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- analysis (62)
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to

Go**Abstract**

The authors conducted the in-situ gas-tightness tests in a fractured rock at the Namikata underground LPG storage construction site in Ehime prefecture, Japan. The test consisted of two independent setups, a gas-tightness test that used boreholes, and a chamber-scale test that used a horizontal drift sealed with a concrete plug. In each test, the gas pressure was increased up to the onset of the measurable gas flow to obtain the maximum containment pressure. This paper discusses the hydraulic conditions for gas leakage initiation and the importance of the pore pressure measurement for monitoring the gas-tightness of the LPG storage cavern based on the test results. The results of preliminary two-phase flow simulation study based on the in-situ test results are also presented.

**1. INTRODUCTION**

Gas transport characteristics of fractured rocks is a great concern to variety of engineering applications such as underground storage of LPG, nuclear waste disposal, CCS and gas flooding in the oil field.

Besides absolute permeability, relative perme- ability and capillary pressure as a function of liquid phase saturation have direct influences to the results of two phase flow simulation. However, due to limited number of field tests, the applicability of the conventional two-phase flow functions, such as van Genuchten model or linear model to fractured rocks are not well understood.

The authors conducted the two types of in-situ tests, with different scales, a borehole gas-injection test and a chamber water/gas injection test in fractured granitic rock. The test area was developed at the underground LPG storage cavern construction site (Kato et al., 2007) at Namikata in Ehime prefecture in Japan (Figure 1).

ARMA-2015-228

49th U.S. Rock Mechanics/Geomechanics Symposium

air chamber, borehole, Chamber, Chamber Test, Drillstem Testing, drillstem/well testing, enhanced recovery, Fluid Dynamics, formation evaluation, fractured rock, gas injection, gas injection method, gas injection test, gas leakage, leakage, MPa, observation, open fracture, reservoir description and dynamics, Simulation, test, tightness test, Upstream Oil & Gas, water

Country:

- North America > United States (0.68)
- Asia > Japan (0.56)

**Abstract**

This paper presents laboratory experiments designed to explore the interaction between hydraulic fractures and preexisting natural fractures that are strongly cemented but over only a portion of the natural fracture. The results show that a hydraulic fracture penetrates directly through a fully and strongly cemented pre-existing natural fracture. We then vary the proportion of the natural fracture that is strongly cemented. In most of these partially-cemented cases, the hydraulic fracture is observed to persist through the entire height of the specimen both before and after the interface. However, the fracture path persists directly through strongly-cemented portions while there are offsets at uncemented portions. A fully debonded result is obtained when the cemented region is 5 mm in height, that is, 10% the height of the interface and about 13% of the hydraulic fracture halflength at the time of intersection. The initial results of this seldom-considered but almost certainly realistic configuration of partial bonding suggest that hydraulic fracture path is strongly influenced by the size of the bonded region of the natural fracture, and, perhaps more importantly, that strong bonding over only a portion of the natural fracture can be sufficient to promote hydraulic fracture crossing. Four patterns are observed for the interaction between the hydraulic fracture and the strongly cemented natural fracture: (1) complete crossing, (2) crossing and offset, (3) crossing, partial debonding and offset, (4) complete debonding.

**1. INTRODUCTION**

Hydraulic fracturing is a widely used well-stimulation technique for enhancing the productivity of oil and natural gas in unconventional reservoirs. The interaction between hydraulic fractures and pre-existing natural fractures in a reservoir can strongly influence the fracture network geometries and is widely recognized as one of the main issues for understanding hydraulic fracture propagation in unconventional, and some conventional, reservoirs. The mechanics of the interaction of hydraulic fractures with natural fractures is often understood through some now-classical analytical solutions and mechanical models [1-4]. Work on this subject is ongoing, with recent contributions aimed at experimental evaluation of these criteria and/or development of more generalized approaches [5]. Extensive numerical and experimental studies have also been conducted to interpret and predict the mode of interaction [6-10].

ARMA-2015-132

49th U.S. Rock Mechanics/Geomechanics Symposium

block, complex reservoir, experiment, experimental study, hydraulic fracture, hydraulic fracture path, hydraulic fracture propagation, hydraulic fracturing, interaction, interface, intersection, natural fracture, partially-cemented natural fracture, path, propagation, region, reservoir description and dynamics, specimen, uncemented region, Upstream Oil & Gas, well completion, wellbore

SPE Disciplines:

**Abstract**

Underground storage of CO_{2} will lead to chemical fluid-rock interactions which may potentially alter the porosity and the flow patterns in faults. In this study, we present a coupled numerical model combining chemical fluid-rock interactions, aqueous diffusion, fluid flow, and mechanical processes, aiming at a better understanding of mineral reactions leading to changes of the rock properties, the associated flow patterns and the mechanical stability of faulted caprock on the long-term (500 yrs). In the examples that we studied the mechanical stability of the caprock system was not affected, but significant porosity changes were predicted for low-consolidated fault gouges. Coupled chemical-flow modelling is preferred over chemical modelling as this showed significantly higher porosity increases.

**1. INTRODUCTION**

Global emissions of carbon dioxide (CO_{2} ) into the atmosphere, mainly as a result of fossil fuel burning and cement production, is believed to significantly influence global warming [1]. Carbon capture and storage (CCS) is potentially able to reduce these emissions on a short to medium time scale by storing CO_{2} in geological structures of the deep subsurface. The CO_{2} is trapped below a sealing caprock in porous media like sandstones or carbonate rocks. One of the main risks associated with storage activities is the leakage of CO_{2} into shallower regions of continental groundwater systems [2]. The release of CO_{2} results preferentially in water acidification and potential mobilization of trace elements, which may have a toxic effect on the environment [3]. Uncertainties are mainly related to potential leakage mechanisms, through faults and fractures, along wellbores and sealing caprock material, by convection and diffusion.

ARMA-2015-165

49th U.S. Rock Mechanics/Geomechanics Symposium

caprock, carbon concentration, cell, chemical, climate change, concentration, diffusion, distribution, fault, flow in porous media, Fluid Dynamics, gouge, health safety security environment and social responsibility, increase, mineral, model, Phreeqc, porosity, porosity increase, reaction, Reservoir Characterization, reservoir description and dynamics, subsurface storage, Upstream Oil & Gas

SPE Disciplines:

- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Health, Safety, Security, Environment and Social Responsibility > Environment > Climate change (1.00)

**Abstract**

Present study investigates applicability, superiorities and impediments of point estimate methods (PEM) in probabilistic stability analysis of rock slopes. A rock slope which involves correlated non-normally distributed variables, is considered and probabilistic analyses are carried out incorporating four different PEMs with numerical method. It is illustrated that correlation and asymmetry in random variables can be treated in different ways by using different PEMs. Some methods like Rosenblueth’s or Zhou & Nowak’s PEMs are originally applicable for correlated skewed random parameters while deficiencies of Harr’s and Hong’s PEMs arise when random variables are non-normally distributed and correlated, respectively. It is shown that how can manipulate these two methods in order to make them usable for correlated non-normal variables.

**1. Introduction**

Having considered the recent works which have been done by [1-9] in recent two decades, it can be said that probabilistic analyses are increasingly becoming popular in geotechnical engineering in order to take uncertainties into account where stability of geotechnical structures are investigated. When these analyses are performed using numerical methods, it is vital to select an appropriate probabilistic tool that not only can readily be incorporated with numerical method, but also makes the analyses efficient. Monte Carlo Simulation (MCS) [10], reliability methods and point estimate method (PEM) [11] are some probabilistic tools which are widely used in geotechnical engineering. In case that model evaluation is time consuming, MCS is infeasible because small number of simulations leads to inaccurate results and on the other hand, large number of simulations leads to inefficiency. FORM [12] and SORM [13] need to calculate derivatives of performance function with respect to random parameters; as a result, these methods may not easily be combined with numerical methods. Under such circumstances, PEMs often constitute more practical alternatives as they require smaller amount of computations along with statistical moments for inputs only. In this research, the applicability of PEMs in analyzing the stability of a rock slope probabilistically, is investigated.

ARMA-2015-247

49th U.S. Rock Mechanics/Geomechanics Symposium

analysis, Artificial Intelligence, correlation, correlation coefficient, distribution, drilling operation management, Hong, machine learning, method, PEM, point estimate method, reserves evaluation, reservoir description and dynamics, rock slope, Rosenblueth, safety, safety factor, triangular distribution

SPE Disciplines:

Technology: Information Technology > Artificial Intelligence > Machine Learning > Statistical Learning (0.31)

**Abstract**

This paper studies vertical stress redistributions around wellbores and reservoirs due to yielding and plastic deformations. The analyses in this paper compare between predictions of elastic, poroelastic, elastoplastic, and poroplastic material models. Two elastoplastic models are used: 1) The Drucker Prager Model (DP), and 2) The Mohr Coulomb Model (MC); while The Modified Cam Clay Model (MCC) is used as the poroplastic model. Although all models are calibrated to the behavior of an analogue shale using drained triaxial compression tests; the models give different predictions in other modes of shearing and other drainage conditions. Two geomechanical problems are considered in the paper: 1) The Wellbore Stability Problem, and 2) The Reservoir Depletion Problem; both of which are analyzed using the finite element commercial software ABAQUS. The wellbore problem considers an undrained vertical wellbore in uniform horizontal stress conditions using a 2D plane strain model. Analyses show that the MC model gives safe predictions and comparable results of vertical stress redistribution to that of the MCC model. The reservoir problem considers a circular disc-like reservoir using a 2D axisymmetric model. The initial stress distribution is considered; once assuming constant far field stresses, and also including the effect of variation due to gravity. Vertical stress redistribution is significant when plastic pore collapse is considered by using the MCC model for reservoir material. Analysis shows that assuming constant far field stresses is a good approximation to the reservoir depletion problem.

**1. INTRODUCTION**

The geomechanical analysis of wellbores and reservoirs usually includes the assumption of constant vertical stresses. The safe mud window for stable wellbores is determined to prevent the hoop stresses from causing a breakout, ignoring possible change in vertical stresses. Dunayevsky et al. [1] formulated a semi-analytical solution to the thick wall cylinder problem. In this solution the vertical stresses are assumed constant. Zoback [2] formulated the DARS (Deformation Analysis in Reservoir Space) methodology to measure the stress path and compaction of a depleting reservoir. This stress path is considered in the reservoir space where only horizontal stresses vary with pore pressures. The idea of constant vertical stresses is plausible because at any given level the vertical stresses would be the weight of the overburden which is not expected to change. If the theory of elasticity is applied to the reservoir depletion problem, the vertical stresses do not change for infinitely long reservoirs. Segal and Fitzgerald [3] stated that for a reservoir of aspect ratio 10:1, the change in vertical stress can be ignored as predicted by the theory of elasticity.

ARMA-2015-307

49th U.S. Rock Mechanics/Geomechanics Symposium

SPE Disciplines: Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)

**Abstract**

Single digit percentage of oil shale recovery leaves a large room for recovery improvement, while aqueous phase injection into shale formation is extremely challenging. Injecting Carbon Dioxide (CO_{2}) into oil shale formations can potentially improve oil recovery. Furthermore, the large surface area in the organic rich shale could permanently store CO_{2} volume without jeopardizing the formation integrity. This work is a study on evaluating the effectiveness of CO_{2} enhanced oil shale recovery and shale formation CO_{2} sequestration capacity. A compositional reservoir simulator is used to model CO_{2} injection. Petrophysical and fluid properties similar to the Bakken formation are used to set up the base model for simulation. The reservoir model considered petrophysical characteristics of shale formation that affects CO_{2} flow migration like in-situ stress changes, reservoir heterogeneity, and natural fractures. The results are based on sensitivity analysis of the characteristic shale petrophysical and geomechanical properties. Sensitivity analysis method analyzed all uncertain parameters together using the Design of Experiment and Response Surface Modeling approach to counter the interaction between parameters and influential parameters into generating a proxy model for optimizing oil recovery and CO_{2} injection into the formation. The above studies are implemented with and without geomechanical module and results are analyzed. The results show that facilitating oil recovery from shale reservoirs by CO_{2} injection is much higher than primary depletion depending on fracture network connectivity and geomechanical impact. Also, significant CO_{2} storage capacity if applicable in shale formations, will be a major step towards advances in CO_{2} sequestration in widely spread shale reservoirs.

**1. INTRODUCTION**

Unconventional reservoir is a term to describe a hydrocarbon resource that could not be technically or economically recoverable without stimulation. Reservoir quality of tight formations is categorized as very poor because the ultra-low permeability restricts fluid movement within the reservoir. This leads to single digit oil recovery factors and costly development activities. Commercial development of low permeability, ultra-tight formations by advances in horizontal drilling and multi-stage hydraulic fracturing techniques have led to the production of significant amount of hydrocarbons. A typical production profile of an unconventional tight oil formation is illustrated in Figure 1. The high initial production rates usually attribute to hydraulic fractures, and then oil rate declines steeply once the oil near the fractured zone is produced. Beyond this rate, the flow is mainly controlled by inter-porosity mass transfer between the matrix and fracture network. In literature we studied, enhanced oil recovery (EOR) for unconventional oil reservoirs are limited.

ARMA-2015-520

49th U.S. Rock Mechanics/Geomechanics Symposium

analysis, effect, enhanced recovery, formation, fracture, hydraulic fracturing, injection, model, natural fracture, objective function, Oil Recovery, permeability, producer, production, proxy model, reservoir, Reservoir Characterization, reservoir description and dynamics, reservoir model, Simulation, Upstream Oil & Gas, well completion

Oilfield Places:

- North America > United States > North Dakota > Williston Basin > Middle Bakken Shale (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale (0.99)
- North America > United States > North Dakota > Parshall Field (0.99)
- (7 more...)

SPE Disciplines:

**Abstract**

While numerous definitions of what makes Unconventional Plays ‘unconventional’ have been put forth, ranging from the reliance on horizontal wells and hydraulic fracturing technology to the often ultra-low permeability of the matrix, a key characteristic of Unconventionals is the impact of geomechanics on hydraulic fracturing in reservoir formations with natural fractures and/or weakness planes (e.g., bedding planes). Critical geomechanics effects include the influence of: 1) all three principal stress magnitudes; 2) anisotropy in the stress magnitudes; 3) the orientation of the stress field; 4) in-situ pressure (e.g., pressure within the natural fractures and weakness planes); 5) natural fracture and weakness plane frequency and connectivity; 6) natural fracture and weakness plane orientation relative to the stress field; 7) natural fracture and weakness plane mechanical properties (elastic properties such as stiffness as well as strength properties such as cohesion and friction coefficient); 8) natural fracture and weakness plane initial aperture; and 9) the interaction with operational parameters during a hydraulic fracture stimulation (e.g., rate, volume, and viscosity). In this paper, the authors review the importance and impact of these critical geomechanical parameters on hydraulic fracturing design and effectiveness in Unconventionals.

**1. INTRODUCTION**

Numerous definitions of what makes Unconventional Plays ‘unconventional’ have been put forth ranging from the reliance on horizontal wells and hydraulic fracturing technology to the often ultra-low permeability of the matrix (as low as single-digit nanodarcy). However, an important key to Unconventionals is the impact of geomechanics on hydraulic fracturing in reservoir formations with natural fractures and/or weakness planes (e.g., bedding planes), which has often made hydraulic fracture design and implementation both challenging and inconsistent in Unconventionals.

While commercial hydraulic fracturing has been conducted for more than 65 years [1], hydraulic fracture design has been based upon the assumption that equal half-length, bi-planar fractures will develop since a dominant control on fracture length is fracture height growth, which itself is dominantly controlled by the vertical profile of the minimum in-situ principal stress, Shmin [2]. This assumption is often valid because hydraulic fractures are created using hydraulic energy, which acts omni-directionally, ensuring that hydraulic fracture propagation always follows the path of least resistance, which itself is often dominated by a laterally-uniform stress field.

ARMA-2015-514

49th U.S. Rock Mechanics/Geomechanics Symposium

**Abstract**

Construction of mountain roads at western Saudi Arabia is a challenge, where the rock masses are high-rising, steep slopes. Al-Hada mountain road of almost 22 km long shows many incidents of rockfalls. A studied 100 m long portion of mountain road lie along a man-made and natural sharp slope cut suffers from slope failures, rockfalls incidents, mainly in rainy seasons. The igneous rock masses are medium quality. The 40 m-height rock slope-cut along the road has no benches. The steep man-made rock slope cut is very close to the road, forming a potentially source for rockfalls. The *Swedge, Roctopple*, and *RocFal*l computer program utilized to perform modeling and mitigation of the rock slope. No remedial measures taken to prevent the debris flows to take place. Input parameters such as block size, seeder point’s locations of blocks falls, slope angle, restitution coefficients, and slope roughness used to model the rock mass characteristics such as strength, bounce height, kinetic energies, and translational and rotational velocities. Modeling of the input parameters indicates the increase of the hit energy and end-point of rockfalls as the block size and slope angle increases.

**1. INTRODUCTION**

The slope failures, landslides and rockfalls frequently occur along mountain roads in rugged terrains. One of the most difficult terrains in western Saudi Arabia is the Al-Hada descent (Fig. 1). The famous Al-Hada descent lies at the upstream high elevation region of Wadi Na’man in the western part of the Kingdom of Saudi Arabia (KSA), which known as Arabian Shield. The elevations at the top of the Al-Hada road reach almost 2,000 m a.m.s.l. and its alignment lies within the sharp cliff edges of the Sarawat Mountains at the highest elevations. Before ascend the road starts from about 500 m elevation and reaches to more than 2,000 m, in a number of road twists.

ARMA-2015-441

49th U.S. Rock Mechanics/Geomechanics Symposium

**Abstract**

We have used a hydraulic fracture model to quantify fault rupturing promoted by injection and migration of fluid into a fault, which contains in-plane high-conductivity segments and out-of-plane jogs or branches. The fluid under elevated pressure can promote extension-shear fracturing. The model provides numerical results on the opening and pressure variations with position and time. High-conductivity segments aid penetration of the pressurized fluids, but limit fluid pressure increases, so as to sustain a stable rupture growth mode. In the presence of varying normal stresses, stable growth cannot be maintained by pressure variations leading to the unstable growth in shear, and rapid fault movement events can be triggered as the fault re-establishes stable growth, radiating seismic energy and accompanied by local backward slip. These coupled seismic and aseismic faulting processes are applicable to faults with jogs and branches, which interact with the main fault to produce changes in the local stress states. The opening and slip along jogs and branches, either pre-existing or induced by fluid flow, will not only contribute to fluid storage due to their suction pumping action, but also produce changes in the downstream flow rates. The slip along them can produce associated opening along the main fault, but their opening can increase the compressive stress across the main fault which restricts its opening. The deformation transfer at junctions can complicate the fracture and flow responses.

**1. INTRODUCTION**

Injection of liquid waste has been found to result in generation of seismic events and some of these may be large enough to be felt at the surface [1, 2]. The total volume injected and the maximum size of the seismic events generated have been found to be correlated [3]. Microseismic monitoring of low-level induced seismicity generated by hydraulic fracturing is a technology applied in unconventional gas reservoirs [4- 6] for the purpose of mapping the extent of fracturing.

Considerable effort has been devoted to detecting and locating seismic events associated with fluid injection. However, little attention has been paid to understanding the source mechanisms of seismic events for a pressurized fault [7, 8]. Hydraulic fracturing in lowpermeability reservoirs is strongly affected by natural fractures within the targeted rock layers. Stimulation improves the connection of these fractures to one another and to the hydraulic fracture. Slip on these natural fractures can be activated by stress changes to generate low-magnitude seismic events. Meanwhile, shearing and shear-induced dilation on the natural fractures enhances conductivity and increases the stimulated volume. The aperture distribution along a fracture, including the initial and subsequent propagation paths, controls the conductivity and pressure distributions resulting from the injection. An integrated coupled hydraulic fracture model is applied in this paper to this problem to predict the relationship among stress, pressure, deformation and rupture growth.

ARMA-2015-084

49th U.S. Rock Mechanics/Geomechanics Symposium

branch, change, complex reservoir, conductivity, direction, displacement, fault, fracture characterization, frictional, growth, hydraulic fracturing, increase, injection, jog, MPa, Reservoir Characterization, reservoir description and dynamics, reservoir geomechanics, rupture, rupture growth, seismic processing and interpretation, shear, shear stress, slip, stress, Upstream Oil & Gas, variation, well completion

Oilfield Places:

- North America > United States > Texas > East Texas Basin > Carthage Field > Cotton Valley Sand (0.99)
- North America > United States > Oklahoma > Oklahoma Resource Basin (0.97)

Hosseini Boosari, S. Sina (West Virginia University and University of Texas at Austin) | Aybar, Umut (University of Texas at Austin) | Eshkalak, Mohammad O. (University of Texas at Austin)

**Abstract**

Thousands of horizontal wells are drilled into the shale formations across the U.S. and natural gas production has substantially increased during past years. This fact is accredited to the fast progresses obtained in hydraulic fracturing and pad drilling technologies. The contribution of shale rock surface desorption to production is widely accepted and confirmed by the industry experts often observed through laboratory and field evidences. Nevertheless, the subsequent changes in porosity and permeability due to methane desorption combined with hydraulic fracture closures due increased net effective rock stress state, have not been captured in current shale gas modeling and simulation. Hence, it is very critical to investigate the effects of induced permeability, porosity, and stress by methane desorption on gas production.

We have developed a numerical model to study the effect of changes in porosity, permeability and compaction on four major U.S. shale formations considering their Langmuir isotherm desorption behavior. These resources include; Marcellus, New Albany, Barnett and Haynesville shales. First, we introduced a model that is a physical transport of single-phase gas flow in shale porous rock. Later, the governing equations are implemented into a one-dimensional numerical model and solved using a fully implicit solution method. It is found that the natural gas production is substantially affected by desorption-induced porosity\permeability changes and geomechanics. This paper provides valuable insights into accurate modeling of unconventional reservoirs and consequently leads to a significant change in future production predictions which might enormously contribute to the U.S. economy.

**1. INTRODUCTION**

Recoverable reserves of shale gas in the U.S. are estimated to be 862 Tcf [1]. Although challenges associated to exploration and management of shale assets are yet to be resolved, decreased evaluated risk promises a secure gas supply for next decades. The large accumulation of gas shale formations might serve as both a hydrocarbon source and a productive reservoir. Most of the gas is stored in organic-rich rock while a minor fraction of gas in place is in pore spaces [2]. Extremely low matrix permeability as well as highly complex network of natural fractures are challenging characteristics of shale formations. Permeability of shale rocks is estimated to be between 50 nD (nano-Darcy) to 150 nD [3]. Recent advances and innovations in hydraulic fracturing are key success of shale gas economic production as a viable global energy supply. Nevertheless, complexities associated with flow mechanisms and existence of many pressure dependent phenomena, such as combined hydraulic and natural fracture conductivity losses, Klinkenberg gas slippage effect, desorption/adsorption and Darcy/non-Darcy flow, are not yet completely understood and need more extensive studies and modeling in order to meet our industry needs. In this study, desorption-induced porosity and permeability changes of shale matrix as well as closure effect of hydraulic fractures are focused in detail to evaluate their impact on production form four very productive U.S. shale resources

ARMA-2015-256

49th U.S. Rock Mechanics/Geomechanics Symposium

change, complex reservoir, desorption, effect, formation, gas production, geomechanics, hydraulic fracture, hydraulic fracturing, Langmuir, model, natural gas, paper, permeability, permeability change, porosity, production, reservoir description and dynamics, rock, shale gas, Upstream Oil & Gas, well completion

Oilfield Places:

- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale (0.99)
- North America > United States > Texas > Haynesville Shale (0.99)
- (10 more...)

SPE Disciplines:

Thank you!