A major challenge when operating a gas lifted unconventional well is severe slugging. Without addressing its root causes, production fluctuation can remain for a long time and pose high risks to the entire operating system. This paper first reviews the gas lift for U.S. unconventional shale plays. Then it describes the major causes of gas lifted shale well slugging and proposes mitigation plans respectively, considering the implications on value and profitability. A systemic diagnostic workflow was developed for shale well slugging by combing production data analytics and dynamic simulation workflow. It also incorporated cost benefit analysis to evaluate incremental economic value. Transient modeling reveals key aspects of gas lift well slugging causes. A case study involving a shale well demonstrates the technical and economic impact of this transient behavior on gas-lift well performance. This study can assist operators in developing a mitigation plan for gas-lifted shale well severe slugging through transient simulation and in leading to substantial cost saving while extending asset economic life. It also demonstrates that transient multiphase flow simulation is an effective tool for the troubleshooting and the mitigation strategy selection for unconventional shale wells under gas lift.
The stress state at infill wells changes as a function of production from the existing producer. Understanding spatial and temporal in situ stress changes surrounding drilled uncompleted (DUC) wells or infill wells has become increasingly important as the industry works through its inventory of DUC wells and redesigns infill wells with an engineering approach. Optimizing infill/DUC well completion designs requires an estimation of the altered in situ stress state. This study presents the concept of a "production shadow" as the stress change in four-dimensional space, affecting well performance and optimal well configurations for pad development. The production shadow accounts for the compound effects from both hydraulic fracture mechanical opening and stress-state alteration from depletion. This paper details an Eagle Ford case study integrating production shadow effects into the parent and infill well hydraulic fracture modeling as well as "frac hit" analysis. The production shadow influences the degree of fracture complexity developed by the infill/DUC well stimulation. Understanding and accounting for the production shadow are critical in engineering to establish and preserve an optimal connection of the induced stimulated fracture network to the wellbore.
In response to the low hydrocarbon price environment, most operators have decreased the number of rigs actively drilling wells (Cui 2016, Chapman et al. 2016). However, the production decline in wells completed in a given timeframe has undergone far more change than the count of active rigs. In many cases, wells must be drilled to meet contractual lease obligations but are not being completed due to uncertain economic conditions. Type curves are valuable tools to predict future performance of such drilled-but-uncompleted (DUC) wells by analyzing results of existing wells exhibiting similar characteristics. It is reasonable to assume, while considering reservoir characterization and completion engineering, that existing wells can predict the performance of future wells. However, to generate a larger sample size with which to construct the type curves, data can be normalized by a particular variable. A normalized curve is then scaled by an adjustment associated with the new well to produce its expected production profile. This same process also allows type curves to be applied to other areas with different reservoir properties or completion parameters. Analysis focuses on applying normalized type curves to estimate DUC well performance and populate a ranking system to guide the completion planning process. Reservoir material balance and surface network simulation are also utilized to understand subsurface effects and identify possible facility constraints above ground. Additionally, there is a brief discussion regarding type well best practices to aid in the analysis.
Production drivers including reservoir, completion quality, and number and quality of hydraulic fracture stages influence overall production performance of a well. In an integrated engineering study, all production drivers were assumed to be very similar except for the well horizontal lateral length. Well production rate was calculated with horizontal lateral lengths varying from about 1,000 ft to 20,000 ft with an increment of 1,200 ft. Statistical field data and integrated reservoir-wellbore simulation were compared to draw a comprehensive conclusion. Different domain engineering principles were used to understand the impact of increase in lateral length on production performance of horizontal shale wells.
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