Factor Analysis of Vertical Hydraulic Fracture Geometry in Coal Bed

2013 ◽  
Vol 316-317 ◽  
pp. 892-895 ◽  
Author(s):  
Bai Lie Wu ◽  
Yuan Fang Cheng ◽  
You Zhi Li ◽  
Peng Xu ◽  
Yu Ting Zhang
Keyword(s):  
Effective Means ◽  
Propagation Model ◽  
Coal Bed ◽  
Vertical Wells ◽  
Differential Stress ◽  
Fracture Geometry ◽  
Fracture Length ◽  
Treatment Conditions ◽  
Pump Rate ◽  
Fracture Height

Hydraulic fracturing is one of the effective means to enhance coal bed methane production for vertical wells. This paper presents an approach that uses pseudo-3D fracture propagation model to study the influence of petrophysical properties, differential stress, treatment conditions, etc. on fracture geometry. It is shown that differential stress, pump rate is proportional to fracture length and width; elastic modulus, Poisson`s ratio, pump rate, etc. is proportional to fracture height. The finding is of great importance for acquiring ideal fracture geometry.

Utilizing Microseismic to Monitor Fracture Geometry in a Horizontal Well in a Tight Sandstone Formation

2021 ◽  
Author(s):  
Abu M. Sani ◽  
Hatim S. AlQasim ◽  
Rayan A. Alidi
Keyword(s):  
Horizontal Well ◽  
Fracture Propagation ◽  
Horizontal Stress ◽  
Height Growth ◽  
Tight Sandstone ◽  
Fracture Geometry ◽  
Fracture Length ◽  
Sandstone Formation ◽  
Fracture Height ◽  
Maximum Horizontal Stress

Abstract This paper presents the use of real-time microseismic (MS) monitoring to understand hydraulic fracturing of a horizontal well drilled in the minimum stress direction within a high-temperature high-pressure (HTHP) tight sandstone formation. The well achieved a reservoir contact of more than 3,500 ft. Careful planning of the monitoring well and treatment well setup enabled capture of high quality MS events resulting in useful information on the regional maximum horizontal stress and offers an understanding of the fracture geometry with respect to clusters and stage spacing in relation to fracture propagation and growth. The maximum horizontal stress based on MS events was found to be different from the expected value with fracture azimuth off by more than 25 degree among the stages. Transverse fracture propagation was observed with overlapping MS events across stages. Upward fracture height growth was dominant in tighter stages. MS fracture length and height in excess of 500 ft and 100 ft, respectively, were created for most of the stages resulting in stimulated volumes that are high. Bigger fracture jobs yielded longer fracture length and were more confined in height growth. MS events fracture lengths and heights were found to be on average 1.36 and 1.30 times, respectively, to those of pressure-match.

Investigation of Rupture and Slip Mechanisms of Hydraulic Fractures in Multiple-Layered Formations

SPE Journal ◽  
2019 ◽  
Vol 24 (05) ◽  
pp. 2292-2307 ◽  
Author(s):  
Jizhou Tang ◽  
Kan Wu ◽  
Lihua Zuo ◽  
Lizhi Xiao ◽  
Sijie Sun ◽  
...  
Keyword(s):  
Fluid Flow ◽  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Propagation Model ◽  
Rock Deformation ◽  
Hydraulic Fractures ◽  
Fracture Geometry ◽  
Fracture Width ◽  
Hydraulic Fracture Propagation ◽  
Fracture Height

Summary Weak bedding planes (BPs) that exist in many tight oil formations and shale–gas formations might strongly affect fracture–height growth during hydraulic–fracturing treatment. Few of the hydraulic–fracture–propagation models developed for unconventional reservoirs are capable of quantitatively estimating the fracture–height containment or predicting the fracture geometry under the influence of multiple BPs. In this paper, we introduce a coupled 3D hydraulic–fracture–propagation model considering the effects of BPs. In this model, a fully 3D displacement–discontinuity method (3D DDM) is used to model the rock deformation. The advantage of this approach is that it addresses both the mechanical interaction between hydraulic fractures and weak BPs in 3D space and the physical mechanism of slippage along weak BPs. Fluid flow governed by a finite–difference methodology considers the flow in both vertical fractures and opening BPs. An iterative algorithm is used to couple fluid flow and rock deformation. Comparison between the developed model and the Perkins–Kern–Nordgren (PKN) model showed good agreement. I–shaped fracture geometry and crossing–shaped fracture geometry were analyzed in this paper. From numerical investigations, we found that BPs cannot be opened if the difference between overburden stress and minimum horizontal stress is large and only shear displacements exist along the BPs, which damage the planes and thus greatly amplify their hydraulic conductivity. Moreover, sensitivity studies investigate the impact on fracture propagation of parameters such as pumping rate (PR), fluid viscosity, and Young's modulus (YM). We investigated the fracture width near the junction between a vertical fracture and the BPs, the latter including the tensile opening of BPs and shear–displacement discontinuities (SDDs) along them. SDDs along BPs increase at the beginning and then decrease at a distance from the junction. The width near the junctions, the opening of BPs, and SDDs along the planes are directly proportional to PR. Because viscosity increases, the width at a junction increases as do the SDDs. YM greatly influences the opening of BPs at a junction and the SDDs along the BPs. This model estimates the fracture–width distribution and the SDDs along the BPs near junctions between the fracture tip and BPs and enables the assessment of the PR required to ensure that the fracture width at junctions and along intersected BPs is sufficient for proppant transport.

Proppant and Fracture Height Measurement from Forgotten Vertical Well Diagnostics

2021 ◽  
Author(s):  
Christopher Lawrence Squires
Keyword(s):  
Hydraulic Fracture ◽  
Height Growth ◽  
Vertical Wells ◽  
Gas Reservoirs ◽  
Height Measurement ◽  
Fracture Geometry ◽  
Role Changes ◽  
Fluid Systems ◽  
Fracture Height ◽  
The Many

Abstract This paper reviews the diagnostic data from vertical wells where operators targeted Burkett, Hamilton and Marcellus Shales and other deeper unconventional shale or tight gas reservoirs with vertical wells between the years 2006-2013. The learnings are then translated for their applicability in horizontal development wells. Its purpose is to deliver a better perception of fracture geometry and interactions between payzones that are separated by potential fracture barriers. Multiple vertical wells employed the use of diagnostics in the form of proppant tracer, production logging and post-fracture temperature surveys to provide an improved understanding of hydraulic fracture and propped fracture height and the formations that serve as hydraulic fracture barriers. Completions variables such as treating rates, proppant volumes, perforation designs and frac fluid systems are examined to determine how they relate to propped fracture height growth. In the majority of the logs reviewed, the proppant was contained to the perforated interval or just above and below. Some wells did have extensive proppant height growth. However, in most of those cases, the propped fracture height was the result of poor cement bonding, multiple fractured intervals growing towards one another and frac plug failures. As expected, hydraulic fracture height is typically significantly higher than the proppant height. Few vertical wells showed evidence of proppant connecting the Marcellus and Burkett zones. Formations acting as fracture barriers did not respond to many of the completions variables. Large treatment volumes, up to 500,000 lbs or more of proppant in a single stage, are often contained to propped fracture heights of less than 50 ft. Few vertical unconventional wells are currently drilled now that most economic Marcellus fairways are well into their development phase. Vertical wells and their learnings are often forgotten with the many personnel and role changes, acquisitions, mergers and other fast paced changes in the industry over the last decade. The purpose of this paper is to reintroduce the valuable and still relevant vital information from these forgotten vertical wells.

Hydraulic Fracture Containment: New Insights Into Mapped Geometry

2015 ◽  
Author(s):  
C.J.. J. de Pater
Keyword(s):  
Pore Pressure ◽  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Ground Truth ◽  
Height Growth ◽  
Propagation Model ◽  
Fracture Geometry ◽  
Fracture Length ◽  
Propagation Modeling ◽  
Fracture Mapping

Abstract Recently, fracture mapping has contributed a vast amount of data on hydraulic fracture geometry showing in general a fairly strong containment of fractures, but it is unclear what explains observed height containment. Re-analysis of published fracture mapping data yields a rule-of-thumb for expected fracture geometry and gives insight into the role of reservoir pressure in the observed containment. Fracture containment is important for designing stimulation treatments that cover the entire pay, without breaching into aquifers or gas caps. Although modern fracture mapping provides the ground truth for post-treatment fracture geometry, it is still important to forecast fracture height growth based on pre-treatment data. Fracture mapping shows that on average, fracture length is five times height. Some, (often depleted) reservoirs show even more extreme containment effects. In addition to stress differences, new mechanisms have been proposed to explain the strong observed containment, such as layer interface opening. Although such mechanisms are quite plausible in some formations, it is unlikely that they provide a universal explanation. New developments in fracture propagation modeling provide a simple mechanism for stronger containment than predicted by conventional models. Laboratory testing indicates that fracture propagation must be described by a cohesive zone at the tip. In such a model, rock ruptures at the fracture tip due to effective stress exceeding strength, which introduces the difference between stress and pore pressure into fracture propagation (Schmitt et al., 1989; Visser, 1998). In the first place this propagation model readily explains high net pressure, while a relatively small stress difference can yield much slower height growth compared with length growth. Furthermore, pore pressure changes upon failure can yield a strong containment effect.

Simulation of Hydraulical Fracture Height by Creating Artificial Barrier

2013 ◽  
Vol 734-737 ◽  
pp. 1262-1267
Author(s):  
Chuan Min Li ◽  
Yong Quan Hu
Keyword(s):  
Stress Gradient ◽  
Fracture Propagation ◽  
Propagation Model ◽  
Open Crack ◽  
Fracture Criteria ◽  
Intensity Factors ◽  
Net Pressure ◽  
Fracture Height ◽  
Barrier Zone ◽  
Treatment Pressure

It is quite difficult for reservoir exploitation with worse barrier zone, especially in thin pay-zone, limiting hydraulic fracture height propagation. This paper described the theory of controlling the fracture height by creating artificial barrier, and net pressure distribution in the crack was determined by assuming the artificial barrier is with stress gradient. Then, stress intensity factors in the crack tip were gotten on the basis of fracture mechanics theory, and fracture propagation model was established in accordance with fracture criteria of tensile open crack. The established model also described the action of treatment pressure on the fracture height and influence of artificial barrier on the fracture height propagation. By contrasting the results, it is feasible for artificial barrier to limit the fracture height propagation, and this model also can be used in hydraulic fracturing design in the oilfield.

A new approach to evaluate the performance of partially propped hydraulic fractures

2013 ◽  
Vol 53 (1) ◽  
pp. 355 ◽  
Author(s):  
Luiz Bortolan Neto ◽  
Aditya Khanna ◽  
Andrei Kotousov
Keyword(s):  
Sensitivity Study ◽  
Economic Benefits ◽  
Productivity Index ◽  
Hydraulic Fractures ◽  
Fracture Geometry ◽  
Fracture Conductivity ◽  
New Approach ◽  
Fracture Length ◽  
Compressive Stresses ◽  
Initial Fracture

A new approach for evaluating the performance of hydraulic fractures that are partially packed with proppant (propping agent) particles is presented. The residual opening of the partially propped fracture is determined as a function of the initial fracture geometry, the propped length of the fracture, the compressive rock stresses, the elastic properties of the rock, and the compressibility of the proppant pack. A mathematical model for fluid flow towards the fracture is developed, which incorporates the effects of the residual opening profile of the fracture and the high conductivity of the unpropped fracture length. The residual opening profile of the fracture is calculated for a particular case where the proppant pack is nearly rigid and there is no closure of the fracture faces due to the confining (compressive) stresses. A sensitivity study is performed to demonstrate the dependence of the well productivity index on the propped length of the fracture, the proppant pack permeability, and the dimensionless fracture conductivity. The sensitivity study suggests that the residual opening of a fracture has a significant impact on production, and that partially propped fractures can be more productive than fully propped fractures. Application of this new approach can lead to economic benefits.

scholarly journals Liquid–liquid gravity displacement in a vertical fracture during drilling: Experimental study and mathematical model

2019 ◽  
Vol 38 (2) ◽  
pp. 533-554
Author(s):  
Dong Xiao ◽  
Yingfeng Meng ◽  
Xiangyang Zhao ◽  
Gao Li ◽  
Jiaxin Xu
Keyword(s):  
Mathematical Model ◽  
Drilling Fluid ◽  
Effective Means ◽  
Fluid Density ◽  
Shape Factors ◽  
Fracture Width ◽  
Factors Affecting ◽  
Double Substrate ◽  
Fracture Height ◽  
Liquid Displacement

Gravity displacement often occurs when drilling a vertical fractured formation, causing a downhole complexity with risk of blowout and reservoir damage, well control difficulty, drilling cycle prolongation, and increased costs. Based on an experimental device created for simulating the gravity displacement, various factors affecting the displacement quantity were quantitatively evaluated by simulating the fracture width, asphalt viscosity, drilling fluid density, and viscosity under different working conditions, and a liquid–liquid displacement law was obtained. Using the theories of rock mechanics, fluid mechanics, and seepage mechanics, based on conformal mapping, as well as a fracture-pore double substrate fluid flow model, we established a steady-state mathematical model of fractured formation liquid–liquid gravity displacement by optimizing the shape factors and using a combination of gravity displacement experiments to verify the feasibility of the mathematical model. We analyzed the influence of drilling fluid density, fracture height and length, and asphalt viscosity on displacement rate, and obtained the corresponding laws. The results show that when the oil–fluid interface is stable, the fracture width is the most important factor affecting the gravity displacement, and plugging is the most effective means of managing gravity displacement.

Calibrating Coal Bed Methane Fracture Geometry in the Helper Utah Field Using Treatment Well Tiltmeters

2002 ◽  
Author(s):  
H.L. Stutz ◽  
D.J. Victor ◽  
M.K. Fisher ◽  
L.G. Griffin ◽  
L. Weijers
Keyword(s):  
Coal Bed ◽  
Coal Bed Methane ◽  
Fracture Geometry

Applying Slim Dipole Sonic Tool to Evaluate Hydraulic Fracture Geometry and Orientation Using the Differential Sonic Method

2022 ◽  
Author(s):  
Azzan Al-Yaarubi ◽  
Sumaiya Al Bimani ◽  
Sataa Al Rahbi ◽  
Richard Leech ◽  
Dmitrii Smirnov ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Oil Recovery ◽  
Critical Role ◽  
Differential Method ◽  
Optimum Number ◽  
Well Test ◽  
Fracture Geometry ◽  
The Subject ◽  
Fracture Height ◽  
Depth Of Investigation

Abstract Successful hydraulic fracturing is critical for hydrocarbon recovery from tight reservoirs. Fracture geometry is one essential quality indicator of the created fracture. The geometry provides information about the size of the created fracture and containment and verifies the pre-job modeling. Different techniques are applied to determine fracture geometry, and each has its own advantages and limitations. Due to its simplicity, the radioactive tracer log is commonly used to determine fracture placement and fracture height. Its main drawbacks include shallow depth of investigation, time dependency, and the requirement for multiple interventions for multistage fracturing operations. The crosswell microseismic technique probes a larger volume and it is potentially capable of providing fracture height, length, and orientation. Operational complexity and long processing turnaround time are the main challenges of this technique. Time-lapse shear slowness anisotropy analysis is an effective method to determine hydraulic facture height and orientation. In this technique, the shear slowness anisotropy is recorded before and after the fracture is created. The observed shear anisotropy difference indicates the intervals where the fractures were created, allowing these intervals lengths to be measured. Combining this analysis with gyroscopic data allows determining the fracture orientations. Compared to a tracer log, the differential casedhole sonic anisotropy (DCHSA) has a deeper depth of investigation, and it is time independent. Thus, the repeated log can be acquired at the end of the multistage fracturing operations. Compared to the microseismic technique, this new technique provides more precise fracture height and orientation. The new generation slim dipole sonic technology of 2.125-in. diameter extends the applicability of the DCHSA technique to smaller casing sizes. The shear differential method was applied to a vertical well that targeted the Athel formation in the south of the Sultanate of Oman. This formation is made of silicilyte and is characterized by very low permeability of about 0.01 md on average. Thus, hydraulic fracturing plays a critical role for the economic oil recovery in this reservoir. Aiming to achieve a better zonal contribution, the stimulation design was changed from a limited number of large fractures to an extensive multistage fracturing design in the subject well. Sixteen hydraulic fracturing stages were planned. The DCHSA was applied to provide accurate and efficient fracture geometry evaluation. The DCHSA accurately identified fracture intervals and their corresponding heights and orientations. This enabled effectively determining the created fracture quality and helped explain the responses of the production logs that were recorded during the well test. This study provided a foundation for the placement and completion design of the future wells in the subject reservoir. It particularly revealed adequate fracturing intervals and the optimum number of stages required to achieve optimum reservoir coverage and avoid vertical overlapping.

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