Since early 2016, commodity prices have been gradually increasing, and the Permian Basin has become the most active basin for unconventional horizontal well development. As the plays in the basin are developed, new infill wells are drilled near pre-existing wells (known as "parent wells"). The impact of pressure depletion caused by adjacent existing producers may have a larger role in the performance of these new infill wells. How the various well spacing impact with the degree of reservoir pressure depletion from parent well is more important than ever for operators to optimize the completion design. Through data analytics and comprehensive fracture/reservoir modeling this paper studies how changes in well spacing and proppant volume in the Spraberry, a main formation in the Permian Basin, will impact new infill well performance. The studies in this paper are focused on the Midland Basin. A public database was used to identify the number of parent and child wells in the Midland basin. Data analysis of production normalized by total proppant and lateral length shows that parent wells outperform infill, or child, wells. To further understand the relationship between parent and child wells, a reservoir dataset for the Spraberry formation was used to build a hydraulic fracture and reservoir simulation model for both the parent well and a two-well infill pad. After production history matching a P50 type well as the parent well, three periods of production depletion were modeled (6 months, 3 years and 5 years) to understand the timing impact on the infill well production. A geomechanical finite-element model (FEM) was then used to quantify the changes to the magnitude and azimuth of the in-situ stresses from the various reservoir depletion scenarios. A two-well infill pad was then simulated into the altered stress field next to the parent well at various spacings between the parent and child wells. A sensitivity was then performed with different stimulation job sizes to understand the volume impact on created complex fracture propagation and total system recovery. This study can help operators understand how well spacing, reservoir depletion, and completion job size impact the infill well performance so they can optimize their infill well completion strategy.
As a major unconventional resource play, the Williston basin contributes more than 10% of total U.S. crude oil production. Due to significant concerns about net present value and payback period, the process to select the optimum artificial lift method has always been a top priority for operators. In this case study, we investigate the potential artificial lift strategies for new wells in Williston basin. The objective is to propose an artificial lift strategy that handles the challenges associated with unconventional resources and that maximizes the asset value. In this study, a novel workflow that replaces subjective decisions with objective analysis has been applied for the process of selecting the lifting strategy that will best achieve an operator's goal based on analysis of technical criteria and economic calculated results. An initial prescreening is performed to narrow down the number of applicable artificial lift systems that will meet the technical challenges of the well. Then, the selected artificial lift methods are evaluated combining a steady state flow simulator and a reservoir model to determine the well performance and response to each lift system. This response is integrated with an economic model to determine the net present value of the proposed strategy. Different strategies and sensitivities on key parameters as oil price, expected production, and water cut are performed to determine the optimum artificial lift approach. The ability to include future well performance based on a reservoir model helps in building a strong analysis that goes beyond current well conditions and includes the changes that occur to the reservoir during the production phase, such as pressure depletion and consequent production decline. Those changes drive the need to switch from one artificial lift system to another as conditions evolve. The workflow allows the user to determine the best time to start the selected artificial lift system and the appropriate transition time to a second artificial lift method. For the Williston basin case study, only electric submersible pumps (ESP) and jet pumps (JP) can be implemented during the high-flow-rate period. As production declines, a transition to a lower-flow-rate method is required. Hydraulic rod pump systems are considered the most appropriate transition method because they make it possible to pump the required volumes from deep installations. A production forecast is combined with two different water cut scenarios to evaluate the impact on the economic results of the project. The successful use of this workflow has proven its ability to analyze the life cycle of an unconventional well and establish a process for artificial lift selection. Furthermore, the current workflow is flexible enough to be extended to other fields with different input variables.
The challenges of unconventional reservoirs have driven electric submersible pump (ESP) providers to continue making improvements to the mechanical design of the pump stages. These improvements enable covering wider operating flow ranges and maximizing production without the need to replace the artificial lift system with a different method such as gas lift or rod pumps. In 2016 and 2020, two new pump types were introduced as a solution for unconventional wells. This case study summarizes the results of the analysis of 52 ESPs installed with the new pump types in the Midland Basin from 2019 to 2021 for a leading operator in the basin. The operator's well test data showed a declining production averaging from 1,300 to 100 BFPD, with water cut from 40% to 99% and gas-oil ratios up to 9,000 SCF/STB. This paper presents the results of how the re-engineering of a standard mixed-flow stage becomes a solution to improve the performance of the ESPs when producing from unconventional shale plays where the downhole environment is extremely harsh. The re-engineering of the standard mixed-flow stage produced a stage characterized by high hydraulic performance and superior efficiency. The study's conclusions can also be applied to conventional shale plays with more benign conditions. To develop the new stages used in the two new pump types, an engineering team conducted an extensive study considering the available run life data and the results of the top failure modes of the ESPs when operating at low flow ranges in unconventional wells. The engineering team considered a stage design to optimize the operation in the low-flow-rate region by a better distribution of downthrust and stress management of the pump's internal components.
Several methods have been deployed for artificial lift in deep long horizontal wells completed in unconventional reservoirs. Some methods have been successful whereas some others have failed. In our study, we investigated the various lift mechanisms and derived an envelope for their application to such horizontal wellbores using a sensitivity study through a transient fluid- flow wellbore model. A calibrated earth model from the Eagle Ford Shale basin with hydraulic fracture geometries in the horizontal wellbore was used for the sensitivity study. The wellbore profile was changed in the simulation model to four different types of profiles: toe up, toe down, toe up with hold trap, and toe down with hold trap. Other factors such as location of the artificial lift equipment in the wellbore, reservoir performance, and deliverability were considered for the deployment of the artificial lift method. Transient fluid-flow wellbore simulations and numerical reservoir simulations were used to determine the performance potential and effectiveness of the artificial lift mechanism for long-term productivity. Multiphase fluid flow and transient flow phenomenon are critical modeling considerations for horizontal wellbores. It was found that the critical flow rate in horizontal wells can vary considerably when the well profile is considered. As the drilling dogleg severity increases, the chances of wellbore slugging and liquid holdup increase. Additionally, with producing time, the conditions change. In a gas lift well, if the gas injection rate is maintained above the critical rates as determined in this study, the production issues can be controlled. Therefore, it is clear from this study that the well trajectory and drilling uncertainty window must also account for the artificial lift method that is planned to be deployed. Adjustments to the artificial lift method placement in the wellbore would help offset negative impacts if the wells are poorly drilled. Recommended practice for drilling, completion, and artificial lift can be derived from this study. Integration of the artificial lift selection to the earth model, drilling trajectory and landing, hydraulic fractures, and the completion model is paramount to improve the efficiency of artificial lift in the unconventional reservoirs.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.