Gas lift is becoming a predominant, intermediate term, artificial lift system in the Delaware and other basins. Besides the proper selection and management of the gas lift systems, design methodology is still a challenge due to the drastic change in flow conditions in the transient phase. The main objective of this paper is to develop a new methodology to design and optimize gas lift wells in unconventional reservoirs. A case study is provided to review, model, and analyze the current design over different stages of the well's production life. Consequently, application of new designs over different stages of the well's life will be implemented using a performance comparison which includes production and unloading scenarios. Actual well data will be used along with steady-state and dynamic modeling for unloading and production performance estimation. The models will be evaluated using actual data to perform history matching over different stages of the well's production life. This evaluation will also answer the following questions: Is the use of conventional mandrels the best option for these types of wells? Are the number of mandrels deployed using the traditional design methodology the correct solution? Are the tools used to design and analyze these types of wells sufficient? Most importantly, is more data required to create a better design and analysis? Also, this study compares the existing design to modified designs and justifies how the later could perform better. Integration of all data sources including historical performance, flowing bottom hole pressure, inferred dynamic IPR data, and the use of dynamic and nodal analysis tools for modeling while varying production conditions and unloading scenarios.

The continually evolving water management practices of liquids-rich tight oil operators (for optimizing the water use and costs of their water life cycle) is a topic of major impact. One area during the produced water phase of the water life cycle, is the less understood effect of different water cut fractions of the total fluids production from the formation on both the producing three-phase flow rate trends on surface as well as the downhole multiphase flow conditions, in particular, lateral to bend slugging and loading tendencies. This paper quantifies this effect of varying water cut production in a variety of operational conditions. In order to quantify the effect of varying water cut production, the methodology of this work involves first understanding the basic differences between gas-and-water (100 % water cut) and gas-and-oil (0% water cut) multiphase production in terms of their averaged slip behaviors, and therefore, total pressure gradient observations. We utilize published lab-scale flow loop experiments and a few actual, field-scale wells to demonstrate the different reported behaviors. An analytical multiphase flow simulator is then validated against these observations. Once verified, we then use the simulation tool to perform downhole calculations of flowing bottomhole pressure, gas volume fraction (gas-liquids slip), wellbore flow pattern, difference in wellbore and critical gas velocities and slugging flow characteristics (slugging frequency, velocity and lengths) for a given set of surface operating conditions. The workflows presented in this work will enable a deeper insight into the differences between gas and liquids slip under varying water cut fractions in both lighter condensate fluids as well as denser black oil fluids production. This work adds an improved understanding of the effect of water cut fractions on the total pressure gradient behaviors and downhole multiphase flow slugging and loading behaviors in liquids-rich tight oil developments.

The pressure and flow rates in an unconventional horizontal well decline rapidly, making artificial lift (AL) an integral part of development. Due to the dynamic behavior of these wells, the artificial lift life cycle is critical, and detailed attention to the AL system is needed at all stages for optimized recovery. This includes the selection and reselection of the proper AL method, adjusting the operating parameters, and scheduling the related workovers. With higher well counts and every well having some form of AL, a workflow to help in understanding the dynamic nature of the wells and to plan the artificial lift life cycle proactively will be beneficial. This has the potential to add significant value in terms of failure reduction, expense and downtime reductions, and improved operating efficiency. The objective of this paper is to present a workflow using field data and an example case study that is easily scalable and can be applied to any field to add value.

Agile, a scrum-based project management approach, is typically used in the software development arena, but it also has advantages in the oil and gas industry. This paper demonstrates the feasibility of this project management approach when applied to a full field development evaluation. Using this method for a multi-reservoir evaluation improved the quality and speed of decision making. The Agile process uses the scrum approach – a term borrowed from rugby where teams push the ball towards the goal together. We share a case study of evaluating a Gulf of Mexico platform and associated producing field, and we discuss the objectives, best practices, and lessons learned. Twelve reservoirs were thoroughly evaluated in only 5 months with multiple opportunities identified and ranked, a process that could take multiple years using conventional approaches. The blueprint of the process involved scrum lanes, sprints, and Minimum Viable Products (MVPs). Sprint meetings were held every day with the three core team members: a Geophysicist, a Geologist, and an Asset Engineer. Weekly scrum lane updates were provided to stakeholders to show progress and the potential opportunities identified. The technical workflow was funneled into three scrum lanes: 1) geophysical interpretation using 3D seismic data for subsurface framework; 2) geological mapping using well data for volumetric analysis; and 3) engineering analysis using production and pressure data for material balance. This process was iterative across the disciplines for each of the 12 reservoirs, and once all the analyses converged, the individual reservoirs were ready for economic evaluation. A scrum lane tracker was provided to the management team for weekly updates. Weekly sprints helped the team create the priority list. In cases when there was no reasonable MVP identified, the interval evaluation was moved to a lower priority, and efforts were then refocused on other intervals. Completed interval evaluations included economic analyses for remediation, recompletion, and sidetrack projects. Potential new drilling opportunities were also identified and ranked in a pyramid hierarchy based on the capital requirements and regulatory constraints. Using the Agile scrum-based approach for the analysis of multiple reservoirs in an offshore field was highly advantageous. Even with a compressed timeline and a small team, a high-quality technical and commercial product was delivered in a fraction of the typical project timeline. The level of technical detail, coupled with the relentless opportunity pursuit and overall high energy level, resulted in a productive and positive work environment that was acknowledged by the core team, asset peers, and management team. The frequent nature of the MVP results and deliverables also fostered and kept motivation levels high. The success of this pilot project will be used and adapted as a template for other asset evaluations.

Gas-assisted plunger lift (GAPL) could be an effective and economically favorable artificial lift (AL) method to be considered during the AL life cycle for North American shale wells. The main advantage of GAPL is that it improves the well production by reducing liquid fallback and boosts the plunger efficiency through gas injection and increases the gas lift efficiency by assisting in delivering the slugs to the surface. The objective of this study is to capture the GAPL dynamic behavior through a transient multiphase flow simulator. The entire GAPL production cycle was modeled, including plunger fall, gas injection, pressure buildup, and production. First, the GAPL well production history was analyzed to evaluate the well operating condition. Then, a transient simulator was used to model the well flow behavior and production performance with GAPL. The study demonstrated the GAPL impact on flowing bottomhole pressure and the improvement in the well productivity. A Delaware Basin well case study demonstrates the benefits of dynamic modeling and provides a comprehensive comparison between dynamic simulation results and field data. The simulation work provides insights into the fluid flow, GAPL behavior, and pressure and rate transients of a GAPL well. The modeling results were validated against field data. A commercially available transient multiphase flow simulator was used and produced outcomes that were in alignment with field data collected. The dynamic plunger cycles were reproduced in the simulation, and the results showed the benefits of GAPL in a typical shale oil well. This could extend the gas lift life by delaying the transition to rod pumps or potentially act as an end-of-life AL solution. In the long term, this reduces the overall AL life cycle cost. The use of transient simulation helps validate AL design concepts, especially for unconventional wells where the flow behavior is very dynamic. This study encourages the use of this analysis in the AL selection workflow to help optimize the overall AL life cycle cost and maximize the net present value (NPV).