bluuebunny/crossref_metadata_2025_split huggingface dataset:
Anomalous Induced Seismic Deformation Associated with Hydraulic Fracturing
Authors: Maxwell S. C. 
Published: November 2013

Abstract
Induced seismicity resulting from fluid injection is a growing concern with a number of operations, including hydraulic fracturing. The vast majority of hydraulic stimulations results in no felt seismicity. However, three examples of larger, anomalous seismicity have been attributed to hydraulic fracturing, which seem to be associated with operations in unique geologic and geomechanical settings. In response, a number of operational protocols have been developed and include specific requirements for seismic monitoring. Seismological aspects are obviously central to these protocols, including characterizing the seismic source strength and associated seismic hazard. The typical microseismicity recorded during hydraulic fracturing represents a small portion of the hydraulic energy associated with the injection. However, the energy balance of the relative amount of seismic energy increases in the cases of anomalous seismicity, which may provide a monitoring tool to potentially help mitigate induced seismicity. Although the number of cases with anomalous seismicity is relatively small, other examples have been observed from geothermal stimulations. In these cases, the ratio of seismic energy is relatively larger but of potentially interest remains significantly less than the hydraulic energy. Furthermore, the ratio of seismic moment to injected volume also increases but typically remains less than a limit suggested by McGarr (1976). Potentially the energy and volume balances could be useful monitoring tools to assist in ongoing operation decision processes.
Fracture Cell for Flow Modeling
Authors: Sakhaee-Pour A. , Wheeler Mary F. 
Published: November 2013

Abstract
Hydrocarbon production from unconventional resources such as shale usually entails stimulation by hydraulic fracturing, which results in non-planar (curved) fractures. However, most reservoir models assume that the induced fractures are planar for the sake of simplicity. Considering the growing interest of the petroleum industry in better understanding production from these resources, we develop a fracture cell model to capture the effects of fracture non-planarity on transport properties.
To build a realistic reservoir model for a fractured formation, three types of interactions must be accounted for: matrixmatrix (M-M), matrix-fracture (M-F), and fracture-fracture (F-F). The transport properties of the matrix-matrix interaction (MM) are based on lab measurements. In this study, we analytically determine the transport properties of the two other types of interactions (M-F and F-F). For this purpose, we account for the aperture size and spatial location of the fracture. As a result, we provide effective porosity and effective anisotropic permeabilities for a reservoir cell that contains a fracture inside it. The reservoir cell whose transport properties are modified is a fracture cell.
We implement the fracture cell model in a reservoir simulator and perform analyses for a single fracture and for multiple intersecting fractures; these fractures are non-planar. The analyses include both single- and multiphase flow models and show that the hydrocarbon pressure inside the reservoir is strongly dependent on the fracture geometry when the matrix permeability is smaller than 1 microD. Thus, it is crucial to model the fracture geometry more accurately in unconventional reservoirs with ultra-low permeabilities such as shale.
The developed fracture cell model can easily be implemented in reservoir simulators, and there is no need for local refinement around the fracture. The main advantage of the proposed model is its simplicity, conjoined with its ability to capture the non-planarity of the fracture. The developed model has major applications for understanding production from formations that are heavily fractured.
Pseudotime Calculation in Low Permeability Gas Reservoirs
Authors: Tabatabaie S. Hamed , Mattar Louis , Pooladi-Darvish Mehran 
Published: November 2013

Abstract
Due to the recent advances in well design and production techniques, tight/shale gas reservoirs have received considerable attention. At the early phase of development of these reservoirs, fast analytical models are attractive since data are limited and a large number of sensitivity studies is required. This analytical solution is possible if the governing partial differential equation is linear. However, the pressure dependency of gas compressibility and viscosity makes the governing partial differential equation nonlinear. The use of pseudovariables (i.e. pseudopressure and pseudotime) significantly reduces this nonlinearity. Unlike pseudopressure, which is an exact mathematical transformation, pseudotime is an approximate transformation. For conventional gas reservoirs, the average reservoir pressure was utilized to evaluate pseudotime and worked very well during boundary dominated flow.
However, in low permeability systems, when transient flow prevails, use of average reservoir pressure for pseudotime calculation is not valid and its use can create inconsistent results. Anderson and Mattar (2007) proposed that, during transient and transitional flow, the use of average pressure within the region of influence, rather than the average pressure of the whole reservoir, results in responses that are more consistent with those from numerical simulators.
In this study, the idea of using average pressure within the region of influence is utilized to calculate pseudotime during constant rate production from a tight/shale gas reservoirs. In order to achieve this, the liquid type curve was employed to find the volume of investigation, and then the gas material balance equation was incorporated to evaluate the average pressure within the region of influence. The significant advantage of this method is that the volume of investigation is determined based on material balance principles by imposing a unit-slope line at each point in time, rather than depending on the radius of investigation formulation as was used by Anderson and Mattar (2007). In an irregularly shaped drainage area, different methods were investigated for evaluating the distance of investigation in the x- and y-directions. It was found that the distance of investigation in the x- and y- directions could not be represented by the same formula (i.e., yinv.=0.113kt/μgctϕ≠xinv. where all parameters are in field units).
The method developed in this paper is applicable in modeling different flow regimes during transient, boundary affected and boundary dominated flow periods. This paper outlines the proposed approach and explains its usefulness by comparing the analytical and numerical results for different cases. It is shown that reliable forecasts of production can be obtained.
Impact of Fluid Behavior Modification under Elevated Pressure and Temperature Conditions on Shale-Gas/Condensate Reservoir Engineering and Production Analysis
Authors: Civan Faruk , Michel Guillermo , Sigal Richard 
Published: November 2013

Abstract
This paper primarly focuses on the proper description of single- and multi-component hydrocarbon transport in nanoporous organic-rich shales and therefore presents the relevant issues and exploratory modeling studies to account for the effects necessary for accurate reservoir simulation. The deviation from the Darcian flow behavior of the gas/condensate transport through shale reservoirs is shown to occur mainly by alteration of fluid properties because of pore proximity effects at elevated reservoir pressure and temperature conditions although the Knudsen and Klinkenberg type corrections may involve at low pressures at later stages of hydraulically-fractured wells in shale reservoirs. A systematic methodology is presented for modification of the fluid and phase behavior relevant to transport at elevated pressure and temperature conditions. The modifications of the phase diagram, density, viscosity, and surface tension for typical hydrocarbon components and mixtures in various size pores reduced further by adsorbed components layers are compared with those of the bulk systems. Further, the role of organic connectivity in shales characterized by organic and inorganic nanopores on production from shale wells is investigated. The role and performance of isolated organics in the form of a ‘raisin-bread’ model in comparion with organics that are organized in slabs with relatively longer correlation lengths are demosntrated by simulation. The methodology for haldling of the organic connectivity and the pore-proximity effects on fluid properties provided here may be instrumental for accurate shale gas and liquids-rich shale reservoir simulation.
Novel Controlled Pressure Coring and Laboratory Methodologies Enable Quantitative Determination of Resource-in-Place and PVT Behavior of the Duvernay Shale
Authors: Davis M. , Williams R. , Willberg D. , Bjorum Matt , Akbarzadeh Kamran 
Published: November 2013

Abstract
The North American hydrocarbon supply market has been transformed by recent discoveries in regionally continuous reservoir units consisting of shale and tight sands. Effective porosity values in these reservoirs average as low as 2% to 6% with nanoDarcy permeability in situ. Classical means of determining resource-in-place values in these unconventional formations involves integrating core and log analysis methodologies, where numerous levels of uncertainty exist. Controlled pressure coring operations were conducted on a sequence of wells drilled into various maturity windows in the rapidly emerging liquids-rich Duvernay Shale through the course of 2011 and 2012. Capturing critical resource-in-place parameters and conducting quantitative analysis of volatile hydrocarbons contained within the cored interval required the development of new field and laboratory methodologies. These procedures represent the only currently available workflow capable of directly capturing and analyzing reservoir hydrocarbons from core material. Field operations and core preservation steps were developed to maintain the integrity of the hydrocarbon system during shipping and core processing. Additionally, a laboratory methodology was developed for preserving and extracting liquid hydrocarbons from core material. By quantitatively recombining these extracted fluids with volatile hydrocarbons captured from the controlled pressure coring operation, in situ PVT behavior of this single-phase volatile oil/condensate reservoir can be determined. As a result, recombined fluids can be compared to production samples for the purpose of studing pore scale mechanisms affecting production. Key breakthroughs were made during all stages of the workflow, and it was determined that core capture and surface handling operations are just as important as developing the new laboratory techniques required to understand resource uncertainty, effective fluid mobility, and PVT behavior. This paper describes and documents the key advancements made in coring operations and specialized core analysis, as well as their role in accurate quantification of hydrocarbons in place and the determination of in situ PVT behavior of the Duvernay Shale.
Hydrocarbon Mobilization Mechanisms from Upper, Middle, and Lower Bakken Reservoir Rocks Exposed to CO2
Authors: Hawthorne Steven B. , Gorecki Charles D. , Sorensen James A. , Steadman Edward N. , Harju John A. , Melzer Steve 
Published: November 2013

Abstract
Efforts to increase Bakken oil recovery factors above a few percent could include carbon dioxide (CO2) enhanced oil recovery (EOR). CO2 EOR processes are expected to be very different in tight reservoirs compared to conventional reservoirs. During CO2 EOR in conventional reservoirs, CO2 flows through the permeable rock matrix, and oil is mobilized by a combination of oil swelling, reduced viscosity, hydrocarbon stripping, and CO2 displacement especially when above the minimum miscibility pressure. In the Bakken, CO2 flow will be dominated by fracture flow, and not significantly through the rock matrix. Fracture-dominated CO2 flow could essentially eliminate the displacement mechanisms responsible for increased recovery in conventional reservoirs. As such, other mechanisms must be optimized in tight reservoirs such as the Bakken.
Conceptual steps for the Bakken include: (1) CO2 flows into and through the fractures, (2) unfractured rock matrix is exposed to CO2 at fracture surfaces, (3) CO2 permeates the rock driven by pressure, carrying some hydrocarbon inward; however, the oil is also swelling and extruding some oil out of the pores, (4) oil migrates to the bulk CO2 in the fractures via swelling and reduced viscosity, and (5) as the CO2 pressure gradient gets smaller, oil production is slowly driven by concentration gradient diffusion from pores into the bulk CO2 in the fractures.
To investigate these concepts, rock samples from the Middle Bakken (low permeability), Upper and Lower Bakken (very low permeability), and a conventional reservoir (high permeability) were exposed to CO2 at Bakken conditions of 110°C and 5000 psi (230°F, 34.5 MPa) to determine the effects of CO2 exposure time on hydrocarbon production. Varying geometries of each rock ranging from small (mm) "chips" to 1 cm-diameter rods were exposed for up to 96 hours, and mobilized hydrocarbons were collected for analysis. Nearly complete (&gt;95%) hydrocarbon recovery occurs in hours from the middle Bakken reservoir rock, and even faster with the more permeable conventional matrices. Unexpectedly, nearly complete recovery of hydrocarbons can even be achieved from the very tight source shales from the Lower and Upper Bakken, but requires longer exposure times and smaller rock sample sizes (i.e., high surface area to volume ratio). These results demonstrate that CO2 is capable of recovering hydrocarbons from Bakken source and reservoir rock (i.e., the thermodynamics of CO2 oil recovery are favorable), but that long periods of exposure combined with high rock surface areas are required (i.e., the kinetics of the recovery process are slow). The present study reports experimental methods and the resultant data to investigate the proposed mechanisms that will control CO2 EOR in tight formations. Implications for CO2 EOR processes in unconventional reservoirs are discussed.
Integrated Analysis of Core Geology, Rock Properties, Well Logs, and Seismic Data Provides a Well Constrained Geologic Model of the Bossier/Haynesville System
Authors: Suarez-Rivera Roberto , Herring Shanna , Handwerger David , Marino Sonia , Petriello John , Stevens Kimberly 
Published: November 2013

Abstract
In unconventional reservoirs, the drivers of reservoir quality and hydrocarbon producibility are mostly evident at the scanning electron microscope (SEM) scale. For field applications, the practical scales of observation have resolutions from few feet to tens of feet. Finding ways of integrating the two scales allows propagation of knowledge, obtained at SEM and core scale, across the field. This is achieved via strong understanding of rock texture and composition, and of the geologic processes that defined them. The objective is to understand the rock, via detailed geologic and petrologic core studies, and define ways to identify core-scale rock texture and composition with well log and seismic measurements.
We define the depositional and diagenetic transformations that occurred in the various facies of the Haynesville and Bossier system using core geologic and petrologic studies. We identify the different textural and compositional properties that define these facies and, by selecting a log suite sensitive to texture and composition, investigate their ability to discriminate these differences. We use a core-log model to predict the distribution of these geologic facies in other regions of the field, and validate these predictions with additional core studies in these regions. The potential and limitation of the log responses to identify subtle changes in rock texture and composition is critical to this effort. Once validated, the log-scale model is filtered to seismic resolution, and used to map geologic units at the seismic scale.
The log-scale measurements detect sequences of the core-scale facies, thus allowing us to map their presence and distribution across the play. The method improves field geologic characterization, defines an efficient selection criterion for additional science wells with core and for selection of additional seismic data.
Core-log integration was successful across a region of 7,185 square miles, and core-log-seismic integration was successful across a region of 200 square miles. The method provided a cost efficient concept for exploration, and for tying the varying geologic processes in the basin to the resulting conditions of reservoir quality and production potential. It also provided information for more effective well placement design.
Lessons Learned from Shell's History of Casing Conveyed Fiber Optic Deployment
Authors: Bateman K. , Molenaar M. M , Brown M. D. 
Published: November 2013

Abstract
Fiber Optic Sensing is an emerging technology that can provide a means to measure a broad range of downhole events that span geophysics, completion and production engineering applications. All these measurements can be performed by installation of a single fiber optic cable; assuming reliability and life-cycle cost(s) are sufficiently robust. The multiple applications of fiber optic technology provide an effective way to maximize data collection from a single well. This data can result in a better understanding of the subsurface, which can help make more efficient and effective commercial and development decisions.
For the Unconventional Gas and Light Tight Oil projects, Shell has completed a number of wells across North America with fiber permanently conveyed on the outside of the production casing and across the completion interval for the primary purpose of capturing hydraulic fracture (HF) stimulation data. Multiple fibers can be deployed in a single cable, enabling simultaneous data gathering from distinct optical technologies. As such, the installed fibers have also been used to detect micro-seismic events, capture VSP data, and to analyze stimulation flow-back and production inflow profiles.
In order to fully realize the potential of fiber optic technology for the multiple applications, it is necessary that the fiber optics remain operational for a sufficient length of time to gather the desired data sets over the well life. This has proven quite challenging in this severe environment: often fiber optic cables fail prematurely during, or shortly after, deployment or during HF stimulation operations. These failures have been categorized into three general groups: downhole, surface, and supporting data collection systems.
Before this technology can fully mature, it is critical that the current reliability issues are addressed. This paper will study the status of Shell fiber wells across North America, illustrate the temperature and acoustic response when a fiber fails during HF stimulation, and share the results of reliability testing on several different fiber optic cable designs.
How to Estimate Water Saturation Exponent In Dual and Triple Porosity Reservoirs With Mixed Wettability
Authors: Olusola Bukola K. , Aguilera Roberto 
Published: November 2013

Abstract
Mixed wettability is a common concern in heterogeneous reservoirs. The problem from a practical point of view is the general lack of water saturation exponent (n) laboratory values in rocks with mixed wettability.
To contribute to the solution of this concern, we utilize electromagnetic mixing rules to develop a new petrophysical model capable of estimating the water saturation exponent (n) and water saturation (Sw) in heterogeneous reservoirs with mixed wettability. The reservoirs are represented by dual porosity (matrix and fractures or matrix and isolated porosity) and triple porosity (matrix, fractures, and isolated porosity) models. Results from the models developed in this work compare well with core data.
We have used the same electromagnetic mixing rules in the past for successful determination of the porosity exponent (m) in heterogeneous reservoirs. The addition in this paper offers a means for calculating the water saturation exponent (n) and makes the electromagnetic mixing rules a powerful tool for complete formation evaluation of heterogeneous reservoirs with complex pore structures and mixed wettability.
It is concluded that the new petrophysical models developed in this study provide a significant contribution to the determination of water saturation exponent (n) and water saturation (Sw) in rocks with mixed wettability and hence lead to improved values of hydrocarbon in place estimates.
A Case Study on Formation Evaluation of Horizontal Wells in the Tight Gas Nikanassin Group of the Western Canada Sedimentary Basin Using Drill Cuttings
Authors: Olusola Bukola K. , Aguilera Roberto 
Published: November 2013

Abstract
The use of drill cuttings has evolved recently from qualitative to quantitative evaluations due to the possibility of measuring porosity and permeability from drill cuttings in the laboratory with a good level of certainty. One of the advances has been the implementation of complete quantitative formation evaluation for vertical wells from drill cuttings only in the absence of well logs.
This paper uses the same methodology in the case of a horizontal well. The case study is demonstrated with the use of sixty five (65) drill cuttings samples collected over 760 meters of a horizontal well drilled through the Monteith formation, Nikanassin group of the western Canada sedimentary basin (WCSB).
Starting with only drill cuttings measurements of porosity and permeability in the laboratory, the method allows a successive approach for determination of several parameters of interest including pore throat aperture radius, water saturation, porosity exponent (m), true formation resistivity, Knudsen number, capillary pressure, construction of Pickett plots, and the estimation of geomechanical properties such as Young Modulus, Poisson’s ratio and brittleness index throughout the horizontal length of the well.
And for those cases where there is close to no data at all in the Nikanassin formation, empirical correlations have been developed for estimating Poisson’s ratio, static Young Modulus and brittleness index with the use of only porosity from drill cuttings. The correlation coefficient (R2) in this case is 0.99.
It is concluded that drill cuttings provide a useful direct source of information for quantitative formation evaluation of horizontal wells particularly in those cases where core and log data are scarce.