Linking Natural Fractures to Karst Cave Development: A Case Study on Naturally Fractured Carbonates

Summary Designing matrix-acid stimulation treatments in vuggy and naturally fractured carbonate reservoirs is a challenging problem in the petroleum industry. It is often difficult to physically model this process, and current mathematical models do not consider vugs or fractures. There is a significant gap in the literature for models that design and evaluate matrix-acid stimulation in vuggy and naturally fractured carbonate reservoirs. The objective of this work is to develop a new model to simulate matrix acidizing under field conditions in vuggy and naturally fractured carbonates. To obtain accurate and reliable simulation parameters, acidizing coreflood experiments were modeled using a reactive-flow simulator. A 3D radial field-scale model was used to study the flow of acid in the presence of vugs (pore spaces that are significantly larger than grains) and natural fractures (breaks in the reservoir that were formed naturally by tectonic events). The vugs’ size and distribution effects on acid propagation were studied under field conditions. The fracture length, conductivity, and orientation, and the number of fractures in the formation, were studied by the radial model. The results of the numerical simulation were used to construct Gaussian-process (GP)-based surrogate models for predicting acid propagation in vuggy and naturally fractured carbonates. Finally, the acid propagation in vuggy/naturally fractured carbonates was evaluated, as well.The simulation results of vuggy carbonates show that the presence of vugs in carbonates results in faster and deeper acid propagation in the formation when compared with homogeneous reservoirs at injection velocities lower than 8×10–4 m/s. Results also revealed that the size and density of the vugs have a significant impact on acid consumption and the overall performance of the acid treatment. The output of the fracture model illustrates that under field conditions, fracture orientations do not affect the acid-propagation velocity. The acid does not touch all of the fractures around the well. The GP model predictions have an accuracy of approximately 90% for both vuggy and naturally fractured cases. The vuggy/naturally fractured model simulations reveal that fractures are the main reason behind the fast acid propagation in these highly heterogeneous reservoirs.

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Controlled Hydraulic Fracturing of Naturally Fractured Shales - A Case Study in the Marcellus Shale Examining How to Identify and Exploit Natural Fractures

10.2118/164524-ms ◽

2013 ◽

Cited By ~ 2

Author(s):

Iraj A. Salehi ◽

Jordan Ciezobka

Keyword(s):

Hydraulic Fracturing ◽

Marcellus Shale ◽

Natural Fractures ◽

Naturally Fractured

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Acid Leakoff Mechanism in Acid Fracturing of Naturally Fractured Carbonate Gas Reservoirs

Advanced Materials Research ◽

10.4028/www.scientific.net/amr.868.682 ◽

2013 ◽

Vol 868 ◽

pp. 682-685 ◽

Cited By ~ 2

Author(s):

Lin Jing Xu ◽

Shi Cheng Zhang ◽

Jian Ye Mou

Keyword(s):

Fluid Loss ◽

Natural Fractures ◽

Gas Reservoirs ◽

Gas Reservoir ◽

Acid Rock ◽

Acid Fracturing ◽

Naturally Fractured ◽

Fractured Carbonate ◽

Acid Leakoff ◽

Fractured Carbonates

In acid fracturing, excessive acid leakoff is thought to be the main reason that limits fracture propagation and live acid penetration distance, so its very important to do research about acid leak-off on naturally fractured carbonates. we developed a new model in this paper to simulate acid leakoff into a naturally fractured carbonates gas reservoir during acid fracturing. Our model incorporates the acid-rock reaction on the fractured surfaces. Given the information of the Puguang gas reservoir, the model predicts acid filtration and leakoff rate over time. In this study, we found that acid leak-off mechanism in naturally fractured carbonates is much different from that in reservoirs without natural fractures. The leakoff volume is several times of nonreactive acid. Since the acid widened natural fractures, leakoff velocity increase with time firstly , then decrease. While the leakoff velocity of the nonreactive fluid decrease sustained. We also analyze other sensitivity parameters of the acid leakoff. In this model, we explain the acid leakoff mechanism in naturally fractured carbonates, and provide a more accurate calculating of fluid loss.

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INFLUENCE OF NATURAL FRACTURES ON OIL MIGRATION AND CHARGING: A CASE STUDY ON THE PERMIAN LUCAOGOU FORMATION IN THE JIMSAR SAG, JUNGGAR BASIN, NW CHINA

10.1130/abs/2019am-333029 ◽

2019 ◽

Author(s):

Yunzhao Zhang ◽

◽

Zeng Lianbo

Keyword(s):

Junggar Basin ◽

Natural Fractures ◽

Oil Migration ◽

Nw China ◽

Lucaogou Formation ◽

Jimsar Sag

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Controls of interlayers on the development and distribution of natural fractures in lacustrine shale reservoirs: A case study of the Da'anzhai member in the Fuling area in the eastern Sichuan Basin

Journal of Petroleum Science and Engineering ◽

10.1016/j.petrol.2021.109224 ◽

2021 ◽

pp. 109224

Author(s):

Xiaoju Zhang ◽

Jianhua He ◽

Hucheng Deng ◽

Meiyan Fu ◽

Zehou Xiang ◽

...

Keyword(s):

Sichuan Basin ◽

Natural Fractures ◽

Eastern Sichuan Basin ◽

Eastern Sichuan ◽

Lacustrine Shale ◽

Shale Reservoirs

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A numerical investigation on the performance of hydraulic fracturing in naturally fractured gas reservoirs based on stimulated rock volume

Journal of Petroleum Exploration and Production Technology ◽

10.1007/s13202-020-00980-8 ◽

2020 ◽

Vol 10 (8) ◽

pp. 3333-3345

Author(s):

Ali Al-Rubaie ◽

Hisham Khaled Ben Mahmud

Keyword(s):

Hydraulic Fracturing ◽

Hydraulic Fracture ◽

Natural Fracture ◽

Shear Stresses ◽

Individual Element ◽

Natural Fractures ◽

Gas Reservoirs ◽

Stimulated Reservoir Volume ◽

Reservoir Volume ◽

Naturally Fractured

Abstract All reservoirs are fractured to some degree. Depending on the density, dimension, orientation and the cementation of natural fractures and the location where the hydraulic fracturing is done, preexisting natural fractures can impact hydraulic fracture propagation and the associated flow capacity. Understanding the interactions between hydraulic fracture and natural fractures is crucial in estimating fracture complexity, stimulated reservoir volume, drained reservoir volume and completion efficiency. However, because of the presence of natural fractures with diffuse penetration and different orientations, the operation is complicated in naturally fractured gas reservoirs. For this purpose, two numerical methods are proposed for simulating the hydraulic fracture in a naturally fractured gas reservoir. However, what hydraulic fracture looks like in the subsurface, especially in unconventional reservoirs, remain elusive, and many times, field observations contradict our common beliefs. In this study, the hydraulic fracture model is considered in terms of the state of tensions, on the interaction between the hydraulic fracture and the natural fracture (45°), and the effect of length and height of hydraulic fracture developed and how to distribute induced stress around the well. In order to determine the direction in which the hydraulic fracture is formed strikethrough, the finite difference method and the individual element for numerical solution are used and simulated. The results indicate that the optimum hydraulic fracture time was when the hydraulic fracture is able to connect natural fractures with large streams and connected to the well, and there is a fundamental difference between the tensile and shear opening. The analysis indicates that the growing hydraulic fracture, the tensile and shear stresses applied to the natural fracture.

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Managing Wellbore Stability Window and Well Integrity by Adjusting the Tight Margin to Successfully Drill through Naturally Fractured Zone Onshore Niger Delta

10.2118/207189-ms ◽

2021 ◽

Author(s):

Bassey Akong ◽

Samuel Orimoloye ◽

Friday Otutu ◽

Akinwale Ojo ◽

Goodluck Mfonnom ◽

...

Keyword(s):

Niger Delta ◽

Wellbore Stability ◽

Rock Properties ◽

Failure Behavior ◽

Natural Fractures ◽

Gas Well ◽

Well Integrity ◽

Trajectory Formation ◽

Naturally Fractured ◽

Drilling Operations

Abstract The analysis of wellbore stability in gas wells is vital for effective drilling operations, especially in Brown fields and for modern drilling technologies. Tensile failure mode of Wellbore stability problems usually occur when drilling through hydrocarbon formations such as shale, unconsolidated sandstone, sand units, natural fractured formations and HPHT formations with narrow safety mud window. These problems can significantly affect drilling time, costs and the whole drilling operations. In the case of the candidate onshore gas well Niger Delta, there was severe lost circulation events and gas cut mud while drilling. However, there was need for a consistent adjustment of the tight drilling margin, flow, and mud rheology to allow for effective filter-cake formation around the penetrated natural fractures and traversed depleted intervals without jeopardizing the well integrity. Several assumptions were validly made for formations with voids or natural fractures, because the presence of these geological features influenced rock anisotropic properties, wellbore stress concentration and failure behavior with end point of partial – to-total loss circulation events. This was a complicated phenomenon, because the pre-drilled stress distribution simulation around the candidate wellbore was investigated to be affected by factors such as rock properties, far-field principal stresses, wellbore trajectory, formation pore pressure, reservoir and drilling fluids properties and time without much interest on traversing through voids or naturally fractured layers. This study reviews the major causes of the severe losses encountered, the adopted fractured permeability mid-line mudweight window mitigation process, stress caging strategies and other operational decisions adopted to further salvage and drill through the naturally fractured and depleted intervals, hence regaining the well integrity by reducing NPT and promoting well-early-time-production for the onshore gas well Niger Delta.

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