bluuebunny/crossref_metadata_2025 huggingface dataset:
Differential expression and regulation of Tdo2 during mouse decidualization
Authors: Li Dang-Dang , Gao Ying-Jie , Tian Xue-Chao , Yang Zhan-Qing , Cao Hang , Zhang Qiao-Ling , Guo Bin , Yue Zhan-Peng
Published: November 2013

Tryptophan 2,3-dioxygenase (Tdo2) is a rate-limiting enzyme which directs the conversion of tryptophan to kynurenine. The aim of this study was to examine the expression and regulation ofTdo2in mouse uterus during decidualization.Tdo2mRNA was mainly expressed in the decidua on days 6–8 of pregnancy. By real-time PCR, a high level ofTdo2expression was observed in the uteri from days 6 to 8 of pregnancy, althoughTdo2expression was observed on days 1–8. Simultaneously,Tdo2mRNA was also detected underin vivoandin vitroartificial decidualization. Estrogen, progesterone, and 8-bromoadenosine-cAMP could induce the expression ofTdo2in the ovariectomized mouse uterus and uterine stromal cells.Tdo2could regulate cell proliferation and stimulate the expression of decidual markerDtprpin the uterine stromal cells and decidual cells. Overexpression ofTdo2could upregulate the expression ofAhr,Cox2, andVegfgenes in uterine stromal cells, whileTdo2inhibitor 680C91 could downregulate the expression ofCox2andVegfgenes in uterine decidual cells. These data indicate thatTdo2may play an important role during mouse decidualization and be regulated by estrogen, progesterone, and cAMP.
Onset of Breast Development in a Longitudinal Cohort
Authors: Biro Frank M. , Greenspan Louise C. , Galvez Maida P. , Pinney Susan M. , Teitelbaum Susan , Windham Gayle C. , Deardorff Julianna , Herrick Robert L. , Succop Paul A. , Hiatt Robert A. , Kushi Lawrence H. , Wolff Mary S.
Published: November 2013

BACKGROUND AND OBJECTIVES:

There is growing evidence of pubertal maturation occurring at earlier ages, with many studies based on cross-sectional observations. This study examined age at onset of breast development (thelarche), and the impact of BMI and race/ethnicity, in the 3 puberty study sites of the Breast Cancer and the Environment Research Program, a prospective cohort of >1200 girls.

METHODS:

Girls, 6 to 8 years at enrollment, were followed longitudinally at regular intervals from 2004 to 2011 in 3 geographic areas: the San Francisco Bay Area, Greater Cincinnati, and New York City. Sexual maturity assessment using Tanner staging was conducted by using standardized observation and palpation methods by trained and certified staff. Kaplan-Meier analyses were used to describe age at onset of breast maturation by covariates.

RESULTS:

The age at onset of breast stage 2 varied by race/ethnicity, BMI at baseline, and site. Median age at onset of breast stage 2 was 8.8, 9.3, 9.7, and 9.7 years for African American, Hispanic, white non-Hispanic, and Asian participants, respectively. Girls with greater BMI reached breast stage 2 at younger ages. Age-specific and standardized prevalence of breast maturation was contrasted to observations in 2 large cross-sectional studies conducted 10 to 20 years earlier (Pediatric Research in Office Settings and National Health and Nutrition Examination Survey III) and found to have occurred earlier among white, non-Hispanic, but not African American girls.

CONCLUSIONS:

We observed the onset of thelarche at younger ages than previously documented, with important differences associated with race/ethnicity and BMI, confirming and extending patterns seen previously. These findings are consistent with temporal changes in BMI.
Strength Training and Physical Activity in Boys: a Randomized Trial
Authors: Meinhardt Udo , Witassek Fabienne , Petrò Renato , Fritz Chris , Eiholzer Urs
Published: November 2013

BACKGROUND:

In developed societies levels of daily physical activity (PA) among school-age children are decreasing. This implies risk factors for cardiovascular and metabolic diseases. Specific strategies to improve levels of PA are needed. In prepubertal boys there is evidence that strength training increases spontaneous PA outside of training.

METHODS:

A total of 102 schoolchildren (age 10–14 years) in Switzerland were randomly assigned to physical education classes or to participate twice weekly at a guided strength training program for 19 weeks. Spontaneous PA energy expenditure (PAEE; 3axial accelerometry for 7 days), leg and arm strength, and body composition (dual energy radiograph absorptiometry) were measured at baseline, after 19 weeks of training intervention, and after 3 months of washout.

RESULTS:

There were no significant differences between the groups at baseline. In the intervention group, PAEE increased by 10% from baseline to end of training in boys (P = .02), but not in girls. Leg and arm strength were increased owing to training intervention in both boys and girls. All other variables were unchanged. Baseline PAEE was significantly negatively correlated with changes of PAEE.

CONCLUSIONS:

Targeted strength training significantly increases daily spontaneous PA behavior in boys. The less active children showed the greatest increase in spontaneous PAEE. Girls showed a similar increase in strength, but not in spontaneous PAEE. This may be explained by their earlier pubertal development. Strength training may be a promising strategy in schools to counteract decreasing levels of PA.
Implant-Guided Vertical Bone Augmentation Around Extra-Short Implants for the Management of Severe Bone Atrophy
Authors: Anitua Eduardo , Murias-Freijo Alia , Alkhraisat Mohammad H. , Orive Gorka
Published: November 2013

The purpose of this study is to describe the conservative treatment of severe vertical bone atrophy by combining the insertion of extra-short implants and implant-guided bone augmentation. For that, a low-speed drilling protocol was selected to facilitate the collection of bone particles and to maintain graft osteogenic properties. Extra-short implants were incompletely inserted because of the severe atrophy, and the denuded implant surface was covered by autologous bone particles held together by the adhesive properties of plasma rich in growth factors. The surgical site was then covered with resorbable fibrin membrane, and the flap was repositioned and sutured. Eight patients with a mean residual bone height of 4.19 ± 0.97 mm were treated according to the described treatment protocol. The distance between the implant shoulder and the bony crest was 1.77 ± 0.18, 2.16 ± 0.23, and 1.97 ± 0.26 mm at the mesial, central, and distal aspects, respectively. Vertical bone augmentation resulted in the coverage of 85% of exposed surface by stimulating 1.6 ± 0.5 mm of supra-alveolar bone growth. All 10 extra-short implants placed were successfully osseointegrated. After a mean of 5 ± 1.6 months, provisional screw-retained prostheses were placed. Within the limitations of this study, we conclude that the minimally invasive approach described may successfully rehabilitate extreme vertical bone atrophy in the posterior mandible.
Best Practice of Using Empirical Methods for Production Forecast and EUR Estimation in Tight/Shale Gas Reservoirs
Authors: Yu Shaoyong
Published: November 2013

Since 2008, a number of new empirical methods have been introduced to the petroleum industry, specifically for gas wells in tight and shale reservoirs. Among them, Valko’s Stretch Exponential Production Decline (SEPD) and Duong’s Rate Decline for Fractured Dominated Reservoir are two most mentioned methods by industry experts. These two methods are claimed to be accurate in both tight and shale gas wells. However, since the reservoir rock permeability in those reservoirs ranges from 0.1 to 0.0001 mD in tight gas to less than 0.0001 mD in shale gas, are these two empirical methods still applicable in all ranges of permeability?

This paper presents the results of an evaluation study by applying these two empirical methods to tight and shale gas wells under a wide range of permeability generated based on both actual and synthetic production data. The key findings and recommended improvements resulted from the study are: Both SEPD and Duong’s Rate-Decline Methods are not applicable to tight gas reservoirs with a permeability ranging from 0.1 to 0.001mD. Duong’s Rate Decline Method will significantly over-estimate EUR whereas SEPD will most likely mismatch the production history as well as yielding a lower EUR while using its Recovery Potential Curve to find parameters.A Modified SEPD Method (YM-SEPD) developed by the author is a much easier and versatile method to use, and most importantly it will yield a more reliable production forecast and EUR estimation.With respect to reservoirs with rock permeability less than 0.01mD, a more rigorous step-by-step work flow using Duong’s Method has been proposed. Moreover, for tight gas reservoirs Duong’s Method can only be used for production forecast during early years, prior to pseudo-steady state (PSS) flow.Hundreds of horizontal wells including both oil and gas wells, from various formations (Cadomin, Montney, Notikewin, Cardium, etc. in Canada) and under different hydraulic fracturing conditions, have been analyzed using these three different methods. Results indicate that the new YM-SEPD Method will yield a more reliable EUR as well as production forecast in comparison with other two methods, especially when there is only less than 2~3 years of production history.For wells having less than 2 years of production history, the YM-SEPD Method will also be able to yield a reasonable prediction by coupling with Duong’s Decline Method
Effects of Thermally-Induced Secondary Cracks on Hydraulic Fracture Geometry
Authors: Tran David , Settari Antonin , Nghiem Long
Published: November 2013

The aim of this paper is to investigate the fracture aperture behavior when secondary cracks occur on the main fracture surface. This phenomenon has not been analyzed in the literature. The investigation shows that the aperture profile of a hydraulic fracture with secondary cracks is no longer a smooth elliptical shape as it used to be when there is no secondary crack, but an irregular shape containing discontinuities (also called jumps). The jump keeps on growing with time when the secondary crack propagates into the formation. The investigation also reveals that the aperture profile of the hydraulic fracture with secondary cracks can be larger or smaller than the one without secondary cracks depending primarily on following factors: permeable (leakoff) or non-permeable (no leakoff) media, locations of secondary cracks and pressurization on the secondary crack surfaces. With the existence of secondary cracks, the location of the maximum fracture aperture is no longer at the centre of the fracture. The study has led to two main conclusions: (i) The effects of secondary cracks on the hydraulic fracture geometry emphasize the important role of geomechanics when simulating a hydraulic fracturing problem. Without considering geomechanics, the jumps in the aperture profile can never been seen; (ii) Abnormal changes in the profile of the main hydraulic fracture with secondary cracks can strongly influence the fracturing stimulation process.
Integration of Nonempirical Shale Permeability Model in a Dual-Continuum Reservoir Simulator
Authors: Singh Harpreet , Azom Prince N.
Published: November 2013

Physics of fluid flow in shale reservoirs cannot be predicted from standard flow and mass transfer models due to presence of nanopores (1-100s of nanometer) in shales. Recently, few models have been developed to account for Slip-flow and Knudsen diffusion due to nanopores in apparent permeability. The limitation with all of these models is that they employ use of some form of empirical coefficient and its value form the basis of accuracy of their models. Additionally, to date, there is no reliable empirical data available for shales due to complexity of the system, i.e., different organic materials and mineral types as well as different gas components in gas shales.

In this paper a new analytical model for permeability of an ultra-tight porous media, consisting of tortuous micro/nano-pores, which is free of any empirical coefficients is incorporated in a dual-continuum reservoir simulator. We use an implicit compositional single phase dual-continuum reservoir simulator capable of modeling gas recovery from naturally fractured, or fissure rich hydraulically fractured, tight to ultra-tight reservoir.

A field scale case study is used to validate the accuracy of the nonempirical permeability model by comparing our predicted results with the results reported by other empirical models. The simulation results obtained with nonempirical permeability model closely match the simulation results reported by other authors with their case study. The nonempirical model shows that the pore-surface roughness and mineralogy has negligible influence on gas flow rate in the complete range of reservoir operating conditions. Finally, apparent permeability for ultratight reservoir (r < 100 nm) is a dynamic parameter and should be adjusted with other reservoir conditions, specifically, reservoir pressure. The model is valid throughout the operating conditions of a reservoir i.e. from the beginning of production until the limit of economic production.
Modeling and Prediction of Cone Rotary Speed of Roller Cone Bits
Authors: Wu A. , Hareland G. , Lei L. , Lin Y. , Yang Y.
Published: November 2013

In this paper, moment of momentum theorem is introduced and used to model the ratio of the rotary speed of cone to the bit. The ratio model has been integrated in a ROP simulator and the simulator can predict the ratio of both tricone and monocone bits. A series of tests measuring the ratio of a 517 IADC roller cone bit has been done. These tests were done with three types of rocks, different weight on bit (WOB) and revolution per minute (RPM). Comparisons between the predictions with the simulator and experimental results are carried out. It shows that the prediction accuracy of the tricone bit is close to 90% and that there is also a good prediction accuracy to the ratio of a monocone bit. The modeling of the ratio of rotary speed of the cone to the bit has improved the accuracy of the ROP simulator, which plays an important role in drilling optimization. Integration of the cone ratio into the modeling increases the overall bit design capabilities to a higher level by using simulators for drill bit performance analysis.
Multi-Porosity Simulation of Unconventional Reservoirs
Authors: Hinkley Richard , Gu Zhiqiang , Wong Terry , Camilleri Dominic
Published: November 2013

Today, most unconventional reservoir simulations are performed within a single-porosity framework. Very fine, high permeability gridblocks are used to represent the discrete fractures. Geometric spacing of blocks away from the fractures is necessary to capture the pressure gradients and simultaneously keep the number of gridblocks manageable. Without further subgridding the effects of desorption, diffusion, and transport through macro- and micro- fractures must be lumped resulting in a possible loss of transient fidelity. Yet these processes readily lend themselves to analysis with additional porosity types where the transport sequence can be preserved and studied. In this paper, we use a full production simulator to explore the advantages and disadvantages of simulating unconventional reservoirs with one-, two-, three-, and four-porosity systems. Kerogen, macro-fractures, micro-fractures, and an inorganic matrix are represented directly in the four-porosity system.
Smart-Engineered Ball Seat System to Optimize Flow Area in Multi-Zone Fracturing Treatments
Authors: Carrejo Nick , Wibowo Hendra , Espinoza Omar R , Gaudette Sean L
Published: November 2013

Conventional hydrocarbon reservoirs are being depleted, and the demand for energy grows as the world’s population progresses. Unconventional reservoirs are playing an increasingly important role in today’s effort to meet these growing demands. Two common forms of unconventional resources are the extraction of heavy oil or oil sands and the hydraulic fracturing of tight, hydrocarbon-bearing shale. Hydraulic fracturing is a technique made popular by the results yielded in the Barnett Shale basin in 1998. Of these two, hydraulic fracturing is more commonly used due to production economics. Over the last 15 years a significant effort has been made to increase the efficiency of this process. A common method of hydraulic fracturing is using a tripping ball and ball seat system. This system leads to a reduction in flow area. In addition, tripping balls can produce significant production risks. The production risks include lost production time if a stuck ball requires the well to be worked over. Lost flow area can be detrimental if the tripping ball remains in the lateral. A new smart-engineered composite has been developed to significantly optimize this process and provide flow assurance after the hydraulic fracture treatment. High-strength corrodible material (HSCM) is a metallic composite. HSCM is designed for the ball-actuated system used during hydraulic fracturing. This paper will explore the development and reliability of this new technology, and discuss development of a new interventionless ball seat system.
Shale Failure around Hydraulic Fractures in Water Fracturing of Gas Shale
Authors: Ji Lujun , Geehan Thomas
Published: November 2013

Even though shale has traditionally been considered a hydrocarbon source rock and/or seal rock, some gas bearing shales have been recognized as major reservoir rocks for unconventional hydrocarbon resources. The exploitation of gas shale across North America has generated much activity in the drilling and completion sector of the oil and gas industry, including drilling horizontal wells and multi-stage fracturing with water-based fracturing fluids. During water fracturing, the shale will interact with water and create consequences (hydration, dehydration, fractures etc.) as that happens in drilling. The consequences from this shale/water interaction will not only alter the shale mechanical properties, but also induce stress changes in the shale. These changes may induce favorable or unfavorable fractures in the shale/water interacted zones.

This paper first outlines lab observations of the shale/water interactions which generating fractures in gas shale. Then, a stress model is developed with poro-elasticity effect and simulation method for studying stress changes due to shale hydration in near-fracture zones. This paper also describes a sample application of the models to investigate stress changes and potential shale failures in shale around major hydraulic fractures in shale gas.

The study presented in this paper that it was mechanically possible to induce multiple secondary fractures around major hydraulic fractures via shale hydration. The modeling in this paper completes the preliminary study and provides a foundation for more complex scenarios in future studies focusing on water fracturing and horizontal well drilling in gas shale. It also provides some new ideas of optimizing hydraulic fracturing in gas shale.
Understanding Flowback as a Transient 2-Phase Displacement Process: An Extension of the Linear Dual-Porosity Model
Authors: Ezulike D. O. , Dehghanpour H. , Hawkes R. V.
Published: November 2013

Existing rate transient models for fractured horizontal wells assume single-phase fluid flow. This assumption is violated in early times, when hydraulic fractures (HF) are filled with fracturing water and hydrocarbon. This calls for a model that captures the transient 2-phase (gas/oil + water) flow in HF, and can be used for history matching rate and pressure data measured during flowback operations. Existing models for analysing multiphase data from solution-gas drive and high-water-saturation conventional reservoirs cannot be applied to flowback data because of simplifying assumptions such as (1) constant average phase saturation with time, (2) constant rate or pressure well constraint and (3) radial flow. This paper extends the existing linear dual-porosity model (DPM) and develops a flowback analysis model (FAM) which accounts for transient multiphase flow in HF.

The proposed model adopts an explicit dynamic-relative-permeability (DRP) function of time for hydrocarbon phase in the fracture network to account for water-saturation drop. This model assumes that water-saturation drop with time causes a corresponding non-linear increase in hydrocarbon relative-permeability in HF. The DRP function is obtained from analysing cumulative hydrocarbon + water measured during flowback operation and drainage relative-permeability curves from existing literature. Fifteen tight oil, tight gas and shale gas wells completed in the Bluesky, Cardium, Evie, Muskwa and Otter-Park Formations were used for this study. The resulting DRP parameters control the rate of water-saturation drop in HF (clean-up rate). DRP is incorporated into the existing DPM to obtain FAM flow equations. This paper attempt solving these equations with Mellin transforms under variable bottom-hole rate and pressure well constraints.

FAM converges to the existing DPM at the limit of residual water-saturation. DRP captures the fluid physics from flowback phase till the "full" hydrocarbon production phase in the life of a multifractured horizontal well. The application of FAM on transient 2-phase flowback data (rate + pressure) could help estimate key reservoir parameters (e.g. effective HF half-length) and evaluate flowback performance (e.g. percentage of total inject fluid left in HF and matrix and the speed of HF clean-up). Results from this study is applicable for interpreting 2-phase flowback data from multi- fractured horizontal wells completed in tight and shale reservoirs. This study allows the industry to forecast hydrocarbon recovery from flowback data and estimate/predict the effectiveness of flowback operations.
Flowback Volumetric and Chemical Analysis for Evaluating Load Recovery and Its Impact on Early-Time Production
Authors: Ghanbari Ebrahim , Abbasi Majid Ali , Dehghanpour Hassan , Bearinger Doug
Published: November 2013

Field studies demonstrate low flowback efficiency determined by volumetric analysis of injected and recovered fracturing water. However, the reasons for inefficient water recovery, and its impact on short-term and long term production are poorly understood. Furthermore, volumetric water analysis is not sufficient for determining the source of recovered water and the true load recovery. This paper aims at understanding how flowback efficiency is related to the imbibition process, presence or absence of natural fractures, and the complexity of induced fracture network.

We interpret the flowback rate and salt concentration, measured from several multi-fractured horizontal wells recently completed in different members of the Horn River basin. We also measure and analyze water imbibition and salt diffusion rate in actual cores drilled from the same shale members. The wells are classified into those with 1) low water and high gas production, 2) high water and low gas production. This classification is explained by lab imbibition data and possible fracture patterns. Furthermore, the flowback salt concentration change is explained by the diffusion data measured in the laboratory. This systematic study provides a practical database for understanding the factors impacting the water recovery that will potentially help the operators to optimize the flowback operations, and obtain useful information about the induced fracture network.
Stable Fracturing Fluids from Waste Water
Authors: Kakadjian Sarkis , Thompson Joseph , Torres Robert , Trabelsi Siwar , Zamora Frank
Published: November 2013

Environmental concerns and public opinion have elevated the visibility of hydraulic fracturing. Currently oil companies and operators acquire fresh water for fracturing treatments on the front end and pay to dispose or transport the flowback or produced water on the back end, increasing dramatically the cost of the hydraulic fracturing job. We report a newly developed fracturing fluid system utilizing 100% untreated produced water which eliminates the upfront costs of purchasing fresh water. In addition, the back end costs are significantly reduced by transporting produced and/or flowback water to locations for re-use rather than to disposal well(s) located miles away or even in other states.

This new system uses conventional gelling agents and crosslinkers used in active US shale plays, addressing the fracturing focus initiative.

This new fluid system was developed for temperature ranges between 120-300+ °F. Field tests prove shear stability and good proppant transport at 20 BPM through a 1.25 in sliding sleeve baffle. The fracturing fluid system can be designed for instant or delayed crosslinking in recycle water with total dissolved solids exceeding 300,000 mg/L with hardness exceeding 30,000 mg/L. Another concern in the past was the presence of boron in produced water. This system can be used in water containing boron levels exceeding 500 mg/L.

The code for recycle water has been broken utilizing this unique fracturing fluid system designed to conserve fresh water aquifers and recycle produced and flowback waters, reducing significantly disposal costs.

This paper reports laboratory testing of the fluid characteristics in untreated produced water from the Bakken as well as the outcome of hybrid fluids in field applications, recommendations for field applications and economic impacts on fracturing fluid systems.
Study on Gas Permeability in Nano Pores of Shale Gas Reservoirs
Authors: Guo Chaohua , Bai Baojun , Wei Mingzhen , He Xiaoming , Wu Yu-Shu
Published: November 2013

Producing gas from shale gas reservoirs has played an increasingly important role in the volatile energy industry over recent years in North America for considerable volume of natural gas stored in the reservoirs. Unlike conventional gas reservoirs, the gas flow in shale reservoirs is a complex multi-scale flow process and has special flow mechanisms. Most importantly, the shale gas reservoir contains a large portion of nano pores. The study of flow in nano pores is essential for accurate shale gas numerical simulation. However, there is still not a comprehensive study in understanding how gas flows in nano pores.

In this paper, based on the advection-diffusion model, we constructed a new mathematical model to characterize gas flow in nano pores. We derived a new apparent permeability expression based on advection and Knudsen diffusion. Acomprehensive coefficient in characterizing the flow process was proposed. Simulation results were verified against the experimental data for gas flow through nano membranes. By changing the comprehensive coefficient, we found the best candidate for the case of Argon with membrane pore diameter 235 nm. We verified the model using different gases (Oxygen, Argon) and different pore diameters (235 nm, 220 nm). The comparison shows that the new model matches the experimental data very closely. Additionally, we compared our results with experimental data, Knudsen/Hagen-Poiseuille analytical solution, and existing researcher’s work. The results show that this study yielded a more reliable solution. For shale gas simulation where gas flowing in nano pores plays a critical role, the results from this work will made the simulation more accurate and reliable.
Analytical Modeling for Geomechanical Changes in Multi-Frac Completions
Authors: Stalgorova E. , Mattar L.
Published: November 2013

There are a number of analytical solutions describing fluid flow through multi-frac horizontal wells presented in literature. This paper presents a way to extend the existing analytical solutions for multi-frac wells to the cases when completion properties (such as fracture conductivity and fracture length) are varying with pressure, and thus with time.

The paper provides a derivation of the suggested method; it uses the formulation of analytical solution of the diffusivity equation based on Green’s function. However it is demonstrated that the same methodology can also be applied to analytical solutions obtained without using Green’s function.

It is believed that in tight formations, production at high drawdown often results in an increased effective stress around the hydraulic fracture system (e.g. Okouma et al. 2011). Higher effective stress causes a decrease in conductivity and/or effective length of hydraulic fractures. Being able to model such a variation of fracture properties with pressure is essential for accurate history matching and production forecasting.

The suggested methodology was validated by comparing the derived solutions against numerical simulation. We found that results obtained by using the suggested methodology and numerical results are in good agreement for single phase fluid and single plane fractures; therefore the suggested method can be applied to analytical models for pressure-dependent multi-frac completions for such cases.

The proposed methodology allows extending available analytical solutions for multi-frac systems in a way that captures the variation of fracture properties with pressure.
First Field Application in Canada of Carbon Dioxide Separation for Hydraulic Fracture Flow Back Operations
Authors: Reynolds M. M. , Ku R. Y. , Vertz J. B. , Stashko Z. D.
Published: November 2013

Carbon dioxide has a long history of successful usage in hydraulic fracturing fluids, dating as far back as 1962. The Canadian Deep Basin area is known to contain many water desiccated natural gas reservoirs which are very amenable to carbon dioxide based stimulation. Another major advantage of carbon dioxide use is to displace fresh water, reducing environmental impacts.

However, in recent years, some operators have moved away from carbon dioxide, due to difficulties related to the contaminated gas stream during fracture flow back operations. An extended period of flaring may be required to reduce the carbon dioxide content to acceptable levels in the sales pipeline. This may contribute to longer periods of flaring, noise and light pollution, increased green house gas emissions, as well as lost revenue to the operator, as otherwise saleable natural gas and gas liquids are being flared.

This paper will outline the development of portable trailer mounted membrane separation equipment for well site separation of carbon dioxide from natural gas. The equipment used and how the process works will be discussed.

Included is documented information from what is believed to be the first successful deployment of this equipment in Canada, on a well site near Grande Prairie, AB. Process information on flow rates, pressures, carbon dioxide inlet and sales content, etc. will be included.

The development of this equipment has many benefits, including reduced flaring, increased sales volumes for the operator, increased royalties for governments, etc. Operators may now take advantage of the reservoir enhancing benefits of carbon dioxide, without any of the negative flow back issues.

In conclusion, we will discuss future research and developments that will reduce or eliminate carbon dioxide venting at the well site.
Highly Reactive Fly Ash Material Improves Economics of Lightweight Cementing with Lower Carbon Footprint
Authors: Jangid Gajendra K , Marjason Stephen R
Published: November 2013

Fly Ash is a light weight residue from coal fired power plants. Blends of Portland cement and Fly Ash are widely used in construction and oilfield industry. The addition of Fly Ash in cement slurries improves compressive strength, sulphate resistance, reduces cement permeability (Golapudi U et al, 1993) and allows lower density slurries while maintaining good mechanical properties (Purvis et al, 2003).

Fly ash is a cheaper, readily available by product. It brings down overall cost by reducing cement consumption. This also helps the environment as every ton of cement produce generates an average of 0.9 ton of CO2. Historically, increasing the Fly Ash ratio above 50% has resulted in significant reduction in its benefits (Purvis et al, 2003) in terms of cement mechanical properties degradation, and especially the compressive strength development at short duration.

A new Highly Reactive-Fly Ash Material (HR-FAM) was developed for higher ratios of Fly Ash in a cement blend. This paper will study and discuss the use of HR-FAM in oil well cementing applications. To prepare lightweight cement systems, various ratios of HR-FAM are blended with neat API Class H cement. All laboratory tests were carried out according to API RP 10B-2 practices for oil well cement. Results were compared against conventional Fly Ash based cement systems. The laboratory test results show that HR-FAM based blends provide better mechanical properties than regular Fly Ash in terms of compressive strength development.

The use of HR-FAM in Portland cement allows slurry designs at lower densities with mechanical properties meeting regulatory requirements. Additionally, it also reduces the consumption of Portland cement up to 33% compared to regular Fly Ash based systems currently used in the oilfield.
The Impact of Well Trajectory on Horn River Shale Gas Well Production in a Multi-Well Pad: A New Approach Using Steady State and Transient Simulation
Authors: Becze A. , Nascimento C. M. , Jackson D. F. , Virués C. J. , Wang A.
Published: November 2013

Shale well production performance is influenced by an array of factors including reservoir quality, wellbore trajectory, well completion, and operating conditions and fluid behavior. Simulation in combination with field measurements offers insights into understanding the interplay between these factors and helps to understand how they impact well performance and, more importantly, how they can enhance well design. This paper focuses on an analysis of the relationship between well trajectory and production performance for three horizontal shale gas wells in the Horn River. It presents liquid holdup data obtained through downhole camera and production logging and compares these with results from integrated modeling and transient simulation technologies. It is important to minimize liquid holdup in the case of shale gas wells as holdup contributes to instabilities and can also plug off contributing stages if those stages are flooded with liquids. Recommendations on horizontal shale well design are presented.
A Practical Guide to Unconventional Petroleum Evaluation Part 2
Authors: Russell Boyd , Freeborn Randy
Published: November 2013

When it comes to decline analysis, very little has changed since Arps’ "Analysis of Decline Curve" paper published in 1945. An evaluator tries to visually match a production profile with either an exponential, harmonic or hyperbolic equation. Certainly, French Curves have been replaced by computers that quickly reflect our best guess, but for hyperbolic wells where the profile cannot be represented by a straight line it’s still a guess, granted it’s an educated guess based on experience. This paper will propose that in many instances, automatic forecasting, using an accurate tool, can replace manual forecasting.

A common problem faced by all evaluators is how to forecast new wells with little production history. In this paper, an analog forecasting method is proposed that yields excellent results both in predicting budget volumes and matching future production profiles. This method will be demonstrated using back casting studies on real world examples.

In SPE 147059, Haskett indicated that the production forecast represented sixty seven percent of the NPV uncertainty in resource play development. Type wells are the primary technique used to generate production forecasts for these new wells. Hence you would expect the oil and gas industry to devote significant research on this topic. When the authors performed a search on SPE One Petro® and Google® for papers about type wells, they only found their two previous papers (SPE 158867 and SPE 162630). In an informal survey of the industry, the authors found that the time slice method of creating type wells was widely accepted. In SPE 158867, Russell et al recommended that the selected well method of creating percentile type wells was preferred over the time slice method. Further research, presented in this paper recommends that the time slice method should be avoided.
Simulation of Proppant Distribution Effect on Well Performance in Shale Gas Reservoirs
Authors: Yu Wei , Sepehrnoori Kamy
Published: November 2013

The economic viability of shale gas development hinges on uniform proppant distribution and sustaining sufficient fracture conductivity in hydraulic fractures over the lifetime of a well; however, it is very challenging to simultaneously maintain uniform proppant distribution and such conductivity due to proppant settlement, proppant embedment and proppant crushing in shale reservoirs, especially in soft shale formations. It has been reported that the proppant concentration is heavily weighted toward the end clusters, while the initial clusters receiving much less proppant in the same stage. In addition, proppant will settle rapidly in slickwater fracture treatments, forming a proppant bank at the bottom of the fracture, which results in uneven proppant distribution along the fracture height. The effects of the above proppant distribution along with stress-dependent fracture conductivity on ultimate gas recovery are not clearly understood and systematically studied, and have been largely neglected by most fracture modeling work in the literature. Therefore, it is absolutely critical to develop a reservoir-modeling approach that properly examines the relationships between proppant distribution, stress-dependent fracture conductivity and well performance for shale gas reservoirs.

In this paper, numerical reservoir simulation techniques, validated by field production data from Marcellus Shale, are employed to model the proppant distribution and geomechanics effect. A series of reservoir simulations was performed to quantify the impact of uneven proppant distribution between different clusters in the same stage on well performance. The fracture conductivity ratio of 1:1.5:2.5:4 for four clusters within one stage was investigated in this study. The simulations evaluate a range of reservoir permeability from 0.00001 to 0.0001 md. Gas desorption effect is also taken into account. This work enables operators to develop an early understanding of the effects of proppant distribution and geomechanics on shale gas well productivity, and provides insights into fracture conductivity requirements in shale gas reservoirs that can be used to improve hydraulic fracturing treatment design through improved proppant distribution.
Numerical Modeling of Multilateral Junction Stability in the Montney Shale Play
Authors: Li Qiuguo , Hussein Assef Mohamad , Bakhtiari Siamak , Newman Robert , Khosravi Nader , Teichrob Bob
Published: November 2013

While drilling and completing multilateral wells in unconventional shale plays, a major concern is the stability of the junction. If the junction area is to remain open while producing, the stability of the junction is essential until the end of the well life. Due to the complex geometry of the junction, numerical simulations are typically required to understand the stress concentrations and simulate the stability of the junction.

A dual-lateral well was to be drilled and completed in the Montney shale play in Alberta, with the two laterals targeting Middle and Lower Montney, respectively. With the Technical Advancement of Multilaterals (TAML) Level 2 multilateral completion, one lateral would be cased and the other would remain open. Because relatively large drawdown pressures were planned for the well, understanding of the junction stability became an important consideration not only while drilling the lateral, but also while the well was producing.

This paper will present a geomechanical analysis of the multilateral junction stability under two drawdown-pressure conditions, including determination of the mechanical properties and in-situ stresses, numerical simulation of the stress concentrations, and rock deformations at the junction.
Groundwater Considerations of Shale Gas Developments Using Hydraulic Fracturing: Examples, Additional Study and Social Responsibility
Authors: Uwiera-Gartner Michelle
Published: November 2013

Since the mid-1900s, hydraulic fracturing has been used to improve well productivity and gain access to additional resources. For more than a decade, hydraulic fracturing in North America has resulted in the development of significant natural gas resources that would have otherwise been inaccessible.

Recent advances in hydraulic fracturing methods and its access to shale gas resources have prompted public concern about the environmental impacts of using this technology. Concerns about fracking out of the pay zone, the upward migration of methane gas, and contamination of water resources from deeper formation waters, flowback and produced waters, and fracturing fluids are documented. These affect a corporation’s social license to develop unconventional resources.

This manuscript summarizes the potential sources for increased risk to water resources resulting from hydraulic fracturing of shale gas developments. Also provided is a description of some of the hydraulic fracturing operations of natural gas plays that have or believed to have impacted groundwater resources in Western Canada.

A literature review about the groundwater flow systems at the shale gas, unconventional resource plays in Northeast British Columbia is provided. Also summarized is some of the water management strategies used and/or are proposed for shale gas development.

A discussion of social responsibility for exploiting shale gas using hydraulic fracturing is provided. The author indicates that results from continued and additional hydrogeologic investigations should be disclosed in a timely manner as this affects the perception of industry transparency, and can assist with maintaining a social license for resource development.
Uncertainty Analysis of Shale Gas Simulation: Consideration of Basic Petrophysical Properties
Authors: Wu Peng , Aguilera Roberto
Published: November 2013

Uncertainties in basic petrophysical parameters in shale gas reservoirs are discussed in this paper. These parameters include porosity, permeability, gas adsorption, water saturation and TOC. Current available methods to evaluate shale gas petrophysical properties are summarized. These methods include core laboratory measurements and well logs. Sources of uncertainty in these measurements are discussed.

Uncertainty analysis using commercial simulation software was performed to understand how these uncertainties influence reservoir simulation results and predictions. Sensitivity and uncertainty studies in this paper are based on typical ranges of shale gas properties extracted from published evaluation reports or open data. Results from this study will help guide the focus of future research and technology development for shale gas reservoirs.
Assessment of Eagle Ford Shale Oil and Gas Resources
Authors: Gong Xinglai , Tian Yao , McVay Duane A. , Ayers Walter B. , Lee W. John
Published: November 2013

The Eagle Ford play in south Texas is currently one of the hottest plays in the United States. In 2012, the average Eagle Ford rig count (269 rigs) was 15% of the total US rig count. Assessment of Eagle Ford oil and gas resources and their associated uncertainties in the early stages is critical for optimal development. The objective of our research was to assess Eagle Ford shale oil and gas reserves, contingent resources, and prospective resources.

Probabilistic decline curves using Markov Chain Monte Carlo (MCMC) were used to forecast reserves and resources. The Eagle Ford play from the Sligo Shelf Margin to the San Marcos Arch was divided into 8 different production regions based on geology, fluid type, and well performance. We used the Duong model switching to the Arps model with b = 0.3 at the minimum decline rate to model the linear flow to boundary-dominated flow behavior often observed in shale plays. Cumulative production after 20 years predicted from Monte Carlo simulation combined with reservoir simulation was used as prior information in the Bayesian decline-curve methodology. Probabilistic type decline curves for oil and gas were then generated for all production regions. Individual-well reserves and resources estimates were aggregated probabilistically within each production region and arithmetically between production regions.

The total oil reserves and resources range from a P90 of 5.3 to P10 of 28.7 billion barrels of oil (BBO), with a P50 of 11.7 BBO; the total gas reserves and resources range from a P90 of 53.4 to P10 of 313.5 trillion cubic feet (TCF), with a P50 of 121.7 TCF. These reserves and resources estimates are much higher than the U.S. Energy Information Administration’s 2011 recoverable resource estimates of 3.35 BBO and 21 TCF. The results of this study provide a critical update of the reserves and resources estimates and their associated uncertainties for the Eagle Ford shale formation of South Texas.
Evaluation of Time-Rate Performance of Shale Wells using the Transient Hyperbolic Relation
Authors: Fulford D. S. , Blasingame T. A.
Published: November 2013

In this work we present the “Transient Hyperbolic” relation for the analysis and interpretation of time-rate performance data from wells in shale gas/liquids-rich shale plays. This model assumes a transient “b(t)” function which has constant early-time and constant late-time values, with an exponentially decaying transition function. This “b(t)” function is derived from the Gompertz logistic function.

Our goal in developing this formulation is to represent the early-time (or clean-up) portion of the production profile (often a hyperbolic function), the transition to the terminal hyperbolic behavior, and finally, the terminal hyperbolic behavior — where the terminal hyperbolic is usually representative of the “non-interfering” vertical fractures in a multi-fractured horizontal well (MFHW). We could further modify this relation to have a terminal exponential decline (thought to represent the performance of the stimulated-reservoir-volume (or SRV)), but that is not a primary purpose of this work — our primary purpose is to demonstrate the “Transient Hyperbolic” nature of the flow behavior from a multi-fractured horizontal well in a shale gas/liquids-rich shale play.

The technical contributions of this work are: Development of the “Transient Hyperbolic” time-rate relation — this relation includes an early AND a late-time hyperbolic behavior, as well as a logistic transition function.Application of the “Transient Hyperbolic” time-rate relation to modeling completion heterogeneity in a MFHW by a superposition of divisions that have differing durations of linear flow.Application of the “Transient Hyperbolic” time-rate relation to several field cases — specifically: tight gas, shale gas, and “liquids-rich” shale cases.