A New Material-Balance Equation for Naturally Fractured Reservoirs Using a Dual-System Approach

Penuela, Gherson; Idrobo, Eduardo A.; Ordóñez, Aníbal; Medina, C. E; Meza, Nestor Saul

doi:10.2118/68831-ms

Cited by 22 publications

(8 citation statements)

References 7 publications

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“…Naturally fractured reservoirs are the result of natural processes that present the diastrophism and volume shrinkage that lead to fractures that have dispersed as a consistently linked network across the reservoir [1]. Te tectonic processes have evolved in reservoirs, fractured reservoirs are frequently found in weak reservoir rocks with poor porosity [2]. Due to that, the fracture is extended and large, where it is often referred to as the large fracture [3].…”

Section: Introductionmentioning

confidence: 99%

Fluid Flow Behavior Prediction in Naturally Fractured Reservoirs Using Machine Learning Models

et al. 2023

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The naturally fractured reservoirs are one of the most challenging due to the tectonic movements that are caused to increase the permeability and conductivity of the fractures. The instability of the permeability and conductivity effects on the fluid flow path causes problems during the transfer of the fluids from the matrix to the fractures and fluid losses during production. In addition, these complications made it difficult for engineers to estimate fluid flow during production. The fracture properties’ study is important to model the fluid flow paths such as the fracture porosity, permeability, and the shape factor, which are considered essential in the stability of fluid flow. To examine this, this research introduced new models including decision tree (DT), random forest (RF), K-nearest regression (KNR), ridge regression (RR), and LASSO regression model,. The research studied the fracture properties in naturally fractured reservoirs like the fracture porosity (FP) and the shape factor (SF). The datasets used in this study were collected from previous studies “i.e., Texas oil and gas fields” to build an intelligence-based predictive model for fluid flow characteristics. The prediction process was conducted based on interporosity flow coefficient, storativity ratio, wellbore radius, matrix permeability, and fracture permeability as input data. This study revealed a positive finding for the adopted machine learning (ML) models and was superior in using statistical accuracy metrics. Overall, the research emphasized the implementation of computer-aided models for naturally fractured reservoir analysis, giving more details on the extensive execution techniques, such as injection or the creation of artificial cracks, to minimize hydrocarbon losses or leakage.

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Section: Introductionmentioning

confidence: 99%

Fluid Flow Behavior Prediction in Naturally Fractured Reservoirs Using Machine Learning Models

et al. 2023

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“…Material balance calculations are very well established techniques that apply the law of conservation of matter to petroleum engineering (Penuela et al, 2001). Nevertheless, it seems no longer fashionable to apply the concept of material balance to oil fields, the belief being that it has now been superseded by the application of the more modern technique of numerical simulation modeling.…”

Section: Introductionmentioning

confidence: 99%

The effects of the volatile oil-gas ratio on reserve estimation (GMBE versus CMBE) in undersaturated volumetric reservoirs

Omoniyi¹,

Rodney²

2015

J. Pet. Technol. Altern. Fuels

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This work presents a general, straight-line method to estimate the original oil and gas in-place in a reservoir without restrictions on fluid composition. All past efforts are applicable to only restricted ranges of reservoir fluids. The work supersedes these and it is applicable to the full range of reservoir fluids-including volatile-oils and gas-condensates. The work is based on the new generalized materialbalance equation recently introduced by Walsh. The superiority of the new method is illustrated by showing the error incurred by preexisting calculation methods; guidelines are offered to help identify when preexisting calculation methods must be abandoned and when the new methods featured herein must be employed. Empirical correlations for the volatile oil-gas ratio Rv for volatile-oils and gascondensates have been introduced to accurately define how much fluid volatility a reservoir oil can exhibit before one can no longer justifiably use the CMBE and one must apply the generalized material balance equation (GMBE). Thus, if there is interest in applying the conventional material-balance equation (CMBE) and its applicability is in question, we recommend measuring the fluid's volatile oilgas ratio Rv at its saturation pressure and comparing it to the critical value offered herein.

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“…However, the method is restricted to primary and secondary recovery processes. Penuela et al (5) developed MBE for a dual porosity carbonate reservoir to determine the original oil-in-place (OOIP) in matrix and fractured systems. Hsieh et al (6,7) proposed a horizontal line MBE to estimate the OOIP and calculate the water influx.…”

Section: Introductionmentioning

confidence: 99%

Monitoring and Predicting CO2 Flooding Using Material Balance Equations

Tian

Zhao

2008

Journal of Canadian Petroleum Technology

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In order to operate a CO2 flooding scheme successfully, it is necessary to get accurate information about the reservoir dynamic performance and the fluids injected. Although some numerical simulation studies have been conducted, the complicated drive mechanisms and actual reservoir performance have not been fully understood. Thus, there is a strong industrial need to develop models using different perspectives to provide valuable and complementary insights into the reservoir performance during the CO2 flooding process. The objective of this study is to develop models using material balance equations (MBE) to analyze the field data before and after CO2 injection. After matching the historical field data, the proposed model can be applied to evaluate, monitor and predict the overall reservoir dynamic performance during the CO2 flooding process. To accurately account for the complex displacement process involving compositional effect and multiphase flow, the PVT properties of reservoir fluids and the four-phase fluid relative permeability relationship are integrated into the model. This study has investigated the effects of a number of factors, such as the reservoir pressure, the amount of CO2 injected, the CO2 partition ratios in reservoir fluids, the possibility of the existence of a free CO2 gas cap, the proportion of reservoir fluids contacted by CO2, the oil swelling and the oil relative permeability improvement. The model has been applied to analyze the Weyburn CO2 flooding project. The study has shown that the proposed MBE model is an effective complementary tool to analyze overall reservoir performance in tertiary CO2 recovery processes. The results show that:there exists a free CO2 gas cap under reservoir conditions, even if the reservoir pressure is larger than MMP (minimum miscible pressure) in the Weyburn Field;the CO2 partition ratios in oil, water and gas phases and the proportions of reservoir fluids contacted by CO2 largely affect the drive mechanism and production performance; andthe effect of CO2 solubility in water under actual reservoir conditions cannot be neglected. The proposed new model is the first one in developing and applying MBE to evaluate the overall dynamic performance for the CO2 flooding process and a valuable insight into reservoir responses during this process has been achieved. Introduction CO2 flooding is considered one of the most effective tertiary recovery processes in light/medium oil reservoirs and has achieved widespread use in the petroleum industry. However, the complicated displacement mechanisms and reservoir performance involved in the CO2 injection process have not been completely understood. Monitoring reservoir performance and obtaining accurate information regarding reservoir fluid and injected fluid using field data will help understand the mechanisms and manage the CO2 injection project efficiently. There are two types of methods that monitor and evaluate reservoir performance: numerical simulation and MBE. MBE is a classic reservoir engineering tool. It is applied to analyze the reservoir performance based on the law of conservation of matter. Compared with MBE, reservoir numerical simulation is a more modern technique for modelling reservoir performance.

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A New Material-Balance Equation for Naturally Fractured Reservoirs Using a Dual-System Approach

Abstract: TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe complexity associated to naturally fractured formations constrains reservoir engineers to use simplified versions of the Material Balance Equation for determining the initial hydrocarbon in place and predicting reservoir performance.

Cited by 22 publications

References 7 publications

Fluid Flow Behavior Prediction in Naturally Fractured Reservoirs Using Machine Learning Models

Fluid Flow Behavior Prediction in Naturally Fractured Reservoirs Using Machine Learning Models

The effects of the volatile oil-gas ratio on reserve estimation (GMBE versus CMBE) in undersaturated volumetric reservoirs

Monitoring and Predicting CO2 Flooding Using Material Balance Equations

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