bluuebunny/crossref_metadata_2025_split huggingface dataset:
Carboxymethylcellulose a Cost Effective Alternative to Guar, CMHPG and Surfactant-Based Fluid Systems
Authors: Azizov E. , Quintero H. J. , Saxton K. , Sessarego S. 
Published: October 2015

Abstract
The first fracture treatment using crosslinked guar was performed in 1969. Since then, guar and its derivative polymers have dominated hydraulic fracturing. Because of volatility and supply issues with guar gum that have surfaced during peak activity years, the industry has turned to alternatives. One of those alternatives is carboxymethylcellulose (CMC) that, just like guar, comes from the food industry. CMC is also used in pharmaceuticals as a thickening agent and in the oil and gas industry as an ingredient in drilling mud. Use in hydraulic fracturing is surprisingly limited. The objective of this paper is to demonstrate successful cases of CMC-based treatments over traditional guar and surfactant-based treatments used in linear and foamed applications.
This paper presents several cases from treatments performed on formations such as Cardium, Montney, Belly River, and Dunvegan. Presented production comparison will demonstrate that wells treated with CMC-based hydraulic fracturing fluid system yield similar performance when compared to wells treated with guar, its derivatives, and surfactant-based fluid systems.
Cost savings realized when switching to CMC-based fluid systems are also discussed in this paper. Laboratory tests are described, and results are shared to demonstrate the performance of CMC compared to guar, carboxymethylhydroxypropyl guar (CMHPG), and surfactant systems.
The paper attempts to provide a degree of confidence to the operators looking for cleaner alternatives to industry-established fluid systems, and shows that these can be successfully implemented without additional risk or cost.
Guidelines for the Handling of Natural Fractures and Faults in Hydraulically Stimulated Resource Plays
Authors: Stephenson B. , Coflin K. 
Published: October 2015

Abstract
Do fractures help or hinder production in hydraulically stimulated resource plays? Most say they help, but some say they hinder. After monitoring productivity for over 10 years in a number of plays in Shell's unconventional portfolio, it appears that the evidence for fractures helping is more conceptual than empirical, further substantiated by a detailed literature review. The objective of this paper therefore is to bring some objectivity to the discussion around the impact of structure using logical arguments by reason, incorporating knowledge of the variability in structure and well performance within the spectrum of unconventional plays.
Fundamental to this assessment is the recognition that different scales of features will have a markedly different impact. And to communicate the concepts herein, small-scale features are referred to as "natural fractures" and large-scale features, referred to as "faults" or "lineaments".
This analysis indicates that the variability in (small-scale) natural fracture intensity across most plays is not sufficient to be detected in well performance metrics, given the other sub-surface heterogeneity and the large range in estimated ultimate recovery (EUR) for any given set of wells. Furthermore, natural fracture connectivity is typically low and stimulation of networks is not supported by data or trials. It is proposed to consider natural fractures as an intrinsic rock property which will modify the bulk geomechanical properties of the formation. The only exception found was for folded tight-sand plays, where fracture network connectivity may be sufficient to provide a measurable enhanced deliverability.
Understanding the impact of seismically-visible, planar, structural features (e.g. faults or lineaments) proved to be more problematic, with operators reporting both EUR increases and decreases. This inconsistency is explained with a novel concept classifying faults as contained or uncontained, contingent on whether they are within a closed fluid- and pressure-contained system, or not (respectively) before and after hydraulic stimulation.
Rather than searching for a production performance correlation, it is suggested that an enhanced understanding of the physical processes during a hydraulic stimulation would be more beneficial to clarify the impact of structure. And to this aim, a compilation of potential fracturing diagnostics is presented herein.
The Well Factory Approach to Developing Unconventionals: A Case Study from the Permian Basin Wolfcamp Play
Authors: Rexilius Jarrad 
Published: October 2015

Abstract
In order for operators to grow production and maintain profit margins in unconventional resource plays, a ‘Well Factory’ or ‘Manufacturing’ style of development is often employed. These types of plays are commonly termed ‘statistical’ and the popular school of thought is to drill and complete hundreds (or thousands) of wells in the same manner and design. Such a strategy, likened to the assembly line model that made the car manufacturing industry so successful, requires making some general assumptions regarding subsurface and surface homogeneity across the field. There are both merits and potential drawbacks to employing an overly strict well factory approach to development with standardized designs. A manufacturing style typically results in faster execution speeds and improved efficiency, meaning more wells on production over a shorter period of time at a lower cost. This approach also lends itself to taking advantage of economies of scale, by applying standard designs across multiple rig lines over a large geographical area. However there are drawbacks to this approach if not implemented appropriately, including slower adoption of industry best practices, suppressed innovation, and increased likelihood of value erosion due to lower well recoveries as a result of suboptimal or incomplete subsurface characterization.
This paper will analyse differing well factory approaches to unconventional assets, using examples from the Wolfcamp Unconventional Oil Play in the Permian Basin. The Wolfcamp play is one of most active and mature unconventional oil plays in the world, with over 200 industry rigs currently developing the resource base, and more than 12,000 industry wells already drilled.
An emphasis is placed on utilizing a factory model that enables flexibility for project execution teams to optimize, while maintaining the efficiency and execution speeds that a classical factory model provides. Ultimately it is imperative that operators can adapt to the ever-evolving nature of these plays, as technology, research, and well performance data matures. It is also important that operators can trial new ideas and concepts with a ‘learn fast-fail fast’ culture that does not interrupt the factory performance. This paper will present a framework for a well factory process to most optimally develop an unconventional resource play, with the caveat that all fields and plays are different and a ‘one size fits all’ approach rarely applies in any oil field application, let alone an unconventional play.
The Use of Completion Diagnostics in Haynesville Shale Horizontal Wells to Monitor Fracture Propagation, Well Communication, and Production Impact
Authors: Sani Abu M. , Podhoretz Seth B. , Chambers Brent D. 
Published: October 2015

Abstract
This paper presents case studies of several leases containing horizontal wells in the Haynesville shale. The studies involve the successful use of completion diagnostics: fluid tracer, proppant tracer, and offset wells pressure monitoring. The diagnostics were used to evaluate fracture propagation, connectivity and communication (between stages and offset wells) and the impact on production performance for different completion methodologies.
Proppant tracers were used to identify cluster efficiency, fracture geometry and communication between stages. Fluid tracers result provided the extent of fracture connectivity between offset wells and show fracture propagation dependency on well spacing and sequence of fracturing. Furthermore, fluid tracers provided an estimate of lower bound on the fracture connectivity, as well as a qualitative measure of stage contribution based on the load fluid recovery period during the initial production phase. Depletion and treatment volume were found to play a key role in fracture propagation and tracer migration. The instantaneous pressure response in monitoring wells during the fracturing operations of adjacent wells was determined to be related to well spacing and the fracture treatment volume. Fracture propagation was found to positively impact the production performance of the depleted wells, thereby changing their original production decline.
Achieving Top of Cement; An Engineered Solution for Loss Zone Wells in the Bakken
Authors: Blake B. , Bowditch R. , Simacheva N. , Hudson M. , Crane D. , Shea C. 
Published: October 2015

Abstract
Primary cementing across the Williston basin Mission Canyon formation, a depleted zone with a low fracture gradient, can require alternative cementing techniques to achieve reduced equivalent circulating density (ECD) to minimize losses during cement placement. Achieving top of cement in this zone is challenging, and has historically required some form of remedial cementing. Some solutions have been foamed and two-stage cementing techniques; however, these techniques can be operationally complex.
The solution used is a lightweight, high-performance cement slurry. This solution uses an engineered, high-crush-rated hollow sphere particle as a cement extender, thus providing the slurry with reduced density and increased solid volume fraction upon comparison to conventional slurries. This slurry is used in combination with a fiber-based loss circulation material (LCM.) The combination of the increased solids content of the cement and the fiber LCM improves the plugging efficiency across the loss circulation zone. This cementing package allows for cement to be effectively placed across the Mission Canyon loss circulation zone with single-stage cement techniques.
Both case study wells sustained losses in the Mission Canyon at approximately 9,500 ft, with target true vertical depths (TVDs) approximately 10,800 ft. The average mud weight used in these wells was 10 ppg, and an aggressive LCM package was used prior to drilling into the Mission Canyon formation. Casing running rate was modified in order to reduce risk of inducing losses. Using the previously discussed design, a low-density, high-performance lead slurry was employed to cover these loss zones. A significant increase in solids content was achieved by extending this slurry with a manufactured, hollow sphere particle. This system gave an overall reduction in ECDs when compared to conventional slurries across the zone of interest. This lightweight, high-performance system was used with a fiber-based LCM package to maintain good circulation throughout cement placement. Critical job parameters were recorded throughout cementing and compared to design ones to support the observation of consistent returns to surface throughout placement. Ultrasonic cement evaluation was used to confirm top of cement post placement.
The novel solution, supported by two case studies, shows the successful use of a lightweight, high -performance cement system, along with fiber-based LCM. This cementing package was used to successfully achieve required top of cement during primary cementing across depleted or naturally fractured zones in the Williston basin during a single-stage cement placement.
The Full Montney - A Critical Review of Well Performance by Production Analysis of Over 2,000 Montney Multi-Stage Fractured Horizontal Gas Wells
Authors: Reynolds Murray , Bachman Robert , Buendia Juliana , Peters Wade 
Published: October 2015

Abstract
In today's low price environment, maximizing productivity and hydrocarbon recovery while reducing cost has become more critical than ever. In many resource plays, factory style completion campaigns using high rate / volume fracture treatments have become the accepted norm. However, is that really the optimum design to maximize productivity and net present value (NPV) of the asset?
This paper will present a new style of statistical analysis of the well performance of approximately 2,000 Montney / Doig horizontal gas wells completed since 2010. This analysis will review the important parameters to determine the effectiveness of the completion designs, such as:Fracture fluid systems;Open hole or cased hole multi-stage systems;Number of fracture stages / fracture spacing;Size of fractures, proppant tonnage per well;Cost.
The analysis was performed based upon normalized parameters including: Cumulative production at 3 and 12 months;Cumulative production: per proppant tonnage; completed well length; number of fracture stages; and completion cost.
The study will cover an overall review of the entire Montney / Doig gas fairway, as well as focus on an individual ‘high activity’ area of the Montney. This area includes some operator specific well performance comparisons.
This paper will outline the importance of applying advanced well performance analysis techniques to determine the efficiencies of specific completion and fracture designs. This illustrates the importance of looking back in order to optimize future completions. This paper reinforces the need to move completion designs from the current ‘operational effectiveness’ mode of fracture designs, to a ‘fracture effectiveness’ mode provided by optimizing designs to achieve higher recoveries and improved economics.
Integrated Reservoir Modeling and Optimization Study of Multi-Fractured Horizontal Well in the Swan Hills Formation: A Case Study of Acid Fracturing
Authors: Islam Arshad , Ziarani Ali S. , Glover Ken , Schneider Brian 
Published: October 2015

Abstract
With the advancement of drilling and fracturing technology in recent years, multi-stage fractured horizontal wells have become a norm in the development of unconventional oil and gas reservoirs in North America. This has created a renewed interest in major formations of the Western Canadian Sedimentary Basin. Due to higher completion cost, it is crucial to find an optimal fracture size and spacing as well as wellbore spacing for these horizontal wells. Acid Fracturing is a stimulation process in which acid is used to enhance the conductivity of a hydraulic fracture through differential etching of the fracture face. The effectiveness of acid fracturing depends on retaining fracture conductivity under closure stress after treatment. Fracture face roughness created by the acid etching and mechanical properties of rock after acid treatment are two important factors that play a vital role in retaining conductivity after fracture closure. Acid fracturing treatments of carbonate reservoirs have yielded an increase in production in many areas of the world. The Swan Hills Formation (a member of Beaverhill Lake group) in Alberta, Canada, a carbonate oil play, is the focus of this paper.
A dual porosity model was employed to integrate core, rock mechanics, PVT, stimulation, and production data. Acid treatment data was used to estimate the fracture geometry and conductivity which was then incorporated into a three dimensional reservoir simulation model. A multi-layer, single-wellbore reservoir model of horizontal heterogeneities across the study area was built based on core calibrated formation and geomechanical log data. The model input parameters were further fine-tuned using production history matching.
The calibrated reservoir parameters, based on a history matched model, were used for initial fluid in-place estimation, production forecasting and to investigate the fracture and wellbore interference. Interference analysis was performed based on reservoir pressure depletion and decline in cumulative production. A sensitivity study of fracture density, wellbore spacing, and lateral length of wellbore was carried out and their effects on oil and gas production are discussed. Recommendations on optimal fracture and wellbore spacing for the Swan Hills Formation are also provided.
Production Performance in the In-Fill Development of Unconventional Resources
Authors: Cherian Bilu V. , McCleary Matthew , Fluckiger Samuel , Nieswiadomy Nathan , Bundy Brent , Edwards Sarah , Rifia Rafif , Kublik Kristina , Narasimhan Santhosh , Gray James , Olaoye Olubiyi , Shaikh Hamza 
Published: October 2015

Abstract
Until 2015, North America’s unconventional resource market was known to be home to the largest oil shale deposits of economic value. Although the recent commodity price fluctuations have exposed the role of geo-politics, world economies and commodity trading on the life cycle of assets, few field development studies have consider the impact of commodity cycles on the development of in-fill wells. Papers have been presented to demonstrate the impact of vertical fracture connectivity and fracture asymmetry on in-fill well performance (due to delayed in-fill drilling), but little has been done on validation and coupling the impact of depletion, due to production, and hydraulic fracturing (due to in-fill efficiency fracture operations). This paper presents results from the analysis of in-fill drilling on well performance. Production data, fracture treatment data, completion and production timing are analyzed using pressure/production history matching techniques and compared with results predicted by data driven models (developed to match well performance) with the aim of proposing in-fill development strategies. Analysis of the field production data indicates that timing of in-fill wells (following the parent well) can influence the in-fill production depending on the level of depletion (cumulative fluid produced) and the size/type of fracture treatments pumped. Analysis of raw production data, modeling results from multi-domain model based coupled simulations and high resolution monitoring data also indicates that the order of the in-fill operations (East-West, Zipper, etc.) also has a significant impact on performance. This paper presents a simplistic approach to understand the impact of the quest for operational efficiencies and economic cycles on development strategies.
A Material Balance Equation for Stress-Sensitive Shale Gas Reservoirs Considering the Contribution of Free, Adsorbed and Dissolved Gas
Authors: Orozco Daniel , Aguilera Roberto 
Published: October 2015

Abstract
Unconventional shale gas reservoirs around the world have been proven to store gigantic volumes of natural gas. It has been demonstrated with both laboratory and mathematical work that these reservoirs can be represented by a quintuple porosity formulation plus an additional storage mechanism provided by dissolved gas in kerogen. All these storage mechanisms must be considered for estimation of original gas in place (OGIP). Otherwise pessimistic values of OGIP and recoveries will be obtained by ignoring any of these mechanisms. This paper presents a new easy-to-use Material Balance Equation (MBE) for shale gas reservoirs that considers the contribution of free, adsorbed and dissolved gas and their effects on cumulative gas production. Furthermore the proposed MBE takes into account the stress-dependency of permeability and porosity as the reservoir is depleted.
Aguilera (2008) formulated a MBE to account for the effect of fracture compressibility on OGIP determination in stress-sensitive naturally fractured reservoirs. Cabrapan et al. (2014) extended the method by incorporating adsorption in shale gas reservoirs. The authors used the Langmuir Adsorption theory for quantifying the adsorbed gas volume as a function of average reservoir pressure. In this paper, the method is further extended to include the effect of production by diffusion of dissolved gas from kerogen. The volume of dissolved gas depends on the total fractional volume of kerogen in shale and the methane concentration in the kerogen body, which is in turn a function of pressure and temperature, as proposed by Swami et al. (2013).
Results are presented as crossplots of P/Z (pressure/gas deviation factor) vs. Gp (cumulative gas production), Gp vs. time and gas rate vs. time. The plots allow detecting four stages of production in a shale gas reservoir: 1) production of free gas from fractures and organic porosity, 2) production of free gas from the inorganic matrix when fractures start closing, 3) production by desorption from the organic material and 4) production by diffusion of dissolved gas. The same trends have been observed in Devonian Shales of the Appalachian Basin where long production histories are available. It is concluded that dissolved gas is not only an additional storage mechanism but it also provides an important pressure and production contribution in shale reservoirs.
The new consideration introduced in the MBE proposed in this paper is of importance because although diffusion from kerogen in shale gas reservoirs is by nature a slow process, it provides long term production rates with relatively small declines. To the best of our knowledge, an analytical MBE that includes simultaneously stress-dependent porosity and permeability, free gas, adsorbed gas and dissolved gas has not been published previously in the literature.
Creating More Representative Type Wells
Authors: Freeborn Randy , Russell Boyd 
Published: October 2015

Abstract
This paper presents original research on how to improve the predictive ability of type wells used in evaluating unconventional resource drilling programs by extending traditional Monte Carlo calculations. The paper addresses three critical questions engineers must answer before constructing a type well: which well to use in the construction, the relative importance (weighting) appropriate for each well, and how to adapt the results to reflect certainty (e.g. P10, P50 or P90).
The proposed method involves determining the aggregated distribution of estimated ultimate recovery (EUR) for the specified number of wells by running a statistically significant number of Monte Carlo trials. From this distribution, one can determine mean EURs for the desired type well certainties, such as P50 or P90. Additional Monte Carlo trials yielding the desired mean EUR will help determine which wells to average. Monte Carlo sampling results in several hundred trials that match the desired EURs. The relative frequency of well selection from these trials defines the weighting factor and thus the relative importance of each well. Type wells result from a weighted averaging of history and production from the selected wells.
Engineers can use this new methodology to prepare production profile forecasts for the evaluation of multi-well unconventional resource drilling programs. They can also gain an understanding of the impact aggregation will have on their evaluation work.
Our research concludes that current type well construction practices may not be appropriate for evaluating future drilling because the production profiles for the wells used to build the type well may differ from the production profiles of the planned wells. This paper presents a new method to obtain more representative type wells. The method proves accurate for any ranking criterion (EUR, net present value, payout time) as long as one can identify the ranking parameter for each well.
This paper contributes to the technical knowledge base by:
identifying deficiencies in current type well methodology and proposing methodology to remove those deficiencies, proposing a method to meet selected certainty criteria and aggregate properly using Monte Carlo simulation, and introducing the concept that type wells do not need to be based on EURs, and in fact may be more valuable if they are based on more relevant criteria.