Valuation of hydraulic fracturing potentials of organic-rich shales from the Anambra basin using rock mechanical properties from wireline logs

2021 ◽  
Vol 19 (3) ◽  
pp. 45-44
Author(s):  
Homa Viola Akaha-Tse ◽  
Michael Oti ◽  
Selegha Abrakasa ◽  
Charles Ugwu Ugwueze
Keyword(s):  
Mechanical Properties ◽  
Hydraulic Fracturing ◽  
Horizontal Stress ◽  
Shale Formations ◽  
In Situ Stresses ◽  
Anambra Basin ◽  
Wireline Logs ◽  
Rock Mechanical Properties ◽  
Minimum Horizontal Stress

This study was carried out to determine the rock mechanical properties relevant for hydrocarbon exploration and production by hydraulic  fracturing of organic rich shale formations in Anambra basin. Shale samples and wireline logs were analysed to determine the petrophysical, elastic, strength and in-situ properties necessary for the design of a hydraulic fracturing programme for the exploitation of the shales. The results obtained indicated shale failure in shear and barreling under triaxial test conditions. The average effective porosity of 0.06 and permeability of the order of 10-1 to 101 millidarcies showed the imperative for induced fracturing to assure fluid flow. Average Young’s modulus and Poisson’s ratio of about 2.06 and 0.20 respectively imply that the rocks are favourable for the formation and propagation of fractures during hydraulic fracking. The minimum horizontal stress, which determines the direction of formation and growth of artificially induced hydraulic fractures varies from wellto-well, averaging between 6802.62 to 32790.58 psi. The order of variation of the in-situ stresses is maximum horizontal stress>vertical stress>minimum horizontal stress which implies a reverse fault fracture regime. The study predicts that the sweet spots for the exploration and development of the shale-gas are those sections of the shale formations that exhibit high Young’s modulus, low Poisson’s ratio, and high brittleness. The in-situ stresses required for artificially induced fractures which provide pore space for shale gas accumulation and expulsion are adequate. The shales possess suitable mechanical properties to fracture during hydraulic fracturing. Application of these results will enhance the potentials of the onshore Anambra basin as a reliable component in increasing Nigeria’s gas reserves, for the improvement of the nation’s economy and energy security. Key Words: Hydraulic Fracturing, Organic-rich Shales, Rock Mechanical Properties, Petrophysical Properties, Anambra Basin

A Novel Method and its Application to Define Maximum Horizontal Stress and Stress Path

2021 ◽  
Author(s):  
Jianguo Zhang ◽  
Karthik Mahadev ◽  
Stephen Edwards ◽  
Alan Rodgerson
Keyword(s):  
Fracture Initiation ◽  
Stress Path ◽  
Horizontal Stress ◽  
Geomechanical Model ◽  
Breakdown Pressure ◽  
In Situ Stresses ◽  
Fracture Closure ◽  
Minimum Horizontal Stress ◽  
Maximum Horizontal Stress

Abstract Maximum horizontal stress (SH) and stress path (change of SH and minimum horizontal stress with depletion) are the two most difficult parameters to define for an oilfield geomechanical model. Understanding these in-situ stresses is critical to the success of operations and development, especially when production is underway, and the reservoir depletion begins. This paper introduces a method to define them through the analysis of actual minifrac data. Field examples of applications on minifrac failure analysis and operational pressure prediction are also presented. It is commonly accepted that one of the best methods to determine the minimum horizontal stress (Sh) is the use of pressure fall-off analysis of a minifrac test. Unlike Sh, the magnitude of SH cannot be measured directly. Instead it is back calculated by using fracture initiation pressure (FIP) and Sh derived from minifrac data. After non-depleted Sh and SH are defined, their apparent Poisson's Ratios (APR) are calculated using the Eaton equation. These APRs define Sh and SH in virgin sand to encapsulate all other factors that influence in-situ stresses such as tectonic, thermal, osmotic and poro-elastic effects. These values can then be used to estimate stress path through interpretation of additional minifrac data derived from a depleted sand. A geomechanical model is developed based on APRs and stress paths to predict minifrac operation pressures. Three cases are included to show that the margin of error for FIP and fracture closure pressure (FCP) is less than 2%, fracture breakdown pressure (FBP) less than 4%. Two field cases in deep-water wells in the Gulf of Mexico show that the reduction of SH with depletion is lower than that for Sh.

scholarly journals In Situ Stress Prediction in Subsurface Rocks: An Overview and a New Method

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-11
Author(s):  
Yushuai Zhang ◽  
Shangxian Yin ◽  
Jincai Zhang
Keyword(s):  
Horizontal Stress ◽  
In Situ Stress ◽  
New Method ◽  
Alternative Methods ◽  
Tensile Fracture ◽  
In Situ Stresses ◽  
Stress Estimation ◽  
Minimum Horizontal Stress ◽  
Polygon Method

Methods for determining in situ stresses are reviewed, and a new approach is proposed for a better prediction of the in situ stresses. For theoretically calculating horizontal stresses, horizontal strains are needed; however, these strains are very difficult to be obtained. Alternative methods are presented in this paper to allow an easier way for determining horizontal stresses. The uniaxial strain method is oversimplified for the minimum horizontal stress determination; however, it is the lower bound minimum horizontal stress. Based on this concept, a modified stress polygon method is proposed to obtain the minimum and maximum horizontal stresses. This new stress polygon is easier to implement and is more accurate to determine in situ stresses by narrowing the area of the conventional stress polygon when drilling-induced tensile fracture and wellbore breakout data are available. Using the generalized Hooke’s law and coupling pore pressure and in situ stresses, a new method for estimating the maximum horizontal stress is proposed. Combined it to the stress polygon method, a reliable in situ stress estimation can be obtained. The field measurement method, such as minifrac test, is also analyzed in different stress regimes to determine horizontal stress magnitudes and calibrate the proposed theoretical method. The proposed workflow combined theoretical methods to field measurements provides an integrated approach for horizontal stress estimation.

Simulation of hydraulic fracturing in tight formations

2010 ◽  
Vol 50 (1) ◽  
pp. 581 ◽  
Author(s):  
Mohammad Sarmadivaleh ◽  
Vamegh Rasouli
Keyword(s):  
Mechanical Properties ◽  
Hydraulic Fracturing ◽  
Analytical Models ◽  
Particle Flow Code ◽  
Gas Formation ◽  
In Situ Stresses ◽  
Initiation And Propagation ◽  
Tight Formations ◽  
Tight Gas Formation

Production from tight formations is becoming a main focus around the world and particularly in Australia. Hydraulic fracturing is one of the commonly used approaches to stimulate production from tight reservoirs. A good understanding of mechanical properties of formation and the in-situ stresses is essential for a hydraulic fracturing study. In this work, using the log based approach, the mechanical properties and in-situ stresses were estimated in a tight gas formation. This data is then used as input for 2D numerical simulation of hydraulic fracturing in particle flow code (PFC). The initiation and propagation of an induced fracture was studied by increasing the rock strength to simulate a tight formation response. Thereafter, the model was divided into two zones to investigate the fracture containment capacity to simulate a fracture intersecting an interbed with formation properties being different on the two sides. The formation bond strength was increased on one side of the interbed and fracture extension was monitored. The results of both simulations showed how, by increasing formation strength equivalent to a tighter formation, the fracture extension ability reduces and the interbed containment capacity increases. The results were compared with some of the analytical models and good agreement was observed.

Hydraulic fracturing experiment at the University of Regina Campus

1986 ◽  
Vol 23 (4) ◽  
pp. 548-555 ◽  
Author(s):  
J. D. McLennan ◽  
H. S. Hasegawa ◽  
J -C Roegiers ◽  
Alan M. Jessop
Keyword(s):  
Hydraulic Fracturing ◽  
Stress Component ◽  
Horizontal Stress ◽  
Depth Range ◽  
Precambrian Basement ◽  
Breakdown Pressure ◽  
Overburden Pressure ◽  
Minimum Horizontal Stress ◽  
The University

A hydraulic fracturing stress determination was carried out during May and June, 1979, in a water well intended for the Geothermal Feasibility Project on the campus of the University of Regina, Saskatchewan. Four intervals between depths of 2062 and 2215 m were fractured successfully, one in the Winnipeg Formation (2034–2083 m), two in the Deadwood Formation (2083–2209 m), and one under the Phanerozoic sequence near the top of the Precambrian basement (2209–2215 m).Over the depth range (2062–2215 m) covered by this hydrofracture experiment, the results and inferences are as follow. Downhole breakdown pressure ranges from 42 to 45 MPa, and downhole shut-in pressure from 35 to 42 MPa. The minimum horizontal stress component, σhmin, is taken as being equal to the corresponding shut-in pressure. The vertical stress component, σv, is assumed to be essentially equal to the overburden pressure and varies from 51 to 56 MPa. Whereas σv and σhmin apparently vary smoothly across the Deadwood Formation, the maximum horizontal component, σhmax, appears to undergo a discontinuity in the upper part of the Deadwood Formation, as σHMAX varies from 40 MPa in the Winnipeg Formation to 53 MPa in the upper part of the Precambrian basement. In so far as seismotectonics is concerned, the physical implications of these measurements are that normal faulting should prevail in the Winnipeg (and overlying) formations whereas strike-slip faulting could occur in the Precambrian basement; however, the latter inference has not been firmly established. Breakdown pressure is a useful guide (upper limit) for the potential geothermal demonstration project. Key words: hydraulic fracture, fracture mechanics, faulting, stresses, in situ, breakdown, shut-in pressure, seismotectonics.

scholarly journals Approximate Dynamic Programming Based Control of Proppant Concentration in Hydraulic Fracturing

Mathematics ◽  
2018 ◽  
Vol 6 (8) ◽  
pp. 132 ◽  
Author(s):  
Harwinder Singh Sidhu ◽  
Prashanth Siddhamshetty ◽  
Joseph Kwon
Keyword(s):  
Mechanical Properties ◽  
Dynamic Programming ◽  
Hydraulic Fracturing ◽  
Young’S Modulus ◽  
Large Scale ◽  
Approximate Dynamic Programming ◽  
Young's Modulus ◽  
Computational Cost ◽  
Control Technique ◽  
Rock Mechanical Properties

Hydraulic fracturing has played a crucial role in enhancing the extraction of oil and gas from deep underground sources. The two main objectives of hydraulic fracturing are to produce fractures with a desired fracture geometry and to achieve the target proppant concentration inside the fracture. Recently, some efforts have been made to accomplish these objectives by the model predictive control (MPC) theory based on the assumption that the rock mechanical properties such as the Young’s modulus are known and spatially homogenous. However, this approach may not be optimal if there is an uncertainty in the rock mechanical properties. Furthermore, the computational requirements associated with the MPC approach to calculate the control moves at each sampling time can be significantly high when the underlying process dynamics is described by a nonlinear large-scale system. To address these issues, the current work proposes an approximate dynamic programming (ADP) based approach for the closed-loop control of hydraulic fracturing to achieve the target proppant concentration at the end of pumping. ADP is a model-based control technique which combines a high-fidelity simulation and function approximator to alleviate the “curse-of-dimensionality” associated with the traditional dynamic programming (DP) approach. A series of simulations results is provided to demonstrate the performance of the ADP-based controller in achieving the target proppant concentration at the end of pumping at a fraction of the computational cost required by MPC while handling the uncertainty in the Young’s modulus of the rock formation.

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