bluuebunny/crossref_metadata_2025_split huggingface dataset:
Stress Shadow Evaluations for Completion Design in Unconventional Plays
Authors: Nagel N. , Zhang F. , Sanchez-Nagel M. , Lee B. , Agharazi A. 
Published: November 2013

Abstract
In horizontal well shale completions, multiple stages, each often with multiple clusters, are used to provide sufficient stimulated area to make an economic well. However, each created hydraulic fracture alters the stress field around it, and when hydraulic fractures are placed close enough together, the well-known stress shadow effect occurs in which subsequent fractures are affected by the stress field from the previous fractures. Further, new completion techniques, like simultaneous fracturing and zipper fracs, have been proposed to take advantage of stress shadows to enhance production and are therefore dependent upon a proper understanding of stress shadow effects.
In recent years, several papers, by the authors and others, have been published attempting to describe the stress field associated with hydraulic fracturing. Often, the authors focus on the change in the stress field as indicative of increasing ‘complexity’ where the evaluations are based upon the common modeling of multiple hydraulic fractures assuming a parallel, planar hydraulic fracture geometry. However, for hydraulic fracturing in unconventional plays, parallel, planar hydraulic fractures are unlikely to occur. If there are few natural fractures – or if these are tight with narrow initial apertures - whether pumped simultaneously (as in multiple clusters per frac stage) or sequentially (one stage pumped after the other), the stress shadow effect will force subsequent fractures to grow away from the first fracture. Alternatively, if there are many, hydraulically open natural fractures, the stress shadow effect may be muted by the many open natural fractures and reduced length and aperture of the main hydraulic fracture.
In this paper, we present the results of a numerical evaluation of the effect of multiple hydraulic fractures on stress shadowing as a function of the natural fractures, hydraulic fracture spacing, rock mechanical properties, and in-situ conditions. The results of the study provide a quantitative means to optimize shale completions by understanding the effect of hydraulic fracture spacing on the stress shadow effect and the potential for changing fracture complexity. In addition, the results show the relationship between stress shadowing and microseismic events along multi-stage horizontal wells, which allows for better interpretation of the microseismic data.
Tip-Effect Microseismicity - Numerically Evaluating the Geomechanical Causes for Focal Mechanisms and Microseismicity Magnitude at the Tip of a Propagating Hydraulic Fracture
Authors: Agharazi Alireza , Lee Byungtark , Nagel Neal B. , Zhang Fengshou , Sánchez-Nagel Marisela 
Published: November 2013

Abstract
There have been extensive industry efforts to understand the geophysical implications – and limitations – of microseismic analyses; however, a critical issue that is often overlooked is the geomechanics of the rock failure that is represented by microseismicity. Recall that microseismicity is the acoustic representation of rock failure, whether tensile failure or shear failure, which is driven by the coupled hydro-thermo-mechanical effects of injecting cool fluids at high rates into naturally fractured formations. Often overlooked in the analysis of microseismic data is the stress and deformational effects at the tip of a propagating fracture that cause a significant percentage of the total microseismic record. Previous publications, for example, have noted that at the horizontal leading edge of a propagating fracture, the dominant shear is in a horizontal plane. Conversely, at the upper and lower vertical leading edge of the propagating fracture, vertical shear has been reported to dominate. These would be expected to not only cause a different microseismic response, but also, likely, a different stimulation response.
In this paper, we present a detailed numerical evaluation of the stresses generated at the tip of a propagating hydraulic fracture under varying field conditions. The simulations were performed with a finite difference continuum code. The results of the simulations show that field conditions and position along the perimeter of the propagating hydraulic fracture can significantly impact local stresses, which will have then have an impact on the generated microseismicity. The results of the work will allow for a better interpretation of field microseismicity for completion optimization.
New Technologies Eliminate Drill Bit Wear in Oil Sands Applications
Authors: Beaton Tim , Cyre Jeff , Isnor Sid , Herman J. J. 
Published: November 2013

Abstract
Oil sands applications are well known to be one of the most demanding drilling environments in the industry with regard to durability. The bodies of the cutters and the body of the bit experience severe wear in these applications, leading to inconsistent drilling performance. Extensive efforts in the past decade to solve this issue have been met with limited success. In oil sands applications, the sands are highly abrasive and unconsolidated. The result is that the sand particles quickly become suspended in the drilling fluid and mimic the effect of sandblasting the bit for the duration of the run. In many cases, the bit body wear around the cutters is extensive enough to cause premature bit failure due to cutter loss. The bodies of the PDC cutters themselves also suffer extreme material loss, which leads to cutter breakage and an associated reduction in drilling performance. Finally, in the lateral interval, the sands in cutting beds lying on the low side of the hole cause serious wear to both the gage and backreaming portions of the bit.
This paper will discuss new technologies that have proven to eliminate bit wear in the horizontal reservoir interval. Comparisons will be made detailing the severe wear experienced with conventional bits and the absence of wear experienced with identical bit designs using a new body construction technology. A novel PDC cutter will also be presented that has been developed to eliminate cutter body wear.
The requirements for improving drilling performance in oil sands applications are as unconventional as the wear experienced in these applications. Unlike traditional applications where improving performance includes an effort to drill faster or further, oil sands applications are typically control drilled and the entire interval is almost always completed in one run. The focus in these applications to augment performance is to improve directional control, enhance backreaming efficiency and hole quality, and increase bit durability. The new technologies detailed in this paper have proven to dramatically enhance each of these key performance indicators, resulting in the ability to drill further and faster, while improving the possibility of success of the well completion.
Uncertainty Quantification Improves Well Construction Cost Estimation in Unconventional Reservoirs
Authors: Valdes Alejandro , McVay Duane A. , Noynaert Samuel F. 
Published: November 2013

Abstract
The success of petroleum development projects depends to a large degree on well construction costs. Well construction cost estimates often contain high levels of uncertainty. In many cases, these costs are estimated using deterministic methods that do not reliably account for uncertainty, leading to biased estimates. The objectives of this work were to improve the reliability of deterministic well construction cost estimates by incorporating external probabilistic methods into the estimation process.
The method uses historical well cost estimates and actual costs to develop probabilistic correction factors that can be applied to future well cost estimates. These factors can be applied to the entire well cost or to individual cost components. Application of the methodology to estimation of well construction costs for horizontal Barnett shale wells in the Fort Worth basin resulted in estimated well cost estimates that were well-calibrated probabilistically. Overall, average estimated well cost using this methodology was significantly more accurate than average estimated well cost using deterministic methods.
The methodology is intended for use by individual engineers to improve their well construction cost estimation and by management to externally revise and improve well cost estimates for budgeting purposes. Systematic use of this methodology will provide for more accurate and efficient allocation of capital for drilling campaigns, which could have significant impacts on reservoir development and profitability.
Practical Directional Drilling Techniques in Pinedale Field Wyoming to Improve Drilling Performance
Authors: Han Guangzhi , Lemesany Lane , Azizov Azar A. , DeLeon Frank 
Published: November 2013

Abstract
The giant Pinedale anticline gas field, which is approximately 35 miles long and 6 miles wide, contains 159 Tcf of conservatively estimated in-place natural gas. The field ranks as the third-largest gas field in United States by proved reserves. Gas production is primarily from a 5,500-ft thick "Lance Pool" that overlies the top of the Ericson Sandstone Formation. The Lance Pool consists of the Lance Formation, the Upper Mesaverde Group, and a Paleocene "unnamed" unit. The reservoir is classified as tight gas, with low porosity and micro-darcy permeability. Horizontal drilling is not practical and therefore deviated well (S-well) drilling is prevalent, due to the lenticular sands and stratigraphic nature of this area.
A typical deviated well has a 5° to 25° inclination in the upper section, then a tangent section varying from 1,000 to 5,000 ft, with a total depth (TD) of around 15,000 ft MD. The extensive reach, long tangent and various formation strata encountered place an extremely challenging drilling environment for directional drilling using a conventional adjustable kick-off sub (AKO), positive displacement motor (PDM), and a polycrystalline diamond compact (PDC) drill bit. However, if proper directional drilling techniques are applied, this approach can accomplish the task in a timely manner and provide outstanding cost effectiveness over automated vertical-seeking tools (Han et al., 2013).
This paper discusses difficulties encountered in the Pinedale directional drilling process with a conventional AKO PDM, such as successfully landing in the driller target, predicting the reactive torque under various scenarios, holding the tool face (TF) with a PDC bit, and extensive hole drag. Several practical directional drilling techniques are presented as solutions, such as point-turn-tag, turn-tag-point, tag-turn-point, jerking-while-sliding, counting-number and 6-in.-wiper. These techniques are practical, field-proven and invaluable for Pinedale operations and numerous oil and gas fields with similar directional drilling obstacles. Thorough understanding and mastering of these techniques can substantially increase directional drilling efficiency, reduce drilling time, enhance borehole quality, and improve overall drilling performance.
Optimal Salinity Study to Support Surfactant Imbibition into the Bakken Shale
Authors: Zhang Jin , Wang Dongmei , Butler Ray 
Published: November 2013

abstract
In our previous study of Bakken shale imbibition, a group of surfactant formulations were examined. These surfactants consistently altered the wetting state of Bakken cores toward water-wet, and appeared to have a substantial potential to improve oil recovery from the Bakken Formation compared to brine water alone. To advance this development, this paper investigates the optimal salinities of surfactant solutions by phase behavior and IFT studies using Bakken formation water and oil. The ultimate objective of this research is to determine the potential for surfactant formulations to imbibe into and displace oil from shale, and also examine the viability of a field application.
Using glass tube and encased-pipette methods, as well as a spinning drop tensiometer, dilute surfactant formulations were studied with various surfactants molecular structures (anionic, nonionic, cationic, and amphoteric). In most cases, optimal salinities obtained by phase behavior and IFT study aid surfactant imbibition into the Bakken Shale. In other cases, surfactant formulations were effective in imbibing into and displacing Bakken oil from Bakken cores, even though there were no obvious optimal salinities observed—suggesting that wettability alteration was a more dominant mechanism than IFT reduction in the imbibition process. Where optimal salinity behavior was obtained, the IFT between surfactant water and crude oil were reduced by one to two orders of magnitude with alkaline formulations. Under the same conditions, the inverse Bond number NB-1 which dominates the displacement mechanism, could be decreased below a value of 1 in cores from the Middle member of the Bakken.
Based on phase behavior and IFT measurement at optimal salinity, we found: for Bakken reservoir conditions, (1) at lower concentrations (0.1%), of an anionic surfactant, internal olefin sulfonate shows a fast imbibition rate but lower oil recovery compared with a higher concentration surfactant (2%) with same molecular structure. (2) With 0.1% concentration, nonionic surfactants with an ethoxylated alcohol molecular structure exhibit a fast imbibition rate and strong effect on oil recovery at reservoir temperature (~120°C). (3) A cationic surfactant with a large carbon number and ethoxylated tallow amine structure at 0.1 % concentration has a favorable effect on oil production at high temperature. (4) An amphoteric surfactant with dimethyl amine oxide structure shows a stronger effect on oil recovery at 0.1% concentration. (5) At optimal salinity, the incremental oil recovery (during imbibition into Bakken cores at 120°C) can be up to 18% OOIP higher than seen during comparable experiments using formulations with 15~30% TDS, and the average instantaneous imbibition rate increased up to 45%.
Evaluating Long Term Flow Regimes in Unconventional Oil Reservoirs with Diverse Completion Technology
Authors: Kurtoglu B. , Rasdi F. , Salman A. , Kazemi H. 
Published: November 2013

Abstract
Innovative completion techniques for unconventional oil and gas reservoirs have been developed at a rapid pace. Deciphering the flow regime characteristics of the pressure-time signature of flowing wells associated with these new completion techniques is critical for evaluating well performance and ultimate hydrocarbon recovery. In this paper we present the flow regimes observed in the plots of field production data for several of these new completion techniques. We also present the simulated model results for these completions.
Several rate-transient analyses (RTA) for different well completion techniques from 1990 to 2010 were analyzed to determine how different completion techniques would affect flow regime characteristics—specifically, the linear flow period. Reservoir simulation results for homogenous and heterogeneous reservoirs showed that hydraulic fracture and natural fracture properties are the most crucial variables affecting the linear flow period. A statistical analysis of the Arp’s decline b-factor was also used to show the impact of increased reservoir connectivity with advanced completion techniques and stimulation.
This paper demonstrates that (a) completion techniques can influence the linear flow period and the length of the transition period before boundary-dominated flow prevails, and (b) different completion techniques lead to different flow regime diagnostics and different Arp’s flow rate exponent b.
Wellbore Efficiency Model for CO2 Geological Storage Part II: Wellbore System
Authors: Nabih Ahmad , Chalaturnyk Richard 
Published: November 2013

Abstract
Storing carbon dioxide (CO2) in deep geological formations is one part of the carbon capture and storage (CCS) process that is defined as geological CO2 sequestration or CO2 geo-sequestration. Injecting CO2 into a reservoir does not guarantee safe storage because CO2 could leak back to the surface and/or may contaminate specific strata where other energy, mineral and/or groundwater resources are present. Two mechanisms control assurance of storage integrity, which are geological leakage mechanism and wellbore leakage mechanism (Espie, 2005).
Wellbore element was presented as a basic unit for developing a model of an entire wellbore system. This paper is the second to assess the performance of a wellbore system for geological storage purposes. The analytical model adopts concept of sequence scenarios of possible leakage paths, concept of wellbore efficiency for storage purposes and concept of the reference state.
A new analytical model for modeling leakage through a wellbore system has been proposed. The analytical model represents the wellbore system as serially connected wellbore elements. This provides an advantage that each element can differ from the subsequent one and will have its own characteristics. Effective wellbore permeability also can change from element to another. The effect of site formation arrangement between general system and repeated aquitard-aquifers is investigated and compared. The analytical model is validated with the results of Nordbotten et al. (2004).
Interventionless, Pre-Perforated Liner Using Smart Engineered Materials to Provide Flow Assurance
Authors: Carrejo Nick , Norris Jason , Gaudette Sean L 
Published: November 2013

Abstract
Cased-hole completions utilize solid pipe to protect the wellbore from fluid losses. The casing provides a flow path for cementing or for completion brines and other completion tools without risk of damaging the formation. After the operations have finished running the tools downhole and have completed the well below the target zone, the casing is perforated to provide an optimized flow path. It is common for operators to use gun perforating systems or wireline perforating platforms to complete the casing perforation. These systems call for costly rig downtime while this intervention is completed. Perforating the casing results in a large amount of debris, known as skin damage. The debris from the perforation job can become a production risk, lead to damage of tools above the zone, and reduce the flow area. The debris can also lead to costly interventions needed to stimulate the well. A new smart-engineered, metallic composite has been developed to optimize this process and provide flow assurance. This new technology eliminates the need to later perforate the liner, further reducing costly interventions. High-strength corrodible material (HSCM) is a metallic composite designed to degrade in the presence of brine or acid in a predictable and uniform manner. This paper will explore the development and reliability of this new technology, and discuss how HSCM can reduce production risks while providing flow assurance for the completion.
Pump-Friendly Wellbore Design and Case Study from Mississippian Play of Oklahoma/Kansas
Authors: Reid Leslie C. , Mcdonald Clarence , Baker Ty , Jones Timothy P. , Hess Jeremy , Sharp Kevin 
Published: November 2013

Abstract
Wellbore designs and completions can positively impact long-term production in directional wells, but many directionally drilled wells are designed today without regard for future pump applications. Communication between drilling, completion, and production teams is often poor, and this negatively impacts the ability to produce in liquid-rich multiphase environments. This situation is especially true as the well matures. Early collaboration between these groups is imperative to maximize production options. Without such cooperation, many directional wells are designed without future pump success in mind. Consequently, electrical submersible pumping systems (ESPs) are excluded as a viable artificial lift solution in a majority of directionally drilled wells.
ESP technology advances have made ESPs viable in many multiphase liquid-rich wells. Ignoring current ESP capabilities ultimately diminishes production over the life of some wells. Many of these directional wells flow naturally, but liquid loading reduces production without artificial lift. ESPs can be the most productive method for reducing reservoir pressure and optimizing production, and they should be considered when designing a wellbore. The Mississippian Lime in Oklahoma and Kansas (though not a shale play) has many similar attributes of a liquid-rich shale.
This paper includes a case study from the Mississippian play for a horizontal drilling plan and completion technique aimed at optimizing pump performance. "Pump-friendly" fundamentals for wellbore design and geometry are presented.
This paper concludes that increased awareness and implementation of a few basic principles will pay huge early dividends as the well matures.
Measuring Liquid Uptake of Organic Shales: A Workflow to Estimate Water Loss During Shut-in Periods
Authors: Makhanov K. , Dehghanpour H. , Kuru E. 
Published: November 2013

Abstract
The imbibition of fracturing fluid into the shale matrix is identified as one of the possible mechanisms leading to high volumes of water loss to the formation in hydraulically fractured shale reservoirs. In an earlier study (Makhanov et al., 2012), several spontaneous imbibition experiments were conducted using actual shale core samples collected from Fort Simpson, Muskwa and Otter Park formations, all belong to the Horn River shale basin. This study provides additional experimental data on how imbibition rate depends on type and concentration of salts, surfactants, and viscosifiers. The study also proposes and applies a simple methodology to scale up the lab data for field-scale predictions.
The data shows that an anionic surfactant reduces the imbibition rate due to the surface tension reduction. The imbibition rate is even further reduced when KCl salt is added to the surfactant solution. Surprisingly, viscous XG solutions show a considerable spontaneous imbibition rate when exposed to organic shales, although their viscosity is much higher than water viscosity. This observation indicates that water uptake of clay-rich organich shales is mainly controlled through preferential adsorption of water molecules by the clay particles, and high bulk viscosity of the polymer solution can only partly reduce the rate of water uptake.
The field scale calculations show that water loss due to the spontaneous imbibition during the shut-in period is a strong function of fluid/shale properties, fracture-matrix interface, and soaking time. The presented data and analyses can be used to explain why some fractured horizontal wells completed in gas shales show an immediate gas production after extended shut-in periods.