bluuebunny/crossref_metadata_2025 huggingface dataset:
The Architecture of Provider-Parent Vaccine Discussions at Health Supervision Visits
Authors: Opel Douglas J. , Heritage John , Taylor James A. , Mangione-Smith Rita , Salas Halle Showalter , DeVere Victoria , Zhou Chuan , Robinson Jeffrey D.
Published: November 2013

OBJECTIVE:

To characterize provider-parent vaccine communication and determine the influence of specific provider communication practices on parent resistance to vaccine recommendations.

METHODS:

We conducted a cross-sectional observational study in which we videotaped provider-parent vaccine discussions during health supervision visits. Parents of children aged 1 to 19 months old were screened by using the Parent Attitudes about Childhood Vaccines survey. We oversampled vaccine-hesitant parents (VHPs), defined as a score ≥50. We developed a coding scheme of 15 communication practices and applied it to all visits. We used multivariate logistic regression to explore the association between provider communication practices and parent resistance to vaccines, controlling for parental hesitancy status and demographic and visit characteristics.

RESULTS:

We analyzed 111 vaccine discussions involving 16 providers from 9 practices; 50% included VHPs. Most providers (74%) initiated vaccine recommendations with presumptive (eg, “Well, we have to do some shots”) rather than participatory (eg, “What do you want to do about shots?”) formats. Among parents who voiced resistance to provider initiation (41%), significantly more were VHPs than non-VHPs. Parents had significantly higher odds of resisting vaccine recommendations if the provider used a participatory rather than a presumptive initiation format (adjusted odds ratio: 17.5; 95% confidence interval: 1.2–253.5). When parents resisted, 50% of providers pursued their original recommendations (eg, “He really needs these shots”), and 47% of initially resistant parents subsequently accepted recommendations when they did.

CONCLUSIONS:

How providers initiate and pursue vaccine recommendations is associated with parental vaccine acceptance.
Investigation on microstructures of cementitious composites incorporating slag
Authors: Hu Chuanlin , Li Zongjin , Gao Yueyi , Han Yunge , Zhang Yamei
Published: November 2013

Cementitious composites incorporating slag were investigated by multiple techniques, including scanning electron microscopy with backscattered electron and energy-dispersive X-ray spectroscopy detectors, thermogravimetric analysis, instrumented nanoindentation and ultrasonic measurements. The physical and mechanical properties of individual phases in cementitious composites with and without slag at different water to binder ratios were studied and are reported here. Subsequently, based on the identified phase properties, the macroscopic elastic moduli were calculated through a micromechanical method and verified with the experimental data. The results of this study show that the physical and mechanical properties of hydration products in cementitious composites incorporating slag are quite different from those of pure cement pastes. To explain the differences and improve scientific understanding of the influence of slag on the properties of hydration products, the composition, microstructures and mechanical properties were linked together for cementitious composites incorporating slag through this study.
Durability of mortar with calcined marl as supplementary cementing material
Authors: Østnor Tone Anita , Justnes Harald
Published: November 2013

Calcined marl – ordinary ‘blue' clay containing calcium carbonate – is an effective pozzolan in cementitious materials in terms of strength if calcined at the correct temperature. Marl is unsuitable for the clay product industry, and might thus be the high-volume available alternative pozzolan globally that the cement and concrete industry is looking for in order to reduce its carbon footprint. Mortars are made where calcined marl replaces cement by volume at levels of 0, 20, 35, 50 and 65 vol.%. Excellent strengths at both 1 and 28 d relative to reference are obtained for up to 50 vol.% replacement, and the strength continues to increase up to 1 year. The capillary porosity volume increases along with the electrical resistivity, indicating a pore refinement or segmentation, as well as perhaps reduced ionic strength in the pore-water. These are properties that might reduce the propagation rate of rebar corrosion once initiated by carbonation, as carbonation rate increased with cement replacement. The chloride ingress is significantly reduced when cement is replaced by calcined marl. Sulfate resistance is also tested at both 5 and 20°C, but no significant changes are observed after 9 months' exposure.
Characterization of paddlefish (Polyodon spathula) rostrum stellate bones
Authors: Allison P. G. , Deang J. F. , Diaz A. J. , Poda A. R. , Hoover J. J. , Horstemeyer M. F. , Perkins E. J.
Published: November 2013

The electrosensory capabilities of the rostrum of the paddlefish (Polyodon spathula) were investigated previously. However, the structure–property relationship associated with the rostrum has yet to be explored. In this study, the stellate bone properties of the rostrum are examined as a function of spatial location on the rostrum using nanoindentation and Fourier transform infrared spectroscopy. Nanoindentation results indicated a constant elastic modulus along the middle section of the rostrum. However, the elastic modulus exhibited a gradient along the side of the rostrum, with the maximum modulus at the base of the rostrum. This study is part of an overall research project examining the electrosensory capabilities, hydrodynamics and structure–property relationships of the rostrum to develop new materials for force protection applications.
Traffic monitoring using a structural health monitoring system
Authors: Silva Ignacio Javier González , Karoumi Raid
Published: November 2013

The main factors influencing the deterioration of bridges are the environmental conditions and traffic loads. Therefore, a reliable and accurate characterisation of traffic loads can improve the results from bridge rating and health bridge monitoring. In this study a bridge weigh-in-motion algorithm is developed to monitor trains passing on a steel railway bridge. The implemented system estimates the traffic loads, speeds and axle spacings. Other valuable information such as peak and root mean square vertical bridge deck accelerations are also stored. The system takes advantage of two of the strain gauges from a previously deployed sensor network, installed mainly to monitor the strains for fatigue development. In this paper the possibilities and limitation of this system are explored.
Tracing the biosynthetic source of essential amino acids in marine turtles using δ13C fingerprints
Authors: Arthur Karen E. , Kelez Shaleyla , Larsen Thomas , Choy C. Anela , Popp Brian N.
Published: November 2013

Plants, bacteria, and fungi produce essential amino acids (EAAs) with distinctive patterns of δ13C values that can be used as naturally occurring fingerprints of biosynthetic origin of EAAs in a food web. Because animals cannot synthesize EAAs and must obtain them from food, their tissues reflect δ13CEAA patterns found in diet, but it is not known how microbes responsible for hindgut fermentation in some herbivores influence the δ13C values of EAAs in their hosts' tissues. We examined whether distinctive δ13C fingerprints of hindgut flora are evident in the tissues of green turtles (Chelonia mydas), which are known to be facultative hindgut fermenters. We determined δ13CEAA values in tissues of green turtles foraging herbivorously in neritic habitats of Hawaii and compared them with those from green, olive ridley, and loggerhead turtles foraging carnivorously in oceanic environments of the central and southeast Pacific Ocean. Results of multivariate statistical analysis revealed two distinct groups that could be distinguished based on unique δ13CEAA patterns. A three‐end‐member predictive linear discriminant model indicated that δ13CEAA fingerprints existed in the tissues of carnivorous turtles that resembled patterns found in microalgae, which form the base of an oceanic food web, whereas herbivorous turtles derive EAAs from a bacterial or seagrass source. This study demonstrates the capacity for δ13C fingerprinting to establish the biosynthetic origin of EAAs in higher consumers, and that marine turtles foraging on macroalgal diets appear to receive nutritional supplementation from bacterial symbionts in their digestive system.
Management of a Large Schneiderian Membrane Perforation and Repair of the Missing Maxillary Lateral Wall Using a Collagen Barrier Alone in a Patient With Human Immunodeficiency Virus/Acquired Immunodeficiency Syndrome
Authors: Vanderburg Nikko J. , Kolhatkar Shilpa , Bhola Monish
Published: November 2013

Introduction: Sinus floor augmentation (SFA) to aid in implant placement has been shown to be very predictable. A history of membrane perforation or intraoperative Schneiderian membrane perforation (SMP) is one of the most frequent complications of SFA. In this case report, the management of a large preexisting SMP with the aid of a collagen barrier in a patient with human immunodeficiency virus/acquired immunodeficiency syndrome is described.

Case Presentation: A 51‐year‐old male presented for retreatment of an endodontically treated maxillary molar (tooth #14). The endodontic consultation recommended extraction, which was performed by the patient's primary dentist. Two months later, a clinical and radiographic examination revealed significant vertical and bucco‐lingual bone loss in that area. Cone‐beam computed tomography (CBCT) indicated insufficient bone volume for implant placement and the absence of cortical bone with a homogeneous fibrous mass in the edentulous region. A lack of Schneiderian membrane continuity, most likely the result of the extraction, was suspected. A treatment plan of guided bone regeneration followed by implant placement was presented. The SMP was repaired using a collagen barrier alone, and postoperative healing was uneventful. One year later, a repeat CBCT scan revealed complete reformation of the buccal cortical plate and sinus floor with ≈6 mm of vertical bone gain. An implant was placed without complications 16 months after SMP repair.

Conclusions: This case report describes how a large preexisting SMP was repaired using a collagen barrier alone. Three‐dimensional bone regeneration was achieved without the use of bone grafts primarily because of the stability of the blood clot.
Characterizing Tight Oil Reservoirs Using Dual- and Triple-Porosity Models
Authors: Ezulike D. O. , Dehghanpour H.
Published: November 2013

The response of existing transient triple-porosity models for fractured horizontal wells do not converge to that of linear dual-porosity model (DPM) in the absence of micro-fractures (MF). The reason is the assumption of sequential-depletion from matrix to MF, and from MF to hydraulic-fractures (HF). This can result in unreasonable estimates of MF and/or HF parameters. Hence, the authors proposed a quadrilinear flow model (QFM) in a previous paper which relaxes the sequential-depletion assumption to allow simultaneous matrix–MF and matrix–HF depletion. Also, it is proved that QFM simplifies to both DPM and linear sequential triple-porosity model (STPM).

This work considers the implications of applying QFM, STPM and DPM type-curves and analysis equations on production data from tight reservoirs. QFM, STPM and DPM are applied to two fractured horizontal wells completed in Bakken and Cardium Formations. A comparative study of the reservoir parameters estimated from the application of these models to the same production data set reveals two key results. Firstly, the application of DPM on production data from reservoirs with active MF could result in overestimation of HF half-length. This happens to compensate for the extra fluid depletion pathways/communication-interface provided by MF. Secondly, the application of STPM on production data from reservoirs with active matrix–HF communication could result in underestimation and overestimation of MF spacing and number respectively.

Results from this study are significant when selecting the appropriate model for interpreting production data from fractured horizontal wells completed in formations with or without active MF. DPM is appropriate if analog studies (e.g. outcrop, micro-seismic and image log analyses) reveal high spacing aspect ratio (negligible MF) in the reservoir. Spacing aspect ratio is MF spacing divided by HF spacing. STPM is appropriate if analog studies reveal low spacing aspect ratio (e.g. matrix–HF face damage or high MF density within a given HF spacing). QFM is appropriate for all spacing aspect ratios.
The Critical Role of In-Situ Pressure on Natural Fracture Shear and Hydraulic Fracturing-Induced Microseismicity Generation
Authors: Zhang F. , Nagel N. , Sanchez-Nagel M. , Lee B. , Agharazi A.
Published: November 2013

In this work, the effect of in-situ pressure on natural fracture shear and hydraulic fracturing-induced microseismicity generation was evaluated using a discrete element model. Overall, the initial in-situ pressure was found to play a significant role in the ability to shear natural fractures during a hydraulic fracture stimulation, largely through a reduction in the effective stresses acting on the natural fractures. Simply, the greater the initial in-situ pressure relative to the in-situ principal stresses, the greater the shear on natural fractures for a given stimulation treatment. Shear slip events on natural fractures were divided into "wet" events and "dry" events to help understand the shear failure mechanism and the induced-microseismicity complexity during the hydraulic fracturing process. The results showed that the density and distribution area of the slip events were affected by a combination of multiple factors. Dry events were mainly affected by the total stress change or shear stress change and the initial strength of the natural fractures while the wet events were affected by the total stress change or shear stress change, the initial strength of the natural fractures and the fluid leakoff area. The stimulated reservoir volume (SRV), measured by the scope of the wet events or the shape of the leakoff area, was affected by the trace of the hydraulic fracture and the fracture network connectivity in the matrix. These results provide further understanding and ability to interpret the different microseismicity responses seen in the field, which, ultimately, will allow for improved optimization of stimulation and completion strategies.
Selection of Candidate Horizontal Wells and Determination of the Optimal Time of Refracturing in Barnett Shale (Johnson County)
Authors: Tavassoli Shayan , Yu Wei , Javadpour Farzam , Sepehrnoori Kamy
Published: November 2013

The observed uneconomic production performance in many shale gas horizontal wells suggests refracturing as a restimulation treatment to revive economic gas production. To achieve high-performance re-stimulation, it is critical to select the right well among many other wells in the area and determine the proper time of refracturing. Well selection is challenging in shale gas horizontal wells because of the complexity of natural and induced fracture networks and in many cases due to insufficient reservoir and completion data. Selection of the candidate well and the time of refracturing can be made based on a thorough numerical simulation study developed by precise modeling of hydraulic fractures and refracturing process. Accurate modeling can only be accomplished by considering formation of fracture networks. Induced fracture networks are formed by an altered stress-field as a consequence of the fracturing process and are evidenced by micro-seismic hydraulic fracture monitoring techniques. Tavassoli et al. (2013) modeled gas production of a refractured well in the Barnett formation and validated their simulation methodology with the available field data. The validated model was used to predict gas production after refracturing the well. They then performed systematic sensitivity analyses to specify the characteristics of shale gas horizontal well suitable for refracturing and defined well screening criteria and optimal time of refracturing. In this study we extended their original work to study 188 horizontal wells in Barnett (Johnson County) to identify wells with potentials for refracturing. We found that among these 188 wells only 11 wells are suitable for refracturing and the best time to perform hydraulic fracturing is between 3½ to 5½ years after initial production.
Bottomhole Assembly Result Analysis to Improve Drilling Performance in Pinedale Field, Wyoming, USA
Authors: Han Guangzhi , Lemesany Lane , Azizov Azar A. , DeLeon Frank
Published: November 2013

The giant Pinedale gas field, which is approximately 35 miles long and 6 miles wide, is the largest structural feature in the northern Green River Basin of Wyoming, with conservative estimates of in-place natural gas at 159 Tcf. The Pinedale field ranks as the third-largest gas field in the United States by proved reserves. Gas production is primarily from a 5,500 ft-thick "Lance Pool" on top of the Ericson Sandstone. The pay zone consists of Upper Cretaceous sandstones of the Lance Formation, the Upper Mesaverde Group, and a Paleocene "unnamed" unit. The reservoir is classified as tight gas due to its low porosity and micro-Darcy permeability. The lenticular sands and stratigraphic nature of this area make horizontal drilling impractical, and deviated well drilling is prevalent.

By 2010, the average drilling time was reduced to 15 days by application of automated vertical-seeking tools with limited availability and poor cost effectiveness. Design and reliability improvements to various downhole tools have further reduced the average drilling time to 12.8 days with a conventional adjustable kick-off sub (AKO) mud motor by 2012. However, due to the various downhole tools involved, a bottomhole assembly (BHA) result analysis is a key step to evaluate the effectiveness of each tool, improve BHA design, identify superior drilling strategy, and eventually optimize the overall drilling performance.

Several field cases are presented in this paper to conduct BHA result analysis, and several suggestions are promoted for future operations. These suggestions can reduce bit trip, improve oriented drilling efficiency, increase rotation rate of penetration (ROP) and save substantial financial resources for customers. The valuable information and lessons learned are crucial for Pinedale drilling operations, and they may be readily applied in other tight gas fields with similar characteristics to optimize drilling performance.
Optimizing Well Completions in the Canadian Bakken: Case History of Different Techniques to Achieve Full ID Wellbores
Authors: Alvarez Domingo , Joseph Arun , Gulewicz Dale
Published: November 2013

The development of the Bakken formation has seen a rapid growth in the last ten years thanks to the improvement of horizontal drilling and multistage stimulation techniques. The Canadian Bakken is located in the SE corner of the Province of Saskatchewan. This formation is a Dolomitic Siltstone reservoir that is shallower (1400 to 1700 m TVD) and thinner (4 to 12 m thick) than its counterpart on the US side; adding some challenges to its exploitation. Moreover, it has an overlying water bearing zone (Lodgepole limestone formation) that can dramatically increase the water cut percentage during production if communication occurs during the fracturing process. For this reason, fracture stimulations are typically done at low rates and low sand tonnages and concentrations.

One operator’s focus to date has been to complete the wells using ball drop systems and open hole packers, leaving the balls and ball seats in the wellbore and milling them out later based on well-by-well analysis. This approach does not allow further workover operations or refrac opportunities without removing the restrictions. Production performance dictates the decision of when to mill out the ball seats; however it has several drawbacks like additional cost, loss of production during the operation, longer operation time and excessive fluid losses.

Cost effective and technically sound alternatives to provide full inner diameter (ID) wellbores during initial operations were investigated and a variety of those methods were implemented in the field. The selections included: retrievable frac seat assembly, coiled tubing half straddle frac tool with sliding sleeve ports and milling out conventional frac ports during the initial completions. All of the completions were executed with open hole packers similar to the previous approach. This paper describes and summarizes the observations and lessons from the application of these methods, as well as the modifications to the fracturing fluid systems based on field application. Also, a comparison of all techniques implemented, including time, cost and production, along with this operator’s assessment for future development in the area are presented.
Prior Information Enhances Uncertainty Quantification in Shale Gas Decline Curve Forecasts
Authors: Gonzalez Raul , Gong Xinglai , McVay Duane A.
Published: November 2013

Probabilistic decline curve analysis (PDCA) methods have recently been developed to quantify uncertainty in production forecasts for hydraulically fractured horizontal shale gas wells. The Markov Chain Monte Carlo (MCMC) method has been proposed as a fast and reliable probabilistic method to quantify uncertainty regardless of the decline curve analysis model employed and the amount of production data available for forecasting. In this paper, we integrate other sources of information with PDCA in a Bayesian framework to enhance the reliability of production forecasts for hydraulically fractured horizontal shale gas wells.

Hindcasts using the logistic-growth-curve model coupled to MCMC and two different sources of prior information were performed to assess the reliability of the improved PDCA method. In a hindcast, only a portion of the historical data is matched; predictions are made for the remainder of the historical period and compared to the actual historical production. The logistic-growth-curve model was moderately well calibrated when used with the MCMC probabilistic method and a non-informative prior, regardless of the amount of production data available to match. When EUR distributions from other sources of information were provided as an informative prior, accuracy and calibration of the probabilistic production forecasts were further enhanced. The use of informative prior distributions improves calibration particularly when little production data are available.

The combination of the MCMC method, the logistic-growth DCA model, and use of prior EUR distributions provides an integrated procedure to reliably quantify the uncertainty in production forecasts in shale gas reservoirs. Reliable quantification of uncertainty should yield more reliable expected values of reserves estimates. This can be particularly valuable early in the development of a play, because decisions regarding continued development are based to a large degree on production forecasts for early wells in the play.
A Well Performance Model Based on Multivariate Analysis of Completion and Production Data from Horizontal Wells in the Montney Formation in British Columbia
Authors: Voneiff G. , Sadeghi S. , Bastian P. , Wolters B. , Jochen J. , Chow B. , Chow K. , Gatens M.
Published: November 2013

UGR Blair Creek Ltd. (UGR) developed an empirical equation to predict Montney horizontal well production based on several completion parameters: lateral length, number of fracture stages, perforation clusters per fracture stage and fluid volume. We used multivariate regression analysis to determine how the completion parameters influence observed production rates. Our best model is valid for fracturing treatments using slick-water and all of the wells in this study are located in British Columbia. The Montney is an expansive play and thousands of wells will be drilled in the future, so the results of this analysis and application of this technique to expanded data sets should help with completion optimization and can have a significant impact on well performance and/or completion cost.

We reviewed completion reports on 425 wells to extract several parameters, including lateral length, number of fracture stages, number of perforation clusters per stage, fluid volume, fluid type and sand volume. Public production data were used to obtain monthly production volumes for each well. We performed multivariate linear regression analysis, simultaneously regressing all of the completion variables against the average production during the best year of production.

We found that the number of fracture stages and the number of perforation clusters per stage are the most important completion parameters for predicting well performance. As expected, an increase in either of these variables will increase the production volume of the best year of production. Adding one fracture stage adds roughly 200 Mcf/D (5,600 m3/d) and adding one perforation cluster per stage adds roughly 250 Mcf/D (7,400 m3/d) to the best year of production. The impact of additional fracture stages or perforation clusters was more pronounced on wells using slick-water fracture fluids than treatments using more complex fluid systems. The amount of sand used in the fracture treatments may also have a significant positive impact on production, but there is more uncertainty than with the number of fracture stages and perforation clusters per stage. Lateral length and fluid volume were only marginally important in predicting production volumes. Only by using multivariate regression (all variables are simultaneously combined in a single regression model) were we able to discern the impact of individual variables.
A Numerical Modeling Study for the Impact of Casing Drilling on Wellbore Stability
Authors: Mokhtari Mehdi , Tutuncu Azra N. , Weldu Teklu Tadesse Weldu
Published: November 2013

Smaller annular size in casing drilling impacts both drilling fluid dynamics and wellbore geomechanics. Casing drilling has been the subject of several case studies reporting improvements in wellbore stability in wells traditionally prone to severe breakouts and stuck pipe issues. However, there are only very few publications reporting the theoretical, experimental or numerical results supporting the field observations. In this paper, we will discuss numerical simulations on the wellbore stability studies customized for casing drilling applications.

Compressive failure has been typically prevented in intact shale formations by increasing mud weight since higher mud weight can reduce hoop stresses and raise the radial stress around the wellbore. However, the stress concentration and the formation strength around the wellbore can change with time leading to wellbore instability. Fluid invasion increases the near wellbore pressure which leads to less support to the wellbore. Fluid invasion may also reduce formation mechanical properties due to the physico-chemical interactions between formation and fluid. Casing drilling can help wellbore stability by reducing the shale-fluid interaction time and near wellbore permeability as well as improving near wellbore mechanical properties by plastering effect. We present a numerical study which shows the reduction of potential breakout occurrences using casing drilling compared to conventional drilling scenarios.
Use of Pressure- and Rate-Transient Techniques for Analyzing Core Permeability Tests for Unconventional Reservoirs: Part 2
Authors: Clarkson C. R. , Qanbari F.
Published: November 2013

Although matrix permeability is an important control on the commercial viability of unconventional reservoirs, there is no consensus on the appropriate way to measure it in the lab. In previous work (Clarkson et al. 2012), we investigated the use of pressure- and rate-transient analysis (PTA/RTA) methods to analyze data obtained from a new core plug analysis procedure designed specifically to extract information (permeability and pore volume) from ultra-low permeability reservoir samples (core plugs). The new approach involved analysis of rate and/or pressure data from the core test analogously to larger-scale well-test/production data. Although this approach offers some advantages over conventional pressure-decay and pulse-decay test analysis procedures, there are some practical issues related to core measurements to support the analysis that need to be addressed. For example, injection or production rate measurements, which are difficult to perform, were required to implement some of the analysis procedures. Further, in the original work, constant injection rates for the injection/falloff portion of the test, and constant flowing pressures for the production portion of the test, were assumed. In this work, we demonstrate that accurate measurement of injection rates is not necessary to obtain an accurate estimate of permeability and that the analysis methods can be applied for variable injection rates and flowback pressures.

Several permeability estimates are possible during a single test cycle using the procedures described in this work. Permeability may be estimated from the injection/falloff cycle of the test by 1) identifying the end of transient (linear) flow from derivative techniques combined with the distance of investigation calculation and 2) applying a conventional straight-line analysis of linear flow. Two independent estimates may therefore be obtained, but the latter requires estimation of the injection rate history. Similarly, two permeability estimates may be obtained from the production (flowback) cycle of the test using the distance of investigation and straight-line approaches. Both falloff and production analysis procedures are tested by simulating constant and variable injection rates, and constant and variable flowing pressures, respectively. In some cases, particularly with variable rates/flowing pressures, it may not be possible to obtain permeability from all approaches, making multiple, redundant estimates desirable to avoid a failed core analysis. As with the original test procedure proposed by Clarkson et al. (2012), the unique properties of unconventional reservoirs may be accounted for in the new analysis procedure, such as adsorption and non-Darcy flow (slippage and diffusion), and heterogeneities may be detected and analyzed.

We believe this new technique for analyzing core data will considerably improve on current techniques for establishing permeability of unconventional reservoir samples.
Modeling, Testing, and Case Histories of Swellable Packer Casing Anchoring Performance Enable Wells Destined for Plug and Abandon to Become Producers
Authors: Stein Taylor , Tunstall Michael , Wellhoefer Ben , Veillette Christian
Published: November 2013

During the last decade, swellable packer technology has been accepted more readily, and its usage is increasing as a viable method for zonal isolation in the oilfield. During this time, swellable packers have shown a new side to their versatility, as they are now being used in many other applications. These newer applications are requiring that swellable packers provide an anchoring point for the casing or tubing string, and the swellable technology is accepting this challenge by being used to provide this requirement in applications such as casing repair, liner tieback, corroded casing, and multi-stage fracturing.

This paper will review case histories and testing in order to illustrate procedures for developing, simulating and validating swellable-packer anchoring forces that will enable swellable packer technology to be applied in new oilfield applications. This testing and information will show that when the application and well conditions are understood, swellable packer technology can be a viable alternative to cementing of casing strings or expandable casing patches for providing anchoring points and isolation. This application often allows larger IDs to be considered and costs of workover operations to be reduced. Critical aspects such as the swelling fluids, pressure requirements, production/stimulation scenarios, well conditions and goals, and other concerns of the engineering and design process will be discussed. The impact of these parameters will be explained as well as how each is important in designing the swellable packer to meet any oilfield application. Other job design aspects such as simulating the swellable packer behavior and performing necessary laboratory testing to validate the simulation will also be compared to case history results.

Finally, the paper will conclude how swellable packer technology can be used for many applications requiring anchoring forces.
Analysis of Transient Linear Flow in Tight Oil and Gas Reservoirs with Stress-Sensitive Permeability and Multi-Phase Flow
Authors: Qanbari F. , Clarkson C. R.
Published: November 2013

Horizontal wells and hydraulic fracturing are the key technologies that allow commercial production from tight oil and gas reservoirs. However, rigorous analysis of production data from these reservoirs requires incorporation of the impacts of stress-dependent permeability and multi-phase flow. Changes in the stress state of the system during production may reduce the absolute permeability. Furthermore, gas phase formation and flow in presence of supersaturated oil phase affects fluid dynamics in tight oil reservoirs. This study provides a rigorous methodology for incorporation of the effects of non-static permeability and multi-phase flow in rate transient analysis (RTA) of tight oil and gas reservoirs producing at variable rate/flowing pressures during transient linear flow period.

Analytical solutions for the approximate linearized form of the flow equation have been widely used as the basis for RTA tools for conventional reservoirs during transient flow period. However, they lead to considerable error when applied to tight oil and gas reservoirs. In particular, during the transient linear flow period, the slope of the square -root-of-time plot obtained from numerical solution differs from the slope calculated by analytical methods. Efforts have been made by some researchers to obtain a correction factor from the numerical solution of the flow equation to correct the slope of the square-root-of-time plot for single phase flow of gas during transient linear flow period. In this study, an iterative method is used for evaluation of the slope correction factor in the presence of multi-phase flow and non-static permeability for constant-pressure production during transient linear flow period. Further, the correction factor is used for analysis of production data from tight oil and gas reservoirs producing at variable rate/flowing pressures.

The correction factor is used in the analysis of different sets of synthetic production data for tight oil and gas reservoirs. The results show that the correction factor can reduce/eliminate the considerable errors associated with the conventional analytical methods in initial permeability estimation. For multi-phase flow cases, the producing gas -oil ratio (GOR) is used to estimate the oil saturation-pressure relationship in the reservoir, which is required for calculation pseudo-pressure and the correction factor.

The method developed in this study alleviates the need for using numerical simulation models to generate empirical correlations for the correction factor for the square -root-of-time plot. The easy-to-implement iterative procedure of this method only requires the pressure dependencies of the constituent elements of the hydraulic diffusivity. Therefore, this method is applicable for analysis of production profiles for variety of reservoirs with nonlinear flow equations.
Hydrocarbon Recovery Boosted by Enhanced Fracturing Technique
Authors: Allison Dave , Bryant Jason , Butler Jeremy
Published: November 2013

The oil and gas industry has continuously searched for methods to increase the recoverable reserves of known hydrocarbon reservoirs. Keeping in mind that every reservoir will have its own recovery factor, historic numbers indicate that original completions access between 10 to 25% of available reserves, and secondary and tertiary recovery techniques can improve the recovery factor to as much as 25 to 60% of the hydrocarbons in place. With an industry focus on unconventional shale and its ultra-low permeability, the recovery factors are on the lower end of the historic figures. The ultra-low permeability dramatically limits the drainage radius of a given fracture.

A new completion technique is providing a methodology to improve hydrocarbon recovery. This paper presents the results of case studies for two different fields where a deep reservoir diverting technique using environmentally acceptable self-removing diverters has significantly impacted the production from 15 shale wells. Insight is also presented regarding how this deep reservoir diverting technique has the potential to impact a well’s production, spacing, and ultimate hydrocarbon recovery in unconventional shales.
Fully Compositional and Thermal Reservoir Simulations Efficiently Compare EOR Techniques
Authors: Lucia Angelo , Voskov Denis , James Scott C. , Zaydullin Rustem , Henley Heath
Published: November 2013

Primary oil recovery methods in Saskatchewan’s heavy oil basin extract 5 to 10% of the available resource with the vast majority left in the ground and recoverable only through Enhanced Oil Recovery (EOR) methods. Traditional EOR generates steam in surface facilities and injects it underground to mobilize the oil for production with considerable energy losses inherent in the process. R.I.I. North America’s Solvent Thermal Resource Innovation Process (STRIP) technology moves the steam generator underground, reducing the operating and capital costs of a surface thermal production facility by 30% and 50% respectively, and saving more than 30% of the energy typically required for thermal production. STRIP technology combusts methane to produce in situ CO2 and steam. Because CO2 acts as a co-solvent, STRIP outperforms traditional steam-injection technology. This is demonstrated using a breakthrough modeling technique that couples fully compositional and thermal reservoir flow simulation capabilities. This new approach couples FlashPoint’s equation-of-state solver for the multiphase, multi-component, isothermal, isobaric flash problem, GFLASH, with Stanford’s Automatic Differentiation General Purpose Research Simulator for thermal reservoir flow simulations. This new computational framework exploits advanced techniques for skipping phase-identification computations and only uses exact phase equilibria from GFLASH when needed, reducing computational times by one to two orders of magnitude compared to the full rigorous solution.
A Transient Model for the Liquid-Loading Process in Fractured Horizontal Gas Well
Authors: Li Y. , Teng S. , Shi J. , Xu D. , Lei G.
Published: November 2013

Fractured horizontal well is the most important method for the exploitation in tight gas reservoirs or unconventional gas reservoir. And liquid loading may become a serious problem in fractured horizontal wells when gas product capacities are reducing.

This paper will propose a transient model for liquid loading process of fractured horizontal wells over time.it is obvious that these wells have a large stable rate and all fluids produced from reservoir could be carried to the surface when the gas rate is larger than critical rate; then, the effect of liquid-loading makes the gas rate smaller to be a metastable rate as soon as the gas rate is below critical rate.

A model is introduced for understanding liquid-loading process better in fractured horizontal wells. It is assumed that gas and water coproduction and water reinjection both exist in hydraulic fracture. And part of water produced from reservoir is carried to the surface and the rest water will first accumulate at the bottom of the hydraulic fracture with the help of gravity when liquid loading starts and part of water in fracture may reinject into reservoir later. Then, the water column will reach the horizontal section or even get up to the inclined section and the vertical section. Finally, a metastable rate could be observed when water produced from reservoir is equal to the sum of water carried to the surface and water reinjection.

Then, the sensitivity analysis of several parameters such as the fracture parameters (the length, the width, the height, and number of fractures) and water gas ratio of the surface have been taken to influence the metastable rate and the time reached to the metastable rate.

With this model, liquid-loading process in fractured horizontal wells can be understood better and predicted. And it is very important for the optimization of fracture parameters and well production parameters to prevent and control the liquid-loading process.
Optimizing Cyclic CO2 Injection for Low- permeability Oil Reservoirs through Experimental Study
Authors: Wang Zengxiang , Ma Jinhua , Gao Ruimin , Zeng Fanhua , Huang Chunxia , Tontiwachwuthikul Paitoon , Liang Zhiwu
Published: November 2013

Cyclic CO2 huff ’n’ puff process in diverse reservoir conditions, such as immiscible, near-miscible, and miscible, has been tested in the laboratory and applied in the fields as a viable secondary or tertiary means to recover the residual oil in water flooded reservoirs or pressure depleted reservoirs. Recently, petroleum operators have shown increasingly interest in taking CO2 huff ’n’ puff process as a preferred option to extract light oil in low-pressure and low-permeability reservoirs.

In this paper, experimental results from a series of coreflood tests are presented and operation strategies for cyclic CO2 injection are optimized to maximize the light oil recovery factor in a low- permeability reservoir with low original reservoir pressure and while, minimize CO2 utilization. 6 cyclic coreflood tests, 20 cycles in total, are conducted in a 973 mm-long composite core with an average porosity of 9.6% and an average permeability of 2.3mD. The reservoir pressure is 12.9MPa, far below the measured MMP value of 23MPa, which indicates that the reservoir has no sufficient energy support to do primary production. The impacts of primary operational parameters, such as slug size, injection pressure, chasing gas (N2) and CO2 injection rate on the performance have been investigated.

It is concluded that, on the basis of experimental data, 0.1PV seems to be an optimal slug size for the first cycle, with a cycle recovery factor as high as 14.52% when reservoir pressure depleted to 8MPa. The recovery factor is suggested to be sensitive to the maximum pressure and the maximum pressure should be built up to as high as formation permits. In the following cycles, injecting N2 as chasing gas after CO2 injection seems to improve the cycle performance significantly and concurrently reduce the CO2 utilization. The optimal operation should have three cycles and the ultimate recovery factor for these three cycles could reach above 30%. The findings of this paper extend the understanding of cyclic CO2 operation and may be employed as technique reference for cyclic CO2 process operations in low-pressure and low-permeability closed boundary reservoirs.
Hybrid Horizontal in a Foothills Carbonate
Authors: Holan H. , Ziebell T. , Lowen B.
Published: November 2013

This paper will describe the design objectives and choices prior to drilling of the subject well, and modifications to the completion design once well logs were in hand. The well was a test bed to compare the effectiveness of acid fracturing vs. proppant fracturing in a deep gas carbonate reservoir, as well as the technology used to deliver the stimulations, open hole packers vs. cemented in sleeves. In the current low gas price environment, a multiple well drilling program could not be pursued, the budget was limited to one well to test concepts and methodologies.
Aggregate Production Forecasts for Unconventional Resource Drilling Locations Using Monte Carlo Simulation
Authors: Mireault R.
Published: November 2013

As SPEE Monograph #3 notes, few guidelines exist to evaluate unconventional resource plays. The significant variability in well performance that is inherent to resource plays may preclude the use of an analogous "type" well when evaluating undrilled locations, as is done for conventional reserve evaluation. Yet the necessity of having reliable production forecasts as the foundation for sound investment remains.

The paper uses Monte Carlo simulation to generate an aggregated production forecast distribution for multiple undrilled locations from the forecast distributions for the individual locations. From the central limit theorem, the sum of individual production forecasts tends towards the average value for the undrilled well population times the number of locations as the number of drilling locations becomes very large (infinite).

However, in the real world the number of drilling locations is finite and limited so a forecast based on the "average" for the entire population likely overestimates the results for the group. The reason is that well production rates are characterized by skewed (e.g. lognormal) distributions so more than 50% of the wells drilled will produce at less than the average well rate while a few "stars" will perform at rates that are well above the average.

Accordingly, the first wells in a random drilling sequence will likely produce at below average rates. The group rate will continue to lag the population average with each successive well drilled until "luck" intervenes and a location that produces at well above the average is drilled. Consistently overestimating producing rates as a field is developed can lead to marginal economics or even "gambler’s ruin" if the "star" well is not drilled before the entire drilling budget is spent.

To overcome the practical pitfalls of the central limit theorem, Monte Carlo simulation is used to quantify the uncertainty in the production forecasts of a group of wells. A 10-location drilling example illustrates the variance in the forecasts over a 20-year project life. The resulting P90, P50 and P10 production forecasts provide a means to assess the impact of our uncertain knowledge on production rates, cash flows and project economics.