bluuebunny/crossref_metadata_2025_split huggingface dataset:
Characterization of Anisotropic Elastic Moduli and Stress for Unconventional Reservoirs Using Laboratory Static and Dynamic Geomechanical Data
Authors: Hamza Farrukh , Chen Cheng , Gu Ming , Quirein John , Martysevich Vladimir , Matzar Luis 
Published: October 2015

Abstract
In a vertically transverse isotropic (VTI) medium, accurate prediction of the vertical and horizontal Young's moduli (E) and Poisson's ratios (ν) is crucial to predicting minimum horizontal stress (σhmin) and hence selecting drilling mud, cement weights, and perforation locations. Fully characterizing geomechanical properties of VTI shale requires five independent stiffness coefficients: C33, C44, C66, C11, and C13. In a vertical well, C33 and C44 are directly calculated from the velocity of the vertically propagating P- and S- waves, while C66 is estimated from the Stoneley wave velocity. To obtain C11 and C13, an empirical model must be employed. This study integrates laboratory mechanical and sonic measurements to evaluate the ANNIE and modified-ANNIE models and extend the dynamic-to-static conversion equation.
Laboratory static and dynamic geomechanical methods were applied to multiple core materials extracted at different depths from a target shale play. The dynamic elastic moduli were measured using a laboratory sonic scanner; velocities were measured in different directions to obtain C33, C44, C11, C66, and C13. The dynamic data were then applied in the ANNIE and modified-ANNIE models for estimating the dynamic elastic moduli, including dynamic Young's modulus and Poisson's ratio. The static elastic moduli were measured using axial compression experiments; horizontal and vertical core plugs were tested to account for anisotropy.
Static and dynamic results illustrated horizontal Young's moduli were predominantly higher than vertical Young's moduli, which suggested a horizontal layered structure. Vertical Poisson's ratios can be greater or smaller than horizontal Poisson's ratios, which is consistent with the prediction of the modified-ANNIE model. Conversely, the ANNIE model always predicts ν(vert) ≥ ν(horz). Static and dynamic data illustrated the anisotropic σhmin was predominantly higher than the isotropic σhmin. This implied that using an isotropic model to predict laminated shale will underestimate σhmin. It was noticed that the static Young's modulus increased with decreasing porosity for the target interval. The elastic moduli measured from the dynamic method were consistently higher than those measured from the static method. The dynamic and static data were used to fit the widely-used dynamic-to-static conversion equations—the Canady and Morales equations. The Canady equation was extended to the "very hard" (greater than 70 GPa Young's modulus) regime, while the Morales equation was extended to the regime of porosity &lt; 10%. Finally, σhmin predicted by different models was compared with the measurements, showing that modified-ANNIE improved the prediction by solving the stress underestimation issue of the ANNIE and isotropic models.
Geomechanics Modeling in CO2-EOR: Case Study
Authors: Jabbari H. , Ostadhassan M. , Rabeie M. 
Published: October 2015

ABSTRACT
Horizontal drilling and hydraulic fracturing have enabled production from Bakken tight oil reseroirs. However, since the primary recovery is very low, it is important to use enhanced oil recovery methods to unlock part of the remaining oil in the reservoir. In this study, the CO2 injection as a huff-n-puff EOR process is studied. Numerical simulation was used for coupling the reservoir fluid flow with geomechanics to study the stress and deformation of reservoir rock in a CO2-EOR process. The simulation was performed through porosity and permeability relationships with pressure, temperature, and mean total stress for iterative coupling of stress and flow to account for the effect of geomechanics in CO2-EOR.
An Application of Diversion Technique in Un-Cemented Section of a Horizontal Well in the Williston Basin
Authors: Madsen M. , Carlson J. E. , Rondon J. R. , Valenca A. , Do T. , Stewart M. , Borchardt E. , Dupuis B. 
Published: October 2015

Abstract
A well which was drilled in the Pronghorn formation of the Williston Basin had significant trouble during the cementing process. While the lateral length was 11,103 feet, only the 9,296 feet of the lateral closest to the toe had adequate cement to provide the isolation needed for hydraulic fracture stimulation. An integrated solution with evaluation of well integrity and novel diversion material used over the remaining 1,807 feet of the lateral to generate multiple hydraulic fractures was proposed and results were confirmed with production log evaluation.
After using an ultrasonic imaging logging tool conveyed via tractor to determine the point at which the cement isolation became unreliable, the appropriate completion was designed. The first 33 stages of the stimulation were done using a standard plug and perf technique. The last 1,807 feet of the lateral were completed in two intervals with only one additional bridge plug. The two intervals were each stimulated with seven hydraulic fracturing stages and six diversion pills consisting of a proprietary blend of degradable materials. While more stages were pumped in the heel section, the same amount of proppant per foot of lateral was used as in the larger conventionally completed toe section.
The 14 stages pumped in the heel portion of the lateral showed that in both intervals, the instantaneous shut-in pressures at the end of each one of them increased by 2,300 psi and 340 psi respectively. This increase is consistent with fractures initiating at lower pressure intervals, and then being diverted to higher pressure, unstimulated areas. Well production was evaluated with a production log capable of identifying multiphase holdup along the lateral. This evaluation showed that 42% of the total oil production was coming from the 18% of the lateral which was stimulated using the degradable diversion material.
The application of this degradable diversion material in poorly cemented or un-cemented lateral sections in order to create a more uniform distribution of hydraulic fractures can significantly improve both completion efficiency and hydrocarbon production.
AOF Analysis of One Shale Gas Play
Authors: Pang Wei , Xin Cuiping , Du Juan , He Ying , Mao Jun 
Published: October 2015

Abstract
China is believed to own the world's largest shale gas reserve and is the third country to exploit shale gas breakthrough in the world. Fuling gas play in Sichuan basin is one typical shale gas reservoir in China gaining good production performance, and the absolute open flow capacity (AOF) of some wells reaches as high as 1.5 million cubic meters per day. However, we still haven't get good understanding of AOF to evaluate the producing potential and performance of hydraulic fracturing in Fuling shale gas play.
In order to quantify the influence of parameters on AOF, statistical analyses are conducted on fourteen parameters including formation porosity, total organic carbon (TOC), injected fluid volume, injected proppant volume, injected fluid volume per stage, injected proppant volume per stage, proppant concentration, fractured stages, and fractured clusters, horizontal lateral length, angle between horizontal lateral and minimum stress direction, cumulative production in the first three months, stimulated reservoir volume (SRV) and flowback recovery in the first three months.
Results show that six parameters including cumulative gas in first three months, angle between horizontal lateral and minimum stress direction, SRV, TOC, porosity and injected fluid volume show relative strong correlation with AOF with coefficient bigger than 0.50. The influence of the other nine parameters on AOF is very weak, and the coefficient between AOF and water flowback recovery in early days is even as small as 0.11.
AOF is negatively correlated to three parameters including proppant volume per stage, proppant concentration, and angle between horizontal lateral and minimum stress direction. The negative influence of proppant concentration on AOF may have been caused by ineffective fractures (networks), and a positive correlation can be expected if proppants are injected into "sweet points" that meet the geology and engineering requirements and improved stimulation techniques with better performance of fracture propagation control. The angle between horizontal lateral and minimum stress direction is suggested to be less than 20° in order to get bigger AOF. AOF is positively correlated to the other eleven parameters. High TOC, porosity, injected fluid volume are good indication of high AOF.
Practical Application of Type Curve Analysis to the Interpretation of Multi-Stage Fractured Horizontal Well Data
Authors: Mahmoud I. S. , Anderson D. M. 
Published: October 2015

Abstract
The primary objective of this paper is to demonstrate the practical value of type curve matching, as a complimentary technique to standard diagnostic plots, in the interpretation of production data from complex multi-stage horizontal wells.
The approach is based on the usage of Compound Linear Flow Type Curves (Liang et al, 2012). Our methodology involves identifying the transition from early to late (compound) linear flow that would typically be expected in a multi-stage fractured completion. The "shape" of this transition can be a good indicator of the geometry of the system- specifically degree of stimulation efficiency along the lateral, in relation to the effective fracture half-length. This approach has been applied to several producing wells in the Eagle Ford (nanodarcy reservoir) and Bakken (microdarcy reservoir).
As a result of using CLF type curves, we are able to estimate stimulation efficiency along the lateral, with reasonable confidence. The stimulation efficiency is defined as the effective stimulated horizontal well length divided by the actual horizontal well length. In addition, we are able to estimate stimulated reservoir width in a reasonably objective and consistent way. These results can be used to seed analytical models for subsequent history matching and forecasting. Diagnostic methods currently used for interpreting performance of multi-stage horizontals are based on identifying specific flow regimes using specialized plots (eg- square root time and flowing material balance). These methods are limited, in that they don't consider the transition periods, which in some cases can dominate the production history. Type curve matching is a good compliment to the standard diagnostic plots, providing an independent and objective method of characterizing the reservoir.
Historically, type curve matching has been proven as a valid technique for interpreting production data (Fetkovich, Blasingame, Agarwal et al). However, with the advent of complex multi-stage completions in tight fractured reservoirs, the existing conventional models are no longer useful. The recently introduced CLF type curves are more appropriate for unconventionals. This work represents the first detailed case study where type curve matching is applied to an unconventional oil and gas play.
Preparing for LNG: A Montney Gas Field Optimization Workflow
Authors: Holst Richard P. 
Published: October 2015

Abstract
The Montney formation of northern Alberta is a very low permeability reservoir with regions of liquid-rich gas production. The reservoir is typically developed using multi-stage fracture horizontal wells with multiple wells per pad. The produced gas ultimately flows into a gathering network that may have both high and low pressure systems. The primary objective of this paper is to present an efficient workflow for preparing and utilizing an integrated gas reservoir / network model of a Montney field as a tool to determine the optimum facilities plan for the field. Pipeline infrastructure planning is needed to accommodate the large amount of drilling that will ultimately support future LNG demands. Optimizing the development is critical, especially during times of low commodity prices.
This paper presents a simplified tight gas reservoir modelling workflow, which has proven to be successful in the Montney and other fields. The workflow integrates available technical work on a field into one simplified full-field development planning tool. Basically, for each current and future well, a simple gridded numerical reservoir model is developed that matches the short term flush production and the long term type curve predictions. The wells are then attached to a gathering system model, thus creating a tool for optimization and planning. Type curves alone are not adequate for short term planning because they do not react to changes at the surface.
The implemented workflow has proven to be effective for optimizing development such as the sizing and timing of compression and the scheduling of infill activations. It has also been useful for quantifying back-out of existing production upon infill drilling and ensuring that facilities such as pipelines and compressors are properly sized. The timing and impact of switching rapidly declining wells from high pressure to low pressures systems was also considered when optimizing the system.
The workflow has allowed for full-field shale gas models to be developed with reasonable model construction times and manageable model running times. The workflow could be applied to other similar fields or formations, such as the Horn River in north-eastern British Columbia or the Duvernay in central Alberta.
New Downhole Data Clarifies Coiled Tubing Behavior in Horizontal Wells
Authors: Blanchette C. , Getzlaf D. 
Published: October 2015

Abstract
A downhole force recorder is presented that uses onboard strain gauges along with temperature and pressure sensors to measure and record the forces experienced by a downhole assembly at the end of a coiled-tubing string. Field trials are discussed in order to demonstrate the benefits of the downhole force recorder during a typical fracturing operation.
The downhole recorder measures force, pressure and temperature. The recorder utilizes a system of onboard strain gauges, pressure transducers and temperature sensors in order to determine the force applied to the gauge. The pressure and temperature sensors are used to filter the pressure and temperature effects out of the force measurement, as well as to record standard treatment data. All data is stored onboard the tool and recovered postjob at surface. The data obtained is then downloaded and compared to a static tubing forces model to validate the results captured in dynamic well conditions.
Field trials were completed over the course of two and a half years, with design improvements to refine data capture capabilities. Initial downhole recorder trials showed that pressure had a large effect on the force measurement. This was offset by calculating the piston areas of the gauge and writing algorithms to remove the pressure-induced force. The latest field trials verify the data collected by the downhole force recorder represents actual force measurements in dynamic well conditions and in varied reservoir types. This data provides more precise downhole information than the general data found in static models. The downhole force recorder has been successfully used in over a hundred deployments.
Four significant uses for accurate downhole force measurments have been identified: validating third-party force models and better calibrating downhole force recorders used under similar fracturing operationscompleting an informed rootcause analysis when troubleshooting job performance issuesproviding operators with more information on force, pressure, and temperature to support job planning for typical completionsinfluencing future product development driven by force and depth requirements captured under specific well conditions.
Novel/Additive Information: The novelty of the new downhole force recorder is its ability to accurately determine the force experienced by a bottomholeassembly (BHA) at the end of the string when used during typical fracturing operations. Capturing this new downhole force information will transform how operators approach job planning and troubleshooting on well completions, and how tool designers approach future product development for fracturing operations.
Performance Analysis of the Canadian Deep Basin Unconventional Wells
Authors: Pour Faleh Novin , Sayed Nada El , Eddy John 
Published: October 2015

Abstract
The Canadian Deep Basin is comprised of a stack of tight sand reservoirs including channels and sheet sands with reservoir fluids that regionally vary from dry gas, gas-condensate to volatile oil. This Basin has been ranked one of the most commercially developable unconventional systems and has attracted many operators. Thousands of wells have been drilled in the area that tested a variety of well designs and fracking technologies over time. The initial development started with hydraulically fractured vertical wells that targeted all sand intervals in the vertical section, but the recent technology advancement enabled operators to focus more on horizontal drilling with multiple fractures along the wellbore. Assessment of the commercial development of these wells and the future of the assets depends on the proper evaluation of the performance of the existing wells and reliable production forecasting and estimation., Rate Transient Analysis (RTA) and multi-segment Decline Curve Analysis (DCA) techniques have been identified as the quickest and best fit for purpose techniques. Upon data availability, rates and pressures, RTA models provide better quality analysis over DCA yet DCA is required for many analog wells in the public domain. In our proposed methodology calibration of DCA parameters with the results of RTA is included for enhancing DCA quality.
This paper discusses the generalized performance characteristics of the Deep Basin wells under study. Key decline parameters such as the decline exponent and time to boundary dominated flow are discussed and compared between wells. Differences in well design such as well length and proppant tonnage impact the well performance and are covered in this paper with a suggested methodology for normalizing the performance data. Finally, a key focus of this study is uncertainty and non-uniqueness associated with the results. This is particularly important in early time when the wells are still in the transient period. Methodologies with probabilistic techniques are presented to address the issue.
Acid Additives Effect on Production – A Beaverhill Lake Case Study
Authors: Maley Darren , O'Neil Bill , Ubana Lea , Mattucci Mike 
Published: October 2015

Abstract
Since the start of large volume acid fracturing treatments of horizontal wells in the Beaverhill Lake formation many variations of acid chemistry have been used. Often the changes to the chemical formulations are based on cost reduction and treatment optimization since the volume of acid used became considerably large. Though possibly changes based on cost optimization may have affected the overall economics of the well.
This study will evaluate 56 wells that were acid fractured in the Beaverhill Lake formation, specifically in the Swan Hills area with acid blends that consisted of four different antisludge surfactant packages. Initial interpretation indicates that the acid blends containing cationic surfactants yield significantly higher oil production than the acid blends that utilize anionic surfactants once other variables have been normalized. Acid blends containing anionic surfactants have classically been the preferred chemical formulation for oil wells in the Swan Hills are due to the interpretation of the results of simple laboratory testing and the perception that the chemistry is more cost effective.
In an attempt to correlate the change in chemistry to changes in well production, additional lab testing to support previously published work will be presented, including reaction rate testing, wettability studies using core samples, and a modified acid-oil compatibility test with a longer term fluid exposure at reservoir conditions.
Case Studies in Quantitative Flowback Analysis
Authors: Williams-Kovacs J. D. , Clarkson C. R. , Zanganeh B. 
Published: October 2015

Abstract
Recently, several authors have explored new methods for quantitatively analyzing multi-phase flowback data from multi-fractured horizontal wells (MFHW) to extract both fracture and reservoir parameters. These techniques provide much of the same information as long-term rate-transient analysis (RTA), although in a much shorter period of time. Flowback analysis is complicated by a rapidly changing fracture network and wellbore environment, multi-phase flow in the fractures (and possibly the reservoir), completion heterogeneity, as well as other effects which are often not present, or are ignored, when analyzing long-term (online) production data.
For quantitative flowback analysis, the current authors have previously presented data-driven, pseudo-analytical methods for estimating key fracture properties (i.e. conductivity and half-length) from high-frequency, short-duration production test data. Models have been developed for both oil and gas wells representing a variety of reservoir and operating conditions. In this work, the models and procedures are extended to apply to more challenging reservoir/completion scenarios and are used in the analysis of several case studies from Canada. Each of the case studies demonstrate either the potential value add of the developed techniques, or a unique extension to the basic analysis methods.
The case studies analyzed herein focus on light tight oil plays and consider layered reservoirs, multi-well flowback, and oil fracs in oil reservoirs. Further, the potential capital savings associated with conducting quantitative flowback analysis of early-time production test data is demonstrated. Each case study therefore presents a unique set of challenges that are often encountered in the real world. Numerical simulations are used to validate the sequence of flow-regimes depicted in the models.
The methods presented in this paper will serve to partially satisfy the demands of industry to develop new methods for characterizing hydraulic fractures and forecasting production, particularly early in the well life. Through the use of several unique case studies, the wide-spread applicability and versatility of the techniques is demonstrated.
Water-Free Fracturing: A Case History
Authors: Asadi M. , Scharmach W. , Jones T. , Sampayo A. , Chesney E. , Unruh D. 
Published: October 2015

Abstract
While hydraulic fracturing is primarily used to recover oil and gas from reservoirs, water-free fracturing may soon become the center stage to extract hydrocarbons in certain formations or situations. DryFrac™ waterless fracturing technology, as the name implies, does not use water to create the fracture. Instead, this process uses liquid CO2 to crack open the formation providing a highly conductive path for hydrocarbons to flow into the well. This technology can provide superior technical advantages over water-based hydraulic fracturing by eliminating the need for water, resulting in formations free from water damage and maintaining the intended proppant pack conductivity with no polymer residue. This paper presents in-depth information on a case history where liquid CO2 is used to fracture a formation. The presented data includes background, modeling, liquid CO2 implementation as a fracturing fluid, results and analyses.