bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Linear Flow Volume to Rate Transient Analysis
Authors: Acuña Jorge A. 
Published: February 2021

Abstract
This paper explores the application of two techniques to rate and pressure transient analysis of fractured wells in tight reservoirs. The first one is the Linear Flow Volume (LFV), defined as a region with size determined by a characteristic distance proportional to but smaller than the radius of investigation. Similarly to it, this distance and the LFV increase with time without dependence on flow rate or pressure. The LFV can be calculated analytically for an infinite linear system. It can also be calculated in terms of cumulative production, pressure change and compressibility. When calculated this way, it gives results that are useful to characterize the well and reservoir before and after linear flow. It gives fracture storage volume for early time and reservoir volume when there is boundary dominated flow. It can also be used to help assess whether there is a closed or open boundary condition. The second technique is a normalization method for tests with variable pressure and flow. This is an alternative to the conventional approach of using p/qB with equivalent time (Q/q) as normalizing variables. The alternative technique is simple and provides normalized variables with much less noise and a better defined straight line in linear flow plots with clear indication of the end of linear flow when present. More importantly, it retains dependence on actual production time as opposed to equivalent time. This eliminates distortions caused by the use of equivalent time. The combined use of LFV and the alternative normalization technique provides an improved methodology for analysis of fractured wells in tight reservoirs. Validation with simulated examples is presented and application to actual cases is discussed.
Hydraulic Fracture Height Containment by Weak Horizontal Interfaces
Authors: Chuprakov Dimitry , Prioul Romain 
Published: February 2021

Abstract
Weak formation bedding planes create a unique mechanism for hydraulic fracture height containment. They arrest the vertical growth of hydraulic fracture. The propagation across them may or may not occur. To quantify this fracture behavior, first we developed an analytical model of the elastic T-shaped fracture contact with frictional and cohesional interfaces. The model evaluates the fracture blunting and the shear activation of the interfaces. It predicts the buildup of the net pressure necessary for the fracture to cross the given interface. Next we conduct numerical simulations of the 3D fracture propagation in a formation with closely spaced horizontal interfaces. These simulations manifest intermittent and decelerated fracture growth in height, especially with low-viscosity fracturing fluids. This mechanism of fracture height containment is independent of the multilayer stress-contrast mechanism used conventionally. Combined with the stress mechanism, the fracture height containment model could alleviate the problem of height growth overestimation in some fracturing simulation cases.
A New Generation High-drag Proppant: Prototype Development, Laboratory Testing, and Hydraulic Fracturing Modeling
Authors: Liu Yinghui , Fonseca Ernesto , Hackbarth Claudia , Hulseman Ralph , Tackett II Kenneth N. 
Published: February 2021

Abstract
A new generation alumina ceramic proppant has been developed for higher drag and thus improved settling performance compared to conventional sand or ceramic proppant. Slickwater hydraulic fracture treatments in unconventional gas and tight oil developments are less expensive and less likely to leave residue than cross-linked gel formulations, but due to the lower viscosity, proppant transported with slickwater tends to settle out, likely contributing to screenout of proppant and shorter fracture half length with limited propped height. This novel proppant technology is designed to address the challenges of better proppant placement and increased propped height and half length in slickwater fracturing.
This paper describes prototype development of the novel proppant technology, laboratory testing, and hydraulic fracturing modeling. The new proppant is shaped such that it tumbles and flutters during sedimentation in water and this movement greatly reduces settling rate. Finite element structural analysis was conducted to optimize the geometry to achieve higher crush strength while maintaining the conductivity. Laboratory sedimentation tests show a significant increase in settling time of new generation proppant compared to 30-50 sand poppant which had similar size and weight. Hydraulic fracturing modeling shows potential for a significant increase in proppant coverage area.
With structurally designed and optimized shapes, this high drag proppant has better transport/placement due to lower settling rates, and enhanced proppant flowback control. Finally, a practical manufacturing process has been identified to enable cost-effective manufacturing of this material.
Pre-Frac Injection Test Analysis: A Unified Approach to the Application of Conventional Techniques in an Unconventional Play
Authors: Smith P. , Pinto E. 
Published: February 2021

Abstract
Pre-fracture injection tests have been commonly used, across the industry, in order to estimate the required hydraulic fracture design parameters and associated reservoir pressure. However, evidence would suggest that industry approaches to both the injection execution and the post-injection analyses are not as equally consistent. The result could potentially be an erroneous and inaccurate interpretation, which could lead to over estimation of these reservoir characteristics and subsequent inefficient fracture design and placement.
This paper demonstrates how a unified approach to the analysis of pre-frac injection tests can lead to the valid application of this technique in obtaining reliable estimates of both the reservoir pressure and the matrix permeability in a tight unconventional shale play (Utica play fairway). Analyses of the pressure fall off data, from pre-frac injection tests that were performed in a number of wells, will be discussed here. These analyses included the use of a conventional log-log diagnostic plot, as well as Pressure Decline Analysis using the SQRT (square root time), G function and G dP/dG plots. Finally, the results were also interpreted utilizing the ACA (after closure analysis) approach by employing type curves and flow regime time functions.
The results of the formation permeability, the initial reservoir pressure, the closure time and the closure pressure from three of these field tests will be presented in this paper. Two of these tests achieved pseudo-radial flow, whilst one test failed to reach either pseudo-linear or pseudo-radial flow, resulting in a demonstrable overestimation of the reservoir parameters. The paper will present the injection test execution and analysis, as well as confirming the importance of achieving pseudo radial flow in order to obtain reliable and consistent test results.
Dynamic Interaction within Multiple Limited Entry Fractures in Horizontal Wells: Theory, Implications and Field Verification
Authors: Daneshy Ali 
Published: February 2021

Abstract
Interaction between adjacent fractures in horizontal wells has been recognized and discussed for some time. However, the scope of these discussions has been narrow and covers a limited number of actual field situations.
In this paper, effects of dynamic interactions between multiple fractures are analyzed for different operational scenarios. These include effects of passive (previously fractured), active (being fractured) and multiple active fractures. A new aspect of this study, not previously covered in the literature, is examination of fracture inclination with respect to the wellbore. Paper will show that; The effect of dynamic interaction between adjacent fractures is largest when there is small difference between magnitudes of the two horizontal principal stresses, high net fracturing pressure, and short spacing between fractures.Dynamic fracture interaction is most significant when multiple fractures are created simultaneously (e. g., in Plug & Perf completions with limited entry design).There are important basic differences between dynamic interactions caused by transverse and inclined fractures. The influence is larger with inclined fractures.In multiple fracturing treatments based on limited entry, if the created fractures are transverse, dynamic interaction may cause shorter fractures to deflect and coalesce with longer adjacent fractures, thus further accelerating their growth.Compared to a single fracture, multiple limited entry fractures in horizontal wells require higher extension pressure. However, interaction between fractures is not likely to cause a significantly higher pressure in successive pumping stages in the same well.Dynamic interaction between multiple simultaneous fractures has little impact on ISIP values between successive pumping stages.In cases of small difference between the two horizontal principal stresses and high net fracturing pressure dynamic interaction can cause fracture deviations of more than 45°. This will increase the possibility of linkage between shorter fractures with longer adjacent fractures and accelerating their growth.The results presented here are in line with actual field data.
The analysis presented here differs from some existing solutions in certain critical assumptions regarding the effect of a passive fracture on the propagation of an active fracture. However, the present results are in line with actual field data trends.
The Effect of Rock Mechanical Properties on Fracture Conductivity for Shale Formations
Authors: Jansen T. , Zhu D. , Hill A. D. 
Published: February 2021

Abstract
Hydraulic fracture treatments are used in low permeability shale reservoirs in order to provide conductive pathways from the reservoir to the wellbore. The success of these treatments is highly reliant on the created fracture conductivity. Optimizing fracture designs to improve well performance requires knowledge of how fracture conductivity is affected by rock and proppant characteristics.
This study investigates the relationship between rock characteristics and laboratory measurements of propped and unpropped fracture conductivity of outcrop sample from the Eagle Ford shale and the Fayetteville shale. Triaxial compression tests were performed on core specimens in order to determine the Young's Modulus and Poisson's Ratio of the outcrop samples. Profilometer surface scans were also performed to characterize the fracture topography.
The results from this study show that the main factors affecting fracture conductivity are closure stress and proppant characteristics (concentration, size, and strength). For unpropped fractures, the fracture topography is the main factor in determining fracture conductivity. The topography interaction of the two surfaces determines the fracture width. Higher Young's Modulus helps maintain fracture width by resisting deformation as closure stress increases compared with lower Young's Modulus. For propped fractures, the more influential factor in determining fracture conductivity is proppant characteristics (concentration, size, and strength). At a proppant monolayer placement, the major mechanism for conductivity loss is proppant embedment, leading to decreased fracture width. A higher Young's Modulus reduces the proppant embedment and better maintains fracture conductivity as closure stress increases. For a multilayer proppant pack concentration, the effect of rock characteristics is negligible compared to the effect of proppant pack characteristics.
Multidisciplinary Approach in The Permian Basin - A Geological, Statistical and Engineering Case Study to Production Results on the Wichita-Albany Formation
Authors: Vera Fabián , Lemons Casee , Zhong Ming , Holcomb William D. , LaFollette Randy F. 
Published: February 2021

Abstract
This study compares reservoir characteristics, completion methods and production for 431 wells in 6 counties producing from the Wichita-Albany reservoir to assess major factors in production optimization and derive ultimate recovery estimates.
The purpose of the study is to analyze completion design patterns across the study area by combining public and proprietary data for mining. Integrating several analyses of different nature and their respective methods like statistics, geology and engineering create a modern approach as well as a more holistic point of view when certain measurements are missing from the data set. Furthermore, multivariate statistical analysis allows modeling the impact of particular completion and stimulation parameters on the production outcome by averaging out the impact of all other variables in the system.
In addition to completion type, more than 18 predictor variables were examined, including treatment parameters such as fracture fluid volume, year of completion, cumulative perforated length, proppant type, proppant amount, and county location, among others.
In this sense, this contribution seems unique in unifying statistical, engineering, and geological perspectives into a singular point of view. This work also provides complementary views for well production consideration.
Fully Coupled Hydromechanical Simulation of Hydraulic Fracturing in Three-Dimensional Discrete Fracture Networks
Authors: McClure Mark W. , Babazadeh Mohsen , Shiozawa Sogo , Huang Jian 
Published: February 2021

Abstract
We developed a hydraulic fracturing simulator that implicitly couples fluid flow with the stresses induced by fracture deformation in large, complex, three-dimensional discrete fracture networks. The simulator can describe propagation of hydraulic fractures and opening and shear stimulation of natural fractures. Fracture elements can open or slide, depending on their stress state, fluid pressure, and mechanical properties. Fracture sliding occurs in the direction of maximum resolved shear stress. Nonlinear empirical relations are used to relate normal stress, fracture opening, and fracture sliding to fracture aperture and transmissivity. Fluid leakoff is treated with a semianalytical one-dimensional leakoff model that accounts for changing pressure in the fracture over time. Fracture propagation is treated with linear elastic fracture mechanics. Non-Darcy pressure drop in the fractures due to high flow rate is simulated using Forchheimer's equation. A crossing criterion is implemented that predicts whether propagating hydraulic fractures will cross natural fractures or terminate against them, depending on orientation and stress anisotropy. Height containment of propagating hydraulic fractures between bedding layers can be modeled with a vertically heterogeneous stress field or by explicitly imposing hydraulic fracture height containment as a model assumption. The code is efficient enough to perform field-scale simulations of hydraulic fracturing with a discrete fracture network containing thousands of fractures, using only a single compute node. Limitations of the model are that all fractures must be vertical, the mechanical calculations assume a linearly elastic and homogeneous medium, proppant transport is not included, and the locations of potentially forming hydraulic fractures must be specified in advance. Simulations were performed of a single propagating hydraulic fracture with and without leakoff to validate the code against classical analytical solutions. Field-scale simulations were performed of hydraulic fracturing in a densely naturally fractured formation. The simulations demonstrate how interaction with natural fractures in the formation can help explain the high net pressures, relatively short fracture lengths, and broad regions of microseismicity that are often observed in the field during stimulation in low permeability formations, and which are not predicted by classical hydraulic fracturing models. Depending on input parameters, our simulations predicted a variety of stimulation behaviors, from long hydraulic fractures with minimal leakoff into surrounding fractures to broad regions of dense fracturing with a branching network of many natural and newly formed fractures.
Hydraulic Fracture Containment: New Insights Into Mapped Geometry
Authors: de Pater C.J. 
Published: February 2021

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.
Experiments and Modelling of Water Injection in Soft Heavy Oil Reservoirs
Authors: de Pater C.J. , Brizard Matthieu 
Published: February 2021

Abstract
Water flooding is often applied to increase the recovery of oil from reservoirs. In practice, the water injectivity below the fracture propagation pressure (at so called matrix flow), is usually too low, so that the pressure is increased and the well is fractured. The fracture behavior is however different for unconsolidated sands than for consolidated rock as higher pressures relative to the minimum stress are required to obtain fracture propagation. Injecting water at higher pressure will lead to higher recovery. Our aim was to gain experimental and numerical data to establish the transition from matrix flow to fracturing.
We present a series of model tests on different unconsolidated materials using large cylindrical samples with a diameter of 0.4 m. We changed the permeability of the sample and investigated the effect of cohesion by adding cement to some of the samples. It appeared that fractures obtained in material without any cohesion are really complex. On the other hand, adding some small cohesion to the sample, we observed a fracture more like “classical” fractures in competent rocks.
For interpreting the tests, we have developed a fully coupled numerical model taking into account the two phase flow of oil and water, and the deformation of the sample.
High-Resolution 3D Structural Geomechanics Modeling for Hydraulic Fracturing
Authors: Bérard T. , Desroches J. , Yang Y. , Weng X. , Olson K. 
Published: February 2021

Abstract
Three-dimensional (3D) geomechanical models built at reservoir scale lack resolution at the well sector scale (e.g., hydraulic fracture scale), at least laterally. One-dimensional (1D) geomechanical models, on the other hand, have log resolution along the wellbore but no penetration away from it—along the fracture length for instance. Combining borehole structural geology based on image data and finite elements (FE) geomechanics, we constructed and calibrated a 3D, high-resolution geomechanical model, including subseismic faults and natural fractures, over a 1,500- × 5,200- × 300-ft3 sector around a vertical pilot and a 3,700-ft lateral in the Fayetteville shale play. Compared to a 1D approach, we obtained a properly equilibrated stress field in 3D space, in which the effect of the structure, combined with that of material anisotropy and heterogeneity, are accounted for. These effects were observed to be significant on the stress field, both laterally and local to the faults and natural fractures. The model was used to derive and map in 3D space a series of geomechanically based attributes potentially indicative of hydraulic fracturing performance and risks, including stress barriers, fracture geometry attributes, near-well tortuosity, and the level of stress anisotropy. An interesting match was observed between some of the derived attributes and fracturing data—near-wellbore pressure drop and overall ease and difficulty to place a treatment—encouraging their use for perforation and stage placement or placement of the next nearby lateral. The model was also used to simulate hydraulic fracturing, taking advantage of such a 3D structural and geomechanical representation. It was shown that the structure and heterogeneity captured by the model had a significant impact on hydraulic fracture final geometry.
Evaluating Fracturing Fluid Flowback in Marcellus Using Data Mining Technologies
Authors: Zhou Qiumei , Dilmore Robert , Kleit Andrew , Wang John Yilin 
Published: February 2021

Abstract
Natural gas recovery from low permeability unconventional reservoirs – enabled by advanced horizontal drilling and multi-stage hydraulic fracture treatment - has become a very important energy resource in the past decade. While evaluating early gas production data in order to assess likely rate decline and ultimate gas recovery has been reported in literature, flowback water recovery has been given little consideration. Fracture fluid flowback is defined herein as aqueous phase produced within three weeks following a fracture treatment (exclusive of well shut-in time). Field data from Marcellus Shale wells in Northeastern West Virginia indicated about 2-26% of the fracture fluid is recovered during flowback. However, stimulation of gas shale is a complex engineered process, and the factors that control the volumetric flowback performance are not well understood.
The objective of this paper is to use post-hoc analysis to identify correlations between fracture fluid flowback and attributes of well completion and geological setting, and to identify those factors most important in predicting flowback performances. To accomplish this objective we selected a representative subset of 187 wells for which complete data are available (from a full set of 631 wells), including well location, completion data, hydraulic fracture treatment data and production data. The wells were classified into four groups based on geological settings. For each geological group, engineering and statistical analyses were applied to study the correlation between flowback data and well completion through traditional regression methods. Important factors considered to affect flowback water recovery efficiency include number of hydraulic fracture stages, lateral length, vertical depth, proppant mass applied, proppant size, fracture fluid volume applied, treatment rate, and shut-in time. The total proppant mass, proppant size and shut-in time have relatively large influence on volumetric flowback performance.
The new results enable one to estimate flowback volume in a spatial domain, based on known geological conditions and completion parameters, and lead to a better understanding of flowback behaviors in Marcellus Shale. This also helps industry manage flowback water and optimize production operations.