Understanding and Quantifying Variable Drainage Volume for Unconventional Wells

Zeynal, Asal Rahimi; Kashikar, Sudhendu

doi:10.15530/urtec-2016-2459223

Cited by 3 publications

(4 citation statements)

References 5 publications

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“…(2) If the lengths of the fractures are all increased, the change of the fracture length exerts a slight influence on the control volumes, whereas, if only one of the fracture length is increased, the control volume of the corresponding well will be increased (3) The number of the production wells and the distribution of the production well can significantly influence the control volumes of the production wells, whereas the fracture conductivity exerts negligible influence on the control volumes In Equation (A.2), β is the unit conversion factor, k is the permeability, μ is the viscosity, ϕ is the porosity, and c t is the 10 Geofluids total compressibility. In addition, the DTOF τ has the following relationship with the physical time t in :…”

Section: Geofluidsmentioning

confidence: 99%

“…This approach relies on an asymptotic solution of the diffusivity equation and emulates the propagation of drainage boundaries. Zeynal and Kashikar [3] developed a new methodology to quantify the fracture intensity through a deterministic discrete fracture network model on the basis of the microseismic data, pumping parameters, and rock properties. Gherbati [4] utilized a material-balance approach for determining control volumes of multifracture unconventional oil wells.…”

Section: Introductionmentioning

confidence: 99%

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A New Approach for Determining the Control Volumes of Production Wells considering Irregular Well Distribution and Heterogeneous Reservoir Properties

et al. 2021

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The oil and gas fields are commonly developed with a group of production wells. Therefore, it can be essential for the industries to predict the performance of the production wells in order to optimize the development strategies. In practice, it frequently happens that we only hope to study the performance of a single production well. In such cases, it can be time consuming to run the reservoir simulation with the entire reservoir model to study the well performance. Hence, it can be preferred to determine the control volume (or drainage volume) of the target well from the entire reservoir and run the simulation with the small control volume to reduce the simulation cost. However, an irregular layout of the production wells and the heterogeneity of reservoir properties, which can be commonly observed in real field cases, can induce a stringent barrier for one to determine the control volumes. At present, we are still lacking a method to determine the control volumes of the production wells considering well distribution and reservoir heterogeneities. In order to overcome such a barrier, the authors proposed a new approach to divide the entire reservoir into small control volumes on the basis of the fast marching method (FMM). This approach is validated by comparing the simulation outputs of the target well calculated only with the determined control volume to those calculated with the entire reservoir model. The calculated results show that using the control volume that is determined with the proposed method to calculate the well performance can yield results that agree well with the results that are calculated with the entire reservoir model. This indicates that this proposed method is reliable to determine the control volume of the production wells. In addition, the calculated results in this work show that changing fracture length exerts a slight influence on the control volumes if the length of all fractures is increased, whereas, if only one of the fracture lengths is increased, the control volume of the corresponding well will be significantly increased. The number of the production wells and the distribution of the production well can noticeably influence the control volumes of the production wells. The findings of this study can help for optimizing the well spacing, estimating the ultimate recovery, and reducing the computational cost.

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Section: Geofluidsmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

A New Approach for Determining the Control Volumes of Production Wells considering Irregular Well Distribution and Heterogeneous Reservoir Properties

et al. 2021

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show abstract

Section: Introductionmentioning

confidence: 99%

“…This smaller area that directly contributes is referred to as the "drained rock volume" (DRV) (Figure 1B). DRV is what geochemists are ultimately looking to define from produced fluids, whereas SRV is determined by core extracts and methods such as micro-seismic, completion models, and other techniques [3,4]. Another aspect of defining the DRV and the "reach" of production is how many potential contributing zones are being accessed by a single horizontal well.…”

Section: Introductionmentioning

confidence: 99%

Production Allocation: Rosetta Stone or Red Herring? Best Practices for Understanding Produced Oils in Resource Plays

et al. 2020

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The production of crude oil from resource plays has increased enormously over the past decade. In the USA, around 63% of total output in 2019 was from unconventional production. The major unconventional plays in the USA (e.g., Permian Basin, Anadarko Basin, Eagle Ford, etc.) have become some of the world’s largest oil producers. However, unlike “conventional” exploitation, the target zones in unconventional systems are generally the source rocks themselves or adjacent strata and require numerous horizontal wells and stimulation via hydraulic fracturing to meet production targets. In order to maximize production, operators have developed various well stacking methods, all of which require some form of monitoring to ensure that well spacing is optimized and fluid production is not being “stolen” from adjacent formations, thereby reducing the production potential in associated wells. This necessity, amongst other geochemical considerations related to source rock characterization, has resulted in the expansion of “production allocation” and “time lapse geochemistry” methods. These methods were initially developed for conventional production decades ago, but have since been adapted to unconventional systems. However, the direct applicability of this method is not straightforward and numerous considerations need to be taken into account, foremost among which are: (1) “What defines your end-members?” (2) “Are these end-members valid across a meaningful development area?” and (3) “What is the most appropriate use of geochemistry data in these systems?”. Reservoir geochemistry studies, which include both “time lapse geochemistry/production monitoring” and “production allocation”, are valuable geochemical methods in unconventional plays but need to be used appropriately to provide the cost savings and business direction that operators expect. In this paper, we will discuss a number of case studies, both theoretical and natural, and outline the important factors which need to be considered when designing a reservoir geochemistry study and the common pitfalls which exist. The case studies and best practice approach discussed are designed to highlight the power and flexibility of geochemical data collection methods, integration with the operator’s knowledgebase, and other analytical methods to customize the program for individual development programs. Emphasis is placed upon developing robust and applicable fluid relationships from geochemical data and evidence for statistically significant changes through time.

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Impact of Frac Hits on Production Performance- A Case Study in Marcellus Shale

Khodabakhshnejad

2019

SPE Western Regional Meeting

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A new approach is proposed to quantify the communication between wells in a tight multi-layered shale gas reservoir. In this approach, a wide range of data sets, from microseismic monitoring to the production data are analyzed to evaluate the communication between wells in every stage of well development. The results provide new insight into how the initial well communication during stimulation impacts the well interference during production. Microseismic data collected during hydraulic fracturing are analyzed for a three-well pad drilled in the Appalachian basin. The microseismic event locations, magnitudes, and fracture plane characteristics are used to construct a discrete fracture network (DFN). The permeability of a numerical reservoir model is calculated from the generated DFN, and the model is further integrated with available reservoir data. History matching is carried out using three years of production data to calibrate the reservoir model, which was also used to predict water and gas production for thirty years. Finally, decline curve analysis (DCA) is used to examine the production behavior of the reservoir. The microseismic data monitored during hydraulic fracturing show the presence of communication between wells in the pad. This communication, also known as frac hits, is established as more events are recorded in the offset wells, indicating the extent of hydraulic fractures. In addition, the pressure perturbation in the offset wells confirms the presence of a pathway connecting the wells during stimulation. Furthermore, the reservoir model built in the numerical reservoir simulator shows overlap of drainage volumes. In the reservoir model, the depleted region expands across multilayer formations in both lateral and vertical directions. An analysis of the production behavior of the wells using DCA suggests an almost logarithmic trend which is expected for these types of reservoirs. Surprisingly, detailed analysis of the results reveals there is no significant deviation in the overall performance of wells associated with well interference, especially in the early years of production. However, at greater than 10 years of production, the expansion of the depleted zone accelerates the well interference which leads to lower performance of the pad in the long term. The results demonstrate that the enhanced permeability zones created due to frac hits may not have an immediate impact on production performance. Traditionally, frac hits and well communication were considered damaging to the reservoir production. However, this new result shows that the well communication during fracturing may not impact short-term production. Additionally, it highlights the importance of a thorough examination of the fracture network along with the reservoir properties to evaluate the potential impact of frac hits on reservoir production.

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Understanding and Quantifying Variable Drainage Volume for Unconventional Wells

Cited by 3 publications

References 5 publications

A New Approach for Determining the Control Volumes of Production Wells considering Irregular Well Distribution and Heterogeneous Reservoir Properties

A New Approach for Determining the Control Volumes of Production Wells considering Irregular Well Distribution and Heterogeneous Reservoir Properties

Production Allocation: Rosetta Stone or Red Herring? Best Practices for Understanding Produced Oils in Resource Plays

Impact of Frac Hits on Production Performance- A Case Study in Marcellus Shale

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