Defining the Optimal Drawdown Strategy in the Vaca Muerta Formation

Lerza, Alejandro; Rojas, Daniela; Liang, Baosheng

doi:10.15530/urtec-2018-2880115

Cited by 6 publications

(3 citation statements)

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“…To achieve optimal economic benefits of the Vaca Muerta block, Alejandro Lerza 65 proposed a geo-mechanical reservoir model by coupling the uncertainties of reservoir parameters and proppant performance parameters and designed a DOE method to detect the reliability of the production method under the deterministic parameter conditions.…”

Section: Results and Discussionmentioning

confidence: 99%

“…According to the decreasing speed of bottom hole flowing pressure, the pressure drop control strategy is divided into the conservative type, standard type, and aggressive type. ,, Studies have shown that there is an optimal pressure drop management time for bottom hole flowing pressure . Whether the pressure drops too fast or too slowly, the long-term EUR of the production well can be reduced.…”

Section: Results and Discussionmentioning

confidence: 99%

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Pressure Drawdown Management Strategies for Multifractured Horizontal Wells in Shale Gas Reservoirs: A Review

Liu

et al. 2022

ACS Omega

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The flow capacity of shale gas reservoirs is easily impaired during the depletion process due to strong stress sensitivity. Thereby, an adequate production system, namely, the managed pressure drop method, has been widely introduced to the industrial practice application by decelerating the wellbore pressure drop rate and ultimately improving the long-term production process. This work presents a review of the pressure drawdown management mechanisms for shale gas formations. However, clarifying the water–shale interaction physical chemistry process and developing a mathematical model that accurately describes the water–shale interaction mechanism remain a challenge. Moreover, different classifications of the managed production simulation research approaches are discussed in detail. Each approach has its own merits and demerits. Among them, numerical simulations are commonly seen in cognizance of characterizing the managed pressure drawdown production period but are found to be relatively time-consuming and also computationally expensive. An optimized theoretical model is therefore essential because it can lead to a precise estimation of the ultimate long-term production and capture instantaneously the actual shale gas reservoir depletion phenomenon with various production systems compared to other available methods. The key influence of managed pressured production for single wells in shale reservoirs is elaborated as well. As observed from the current review, an accurate description of the pressure drop management mechanism is crucial for the theoretical model of the pressure control production process for shale gas wells. The influence of water–rock interaction on the managed pressure drawdown mechanism cannot be ignored. There have thus been works to improve and enhance it for use in theoretical models for shale formations. On the other hand, the advancement of theoretical models presents an opportunity for better representation of the managed pressure drop production process.

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Section: Results and Discussionmentioning

confidence: 99%

Section: Results and Discussionmentioning

confidence: 99%

Pressure Drawdown Management Strategies for Multifractured Horizontal Wells in Shale Gas Reservoirs: A Review

Liu

et al. 2022

ACS Omega

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“…Wilson and Alla also mention that the key output from the RTA model is the average reservoir pressure over time, which will be used to predict the changing stress conditions inside the stimulated rock volume (SRV). Results from the RTA workflow and sensitivity analyses pertinent to the research will be fracture half-lengths ( ), SRV permeability ( ), effective thickness (h), and fracture conductivity ( ) (Lerza et al 2018). These parameters could then be used as thresholds (i.e.…”

Section: Decline Curve Analyses (Dca)mentioning

confidence: 99%

Drawdown Management Strategies — Midland Basin Case Studies

Pradhan¹,

Gildin²,

Blasingame³

2021

Proceedings of the 9th Unconventional Resources Technology Conference

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Operators have different production strategies based on maintaining their fracture networks to the reservoir and sand control after flowback. Aggressive production strategies in some liquids-rich producing shale reservoirs could reduce fracture lengths and limit the production life. In addition, operators are constantly trying to achieve a better understanding of the existing fracture network (i.e., to assess if a perceived fracture barrier restricts the potential SRV or if modified drawdown strategies could make up for these "restricted" wells) to determine its impact on different production strategies. This study investigates optimal drawdown strategies through a holistic workflow. The scope of this work will also investigate what are the hydrocarbon recoveries for wells that are landed near a fracture barrier as well as primary-infill well scenarios.The work considers important reservoir and fluid properties to conduct rate-transient analyses, pressure transient analyses, and later to develop the reservoir simulation model to history match and forecast future production rates and pressures. The study considers multiple scenarios of varying properties from fracture and reservoir modeling to obtain a range of recoveries and economics. Case studies will cover the Midland Basin Wolfcamp and Lower Spraberry formations to evaluate how reservoirs of different rock and fluid properties will impact the resulting optimal choke management strategies.Coupled geomechanics and reservoir simulation is a recognized industry practice used to better understand potential fracture network depletion influenced by fracture barriers and primary-infill well scenarios, ultimately providing guidance on optimal drawdown strategies for complex reservoir development scenarios.iii DEDICATION To my family:My parents Amarja and Umesh Pradhanthank you for introducing me to engineering, your unconditional love, and support for everything I do.

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Numerical Simulation of Choke Size Optimization in a Shale Gas Well

Wu¹,

Yang²,

Di³

et al. 2022

Geofluids

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To optimize the flowback system of shale gas horizontal wells after fracturing and to maximize the production capacity of gas wells, pipe flow and flowback models of shale gas multistage fractured horizontal wells were established based on the actual geological engineering conditions and the fracture parameters inverted from automatic history matching by combining experimental and numerical simulation methods. Optimization of the maximum choke size, reasonable opening choke size, replacement stages, and choke replacement frequency were studied. The research results show that the larger the production pressure difference in the early period, the higher the initial gas production rate but the easier the migration of proppant and the higher its stress sensitivity, which increases the permeability damage and weakens the reservoir recovery ability. Thus, the fracture conductivity gets worse and the later gas production rate and liquid production rate get lower. Specifically, the research results mainly include the following: (1) The laboratory experiment results show that the effective stress exceeding 19 MPa caused a proppant breakage and embedding phenomenon, leading to difficult recovery from reservoir permeability damage. Therefore, the maximum production pressure difference corresponding to the single-well maximum choke size shall not exceed 19 MPa. (2) A small opening choke size of a shale gas well is superior to the large one, and according to the numerical simulation, the choke size of 3 mm is recommended to be the reasonable opening choke size. (3) Under the drainage and production systems of replacing the choke size from small to large, the simulation results indicate that the production effect under the drainage and production systems of increasing the choke size incrementally stage by stage with an increase in amplitude of 1 mm is much better than that under the drainage and production systems of increasing the choke size by skipping the stage. (4) When the choke size is increased stage by stage, the research results indicate that the optimal duration of each grade of choke size is 3 days, beyond which, the increase of EUR will not be remarkable. The application of the proposed fine choke system research method in Well-CN001 indicates that the influence amplitude of the reasonable choke system on the daily gas production of Well-CN001 is in the range of 65.96%–121.67% and that on single-well EUR increase amplitude in 20 years is in the range of 5.2%–22.27%. The research results provide technical support for understanding the influence of different choke systems on the productivity of shale gas wells and optimizing the reasonable drainage and production systems of shale gas wells after fracturing.

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Defining the Optimal Drawdown Strategy in the Vaca Muerta Formation

Cited by 6 publications

References 0 publications

Pressure Drawdown Management Strategies for Multifractured Horizontal Wells in Shale Gas Reservoirs: A Review

Pressure Drawdown Management Strategies for Multifractured Horizontal Wells in Shale Gas Reservoirs: A Review

Drawdown Management Strategies — Midland Basin Case Studies

Numerical Simulation of Choke Size Optimization in a Shale Gas Well

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