bluuebunny/crossref_metadata_2025 huggingface dataset:
Hydraulic Fracture Height Containment by Weak Horizontal Interfaces
Authors: Chuprakov Dimitry , Prioul Romain
Published: February 2021

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

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

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

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

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

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

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

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

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

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

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.
Examining the Impact of Hydrocarbon Drainage on Completion and In-Fill Drilling Strategies in Unconventional Reservoirs
Authors: Srinivasan Karthik , Gbededo Midowa , Hue Hongxue , Krishnamurthy Jayanth , Gonzales Veronica
Published: February 2021

Evaluating the effects of asymmetric stress distribution around a lateral can greatly help optimize completion techniques and overall production from in-fill horizontal wells in unconventional shale and tight reservoirs. Several factors affect long-term production from in-fill drilled wells including but not limited to pressure depletion from produced wells, change of effective stresses in the depleted formation and interference between hydraulic fractures when the new in-fill wells are drilled, stimulated and brought into production.

The study addresses a variety of key challenges that the unconventional oil and gas industry is looking to understand. These include understanding: How the presence of a depleted wellbore affects hydraulic fracture propagation from a nearby newly drilled wellHow refracturing considerations in a producing well are affected by hydrocarbon drainage and modified stress contrastsHow fracturing/refracturing pumping designs and volumes should be optimized to address the challenges surrounding the wellbore

Under circumstances mentioned above, pressure distribution around the wellbore from hydrocarbon drainage was estimated by history matching production data over a certain period of time. Then the impact of various types of fracturing treatments on pressure depletion profiles from offset wells was studied using a fully numerical fracture simulator that is capable of handling asymmetric stress distribution around the lateral. Fracture geometries from this study were either asymmetric due to depletion on only one side of the lateral or longer due to increased stress contrast. These fracture geometries were fed to a production model to forecast long-term production from in-fill wells and study drainage patterns over time. Understanding these challenges provided a sub-surface perspective of how completion techniques should be optimized to get maximum hydrocarbon recovery from reservoirs consisting of laterals that have already been on production.
Overcoming Obstacles for Produced Water in Bakken Well Stimulations
Authors: Schmidt Darren D. , Statoil P.E. , MacKay Bruce , Williams Brandon , Beck Frederick , Bell Adam , McMahon Blake , Bradley Heather , Lian Eric Gin
Published: February 2021

The use of produced water in well stimulation is not straightforward and presents numerous challenges. A case study using 100% produced water from the Bakken Formation to stimulate a two-well pad in Williams County North Dakota is presented. The well stimulations include a typical 30-stage plug & perf completion using a hybrid fluid design consisting of slickwater and crosslinked gel. The pad includes both a Middle Bakken horizontal and a Three Forks horizontal well. This case study addresses the challenges and obstacles faced over a two-year period since embarking on the first field experiment using 50% produced water to stimulate a well in the same area. A number of first-time experiences have been addressed in the areas of cost, fluid chemistry, water quality, facilities, logistics, storage, and regulatory. All of these factors appeared to be insurmountable barriers in the early phases of considering the use of produced water for well stimulation. However over time and with careful developments along the way, we have progressed to the point of practicality for such endeavors. This case study presents the barriers, technical issues, technology development, current practice, and expected progress of produced water stimulation in the Williston Basin.
Role of Turbulent Flow in Generating Short Hydraulic Fractures with High Net Pressure in Slickwater Treatments
Authors: Ames Brandon C. , Bunger Andrew P.
Published: February 2021

This paper provides an argument for considering turbulent flow for hydraulic fracturing using slickwater in shale reservoirs. It shows that the tendency of models that assume laminar fluid flow to over-predict fracture length and under-predict net pressure can be corrected by instead recognizing that the flow regime is turbulent for high rate, water-driven hydraulic fractures. Firstly, we provide a rationale supporting the appropriateness of assuming turbulent flow. Then, using a Perkins-Kern-Nordgren (PKN) fracture model and parameters similar to slickwater treatments in shale reservoirs, we show that the laminar flow model overpredicts fracture length and underpredicts fracture width and net pressure, compared to the turbulent flow model. The result, if indeed a hydraulic fracture grows in the turbulent fluid flow regime, is that matching the length with the laminar model requires input of an unreasonably large leak-off coefficient, resulting in an exacerbation of the underprediction of the wellbore pressure. On the other hand, the turbulent model is shown to be able, in principle, to account for short, high pressure hydraulic fractures without resorting to inflating the leak-off coefficient or compromising the calibration of the model to the wellbore pressure.
Arbitrary Fracture Propagation in Heterogeneous Poroelastic Formations Using a Finite Volume-Based Cohesive Zone Model
Authors: Bryant Eric C. , Hwang Jongsoo , Sharma Mukul M.
Published: February 2021

A finite volume-based arbitrary fracture propagation model is used to simulate fracture growth and geomechanical stresses during hydraulic fracture treatments. Single-phase flow, poroelastic displacement, and in-situ stress tensor equations are coupled within a poroelastic reservoir domain, using a fixed-strain split assumption. The domain is idealized as two-dimensional and plane-strain, with heterogeneous elastic material and fracture toughness properties. Fracture propagation proceeds by failure along finite volume cells in excess of a threshold effective stress. The cohesive zone model (CZM) is used to simulate propagation of non-planar fractures in heterogeneous porous media under uniform, anisotropic stresses. In addition the model computes the stress field and the pore pressure in the rock matrix to account for stress interference effects. This allows us to estimate the simulated micro-seismic signature of the rock during fracturing. Results show that the presence of bedding planes or planes of weakness in the rock can lead to complex fracture trajectories. The growth of multiple, non-intersecting, competing fractures is also simulated. It is shown that the fracture geometry obtained using this model is highly dependent on the pattern of heterogeneity. For homogeneous reservoirs and a high in-situ stress contrast, planar fractures are obtained. As the stress contrast is decreased and the degree of heterogeneity is increased, fracture complexity increases. Results for different kinds and levels of formation heterogeneity; planes-of-weakness such as bedding planes or natural fracture networks, and layers with different mechanical properties are presented. This model allows for first-of-kind simulation of fracture propagation with arbitrary geometry in a poroelastic solid domain, using proven computational finite volume methods (FVM). The effect of fluid backpressure, mechanical stress shadow effects, and formation heterogeneity are accounted for. The importance of critical stresses on fracture path is discussed.
Completing the Second Target: Finding Optimal Completion Practices for the Three Forks Formation in the Williston Basin Using Multivariate Statistical Analysis
Authors: Williams Brandon , Weaver Brian , Weijers Leen
Published: February 2021

The Three Forks Formation in the Williston Basin has started to see a large increase in activity in the past six years. This is largely due to the shallower Bakken Formation transitioning into an infill development mode and operators looking at finding incremental reserves from the Three Forks Formation below. The objective of this paper is to evaluate the geological and completion variables of Three Forks horizontal wells in the North Dakota portion of the Williston Basin, and show which factors impact production performance using multivariate statistics. A financial evaluation of the completion factors will also be presented to show which variables have the biggest impact on production.

A database of available completion and geological data has been assembled from the North Dakota Industrial Commission (NDIC) website. To date there are roughly 2,400 horizontal wells targeting the Three Forks Formation on the North Dakota side of the Williston Basin. Some of the variables collected include number of fracture stages, amount and type of proppant, total volume and type of frac fluid, lateral length, max treatment pressure and rate, API oil gravity, formation thickness (from formation tops) and production. The data was subjected to multivariate nonlinear statistical analysis. This type of analysis allows for simultaneously comparing multiple variables to one outcome variable. In this case study the outcome variable is 180-day production.

Using multivariate analysis in the Three Forks Formation of the Williston Basin will aid in predicting production in different parts of the basin and finding which controllable completion variables have the most significant impact on production. The output can also aid in production forecasting based on changes to treatment designs.
From the Laboratory to the Field: Successful Multistage Horizontal Fracturing Design and Implementation in Tight Sandstones in the Anadarko Basin
Authors: Abrams Megan E. , Churcher Peter L. , Piland James R. , Grieser Bill , Squires Scott , Crane Brady
Published: February 2021

This paper discusses the re-engineering of a fracturing design targeting tight oil in horizontal wells drilled in the Pennsylvanian-age Tonkawa sandstones, located in Dewey County, Oklahoma, through the integration of laboratory, geological, petrophysical, fracture simulation, and diagnostic fracture injection test (DFIT) analysis.

Laboratory testing, which included thin section and scanning electron microscopy (SEM), X-ray diffraction (XRD), and mercury injection capillary pressure (MICP) analyses, was conducted to determine mineralogy, nature of the pore body geometry, and potential damage mechanisms. Fracturing fluid chemistry was tested and optimized using both cuttings and core plugs from representative reservoir rock.

Geomechanical rock properties derived from advanced petrophysical analysis of newly acquired high-definition triple combo and full wave sonic logs were combined with geological parameters and potential treating schedules to develop sophisticated fracture simulation models. These models were then refined with in-situ reservoir data obtained from DFIT analyses conducted using downhole gauges to derive the final fracturing treatment design.

The integration of all available data allowed moving away from a “one-size-fits-all” fracture design to one tailored specifically to the targeted reservoir rock. The net result was an optimized fracture design that helped reduce both cost and formation damage, thus improving flowback, long-term productivity, and profitability from these tight sandstones.

A similar fracturing design process is being developed for other tight sandstone reservoirs in the Anadarko basin, with preliminary results confirming that each formation requires a unique fracturing treatment design to be effective.
Use of a CO2-Hybrid Fracturing Design to Enhance Production from Unpropped Fracture Networks
Authors: Ribeiro Lionel H. , Li Huina , Bryant Jason E.
Published: February 2021

This paper introduces a new CO2-hybrid fracturing fluid design that intends to improve production from ultra-tight reservoirs and reduces freshwater usage. The design consists of: (1) injecting pure CO2 as the pad fluid to generate a complex fracture network, and (2) injecting a gelled slurry (water- or foamed-based) to generate near-wellbore conductivity. The motivation behind this design is that while current aqueous fluids provide sufficient primary hydraulic fracture conductivity back to the wellbore, they under-stimulate the reservoir and leave behind damaged stimulated regions deeper in the fracture network. Much of that (unpropped) stimulated area is ineffective for production due to interfacial tension effects, fines generation, and/or polymer damage. We present simulation work that demonstrates how CO2, with its low viscosity, can extend the bottom-hole treating pressure deeper in the reservoir and generate a larger producible surface area. We also present experimental evidence that CO2 leaves behind higher unpropped fracture conductivities than slick water. This paper does not address the many operational and logistical challenges of using CO2 as a fracturing fluid. Rather, it intends to demonstrate the production uplift potential of the proposed design, which seems particularly attractive in reservoirs capable of sustaining production from unpropped fractures (e.g., reservoirs with low stress anisotropy, high Young's modulus, and a pervasive set of natural fractures).
On Liability Issues Concerning Induced Seismicity in Hydraulic Fracturing Treatments and at Injection Disposal Wells: What Petroleum Engineers should know
Authors: Hall K. , Dahi Taleghani A. , Dahi Taleghani N.
Published: February 2021

The rates of oil and natural gas production in the United States have increased dramatically during the past decade, largely due to the use of hydraulic fracturing and horizontal drilling. This has benefitted the U.S. economy and generated hopes that the “shale revolution” could be replicated elsewhere. At the same time, however, public concern has grown regarding potential adverse impacts that fracing or other operations like gas flooding, waterflooding, waste disposal, and other production processes may have. One of the main public concerns relates to induced seismic events – that is, man-made earthquakes. Geologists have concluded that a variety of human activities can induce seismic events. Such operations include the operation of injection disposal wells, though a relatively small fraction of such wells are suspected of inducing seismic activity. Further, available public data shows that, on very rare occasions, hydraulic fracturing itself has caused tangible seismic activity. Although such events have been uncommon, they have attracted significant public attention and strengthened the opponents of oil and gas development. Further, although seismic events induced by oil and gas activity appear to have caused little damage, the potential legal liability could be substantial if such an event ever caused significant damage. Accordingly, industry should give increased attention to minimizing the likelihood of such events. The paper provides context for this issue by briefly reviewing information regarding recent cases of induced seismic activity, current technology for monitoring these events, and the inherent limitations in measurements and interpretation involved in using these techniques. This paper also discusses techniques that operators can use to reduce the likelihood of induced seismic events at hydraulic fracturing sites and at injection disposal wells. These include use of pretreatment geomechanical analyses to assess the likelihood of significant seismic events and, in appropriate circumstances, to guide a modification in perforation clusters design to reduce the likelihood of nearby fault reactivations. Finally, the article provides additional context by discussing relevant laws, including regulatory responses to suspected events of induced seismic activity and the possible legal theories for imposing liability for such events. The new regulations will compel operators to take certain actions and the potential for legal liability may incentivize additional action.
A Cohesive Model for Modeling Hydraulic Fractures in Naturally Fractured Formations
Authors: Gonzalez M. , Taleghani A. Dahi , Olson J. E.
Published: February 2021

A cohesive zone model (CZM) has been developed to couple fluid flow with elastic, plastic and damage behavior of rock during hydraulic fracturing in naturally fractured formations. In addition to inelastic deformations, this model incorporates rock anisotropies. Fracture mechanics of microcrack and micro-void nucleation and their coalescence are incorporated into the formulation of the CZM models to accurately capture different failure modes of rocks. The performance of the developed elastoplastic and CZM models are compared with the available data of a shale play, and then the models are introduced into a commercial finite element package through user-defined subroutines. A workflow to derive the required model parameters for both intact rock and cemented natural fractures is presented through inverse modeling of field data. The hydraulic fractures' growth in the reservoir scale is then simulated, in which the effect of fluid viscosity, natural fracture characteristics and differential stresses on induced fracture network is studied. The simulation results are compared with the available solutions in the literature. The developed CZM model outperforms the traditional fracture mechanics approaches by removing stress singularities at the fracture tips, and simulation of progressive fractures without any essential need for remeshing. This model would provide a robust tool for modeling hydraulic fracture growth using conventional elements of FEA.
Correlation and Interpretation of Microseismic Responses using Pressure Measurements in Offset Observation Wells
Authors: Downie Robert , Calvez Joel Le , Dean Barry , Rutledge Jeff
Published: February 2021

Interpretation of the microseismic data acquired during hydraulic fracture treatments is based on a variety of techniques that make use of the locations, times, and source parameters of the detected events, in conjunction with the stimulation treatment data. It is sometimes possible to observe trends or changes in the microseismic data that correspond to the surface pressure measurements; however this aspect of interpretation becomes problematic due the variability of fluid friction, slurry density, perforation restrictions, and other near-wellbore pressures when computing bottom hole fracturing pressure.

An interpretation technique is proposed that uses pressure measurements in observation wells that are offset to the treatment well during microseismic interpretations. The observation well can be any well with open perforations in close proximity to the treatment well. The observation well pressures are not affected by the many complicating factors that are encountered when estimating pressure in the fracture from the surface pressure measured in the treatment well.

Example data from field observations are used to demonstrate that the detection of microseismic events near an observation well and corresponding detection of fluid pressure from the fracture in the observation well validates the calculated event locations. The relationship between fracture pressure, the state of stress, and microseismic responses is discussed using Mohr-Coulomb failure criteria. Observation-well pressures and microseismic events are also used to identify instances where reservoir pressure depletion near the observation well affects surface operations at the treatment well.

The results of the study show that reliable measurements of fracture pressure for use in microseismic interpretations can be obtained from offset observation wells, and where reservoir pressure depletion causes deviations from expected fracture behavior. The results also show that microseismic responses are directly related to fracture pressure, and not simply the presence of fracturing fluid itself, leading to an improved understanding of the conditions under which microseismic events occur.
Acid Fracturing Shales: Effect of Dilute Acid on Properties and Pore Structure of Shale
Authors: Wu Weiwei , Sharma Mukul M.
Published: February 2021

Many microfractures created during hydraulic fracturing are too small to be filled with proppants and are likely closed during production. However, for some shales that are rich in calcite (calcareous mudstones), such as the Bakken and Eagle Ford shale, dilute acids can be used while fracturing to maintain the conductivity of these microfractures under closure stress by non-uniformly etching the fracture surfaces. The mineralogy and pore structure of the shale and their evolution during acid fracturing are critical factors on the surface surface etching profile and the fluid leakoff. Therefore, understanding how acid dissolution changes the microstructure, petrophysical properties and pore structures of shale is essential in the design and application of acid fracturing in shales.

In this paper changes in shale properties and pore structure by acid fracturing were demonstrated and visually observed for the first time with a scanning electron microscope. Acidized sections of a shale core sample were carefully isolated, and its microstructure, pore structure and petrophysical properties were systematically studied and compared with non-acidized sections of the core.

Microstructure changes were found to be strongly dependent on mineral distribution, and several patterns were identified: channels developed in carbonate-rich regions; cavities or grooves formed in carbonate-rich islands or carbonate rings; and surface roughness was created in mixed zones of scattered carbonate and inert minerals. Inert minerals such as clay, organic matter stay relatively undisturbed in the structure, while some mineral grains can be dislodged from their original locations by dissolution of the surrounding carbonates. Many macropores with size up to 120 µm were created and mesopores mostly associated with clay gained more accessibility. Significantly increased permeability and porosity was measured in an acidized shale matrix. Brinell hardness measurements show that, as expected, the hardness of the shale was reduced by acidizing. This means that for acidizing to work effectively, it is important to not etch the fracture surfaces uniformly. Doing so will result in a reduction in the fracture conductivity under stress. The microstructure changes introduced by acid fracturing demonstrated in this study will result in the formation of surface asperities which is likely to improve the fracture conductivity of induced unpropped fractures. The acidized shale matrix close to the fracture surface with increased abundance of macropores and accessibility to mesopores may serve as a preferred pathway for fluid flow as well.
Nup62 is recruited to pathological condensates and promotes TDP-43 insolubility in C9orf72 and sporadic ALS/FTLD.
Authors: Gleixner Amanda , Verdone Brandie Morris , Otte Charlton , Ramesh Nandini , Gale Jenna , Mauna Jocelyn , Mann Jacob , Copley Katie , Daley Elizabeth , Ortega Juan , Cicardi Maria , Kiskinis Evangelos , Kofler Julia , Pandey Udai , Trotti Davide , Donnelly Christopher
Published: February 2021

Amyotrophic lateral sclerosis (ALS) and Frontotemporal Lobar Degeneration (FTLD) share clinical, neuropathological, and genetic features. This includes common genetic disease-causing mutations such as the expanded G4C2 repeat in the C9orf72 gene (C9-ALS/FTLD) and cytoplasmic and insoluble protein depositions of the TDP-43 in degenerating regions of the brain and spinal cord. Proposed mechanisms of toxicity in C9-ALS/FTLD are the production of repeat expansion transcripts and their dipeptide repeat proteins (DPRs) products which are hypothesized to drive nucleocytoplasmic transport defects. The nuclear pore complex (NPC) regulates nucleocytoplasmic trafficking by creating a selectivity and permeability barrier comprised of phenylalanine glycine nucleoporins (FG nups). However, the relationship between FG nups and TDP-43 pathology remains elusive. Here, we define two mechanisms through which TDP-43 promotes Nup62 nuclear depletion and cytoplasmic in C9-ALS/FTLD and sALS/FTLD. In C9-ALS/FTLD, poly-GR initiates the formation of TDP-43 containing stress granules (SGs) that trigger the nuclear loss and recruitment of Nup62 in vitro and in vivo. When colocalized, cytoplasmic TDP-43:Nup62 assemblies mature into insoluble inclusions through an interaction within the TDP-43 nuclear localization sequence (NLS) suggesting Nup62 promotes deleterious phase transitions. Absent of poly-GR, aberrant TDP-43 phase transitions in the cytoplasm recruits and mislocalizes Nup62 into pathological inclusions. The result of these cytoplasmic Nup62 and TDP-43 interactions are pathological and insoluble TDP-43:Nup62 assemblies that are observed in C9-ALS/FTLD and sALS/FTLD CNS tissue.
Effect of Temperature on the Dielectric and Magnetic Properties of NiFe2O4@MgFe2O4 and ZnFe2O4@MgFe2O4 Core-Shell
Authors: Roumaih Kheled
Published: February 2021

The core-shell NiFe2O4@MgFe2O4 (NiF@MgF) and ZnFe2O4@MgFe2O4 (ZnF@MgF) are stable nanocomposites. The experimental results showed perfect dielectric and magnetic properties different than their components. The experimental data revealed that the mutual effect between the core and the shell increases the space charge polarization. Also, the samples showed semiconducting-metallic behavior, which varies according to the temperatures and the frequencies. Furthermore, the magnetization M(T) was studied using the Faraday balance method of all samples. The obtained results of M(T) exhibit good magnetic properties of the core-shell samples, particularly the sample ZnF@MgF, where it possesses magnetization higher than the pure ferrite phase (MgFe2O4) and Curie temperature (TCm) higher than the room temperature, and this is new for Zn-ferrite. Besides, the effective magnetic moment (µEff) and the Curie-Weiss constant (θ) were obtained from the magnetic susceptibility χ(T) protocols.