bluuebunny/crossref_metadata_2025_split huggingface dataset:
Estimation of Elastic Properties of Organic Matter and Woodford Shale Through Nano-indentation Measurements
Authors: Kumar Vikas , Curtis Mark E. , Gupta Nabanita , Sondergeld Carl H. , Rai Chandra S. 
Published: October 2012

Abstract
Shales are one of the most heterogeneous and complex natural materials found. Recent spike in the activities in shale gas and oil plays has been possible through horizontal drilling and hydraulic fracturing, which requires better understanding of mechanical properties. Complexities associated with elastic properties of shale are amplified with presence of wide range of organic fraction present in them. There is a need to understand the mechanical properties of organics and their associated impact on bulk mechanical properties.
Scanning Electron Microscopy with focused ion beam milling and nano-indentation have been employed to calculate mechanical properties of kerogen at the submicron level in Woodford shale samples of different maturities. A displacement of 500 nm was applied to investigate mechanical properties of kerogen and force in the range of 400–500 mN was applied to measure average mechanical properties of shale.
Young’s modulus of kerogen was found to be linked to localized porosity as well as maturity. Kerogen in different samples with vitrinite reflectance range of 0.5–6.36 % and almost no porosity showed Young’s moduli in the range of 6–15 GPa, whereas, kerogen with significant porosity showed values as low as 1.9–2.2 GPa. Young’s modulus measured by nanoindentation on small shale samples (~ 5–10 mm) was found to be in good agreement with dynamic modulus measured on core plugs (~cm). Young’s modulus is most sensitive to the Total Organic Carbon present. Increase in organics is found to qualitatively reduce both Young’s modulus and hardness.
Measurement of elastic properties of shale is significant for optimizing hydraulic fracture design, for well stability study and better seismic velocity prediction in shale. This technique requires small sample dimension, on the order of millimeters, for experiment and thus eliminates the requirement of larger, centimenter, size samples. This is particularly significant for shale as they are mechanically and chemically unstable which makes retrieval of larger core samples challenging.
Executing Minifrac Tests and Interpreting After-Closure Data for Determining Reservoir Characteristics in Unconventional Reservoirs
Authors: Ewens S. , Idorenyin E. , O’Donnell P. , Brunner F. , Santo M. 
Published: October 2012

Abstract
Pore pressure (pi) and flow capacity (kh) are difficult to ascertain in ultra-low permeability formations due to poor inflow prior to stimulation. Furthermore, radial flow does not develop in horizontal wells completed with massive multi-stage hydraulic fractures. As a result, industry is turning to alternate testing methods, conducted prior to the main hydraulic fracture treatments. Of these, minifrac tests are rapidly gaining acceptance as the most practical way to obtain good estimates of pore pressure and flow capacity in unconventional reservoirs. Unfortunately, these test objectives are often unrealized when design and execution of the minifrac test are conducted with other objectives in mind. Even after a mechanically successful test has been concluded, there can be confusion over how to interpret the after-closure data.
This paper outlines recommended operational guidelines for conducting minifrac tests with the purpose of estimating pore pressure and flow capacity. In addition, various aspects of after-closure analysis are investigated and examples are used to show that all after-closure analysis techniques, when applied correctly, are applicable and give consistent estimates of pore pressure and flow capacity. The power of using analytical models to enhance after-closure analysis is demonstrated.
Comparative Microseismic Interpretation of Hydraulic Fractures
Authors: Maxwell Shawn 
Published: October 2012

Abstract
Microseismic monitoring is often used to evaluate differences in hydraulic fracturing that result from either changes in the stimulation or geologic setting. Often the various microseismic images of individual fractures are each separately interpreted for fracture geometry, and then these absolute interpretations of the various fractures are compared. However, comparisons can be made of variations in specific fracture dimensions between each image, including using statistical tests to quantify significance of relative differences. Such a relative comparative interpretation is more robust and relies on a simpler assessment of the location precision, in contrast to the need to consider all aspects of location accuracy for absolute interpretations. Furthermore, statistical analysis methods can be applied to the relative interpretation to map microseismic location uncertainties to the relative fracture dimension along with defining statistical probabilities to better define the confidence level for further interpretation. The resulting comparative microseismic interpretation can be used as part of a comparative hydraulic fracture evaluation to test the response to different designs and ultimately optimize the stimulation. This paper describes different workflows for a comparative interpretation of microseismic images.
A Semi-analytical Model For Multi-stage Fractured Horizontal Wells
Authors: Yao Shanshan , Zeng Fanhua , Liu Hong , Zhao Gang 
Published: October 2012

Abstract
Multi-stage fractured horizontal wells are widely applied to develop tight reservoirs and shale gas reservoirs. Testing and evaluating well productivity are necessary in horizontal well multi-stage fracturing. Through analyzing the post-fracturing transient pressure data, key parameters affecting the productivity, such as effective fracture lengths, fracture conductivities, fracture skin factors and average formation permeability, can be estimated.
This paper presents a semi-analytical model based on Green’s function and source/sink method to facilitate the transient pressure analysis for a multi-stage fractured horizontal well in a closed box-shaped reservoir. The fluid flow for a multi-stage fractured horizontal well includes the fluid flowing from the reservoir to fractures, the fluid directly from the reservoir to the horizontal wellbore, fluid flow inside the fractures and fluid flow inside the horizontal wellbore. Compared with previous models, fluid flow directly from the reservoir to the horizontal wellbore and pressure drop caused by pipe flow inside the wellbore are considered. In this model, fractures and horizontal wellbore are discretized into vertical plane segments and horizontal line segments, respectively. The fluid flow from the reservoir to fracture and that directly from the reservoir to the horizontal wellbore at each segment are modeled based on analytical solutions of vertical plane source and horizontal line source, respectively. The fluid flow inside the fracture is modeled based on 1-D linear flow. The fluid flow inside the horizontal wellbore is described with Penmatcha and Aziz’s model (1999). Then, the flow equations are coupled together by using the flux- and pressure-continuity conditions on the interfaces.
The effects of the fracture lengths, fracture conductivities and fracture skin factors on the transient pressure behavior are studied and type curves are generated. The results suggested that in a tight or shale-gas reservoir, the transient pressure behavior during a testing period is mainly dominated by fracture stages, fracture lengths, conductivities and skin factors. The fluid flow directly from the reservoir into the horizontal wellbore reduces the pressure drop slightly. A field case is analyzed and reliable results are obtained. This model can be applied to optimize the fracture spacing and fracture length for a multistage fractured horizontal well.
The Effect of Previous Counter-flow Production on the Interpretation of Velocity String Gas Wells Using DTS Temperature Surveys
Authors: Huebsch H , Bruns J , Tripp G , Brown G , Sanchez A , Gonzalez Y 
Published: October 2012

Abstract
Over the past 3 years fiber optic slickline distributed temperature measurements (DTS) have become a commonplace method of monitoring Canada’s Deep Basin commingled gas wells produced through velocity string completions. The use of velocity string completions prohibits conventional production logging, so the wells are flowed up their annulus for a short period of time and a DTS slickline is used to monitor the flowing temperature profile. This temperature profile is then interpreted to give the flow from each reservoir zone. DTS is a much more cost effective solution than having to pull the tubing in order to run a conventional production log and allows testing of lower rate wells that would otherwise liquid load.
The analysis technique conventionally assumes that during the annular flow period, where the DTS is used to acquire the flowing temperature, all the thermal effects of the previous counter-flow production period have dissipated and the problem can be solved by an upward flow thermal model only. This paper evaluates the magnitude of the residual thermal effect of a period of counter-flow on the annular flow response over the timescales typical for DTS monitoring.
A counter-flow thermal model has been developed for typical well scenarios and the shut-in decay of the thermal response of this model is superposed on the conventional annular flow model to highlight the magnitude of influence of previous counter-flow production. The model is used to interpret the counter-flow response of annular flowing gas wells using real well DTS data and demonstrates the magnitude of the effect and how to use this method to improve the accuracy of the resulting flow analysis.
Temporal Evolution of Stress States from Hydraulic Fracturing Source Mechanisms in the Marcellus Shale
Authors: Williams-Stroud Sherilyn , Neuhaus Carl W. , Telker Cherie , Remington Christine , Barker William , Neshyba Garrett , Blair Keith 
Published: October 2012

Abstract
Hydraulic fracture stimulation treatments of 17 wells have been monitored with a shallow buried array for induced microseismicity in the Marcellus Shale in West Virginia, USA. The wide azimuth and large coverage area (18 square miles) of the shallow buried array allowed identification of the source mechanisms of all of the detected events, enabling a statistical analysis of failure mode and associated stress state at failure for all the events in space and time. Detailed analysis of source mechanisms of the largest events revealed heterogeneous failure plane orientations and slip directions, with a combination of dip-slip and strike-slip failure and varying amounts of volumetric failure. Stress inversion analysis of these source mechanisms allowed characterization of the local stress tensor, and how the stress tensor changed from the beginning to the end of the stimulation treatment. The failure mechanisms observed to occur more frequently at the beginnings of the fracture stages were dip-slip and strike-slip failure mechanisms were more common at the ends of the fracture stages. Utilizing the timing of the types of source mechanisms to define temporal groups, the stress inversion analysis showed that the stress state in the stimulated rock changed from being consistent with the regional NE-oriented maximum horizontal stress orientation with sigma1 vertical to a stress state where the maximum horizontal stress becomes sigma1 and is horizontal. The temporal stress state is quantitatively identified and it is demonstrated that the fracture growth directions responds to the temporal stress state. This information can be used by operators to respond to or exploit the expected fracture failure mode and direction, and also to design stimulation treatments that develop complex fracture networks.
Factors That Impact the Performance of Resin Coated Proppant in Low Temperature Reservoirs
Authors: Burke Lyle H. , Roney Dana , Elgar Tyler , Hersey Andrea 
Published: October 2012

Abstract
Pumping a tail stage of resin coat proppant (RCP) is well documented method to control proppant flowback in a wide variety of oil and gas wells. The performance of RCP can be impacted by reservoir temperature and closure stress, as well as fluid and fracture placement parameters. RCP systems were originally designed for higher temperature applications although the use of lower temperature curable resins in shallow lower stress reservoirs has been discussed since at least mid-2005. 1,2,3 Strong oil prices and relatively weak gas prices have recently (2012) been driving the development of relatively shallow tight oil reservoirs within the Western Canadian Sedimentary Basin (WCSB) including the Slave Point, Cardium, Bakken, Viking and others. These reservoirs typically have relatively low reservoir temperatures and closure stresses which highlight the importance of looking beyond the reservoir temperature with a holistic evaluation of the fracture fluid interactions and fracture placement efficiency that can significantly impact RCP placement and performance; existing SPE publications also provide good background to the impact of these contributing factors.4,5
Most RCP literature focuses on clastic applications. In conjunction with our proppant supplier and pumping service partner, Lone Pine Resources Canada Ltd (LPR) has recently conducted laboratory testing designed to optimize the use of RCP within the Slave Point carbonate reservoir that LPR is successfully developing with multi-fractured horizontal wells (MFHZ). The Slave Point reservoir presents a challenge to RCP performance with a combination of a cool reservoir temperature of 40°C (100°F) and low closure pressures of roughly 20 MPa (2,900 psi).
During Q1/Q2 2012 LPR identified a proppant flowback that was inhibiting production and increasing workover expenditures. Study of the problem identified proppant mixing and a lack of RCP bonding as root cause issues. A holistic review of the LPR Slave Point fracture program resulted in significant changes to the fracture treatment design and execution including the RCP type, resin activation parameters and base fluid changes.
LPR has been able to minimize proppant flowback to the point that bottomhole pump failures as a result of proppant production have been significantly reduced, if not eliminated, and no incremental proppant clean-out operations have been required since the implementation of an optimized fracturing program that includes higher viscosity fracturing fluid and an optimized RCP-LT and activator program. In addition, no measurable proppant flowback volumes have been recovered during initial CT clean-out from the last four July 2012 fractured wells.
These are very positive indicators that the RCP-LT and activator changes, improved fracture fluid viscosity and proppant placement has solved the proppant inflow problem.
Productivity Modeling of Multifractured Horizontal Wells Coupled With Geomechanics - Comparison of Various Methods
Authors: Islam A. , Settari A. , Sen V. 
Published: October 2012

Abstract
The advances in hydraulic fracturing technology and horizontal well completions have led in recent years to rapid rise in exploitation and development of tight gas and shale plays all over the world, and particularly in North America. The popularity of new field technology has in fact raised many new questions. In particular, for forecasting the productivity and EUR of multifractured horizontal wells, it is not clear if conventional reservoir simulation concepts can be adapted for modeling or if extra physics must be included to obtain realistic solutions.
This paper presents various methods to model multifractured horizontal wells in tight gas sands using a conventional reservoir simulator coupled with geomechanics. Two actual wells in the same formation but with different fracturing techniques (i.e., Xlink gelled water fracs and un-gelled water (slick water) fracs) are studied. Detailed investigation of the role of fracture conductivity, effects of initial permeability level, net pay thickness, assumed size of the stimulated reservoir volume (SRV), and pressure or stress dependent permeability of the SRV and virgin reservoir were carried out by history matching the rate and cumulative production. It was established that i) history match is not possible without use of stress or pressure dependent permeability and ii) permeability dependence of pressure inside stimulated reservoir volume must be larger than in the rest of the reservoir. It was also observed that the standard method for using the same geomechanical data both in uncoupled reservoir and coupled geomechanical model will give incorrect results in terms of cumulative production.
A new method based on uniaxial deformation theory is proposed to more accurately approximate the geomechanical effects in conventional reservoir simulators without running a fully coupled geomechanical simulator. The results from uncoupled reservoir modeling using the new method for correcting the permeability data for poroelastic effects were remarkably similar to rigorously coupled geomechanical modeling.
This work will be of importance to engineers in analyzing and forecasting production performance of multifractured horizontal completions using numerical models. It will allow engineers to use uncoupled (conventional) reservoir modeling as a practical approximation of more complex coupled geomechanical models.
New Coiled-Tubing-Deployed Multizone Stimulation Method Increases Reservoir Access
Authors: Dunlop Tyson , McNeil Fraser 
Published: October 2012

Abstract
Multiple-zone stimulation poses unique challenges for completion engineers. Achieving accurate fracture and proppant placement while performing an efficient and low-risk operation can be unattainable when using conventional stimulation methods. The uncertainty with respect to fracture and proppant placement is amplified when fracturing in ductile rock, where, to maximize access to the reservoir, more fractures must be placed along a given lateral. This increase in fracture intensity can result in an increased risk of unplanned well intervention and downtime, with more trips to run guns, as well as more plugs to drill out.
Stimulation techniques involving coiled tubing (CT) deliver improved efficiencies in horizontal completions because of the ability to instantly address contingencies by having CT in the hole throughout the operation. This method enables accurate fracture and proppant placement, as these operations typically focus on placing one fracture at a time. Isolation is commonly achieved using sand plugs, which have demonstrated to be especially effective; however, when fracture intensity is applied, sand plugs might not achieve the spacing required. This is because of the length of sand plugs often necessary to achieve isolation. Also, the time to set sand plugs can be considerable if they do not properly set the first time.
This paper introduces a new CT annular fracturing (CTAF) system, referred to as CTAF-Anchor, that offers a low-risk, operationally efficient, and effective multizone stimulation method designed to reduce the non-productive time (NPT) between stages and allow for closer fracture spacing to maximize stimulated reservoir access. Also included is a detailed study of the process and case histories that translated into a maximized return on investment (ROI) for the operator.
Case Study - Evaluation of Horizontal Well Multi-stage Fracturing in the Viking Oil Formation
Authors: Mogensen Arvil C. , Bachman Robert C. , Singbeil Peter 
Published: October 2012

Abstract
The Viking formation in Western Saskatchewan and East to Central Alberta is comprised of many different oil pools. These plays have seen resurgence in activity over the last 6 years as a result of the horizontal multi-stage fracturing revolution. A wide variety of fracturing technologies have been applied, encompassing open versus cased hole, variable proppant tonnage per stage and fracture spacing along the wellbore. How does the average company make meaningful decisions as to how to stimulate their wells? There is a need to make sense of the production response of the wells given reservoir quality differences, primarily permeability variation, and the variety of fracturing technologies being applied. The paper will develop a workflow which integrates publically available production data to first identify a production rate metric. This metric can be used for production forecasting and as a basis to compare area and pool production performance. Combining this information with well ownership leads to a preliminary assessment of whether production success is due solely to the reservoir, or the drilling and completion strategy applied.
Understanding Induced Fracture Complexity in Different Geological Settings Using DFIT Net Fracture Pressure
Authors: Potocki Dan 
Published: October 2012

Abstract
A review of several hundred Diagnostic Fracture Injection Tests (DFITs) from vertical and horizontal wellbores in a variety of lithologies (tight sandstone, siltstone and shale) within a spectrum of geological settings (passive margin, foreland, and active strike-slip/thrust basins) was conducted to determine potential controls on stimulation complexity determined from the DFIT Net Fracture Pressure (NFP). Not surprisingly large differences in NFP complexity exist within this diverse data set and the variability is best explained by grouping the data according to the tectonic setting of the basin. Tectonic setting is interpreted as the first order control on NFP complexity since increasingly complex tectonic and burial histories elevate stresses and create tectonic fractures that promote increasingly complicated interactions between induced hydraulic fractures and intrinsic rock fractures. As a result, rocks in the Gulf Coast passive margin basin (Haynesville, Bossier) which have relatively simple burial and tectonic histories exhibit the lowest NFP complexities whereas rocks in strike-slip/thrust basins with high present day tectonic stress and abundant tectonic fabric have the largest complexity. Rocks in foreland basins (Montney, Horn River, Cretaceous Deep Basin sandstones) have NFP complexity that is generally variable between passive margin and strike-slip/thrust basins. Within any particular tectonic setting, NFP complexity is controlled by a complicated interplay between the natural fracture intensity, net horizontal stress (NHS) and wellbore geometry. Increasingly stiff and brittle rocks are commonly increasingly naturally fractured and this favours greater NFP complexity, and DFITs from vertical wellbores generally exhibit lower NFP complexity as fracture initiation and growth is simpler from vertical wells than from horizontal wells. Relations between NFP complexity and NHS (closure – pore pressure) are complicated by the degree to which tectonics has diminished and overprinted the pore pressure control on closure stress. In the Gulf Coast passive margin setting (eg.Haynesville shale) pore pressure is the dominant control on closure stress and NFP complexity is increased where pore pressures are lower, possibly due to frac geometry changes associated changing stress profiles. In more tectonically complex settings (foreland and strike-slip/thrust basins) pore pressure exerts less influence on closure while tectonic stresses increasingly influence regional NFP complexity.