wells. The first step is to segregate each activity in the well construction process in main categories to allow the system to recognize the operational sequence from all the historical wells. A set of KPIs are defined for each one of the activities and the benchmark is set. Both high-frequency and low-frequency data are quality checked and computed into the pre-defined KPIs. Through the systematic analysis approach, the indicators are reviewed and in-deep understanding of rig capabilities, crew performance, operational constrains and drilling tools efficiency is made available to the team members, accessed via web-based application or automated daily report. With the help of the data coming from the rig sensors and the data collected from the daily drilling reports a perfect match result in a reliable source for the KPI generation is done. The procession of all the historical data provides a good insight to support the benchmark and proceed with the next step, which is the computation of the Invisible Lost Time, measuring the inefficiency of each one of the well construction activities. The drilling team takes appropriate actions using continuous improvement principles to identify waste and performance improvement opportunities. This also involves implementing all the best practices and introduce changes on the way we perform operations. Improvement plans can be prepared for achieving greater operational efficiency by evaluating everyday performance against agreed benchmarks and extend technical limits of established well plans, generating automated best composite times for future wells. Additionally, cost saving initiatives are identified in underperforming areas, non-productive time, and invisible lost time operations. This performance-based approach along with the multi-rig analysis platform has been a tremendous improving tool in the project and greatly enhanced rig performance, and some of the cases and insights to be shared might mutually benefit other operators and service companies in the region.
The deep carbonate reservoir formation on this field has proven to be an extreme High-temperature (HT) environment for downhole equipment. While drilling the 5000 - 6500 ft 5-7/8" slim long laterals across this formation, very high bottom-hole circulating temperatures is encountered (310-340 degF) which exceeds the operating limitation for the downhole drilling/formation evaluation tools. This resulted in multiple temperature-related failures, unplanned trips and long non-productive-time. It became necessary to provide solution to reduce the BHCT-related failures. Performed offset-wells-analysis to identify the BHT regime across the entire-field, create a heat-map and correlate/compare actual formation-temperatures with the formation-temperature-gradient provided by the operator (1.4-1.8 degF/100-ft). Drilling reports and MWD/LWD/wireline logs were reviewed/analyzed. Reviewed tools-spec-sheets, discovered most of the tools had a maximum-temperature-rating of 300-302 degF and were run outside-technical-limits. Observed temperature-related-failures were predominant in very long slim-laterals, which indicated that some of the heat was generated by high flow rate/RPM and solids in the system. Tried drilling with low-RPM/FR, did not achieve meaningful-temperature-reduction. After detailed risk-assessment and analysis on other contributing factors in the drilling process, opted to incorporate mud-chiller into the surface circulating-system to cool-down the mud going into the well. Upon implementation of the mud chiller system, observed up to 40 degF reduction in surface temperature (i.e. temperature-difference between the mud entering/leaving mud chiller). This was achieved because the unit was set-up to process at least twice the rate that was pumped downhole. Also observed reduction in the bottom-hole circulating temperature to below 300 degF, thus ensuring the drilling environment met the tool specifications. The temperature-related tools failure got eliminated. On some of the previous wells, wireline logging tools have been damaged due to high encountered downhole temperature as circulation was not possible prior-to or during logging operation. The implementation of the mud-chiller system has made it possible for innovative logging thru-bit logging application to be implemented. This allows circulation of cool mud across the entire open hole prior to deployment of tools to perform logging operation. This has made it possible for same logging tool to be used for multiple jobs without fear of tool electronic-components failure die to exposure to extreme temperatures. The long non-productive time due to temperature-related tool failures got eliminated. The numerous stuck pipes events due to hole deterioration resulting from multiple round trips also got eliminated. Overall drilling operations became more efficient. The paper will describe the drilling challenges, the systematic approach implemented to arrive at optimized solution. It will show how good understanding of drilling challenges and tailored-solutions delivers great gains. The authors will show how this system was used to provide a true step-change in performance in this challenging environment.
While drilling the 12" section, a water bearing formation is encountered prior to reaching the target gas reservoir formation. This formation is sporadically-charged across the field requiring a KMW up to 21 ppg. This poses major well integrity challenges as it becomes critical to avoid losses in the resulting narrow mud window and ensuring proper cement placement. Inability to predict the mud window makes it impossible to define the drilling strategy to implement. To understand the drilling challenges, in-depth offset wells analysis was performed. Based on mud weights required to drill across the reference formation, the heat-map for historical KMW was created based on confirmed well control events. It was difficult to predict formation-flow potential. Field geomechanics studies were then carried out to correlate the mapping done earlier. Once possibility of encountering abnormally pressured formation is flagged, in order prevent drilling risks such as loss circulation and poor cementing placement, proactive measures such as: Improved influx monitoring, drilling/cementing fluids optimization, liner-and-tieback system implementation, Managed Pressure Drilling/Cementing, optimized casing design were put in place. The integrated approach led to quick influx detection, proper definition of mud window, i.e. Pore Pressure and Fracture Gradient together, helped to prevent the losses, design of fit-for-purpose bridging strategy to ensure full drilling fluid column at all time while avoiding the cost associated with fluid losses. Drilling the section with Managed Pressure Drilling system (MPD) and low mud weight led to achievement of high ROP leading to substantial time saving. The Liner string was run and Managed Pressure Cementing (MPC) was implemented to manage the equivalent circulating density (ECD), avoid losses and ensure good zonal isolation. Overall non-productive time was reduced by 40% as compared to the offset wells in the area. Integrated drilling approach delivers great gains when there is good understanding of the well integrity challenges and solutions are tailored to solve identified problems.
The low success rate of curing complete loss of circulation across fractured carbonates in the field, where all kind of loss circulation material and unconventional plugs were tried without success, required better understating of the fractures and changes to the well design and drilling practices to ensure proper zonal isolation and well integrity. This paper describes the successful planning and implementation of these changes and how they improved overall well construction performance. As most of the total losses occurred in the intermediate section, which combines pressurized water injection formation with depleted oil-bearing reservoir, curing process was very often never achieved. Understanding that some areas of the field are naturally highly fractured, but specially characterized by carbonate karst, dissolution, and mega fractures, was critical to map the high-risk area and modify the well design and practices. The innovative risk-based well design was deployed to a series of wells across the field. The isolation between low- and high-pressured layers to prevent casing-to-casing annulus (CCA) sustained pressure[NMF1] throughout well life and, possibility of drilling ahead with no returns with one of layers already secured by previous casing were implemented. Suitable casing seat was selected in such way that critical high pressure and depleted zones were identified and isolated. Water-bearing layers in the upper section was efficiently balanced with enough mud weight and casing point set above risky zone with addition of double mechanical barrier with gas tight feature. Highly fractures formations in the lower section were drilled with significant lower mud weight at minimum overbalance, surge stresses and best possible fluid rheology. Casing running practices were adjusted to avoid inducing losses, cement slurries redesigned for optimum properties at minimum equivalent circulating density (ECD) and cementing jobs were conducted with full returns. The total loss events were significantly mitigated in the campaign, with overall 15% well performance improvement, ensuring zonal isolation, and reduction of future CCA occurrence, which can compromise the production casing integrity after fracking job, involves high remedial work costs, longer shutdown phase and possible production loss. This solution balances performance and costs can serve a technical reference for future application in the basin or other regions with loss-prone environment across large and fractured formations, and well integrity is a concern for operators and service companies.
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