Regional Top Seal Capacity Analysis in JS-1 Ridge, Offshore Madura Involving Seal Geometry, Capillary Seal, Hydrofracturing Analysis, and Natural Fracture Modelling

2021 ◽  
Keyword(s):  
Vitrinite Reflectance ◽  
Stable Condition ◽  
Horizontal Stress ◽  
Natural Fracture ◽  
Column Height ◽  
Natural Fractures ◽  
Stress Regime ◽  
Hydrocarbon Reservoir ◽  
North East ◽  
Average Maximum

The Early Miocene reefal carbonate of Kujung-1 is the main hydrocarbon reservoir in JS-1 Ridge Area, North East Java Basin. The varying heights of hydrocarbon columns affect the success rate of exploration in Kujung-1 Formation. The shale of Rancak Unit acts as a regional seal of the Kujung-1 Reservoir. This study aims to understand the character, capacity of seal, and its relationship with hydrocarbon column height, to improve the chances of exploration success. The methodology in this study includes estimation of pore pressures, capillary seals, hydrofracturing seals, seal geometry, and natural fractures modeling. The data used in this study include 41 well, laboratory (Mercury Injection capillary pressure, vitrinite reflectance and X-ray diffraction), and 3D seismic data. The pore pressure of Rancak Unit indicates that it is slightly overpressured by loading mechanism. The presence of slight overpressure increases sealing capacity of Rancak Unit to 1.95 MPa or 221 m gas column equivalent. Hydrofracturing seal does not play an important role in Rancak Unit. The seal geometry of Rancak has good to very good qualitative capabilities to hold hydrocarbon in Kujung-1 Reservoir. Present-day stress magnitudes and orientations have been determined from bore-hole breakout, drilling-induced fractures and LOTs from two wells. Interpretation of borehole breakout and drilling-induced tensile shows that average maximum horizontal stress direction is northeast-southwest. The geomechanically model shows that predominant stress regime at KD-1 and KD-3 Wells is normal stressregime. Fracture distribution based on natural fracture modeling is consistent with the percentage of hydrocarbon filling in Kujung-1 Reservoir. However, the fractures are in a stable condition under present-day stress. Based on further analysis, the natural fractures in the Rancak Unit are the main factor affecting the height of the hydrocarbon column in the Kujung-1 Reservoir. The Neogen compressional tectonic period is estimated to be the period of fracture in the study area in critical condition, and leakage occurred in the Kujung-1 Reservoir at that time.

TRAP INTEGRITY IN THE LAM IN ARIA HIGH-NANCAR TROUGH REGION,TIMOR SEA: PREDICTION OF FAULT SEAL FAILURE USING WELL-CONSTRAINED STRESS TENSORS AND FAULT SURFACES INTERPRETED FROM 3D SEISMIC

2000 ◽  
Vol 40 (1) ◽  
pp. 151 ◽  
Author(s):  
D.A. Castillo ◽  
D.J. Bishop ◽  
I. Donaldson ◽  
D. Kuek ◽  
M. de Ruig ◽  
...  
Keyword(s):  
Horizontal Stress ◽  
Column Height ◽  
3D Seismic ◽  
Stress Regime ◽  
Seal Failure ◽  
Hydrocarbon Traps ◽  
Coulomb Failure ◽  
Timor Sea ◽  
Surrounding Areas ◽  
Drilling Conditions

Drilling in the Laminaria High and Nancar Trough areas has shown that many hydrocarbon traps are underfilled or completely breached. Previous studies have shown that fault-trap integrity is strongly influenced by the state of stress resolved on the reservoir bounding faults, suggesting that careful construction of a geomechanical model may reduce the risk of encountering breached reservoirs in exploration and appraisal wells. The ability of a fault to behave as a seal and support a hydrocarbon column is influenced in part by the principal stress directions and magnitudes, and fault geometry (dip and dip azimuth). If a fault is critically stressed with respect to the present-day stress field, there is a high likelihood that the fault will slip, thereby elevating fault zone permeability that enables hydrocarbons to leak. Leakage could be intermittent depending on the degree and rate of fracture healing, and on the recurrence rate between reactivated slip events.High-resolution wellbore images from over 15 wells have been analysed to construct a well-constrained stress tensor. Constraints are based on geomechanical parameters, along with drilling conditions that are consistent with the style of drilling-induced compressive and tensile wellbore wall failure seen in each of these wells. This regional stress analysis of permits AC/P8, AC/P16 and surrounding areas indicates a non-uniform strike-slip stress regime (SHmax > Sv > Shmin) with the orientation of the maximum principal horizontal stress (SHmax) varying systematically from north to south, similar to that previously reported for the western reaches of ZOCA. On the Laminaria High (AC/P8 and AC/L5), SHmax is 15°N ± 6°. Just south of the Laminaria High, there is a marked transition in the SHmax stress direction to about 63°N ± 6°. Over the Nancar Trough (AC/P16), the orientation is consistently NE-SW.Fault surfaces interpreted from 3D seismic data have been subdivided into discrete segments for the purpose of calculating the shear and normal stresses in order to resolve the Coulomb Failure Function (CFF) on each fault segment. The results have been displayed using 3D visualisation techniques to facilitate interpretation. The magnitude of hydrocarbon accumulation (column height) and leakage (residual column) deduced from well results may be explained in part by the CFF resolved on their respective reservoir-bounding faults. By integrating these stress determination and fault imaging technologies, explorationists and reservoir engineers will gain the ability to use these predictive tools to help quantify the likelihood of encountering a breached reservoir prior to drilling.

Geomechanical insights in the Bedout Sub-basin: exploiting technologies for understanding reservoir settings

2018 ◽  
Vol 58 (2) ◽  
pp. 788
Author(s):  
David A. Castillo ◽  
David Kuek ◽  
Melissa Thompson ◽  
Fred Fernandes ◽  
Jon Minken ◽  
...  
Keyword(s):  
Shear Failure ◽  
Image Data ◽  
Horizontal Stress ◽  
Natural Fracture ◽  
Fracture Permeability ◽  
Stress Regime ◽  
Data Set ◽  
Pore Pressures ◽  
The Impact ◽  
The Phoenix

An extensive collection of drilling and wireline data, core and lab strength tests, pressure tests and advanced geomechanical techniques has provided an unprecedented data set to better understand the impact that the stress regime has on characterising reservoir in the Bedout Basin area. An important cost effective method for collecting data while drilling has been the deployment of logging-while-drilling image data followed by wireline image data to document the immediate impact that drilling has on well integrity and potential time-dependent wellbore integrity. Reliable estimates of the minimum horizontal stress (Shmin) were based on carefully executed extended leak-off-tests. Fine-scale observations of drilling-induced isotropic wellbore breakouts, tensile cracks, anisotropic breakouts, and drilling-enhanced natural fractures were collectively used to constrain the Bedout Basin stress regime to be strike-slip (SHmax > SV > Shmin, where SV is the vertical stress and SHmax is the maximum horizontal stress) with stress magnitudes sufficiently high to induce shear failure and fracture permeability on a selected population of natural fracture orientations. Advanced geomechanical modelling of breakouts in the Phoenix South-2 and Roc-2 wells indicated that a unique set of natural fracture induced anisotropic breakouts, which could not be explained as isotropic breakouts because of the high rock strength. In many situations, the responsible natural fracture or joint was undetectable in the image data, but the effect of the natural fracture systems was evident in the anisotropic breakouts. The Phoenix South-2 well suddenly encountered elevated pore pressures (1.56 SG or greater) at total depth where there was no pronounced indication of a systematic pore pressure ramp in the overburden. Geomechanical modelling was used to independently confirm near normal pore pressures in the overburden by predicting that excessive breakouts would have formed if there was a pressure ramp given the ~1.1 SG mud weight used to drill the well.

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

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.

Joint Application of Diagenetic, Petrophysical and Geomechanical Data for Selecting Hydraulic Fracturing Candidate Zone

2021 ◽  
Vol 8 ◽  
pp. 55-79
Author(s):  
E. Bakhshi ◽  
A. Shahrabadi ◽  
N. Golsanami ◽  
Sh. Seyedsajadi ◽  
X. Liu ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Pore Pressure ◽  
Earth Model ◽  
Reservoir Properties ◽  
Stress Regime ◽  
Geomechanical Properties ◽  
Hydrocarbon Reservoir ◽  
Diagenetic Processes ◽  
Mechanical Earth Model ◽  
New Equation

The more comprehensive information on the reservoir properties will help to better plan drilling and design production. Herein, diagenetic processes and geomechanical properties are notable parameters that determine reservoir quality. Recognizing the geomechanical properties of the reservoir as well as building a mechanical earth model play a strong role in the hydrocarbon reservoir life cycle and are key factors in analyzing wellbore instability, drilling operation optimization, and hydraulic fracturing designing operation. Therefore, the present study focuses on selecting the candidate zone for hydraulic fracturing through a novel approach that simultaneously considers the diagenetic, petrophysical, and geomechanical properties. The diagenetic processes were analyzed to determine the porosity types in the reservoir. After that, based on the laboratory test results for estimating reservoir petrophysical parameters, the zones with suitable reservoir properties were selected. Moreover, based on the reservoir geomechanical parameters and the constructed mechanical earth model, the best zones were selected for hydraulic fracturing operation in one of the Iranian fractured carbonate reservoirs. Finally, a new empirical equation for estimating pore pressure in nine zones of the studied well was developed. This equation provides a more precise estimation of stress profiles and thus leads to more accurate decision-making for candidate zone selection. Based on the results, vuggy porosity was the best porosity type, and zones C2, E2 and G2, having suitable values of porosity, permeability, and water saturation, showed good reservoir properties. Therefore, zone E2 and G2 were chosen as the candidate for hydraulic fracturing simulation based on their E (Young’s modulus) and ν (Poisson’s ratio) values. Based on the mechanical earth model and changes in the acoustic data versus depth, a new equation is introduced for calculating the pore pressure in the studied reservoir. According to the new equation, the dominant stress regime in the whole well, especially in the candidate zones, is SigHmax>SigV>Sighmin, while according to the pore pressure equation presented in the literature, the dominant stress regime in the studied well turns out to be SigHmax>Sighmin>SigV.  

Geomechanical Approach in Classification of Borehole Failures in Fractured Carbonates of Boca De Jaruco Field

2021 ◽  
Author(s):  
Anna Vladimirovna Norkina ◽  
Iaroslav Olegovich Simakov ◽  
Yuriy Anatoljevich Petrakov ◽  
Alexey Evgenjevich Sobolev ◽  
Oleg Vladimirovich Petrashov ◽  
...  
Keyword(s):  
Stress State ◽  
Horizontal Wells ◽  
Horizontal Stress ◽  
In Situ Stress ◽  
Vertical Wells ◽  
Stress Regime ◽  
Geophysical Information ◽  
The Republic ◽  
Maximum Horizontal Stress

Abstract This article is a continuation of the work on geomechanically calculations for optimizing the drilling of horizontal wells into the productive reservoir M at the Boca de Haruco field of the Republic of Cuba, presented in the article SPE-196897. As part of the work, an assessment of the stress state and direction was carried out using geological and geophysical information, an analysis of the pressure behavior during steam injections, cross-dipole acoustics, as well as oriented caliper data in vertical wells. After the completion of the first part of the work, the first horizontal wells were successfully drilled into the M formation. According to the recommendations, additional studies were carried out: core sampling and recording of micro-imager logging in the deviated sections. Presence of wellbore failures at the inclined sections allowed to use the method of inverse in-situ stress modeling based on image logs interpretation. The classification of wellbore failures by micro-imager logging: natural origin and violations of technogenic genesis is carried out. The type of breakout is defined. The result of the work was the determination of the stress state and horizontal stresses direction. In addition, the article is supplemented with the calculation of the maximum horizontal stress through the stress regime identifier factor.

Predicting the azimuth of natural fractures and in-situ horizontal stress: A case study from Sichuan Basin, China

Geophysics ◽  
2021 ◽  
pp. 1-97
Author(s):  
kai lin ◽  
Bo Zhang ◽  
Jianjun Zhang ◽  
Huijing Fang ◽  
Kefeng Xi ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Seismic Data ◽  
Sichuan Basin ◽  
Horizontal Stress ◽  
Seismic Attributes ◽  
Seismic Events ◽  
Natural Fractures ◽  
Microseismic Data ◽  
Maximum Horizontal Stress

The azimuth of fractures and in-situ horizontal stress are important factors in planning horizontal wells and hydraulic fracturing for unconventional resources plays. The azimuth of natural fractures can be directly obtained by analyzing image logs. The azimuth of the maximum horizontal stress σH can be predicted by analyzing the induced fractures on image logs. The clustering of micro-seismic events can also be used to predict the azimuth of in-situ maximum horizontal stress. However, the azimuth of natural fractures and the in-situ maximum horizontal stress obtained from both image logs and micro-seismic events are limited to the wellbore locations. Wide azimuth seismic data provides an alternative way to predict the azimuth of natural fractures and maximum in-situ horizontal stress if the seismic attributes are properly calibrated with interpretations from well logs and microseismic data. To predict the azimuth of natural fractures and in-situ maximum horizontal stress, we focus our analysis on correlating the seismic attributes computed from pre-stack and post-stack seismic data with the interpreted azimuth obtained from image logs and microseismic data. The application indicates that the strike of the most positive principal curvature k1 can be used as an indicator for the azimuth of natural fractures within our study area. The azimuthal anisotropy of the dominant frequency component if offset vector title (OVT) seismic data can be used to predict the azimuth of maximum in-situ horizontal stress within our study area that is located the southern region of the Sichuan Basin, China. The predicted azimuths provide important information for the following well planning and hydraulic fracturing.

Usage of Geomechanically Consistent Fracture Model for Drilling Deviated Wells

2021 ◽  
Author(s):  
Nikita Vladislavovich Dubinya ◽  
Sergey Andreevich Tikhotskiy ◽  
Sergey Vladimirovich Fomichev ◽  
Sergey Vladimirovich Golovin
Keyword(s):  
Optimal Trajectory ◽  
Fractured Reservoirs ◽  
Fluid Pressure ◽  
Naturally Fractured Reservoirs ◽  
Natural Fracture ◽  
Fracture Model ◽  
Drilling Process ◽  
Natural Fractures ◽  
Drilling Parameters ◽  
Deviated Wells

Abstract The paper presents an algorithm for the search of the optimal frilling trajectory for a deviated well which is applicable for development of naturally fractured reservoirs. Criterion for identifying the optimal trajectory is the feature of the current study – optimal trajectory is chosen from the perspective of maximizing the positive effect related to activation of natural fractures in well surrounding rock masses caused by changes of the rocks stress-strain state due to drilling process. Drilling of a deviated well is shown to lead to the process of natural fractures in the vicinity of the well becoming hydraulically conductive due to drilling. The paper investigates the main natural factors – tectonic stresses and fluid pressure – and drilling parameters – drilling trajectory and mud pressure – influencing the number and variety of natural fractures being activated due to drilling process. An algorithm of finding the optimal drilling parameters from the perspective of natural fractures activation is proposed as well. Different theoretical scenarios are considered to formulate the general recommendations on drilling trajectory choice according to estimations of stress state of the reservoir. These estimations can be provided based on results of three- and four-dimensional geomechanical modeling. Such modeling may be completed as well for constructing geomechanically consistent natural fracture model which can be used to optimize drilling trajectories during exploration and development of certain objects. The paper presents a detailed algorithm of constructing such fracture models and deviated wells trajectories optimization. The results presented in the paper and given recommendations may be used to enhance drilling efficiency for reservoirs characterized by considerable contribution of natural fractures into filtration processes.

Improving the efficiency of hydraulic fracturing treatment in CBM reservoirs by stimulating the surrounding natural fracture system

2015 ◽  
Vol 55 (1) ◽  
pp. 351
Author(s):  
Alireza Keshavarz ◽  
Alexander Badalyan ◽  
Raymond Johnson ◽  
Pavel Bedrikovetski
Keyword(s):  
Hydraulic Fracturing ◽  
Mathematical Modelling ◽  
Gas Production ◽  
Natural Fracture ◽  
Productivity Index ◽  
Coal Bed ◽  
Natural Fractures ◽  
Core Flooding ◽  
Induced Fractures ◽  
Water Gas

A method is proposed for enhancing the conductivity of micro-fractures and cleats around the hydraulically induced fractures in coal bed methane reservoirs. In this technique, placing ultra-fine proppant particles in natural fractures and cleats around hydraulically induced fractures at leak-off conditions keeps the coal cleats open during water-gas production, and this consequently increases the efficiency of hydraulic fracturing treatment. Experimental and mathematical studies for the stimulation of a natural cleat system around the main hydraulic fracture are conducted. In the experimental part, core flooding tests are performed to inject a flow of suspended particles inside the natural fractures of a coal sample. By placing different particle sizes and evaluating the concentration of placed particles, an experimental coefficient is found for optimum proppant placement in which the maximum permeability is achieved after proppant placement. In the mathematical modelling study, a laboratory-based mathematical model for graded proppant placement in naturally fractured rocks around a hydraulically induced fracture is proposed. Derivations of the model include an exponential form of the pressure-permeability dependence and accounts for permeability variation in the non-stimulated zone. The explicit formulae are derived for the well productivity index by including the experimentally found coefficient. Particle placement tests resulted in an almost three-times increase in coal permeability. The laboratory-based mathematical modelling, as performed for the field conditions, shows that the proposed method yields around a six-times increase in the productivity index.

Development of a new approach for hydraulic fracturing in tight sand with pre-existing natural fractures

2016 ◽  
Vol 56 (1) ◽  
pp. 225 ◽  
Author(s):  
Kunakorn Pokalai ◽  
David Kulikowski ◽  
Raymond L. Johnson ◽  
Manouchehr Haghighi ◽  
Dennis Cooke
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
High Stress ◽  
Gas Production ◽  
Natural Fracture ◽  
Rock Properties ◽  
Fracture Plane ◽  
Natural Fractures ◽  
Geomechanical Model ◽  
Well Design

Hydraulic fracturing in tight gas reservoirs has been performed in the Cooper Basin for decades in reservoirs containing high stress and pre-existing natural fractures, especially near faults. The hydraulic fracture is affected by factors such as tortuosity, high entry pressures, and the rock fabric including natural fractures. These factors cause fracture plane rotation and complexities, leading to fracture disconnection or reduced proppant placement during the treatment. In this paper, rock properties are estimated for a targeted formation using well logs to create a geomechanical model. Natural fracture and stress azimuths within the interval were interpreted from borehole image logs. The image log interpretations inferred that fissures are oriented 30–60° relative to the maximum horizontal stress. Next, diagnostic fracture injection test (DFIT) data was used with the poro-elastic stress equations to predict tectonic strains. Finally, the geomechanical model was history-matched with a planar 3D hydraulic fracturing simulator, and gave more insight into fracture propagation in an environment of pre-existing natural fractures. The natural fracture azimuths and calibrated geomechanical model are input into a framework to evaluate varying scenarios that might result based on a vertical or inclined well design. A well design is proposed based on the natural fracture orientation relative to the hydraulic fracture that minimises complexity to optimise proppant placement. In addition, further models and diagnostics are proposed to aid predicting the hydraulically induced fracture geometry, its impact on gas production, and optimising wellbore trajectory to positively interact with pre-existing natural fractures.

Defining structural permeability in Australian sedimentary basins

2015 ◽  
Vol 55 (1) ◽  
pp. 119 ◽  
Author(s):  
Adam Bailey ◽  
Rosalind King ◽  
Simon Holford ◽  
Joshua Sage ◽  
Martin Hand ◽  
...  
Keyword(s):  
Regional Scale ◽  
Sedimentary Basins ◽  
In Situ Stress ◽  
Natural Fracture ◽  
Enhanced Geothermal Systems ◽  
Structural Development ◽  
Geothermal Systems ◽  
Stress Regime ◽  
Orientation Data

Declining conventional hydrocarbon reserves have triggered exploration towards unconventional energy, such as CSG, shale gas and enhanced geothermal systems. Unconventional play viability is often heavily dependent on the presence of secondary permeability in the form of interconnected natural fracture networks that commonly exert a prime control over permeability due to low primary permeabiliy of in situ rock units. Structural permeability in the Northern Perth, SA Otway, and Northern Carnarvon basins is characterised using an integrated geophysical and geological approach combining wellbore logs, seismic attribute analysis and detailed structural geology. Integration of these methods allows for the identification of faults and fractures across a range of scales (millimetre to kilometre), providing crucial permeability information. New stress orientation data is also interpreted, allowing for stress-based predictions of fracture reactivation. Otway Basin core shows open fractures are rarer than image logs indicate; this is due to the presence of fracture-filling siderite, an electrically conductive cement that may cause fractures to appear hydraulically conductive in image logs. Although the majority of fractures detected are favourably oriented for reactivation under in situ stresses, fracture fill primarily controls which fractures are open, demonstrating that lithological data is often essential for understanding potential structural permeability networks. The Carnarvon Basin is shown to host distinct variations in fracture orientation attributable to the in situ stress regime, regional tectonic development and local structure. A detailed understanding of the structural development, from regional-scale (hundreds of kilometres) down to local-scale (kilometres), is demonstrated to be of importance when attempting to understand structural permeability.

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