Poststimulation operations on multistage hydraulically stimulated horizontal wells producing from conventional and unconventional reservoirs have a major impact on long-term well performance. Most common types of poststimulation services on such wells include plug drillout (PDO) operations and well flowback (WFB) operations. During these operations, the hydraulic fracture system experiences major changes in pressure and flowrate, which may affect the well's long-term productivity. Among the many mechanisms responsible for decrease in well productivity, we highlight 1) the risk of losing the connection between the wellbore and hydraulic fracture system because of the development of an unpropped area; 2) rock destabilization, and 3) the risk of scaling and precipitation. In this paper, we describe an integrated engineering and operations workflow for optimizing poststimulation operations on horizontal wells by controlling the productive fracture system evolution during the poststimulation period. The approach is based on applying the secure operating envelope (SOE) concept, which provides a set of operating parameters that ensure preservation of the connection between the hydraulic fractures and wellbore. The SOE is defined for each individual well, using a combination of geomechanical and multiphase transport modeling. It accounts for reservoir properties, well completion, and fracture treatment parameters. High-resolution, real-time monitoring of well performance and active control of bottomhole conditions through choke management ensure the well is operated within the SOE. The production objectives combined with the evolution of the SOE enable an overall strategy for poststimulation operations. The paper outlines how the SOE is constructed. Applications of the proposed approach on horizontal oil and gas wells in unconventional reservoirs in North America are reported, both during well flowback and plug drillout operations. Using the SOE during well flowback helps to predict and avoid a decrease in well production performance caused by excessive proppant flowback which results in creation of near-wellbore pinch points inside hydraulic fractures. Additionally, plug drillout was identified as a critical operation, during which the proppant pack can be destabilized. The associated risk was strongly reduced by applying the SOE concept in combination with high-resolution monitoring. Based on data obtained from more than 50 operated wells, we conclude that the proposed methodology, including application of geomechanical modeling to poststimulation operations, brings significant opportunities for optimization of well performance and securing long-term well productivity.
Highly efficient multi-stage hydraulic fractured horizontal wellbores are the dominant completion method for many basins worldwide. One potential weakness of multi-stage hydraulic fracturing is that the later stages of the completion workflow – frac-plug drill out (FPDO) and flowback – cause large pressure fluctuations and transient flows through the perforation clusters that coincide with a period of low closure stress in the fractures. The proppant packs in the fractures during this period are fragile and prone to failure. Previously reported results show that flowback and initial production practices have a major impact on proppant production, maintenance and disposal costs and the subsequent well performance. In this paper the results from over 200 FPDO and flowback operations from the United States and Argentina are reviewed. These results show that maintaining a balanced flowrate during FPDO operations is critical for minimizing inadvertent damage to the hydraulic fracture network. The FPDO flowrate balance is the difference between the coiled tubing injection and annular return flowrates. The magnitude and sign of the balance corresponds to the instantaneous flowrate through the open perforation clusters into or out of the hydraulic fracture network. A positive balance rate, or overbalance, injects fluid into the fracture system. A negative balance rate, or underbalance, produces stimulation or formation fluids from the fracture network. Sudden changes between these two regimes creates local flows that can be severe enough to flush large quantities of proppant out of the fractures. Our results show that high-frequency multiphase flowmeters simplify the process of maintaining balance (no inflow, no outflow). Furthermore, close monitoring of any imbalance that develops, and rapid control of the surface choke and injection rate, can provide for an efficient operation while protecting the integrity of the fracture system. Early monitoring of flowback and production with a high frequency flowmeter was shown to be extremely useful technique for optimizing well productivity during well clean-up. This paper also shows how a dual energy gamma ray multiphase flowmeter successfully quantified proppant produced during FPDO and flowback. Examples of the dynamics of sand production are shown, as well as correlations to events of excessive underbalance conditions. At the end of the paper we show that most of the highlighted problems can be solved through making changes to the well construction workflow and accounting for relationships between various well operations. Incorporation of this workflow enables early prediction of well performance issues and their efficient resolution.
The measurements available to estimate reservoir parameters are numerous, yet most wells are completed in various shales without traditional log measurements. Horizontal wells continue to be drilled, and while the number of stimulation stages pumped per lateral length continues to increase, many questions remain: Is there an increase in production commensurate to the added cost, or will it soon become unsustainable? Would better characterization of the effective surface area after hydraulic fracture stimulation help explain the reservoir potential? Analysis of production data from fractured shale gas wells is difficult. Operators try to estimate fracture and reservoir properties for a horizontal well with multiple hydraulic fractures by using pressure transient testing, even though in reality it could take 10,000 years for the actual reservoir pressure to be measured. Alternatively, others model the production of fractured shale gas reservoirs from a zone-altered permeability area, which may be quite limited in areal extent but is surrounded by a low-matrix-permeability reservoir to account for the well productivity. Ultimately a simplistic reservoir model for production forecasting uses whatever data is available and our basin experience. How do we validate these models? Traditionally we look at case studies to find an analogous situation to validate and identify the dominate production drivers. Existing approaches to model shales require years of production data, and even then they cannot uncouple reservoir properties from completion parameters to help optimize flow efficiency. When production is measured on a stage-by-stage basis, and laboratory and log analysis data are presented for reservoir and fluid characterization, solving for the created effective surface area should be straightforward. By better characterizing along the wellbore and by discriminating the contributions of RQ and CQ to the reservoir production, we will be able to better predict long-term well production and better understand the reservoir potential. This paper discusses the current status of production prediction for shale gas reservoirs and provides a vision of possibilities for better interpretation, i.e these production models must go hand-in-hand with hydraulic fracture models to determine the crucial parameters that drive production, thus fully optimize well and field production.
As many unconventional basins are maturing, infill well drilling and completion has taken the center stage in the development phase. Most operators now realize the importance of incorporating the geomechanical changes induced by stimulation and production of the parent wells while placing infill child wells. But after drilling and completion, post-stimulation flowback is also critical in maintaining well productivity and performance. To optimize field management strategy, a comprehensive understanding of the impact of production induced geomechanical property changes on infill well performance and its safe operating window for flowback operation is important. This paper investigates a well located in Permian basin and provides insights on flowback operation strategies for infill well using fully coupled finite element model and flowback simulator to help reduce fracture damage and maximize well deliverability. First an integrated workflow coupling fracture, reservoir and geo-mechanic models is used in this paper to systematically investigate the depletion effects. Then a flowback simulator is utilized to robustly study the safe operating window for the infill well, implementing updated formation properties from previous model. A corresponding base model is created over wells completed in the Permian basin with geo-mechanical earth model generated from logs and field data. The integrated workflow with finite element computation was applied to predict the induced stress change after stimulation and production. To better understand the influence of geomechanical property changes over infill well performance and proppant flowback, a second model is also created, but without consideration of any production induced geomechanical property changes during flowback simulation. The differences of safe operating window simulated from these two models are compared and anaylized to reveal the impacts of stress change over the infill well in this area. Guidelines for adjusting choke settings and possible completion re-design are recommended to help reduce proppant flowback and improve the overall well productivity. Based on the numerical results from above modeling study and comparison, flowback strategy is analyzed for infill well. In normal stress environment, due to the change in stress state from production and increase in differential stress around the wellbore, the choke management and possible completion design are adjusted accordingly as to reduce proppant flowback and optimize well performance. In addition, the capability of the workflow to model pressure depletion and associated stress conditions with respect to time enables us to optimize the field development for the area in long term. The study presents a reference to strategic planning for operators and service companies to manage their infill well flowback operation on an existing pad with improved completion efficiency and stimulated volume in Permian basin. Intensive flowback operation management can help yield significant improvement in the well's long-term performance.
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