bluuebunny/crossref_metadata_2025 huggingface dataset:
Cost Effective Monitoring and Visualization System Used for Real-Time Monitoring of Downhole Operations from the Wellhead
Authors: Hlidek Barry T. , Potts Douglas , Quinlan Andrew
Published: September 2016

A major challenge of multistage completion systems is visualizing and verifying critical operations, especially during high pressure pumping operations, such as hydraulic fracturing. An innovative new technology has been developed to detect and visualize those key completion operations using easily installed surface equipment. This paper describes the real-time visualization system (RTVS), its deployment and operation, and includes examples from the field.

Several methods are currently available to monitor operational events that are critical to the successful execution of a multistage fracturing program. Traditionally, surface pressure signatures and manual methods are used to verify completion equipment functions. However, in many cases the signature is not present or is ambiguous. Microseismic and fiber optic systems are complex and expensive to deploy. The new RTVS method is a surface deployed; non-invasive, self-contained system that provides easy to use high resolution data. The system provides visual representation of downhole and surface events using a unique and specialized array of electronic sensors.

The ruggedized, monitoring system can be rapidly deployed and installed by a single operator, with little or no interference with concurrent surface or downhole operations. Power supply and instrumentation is portable with a very small footprint acceptable for onshore and offshore applications. The system operates independently from conventional pressure measurement, and is designed to provide real-time feedback during completion operations.

During multistage hydraulic fracturing operations, the system will positively verify the function of fracture ball deployment, ball seating, and sliding sleeves, as well as setting of liner hangers and mechanical packers. RTVS can also detect coiled tubing sleeve location and operation, perforating gun firing, plug setting, and function of other downhole and related surface equipment. Additionally, the system has the ability to detect failure of downhole equipment, such as casing or tubing breaches in real-time during hydraulic fracturing operations. Real-time monitoring enables on-the-fly optimization of the fracture treatment and eliminates uncertainty regarding deployment and operation of downhole equipment.

This non-invasive, cost-effective completion equipment and stimulation treatment monitoring system is the first technology of its kind. Combining an array of sensors and innovative signal analysis, this easily deployed system can detect operation and failure of surface and downhole equipment. Real-time monitoring of wellsite events can improve decision making on location, optimizing completion operations, and improving well economics.
New Generation of MPD Drilling Software - From Quantifying to Control
Authors: Rostami S. Ameen , Gumus F. , Simpkins D. , Pobedinski I. , Kinik K. , Rajabi M. Mir
Published: September 2016

Realizing the potential benefits automation brings, many operators have turned to managed pressure drilling (MPD) techniques as a technical and cost-reward solution to hard-to-reach assets, an approach which not only saves time but also enhances the safety capabilities of the operation. The evolving industry shift toward MPD-ready rigs demonstrates the significant need for a reliable software system to interact with the equipment and simultaneously deliver enhanced models able to precisely control annular pressure in geological complexities where drilling windows are narrow.

Several studies have demonstrated the operational benefits of MPD through the application of the constant bottom hole pressure (CBHP) method, imbedded automated kick detection, and control capabilities. MPD technology relies substantially on applying surface back pressure (SBP) using automated chokes to precisely control the annular pressure profile in a closed loop circulation system. During drilling, CBHP connections, mud displacements and fluid anomaly incidents, the SBP is dynamically adjusted in response to operational changes that yield annular pressure changes; such as circulation rate, top drive speed, and rate of penetration to name a few.

The integrated MPD drilling software platform is used in combination with interactive models and surface and downhole data measurement in a unified computing system to enhance real-time analysis of drilling performance. By employing real-time models such as hydraulics, well control, pore and fracture pressure estimation, surge and swab, and drilling optimization torque and drag, the system quantifies the boundaries and aid in understanding the real operational limits. Additional software platform applications deliver the common integration baseline that enables both operations within the pre-drilling, while drilling and post analysis. The current automated MPD software has been successfully used in several onshore and offshore wells with narrow drilling windows. This paper discusses the applications and the newest developments in the MPD integrated software to automatically and precisely manage wellbore pressure. The results to be presented include the summary of planning, while drilling analysis, and post drilling analysis of an offshore case study where a detailed parametric analysis of measured and estimated data are compared.
Geospatial Analysis of Compositional Variations across the Eagle Ford and Barnett Shale Plays
Authors: McMillan M. D. , Nwachukwu C. R. , Rahnema H.
Published: September 2016

Liquid-rich shale (LRS) wells have shown abrupt changes in production rates and fluid composition. In order to maintain high liquid hydrocarbon production rates over the life of well, as well as proper reserve estimation, a better understanding of the in-situ reservoir fluids is required. In this work, an investigation is performed on the areal and vertical geospatial fluid property variations across the Barnett and Eagle Ford. Available Barnett PVT data was adjudged as entirely nonrepresentative and a multi-contact recombination procedure has been implemented to improve estimates of in-situ reservoir composition. Eagle Ford is known to be highly under-saturated and with no concerns about representativeness identified through data validation, these were accepted and utilized without modification. Ternary diagrams indicating fluid type, vertical variations of OGR, C7+ and API gravity were investigated. Maps were created to review areal variations of these properties (API gravity, C7+, and initial OGR), and finally the decline of OGR with time was studied.

Our study used publicly available data to confirm compositional variation across the Barnett and Eagle Ford. Regions were defined based on initial producing OGR and the decline of this property with time. The created maps present not only ranges and trends for OGR, API gravity and well stream C7+ parameters but the methodologies can be applied to assessing other fields.
Molecular Dynamics Study of Carbon Dioxide Storage in Carbon-Based Organic Nanopores
Authors: Kazemi Mohammad , Takbiri-Borujeni Ali
Published: September 2016

With large scale production of gas from shale resources, large volumes of pore space have been vacated. Therefore, there is a large capacity for storage of carbon dioxide in these resources. Furthermore, due to the higher affinity of the organic matter to carbon dioxide compared to methane, injection of carbon dioxide can replace the adsorbed methane and therefore, enhances the recovery of natural gas. The objective for this work is to investigate the sorption (adsorption of carbon dioxide and desorption of methane) in carbon-based organic channels using Molecular Dynamics (MD) simulations.

In this study, adsorption isotherms of methane and carbon dioxide are compared by performing grand canonical Monte Carlo (GCMC) simulations in identical setups of carbon channels. Excess and absolute adsorption isotherms of these gases are plotted and compared. Furthermore, the surface selectivity of carbon dioxide over methane is computed to determine the competitive adsorption of these two gases. To simulate the displacement process, MD simulations of displacement of methane molecules with carbon dioxide molecules in presence and absence of pressure gradients are performed. The results are compared for different values of gas pressures and pressure gradients.

According to the results, adsorption capability of carbon dioxide is found to be higher than that of methane under the same pressure and temperature. The selectivity values of carbon dioxide over methane is found to be higher than the ones for pressure range of 100 to 200 atm, which shows that carbon dioxide molecules have higher affinity to the surface compared with methane. It is also found that carbon dioxide molecules replace adsorbed methane molecules due to their higher affinity to the surface. Concentration of methane sharply decreases as carbon dioxide molecules are introduced in the channel. The results show that the amount of carbon dioxide storage and methane production rate increases as injection pressure increases. The results in this study can impact on the research and development of new tools for both candidate selection (selection of the sites for carbon dioxide storage) and development of predictive models for estimating of the amount of carbon dioxide intake.
Interpretation and Analysis of Transient Sandface and Wellbore Temperature Data
Authors: Onur M. , Ulker G. , Kocak S. , Gok I. M.
Published: September 2016

In this paper, we provide new analytical and semi-analytical solutions based on a coupled wellbore/reservoir thermal model to investigate the information content of transient temperature measurement made within the vertical wellbore across from the producing horizon or at a gauge depth above it during drawdown and buildup tests. Our investigation leads to new interpretation/analysis methodologies of sandface and wellbore transient temperature data based on temperature-derivative and straight line methods for estimating near wellbore and far field formation parameters. Slightly compressible, single-phase, and homogeneous infinite-acting reservoir system with skin effect is considered. The analytical solutions accounts for Joule-Thomson heating/cooling, adiabatic fluid expansion, conduction and convection effects both in the wellbore and reservoir. The development of the analytical and semi-analytical solutions is based on the fact that the effects of temperature changes on wellbore and reservoir pressure transient data can be neglected so that the wellbore mass and momentum and reservoir pressure diffusivity equations and thermal energy balance equations in the wellbore and reservoir can be decoupled. The semi-analytical solution for predicting sandface temperatures is verified by use of a general purpose thermal simulator. Wellbore temperatures at a certain gauge depth are evaluated through analytical steady-state and transient wellbore temperature equations which couple the semi-analytical reservoir temperature model based on the conventional wellbore storage model or the more general model accounting for momentum effects in the wellbore. Results show that drawdown sandface temperatures are totally dominated by advection, whereas buildup sandface temperature data are dominated by conduction. Drawdown and buildup sandface temperature data exhibit two semilog straight lines; one at early-times reflecting the effects of adiabatic fluid expansion in the in the skin zone near the wellbore, whereas the late-time semilog straight line reflecting the Joule-Thomson effects and exhibiting the non-skin zone properties. For temperature measurements made at locations above the producing horizon, the wellbore temperature is strongle dependent upon distance above the producing horizon, geothermal gradient, and radial heat losses from the wellbore fluid to the formation on the way to gauge. Our results indicate that skin-zone properties seems very difficult to estimate from the drawdown and buildup wellbore temperatures unless the gauge location is not far from the producing zone. Buildup wellbore temperature seems mostly dominated by wellbore heat losses as compared to drawdown wellbore temperature data and hence cannot reflect the formation properties.
New Approach for Using Surfactants to Enhance Oil Recovery from Naturally Fractured Oil-Wet Carbonate Reservoirs
Authors: Parra Jose E. , Pope Gary A. , Mejia Miguel , Balhoff Matthew T.
Published: September 2016

Recent research indicates that even small viscous transverse pressure gradients can increase the rate of surfactant imbibition into the matrix of a fractured reservoir. However, surfactants are commonly tested using static imbibition cells without any imposed pressure gradient. Therefore, the effect of viscous pressure gradients was investigated by conducting a series of surfactant corefloods using fractured Silurian Dolomite and Texas Cream Limestone cores. The viscosity of the surfactant solution was increased by adding polymer or by changing the salinity of the aqueous surfactant solution, which affects the in-situ microemulsion viscosity. The fractured cores had a permeability contrast between the fracture and the matrix ranging from 2500 to 90,000. Non-fractured corefloods were also performed and compared with the fractured corefloods. The more viscous surfactant solutions achieved greater oil recovery from the fractured carbonate cores. These results indicate that a viscous microemulsion can serve as a mobility control agent in naturally fractured reservoirs (NFRs) that is analogous to mobility control with foams and polymers, but with less complexity and cost.
Using Completion Diagnostics in Uinta Basin Vertical Wells to Reduce Completion Costs and Identify Horizontal Well Targets
Authors: Ramos C. , Dineen C. , Kolla J.
Published: September 2016

Over 13,000 active oil and gas wells and more than 740 million bbl of oil have been produced from conventional vertical wells in Utah's Uinta Basin (Fig. 1). Located within the basin, the Monument Butte area is among the top 100 oil fields in the United States. Operators with a strong presence in the Monument Butte area are also pursuing ideal target zone(s) for horizontal wells by evaluating various sections of the reservoirs and utilizing the availability of technological advances made in recent years in horizontal drilling. Determining the reservoir water source zones to curb water disposal costs and ascertaining the productivity of different segments of a well to evaluate its profitability are more important than ever considering the current economic situation.

This paper will highlight the completion diagnostic results obtained from using oil-soluble and water-soluble tracers during the completion of eight conventional vertical wells in the Monument Butte area. The eight wells selected for this study are located in Sections I, II and III in Uintah County; the wells were drilled through and completed for comingled production in the Green River and Wasatch formations. Through the deployment of hydrocarbon tracers and fluid tracers, oil contribution and water production were evaluated across all zones. Between 3 and 12 hydraulic fracturing treatments were pumped into each vertical well. The fracturing treatments were designed similarly and each stage was meant to stimulate a unique target zone or formation. Moreover, for each well, each stage design had a unique set of oil-soluble and water-soluble tracers. Oil-soluble tracers were used to quantify the hydrocarbon contribution for each segment from samples taken during the course of 30 and as long as 410 days. In addition, the water-soluble tracers were used to clearly determine the water source intervals, allowing the abandonment of deeper wet zones, thus realizing a significant cost savings from not drilling and completing the bottom 800 to 1,000 ft of each future well.

Finally, the unique sets of oil and water tracers were also used to evaluate the short-term and long-term productivity of each pay zone, with the intention of identifying the best formation(s) to target in horizontally drilled wells.
Highly Efficient Dehydration and Desalting of Crude Oil from Mature Fields in the Middle East
Authors: Sellman Erik , Mandewalkar Pavan
Published: September 2016

Mature crude oil fields are often prone to high water cuts and high content of fines. The large population of small water droplets and fines forms very stable crude oil emulsions that are difficult to break using conventional treaters. The high water cut creates a high-viscosity crude oil emulsion, often leading to a need for higher operating temperatures, high demulsifier dosage, and frequent production upsets.

The high water cut also causes arcing between electrodes. Typically, older crude oil dehydration and desalting treaters use AC-type electrostatic technology, which is less effective in treating crude oils with high water cuts. The use of AC/DC-type electrostatic technology provides a two-pronged approach—bulk water is removed in a weaker AC field, and the remaining smaller water droplets are removed in a stronger DC field. Further improvements to the AC/DC treaters include use of composite electrodes, modulated electrostatic fields, and improved fluid distribution inside the treaters.

AC/DC treaters provide an attractive opportunity for retrofitting existing AC treaters in mature fields and make the treaters more suitable for dehydrating the crude oil emulsions from these fields. Recent upgrading of a large number of older electrostatic treaters and desalters in the Middle East provided the operators with several benefits in the form of higher production, ability to operate the facility at a lower temperature, lower wash water consumption, and improved overall performance.

This paper describes a new enhanced electrostatic dehydration technology that provides improved efficiency in treating high-water-cut crude oil emulsions in mature fields and efficient test methods to optimize use of production chemicals and selection of electrostatic technologies. Several case studies from the Middle East are included.
Characterization of Rock Pore-Size Distribution and Its Effects on Wormhole Propagation
Authors: Dubetz D. , Cheng H. , Zhu D. , Hill A. D.
Published: September 2016

Carbonate rocks have complex heterogeneities that result from syn- and post-depositional stressors. These heterogeneities invariably affect the movement of fluid through the formation. When considering an acid treatment procedure, care must be taken to optimize the acid concentration and pumping schedule to encourage the formation of wormholes. Despite the abundance of carbonate formations (60% of conventional reserves), there is little consensus on the effect of physical formation properties related to acidizing efficiency. This study characterizes the pore-size distribution for different carbonates and evaluates how the optimum pore volume to breakthrough, PVbt,opt, and the optimal interstitial flux, vi,opt, are related to various physical properties of the rock.

The pore-size distributions evaluated in this study are constructed with micro-computer tomography (micro-CT) imaging, a non-invasive X-Ray imaging technique pioneered in the medical field. Micro-CT is improved over medical CT because it can scan at higher energies and higher resolution. In this work, resolution for scanned samples range from 5-8 μm/voxel and sample sizes are approximately 1cm3. Image processing is applied to the raw CT data to segment pore space from the surrounding matrix. Object counter software is used to identify and measure individual pores, which can then be organized into a pore-size distribution. Statistical parameters are calculated by fitting a lognormal distribution function to each sample's pore-size distribution. We find that the shape of the pore-size distribution is influenced by the type of carbonate rock and that fitting the distribution yields better correlations to optimum acidizing parameters than permeability or porosity alone.
Parallel Multilevel Monte Carlo for Two-Phase Flow and Transport in Random Heterogeneous Porous Media With Sampling-Error and Discretization-Error Balancing
Authors: Müller Florian , Jenny Patrick , Meyer Daniel W.
Published: September 2016

We consider two-phase flow and transport in heterogeneous porous media, where the permeability is modeled as a random field. To assess the resulting uncertainty of flow and transport, multilevel Monte Carlo (MLMC) is used. MLMC involves two types of errors: a sampling error and a discretization error, which, under reasonable assumptions, can be conveniently estimated during execution. In this work, we address the question of how to balance the two errors. Furthermore, a simple MLMC parallelization strategy is presented. A numerical comparison of MLMC with standard Monte Carlo (MC) reveals significant gains in computational efficiency at equivalent accuracy.
Super-Large Scale Horizontal Well Position Optimization Method and Infilling Practice in High Water-cut Large Complex Fluvial Reservoir Based On Multidisciplinary Innovative Techniques
Authors: Wang Kai , Wang Haisheng , Shu Xiao , Zhou Dasheng , Wang Ruizhe , Li Yujun , Liu Ning , Su Zhikun , Ren Baicong
Published: September 2016

Tapping the remaining oil with horizontal wells is routinely used in high water-cut oilfields. However, it faces serious challenges in complex fluvial reservoirs with stacked sand body, horizontal interlayers, lateral barrier and complex water flooding conditions. Moreover, the depth uncertainty of the target interval, limited number of offset wells, rapid change of thickness, thin target intervals, and variable fluid contact have also increased the risks of the horizontal well placement. In order to locate the optimal positions of the horizontal wells, get the maximum recovery, reduce the risk of water flooding, minimize the drilling time, we propose a comprehensive well planning and optimization method based on multidisciplinary innovative techniques. New techniques from geology, geophysics, and drilling engineering are assembled to efficiently perform the challenging task.

Firstly, an improved interwell 3D correlation technique was proposed to characterize the single sand body. The technique can depict the vertical hierarcy of reservoir. Secondly, we propose a lateral boundary delineation technique based on seismic geometrical attribute. Combined with ant tracking algorithm, we are able to extract the 3D lateral discontinuous surfaces. Based on above technique, we can build detailed architecture model fast and optimize the positions of horizontal wells. Considering the geological uncertainty, the boundary mapping tool is used to optimize the well trajectories in real time to avoid the water flooded zone and shale zone, and to stay in the sweet zone.

We applied the integrated workflow in Q oilfield in Bohai Bay basin, East China. 112 horizontal wells are drilled. The drilling results proved that boundary mapping tool can achieve smooth landing of well path and delineate the accurate geometry and thickness variation of sand body which reduces the depth uncertainty of seismic horizon explanation, and keeps the horizontal well trajectories away from oil-water contact. The production results show that 86% horizontal wells have achieved low water-cut and high oil production rate. The total production rate of Q oil field has increased by 2.5 times.
Detecting Production Choke Wear in High Rate Dry Gas Wells using Graphical Trending of Production Parameters: An Offshore Saudi Arabia Gas Field Case Study
Authors: Ayoola Olakunle T , DeLandro Wendell WC , Muslim Ali M
Published: September 2016

A production choke is essential in regulating the pressure and flow rate of the produced hydrocarbon stream from a well in a field production system. Regulating the pressure and flow rate is necessary to achieve the production objectives of a field, which are to meet customer demand and optimally manage the reservoir over its life cycle. It is therefore important to have a means of effectively monitoring production choke performance to identify the onset of choke wear. Choke wear results from erosion of the choke due to impingement of particles carried in the produced hydrocarbon stream as it passes through the choke body. Choke wear increases the production rate and downstream pressure of a producing well, thereby upsetting the balance of the production system and resulting in ineffective field pressure management. Taking immediate action to replace a worn choke is therefore necessary to restore the production balance and achieve optimal pressure conservation of the production system. Choke performance monitoring is more critical for gas producing wells than oil producing wells because the velocity of gas is typically much higher than the velocity of oil, and consequently the risk and frequency of choke wear is much higher. Physical inspection of the production chokes to confirm wear for offshore gas wells is more laborious and time consuming due to the need to interrupt production, depressurize the flowline, decouple the choke body from the flowline, and ship the choke body onshore to the manufacturer's workshop for component inspections to confirm choke wear and, if necessary, choke replacement. A way to remotely monitor production choke performance and correctly detect choke wear for offshore gas wells without interrupting production is therefore operationally expedient, reduces exposure of personnel to unsafe rough sea conditions, and saves the cost of unnecessary physical choke inspections. The authors present a graphical method of monitoring the production rate and flowing tubing head pressure trends, with the choke size, of offshore high rate dry gas wells to detect choke wear using real-time production data. Examples of successful application of the method, which demonstrates that innovation can be simplification of processes, to detect choke wear and perform timely choke replacement are highlighted.
The Impact of Normalized Relative Permeability Data on Estimated Ultimate Recovery
Authors: Pollard Victoria , Yusuf Babatunde
Published: September 2016

A typical hydrocarbon reservoir consists of multiple rock types or facies. In reservoir modelling, capturing the properties of each rock type is essential. Relative permeability data, which describes rock-fluid and fluid-fluid interactions is normally developed for each rock types and is often a tuning parameter in History Match (HM); a very important element of reservoir simulation. The objective of this paper is to analyze the effect of applying normalized relative permeability data to model a reservoir. The effect is examined using both manual and automatic History Match, and then predicting the Estimated Ultimate Recovery (EUR) in two scenarios.

Relative permeability curves for each rock type are prepared using corey saturation function equations. The normalization phase requires using separate sets of equations, after which the normalized curve will be denormalized for input into the simulation model. The resulting relative permeability curve is then used in HM by applying manual and automatic methods, after which the resulting matches are used to predict recovery. The reservoir simulation output using the normalized relative permeability curve is then compared to the base case scenario, in which case, individual rock types relative permeability curves were utilized.

Reservoir simulation outputs from normalized relative permeability curves were found to compare very well with outputs using individual rock type relative permeability, with improved efficiency, for the reservoir under study.

Normalized relative permeability data, when used with sound engineering judgement, can be very efficient. Mostly desired as an essential part of History Match, having a single representative set of relative permeability data for the reservoir can improve efficiency and save costs.
Experimental and Numerical Investigation of Oil Recovery from Bakken Formation by Miscible CO2 Injection
Authors: Zhang Ke
Published: September 2016

Unconventional liquid reservoirs are characterized by small matrix permeability that is several orders of magnitude lower than conventional oil reservoirs. The combination of multi-stage hydraulic fracturing and horizontal drilling has improved the overall profitability of these tight-oil reservoirs by enhancing the wellbore - matrix connectivity. Under primary production, however, the recovery factor remains in the range of only 5% to 10% of original oil in place (OOIP). Considering such a large resource base, even small improvements in productivity could lead to millions of barrels of additional oil. Therefore, the need to develop a viable enhanced oil recovery technique for unconventional oil reservoirs is evident.

This study investigates technical feasibility of carbon dioxide as an enhanced oil recovery agent for tight-oil reservoirs. Above minimum miscibility pressure (MMP), CO2 and oil are miscible leading to reduction in capillary forces and therefore high local displacement efficiency. The miscibility pressure of CO2 is also significantly lower than the pressure required for other gases, which makes CO2 miscible injection attainable under a broad spectrum of reservoir pressures.

The coreflood experiments recovered more than 70% of the OOIP from a Bakken core sample with an average porosity of 7.5% and permeability of 1.8 μd. CT scans at dual energies were used as an additional tool to visualize fluid flow and distribution at core level. We discovered that the impact of CO2 penetration is better captured at a lower energy level where the X-ray attenuation mechanism of photoelectric absorption becomes dominant. To decipher the oil recovery mechanisms in the coreflood experiment, a numerical compositional model was constructed to reproduce the laboratory results. Vaporization of light hydrocarbon components into CO2 is shown as a major recovery mechanism. Other controlling factors include re-pressurization, oil swelling, viscosity and interfacial tension reduction. History matching with the laboratory experiment introduces additional complexities such as rock heterogeneities and presence of a fracture that promotes flow perpendicular to the core length. The above issues need to be addressed to match the displacement process exactly.
Applications of Additive Manufacturing to Rock Analogue Fabrication
Authors: Anderson Timothy
Published: September 2016

Enhanced oil recovery (EOR) is an effective method of petroleum recovery, having been shown to extract up to 70% of original oil in place compared to the roughly 50% for conventional oils and less than 50% for unconventional resources such as heavy oil and shale oil obtainable through primary and waterflood recovery methods. Research problems in EOR are often ill-posed due to the large range of relevant spatial and time scales and strong nonlinearities in the physical systems. Consequently, EOR experiments suffer from a lack of repeatability: slight variations in the experimental parameters or environment, including porous medium heterogeneity, may lead to dramatically different outcomes, making it difficult to determine which results are spurious and which are meaningful. Additive manufacturing (3D printing) technology has enabled the unprecedented ability to create repeatable experimental samples. Using 3D printing technologies such as stereolithography, selective laser sintering, and fused deposition modeling, it has become possible to create porous media samples from a wide range of materials with a reliable level of accuracy and repeatability. In this study, we present several applications of additive manufacturing to creating repeatable rock analogues for EOR experiments. Specifically, we outline potential applications of 3D printing to in-situ combustion and microfluidic flow experiments. For in-situ combustion, we demonstrate the efficacy of powder bed printing for creating repeatable sandstone analogues with consistent porosity and permeability. For microfluidics, we show the potential of using 3D printing for producing repeatable rock replicas at-scale in three dimensions. We also present flow visualizations using scaled-up printed rock models of silicates and carbonates. Overall, 3D printing is a very promising technology for applications in EOR experiments. Based on the results of this study, we believe that with further research 3D printing will soon offer an unprecedented degree of experimental repeatability and ability to create representative solid surfaces for EOR research.
A Mechanistic Computational Fluid Dynamic CFD Model to Predict Hydrate Formation in Offshore Pipelines
Authors: Neto E. T.
Published: September 2016

In this paper, a mechanistic computational fluid dynamic (CFD) model has been developed in order to understand the controlling mechanisms of hydrate formation. The conservation of mass, momentum, and energy were solved in order to obtain the velocity, pressure, temperature, and concentration profiles along the pipeline so that not only phase equilibrium but also the transport phenomena could be incorporated in the analysis. To predict the rate at which hydrate particles are formed, a reaction kinetic model was coupled with the transport equations. Also, due to low solubility of methane in water, the mass transfer of methane from gas to liquid phase was considered based on a two-film theory. The results showed that not all the methane dissolved in liquid phase is converted into hydrate particles due to low residence time of reactants, which proves that equilibrium is not reached under operating conditions encountered in offshore pipelines and it could be possible explanation for metastable behavior observed in field operations.
Mechanical Characterization and Corrosion Effects on Glass Reinforced Vinyl Ester Liners used for Oil and Gas Production
Authors: Carpenter Cole
Published: September 2016

In this study, a glass reinforced vinyl ester (GRV) liner was systematically designed to produce a corrosion resistant, toughened, liner with superior corrosion resistance and strength characteristics. This GRV liner system was designed as an alternative to previously tested glass reinforced epoxy systems [1]. The composite liner could theoretically be used in conjunction with standardized oil and gas production tubing to alleviate the effects of corrosion in offshore exploration applications. This particular system was designed using netting analysis for filament wound pressure vessels and tested in accordance with ASTM D2290 split-disk procedures. To ensure that the finalized design would be capable of withstanding the immense pressures and temperatures seen during use in offshore oil and gas production, the project used an API controlled steel alloy already employed by industry as a benchmark for determining the necessary yield stress and internal yield pressure required for the proposed application. To further define the physical characteristics of the proposed system, tests were conducted to verify the coefficient of thermal expansion (CTE) of the composite material. The CTE data was then used to evaluate the potential for interfacial thermal stresses induced when bonding dissimilar materials at elevated temperatures. Furthermore, the vinyl ester composite was environmentally conditioned in accordance with ASTM G202 rotating cage procedures, and evaluated to assess the proposed system's susceptibility to degradation caused by corrosive fluids. The study was conducted with the intent to utilize the design principles of filament wound pressure vessels to produce an oil and gas production liner that emulates the strength characteristics of its steel counterpart, while retaining the corrosion resistance associated with vinyl ester matrix.
Post-Treatment Horizontal Hydraulic Fracture Modeling with Integrated Chemical Tracer Analysis, a Case Study
Authors: Dang Angela
Published: September 2016

As early as the 1950s, the need to track water in various applications, including stream water, sanitary systems, ground water, and oil field water flooding, resulted in the development of chemical tracer technologies. While the utilization of tracer technologies to track water during reservoir development is mature, the use of chemical tracers in unconventional hydraulic fracturing operations is relatively new. With the increasing use of chemical tracers in unconventional settings, questions related to proper execution, interpretation, and integration of chemical tracer tests arise.

This paper discusses the design and analysis of a chemical tracer study conducted in a section of the Wattenberg Field, Colorado. The results of the tracer study show that the preferential direction of cross-well tracer flow during hydraulic fracturing reflected the order of completion, rather than geology. They also show that large geologic features, such as a graben, facilitate cross-well tracer transport of water-based chemical tracers during fracturing. Minor faults and natural fractures facilitate cross-well transport of oil-based chemical tracers during production. Furthermore, the percentage of recovered tracers from different intervals along the wellbore (fractional production flowback) varies, which can reflect the contribution of that interval to the net production. Based on the analysis, suggestions on how to conduct a tracer study to obtain high quality data are provided.

This research also integrates the results of the tracer study into a post-treatment hydraulic fracturing model to evaluate production efficiency. Using the fractional production flowback results from the chemical tracer study, hydraulic fractures were calibrated to match the fractional production from each interval. The fracture model provides insight into what the hydraulic fractures look like, potential communication avenues for the chemical tracers, and production efficiency.
1D and 2D Modeling in Studying Petroleum Potential of the South Kara Basin
Authors: Kishankov Aleksei
Published: September 2016

Over the last years major petroleum fields in different regions of the world have been rapidly running out of their resources due to intensive production. Therefore, it is now essential to explore new territories and aquatories where large oil and gas accumulations could be revealed. One of the most effective methods of analyzing petroleum potential of prospective regions is basin modeling which consists in reconstruction of sediment deposition and formation of oil and gas accumulations by using special computer software.

The objective of this research was studying petroleum potential of the South Kara Basin of the Russian Arctic Shelf. The study included 1D modeling for the wells of the Leningrad Petroleum Field in the Kara Sea, the Bovanenkovo Field on the Yamal Peninsula and 2D modeling for the seismic lines crossing the region in different directions. The 1D models were calibrated with the present day parameters of vitrinite reflectance measured in the studied wells. Thus, appropriate heat flow values for the region were obtained and used for further 2D modeling. As a result of 2D modeling, hydrocarbon accumulations were obtained for several known structures of the region, including the discovered petroleum fields of the Kara Sea and the Yamal Peninsula. This fact could approve the validity of the created models. Therefore, the results of conducted modeling could be used for the forecast of petroleum potential of the region. As a consequence, presence of petroleum accumulations was confirmed for some local structures that had been revealed earlier by seismics. Moreover, the zones of distribution of accumulations with different phase composition were determined within the South Kara Basin. Local structures defined by the modeling were considered to be the most prospective objects for further petroleum exploration in the region.
Pattern Realignment Optimizes Waterflood in Thin Bed Sandstone
Authors: LeRoy Melissa
Published: September 2016

The objective of this study was to determine the remaining waterflood potential for a deep, thin-bed sandstone reservoir with an existing waterflood and to propose a plan to maximize the economics of future field performance. Little published information is available examining the waterflood potential of thin-bed sandstones. In addition, determining how much capital to allocate to increase secondary recovery depends on remaining reserves, an uncertain volume when differing calculation methods yield different values.

My study of the West Verden Hoxbar Unit in Caddo County, Oklahoma led to the conclusion that waterflooding this and similar thin-bed sandstones with 320-acre patterns can achieve secondary recovery factors of 10 to 25%. Downspacing these fields is not necessary because high vertical sweep efficiency allows for effective floods on this spacing. However, 320-acre pattern spacing is wide enough that areal sweep efficiency becomes the primary concern when attempting to increase secondary recovery volumes after breakthrough has occurred in existing flood patterns. The solution is to realign existing patterns by converting selected current producers to injectors, which allows for the production of hydrocarbons not initially contacted by the waterflood.

To determine whether this development plan is appropriate for a field, I recommend a workflow consisting primarily of decline curve and oil cut v. cumulative oil plot analysis, oil recovery v. water input plot interpretation and pattern analysis.

The dominant benefit of this approach to increasing recovery is that it does not require drilling new wells to increase production. Conversions can typically be implemented for 1/10 the cost of drilling a new well. My recommendations are currently being implemented in the West Verden Hoxbar Unit because my studies show that the conversions are economic at oil prices as low as $29/barrel, pay for themselves in less than 2 years, and extend the productive life of the field by over 10 years.
ANÁLISE DO DESEMPENHO E PARTICIPAÇÃO DA AGRICULTURA FAMILIAR NA AVICULTURA DE CORTE NA REGIÃO SUL DO RIO GRANDE DO SUL / BRASIL
Authors: Decker Sérgio Renato Ferreira , Gomes Mario Conill
Published: September 2016

RESUMOO presente estudo foi realizado junto à cadeia produtiva da avicultura de corte estabelecida na região sul do Rio Grande do Sul / Brasil, cuja indústria integradora está localizada no município de Morro Redondo/RS. O artigo, a partir de uma pesquisa bibliográfica e documental, apresenta uma análise da avicultura de corte no Brasil, no Rio Grande do Sul e por fim na Região Sul do RS. Realizou-se uma caracterização dos elos produtores e indústria, evidenciando-se no trabalho dados como: número de produtores, capacidade de produção, volume de produção e outros dados que revelam a importância econômica e social deste segmento. A base de produtores é essencialmente constituída por agricultores familiares e a avicultura é uma das principais atividades que garantem a sustentabilidade das oitenta e nove famílias que compõe a base de fornecimento da cadeia. Constata-se que a existe uma perspectiva promissora de crescimento, haja visto que a indústria está atuando no limite de sua capacidade e já possui projeto de duplicação da planta para os próximos anos. Desta forma, entendemos que a integração dos produtores familiares revela-se uma boa alternativa para o desenvolvimento da agricultura familiar da região.
Simulated Effects of Soil Texture on Nitrous Oxide Emission Factors from Corn and Soybean Agroecosystems in Wisconsin
Authors: Gaillard Richard , Duval Benjamin D. , Osterholz William R. , Kucharik Christopher J.
Published: September 2016

Soil texture is known to have an influence on the physical and biological processes that produce N2O emissions in agricultural fields, yet comparisons across soil textural types are limited by considerations of time and practicality. We used the DayCent biogeochemical model to assess the effects of soil texture on N2O emissions from agriculturally productive soils from four counties in Wisconsin. We validated the DayCent model using field data from 2 yr of a long‐term (approximately 20‐yr) cropping systems trial and then simulated yield and N2O emissions from continuous corn (Zea mays L.) and corn–soybean (Glycine max L.) cropping systems across 35 Wisconsin soil series classified as either silt loam, sandy loam, or loamy sand. Silt loam soils had the highest N2O emissions of all soil types, exhibiting 80 to 158% greater mean emissions and 100 to 282% greater emission factors compared with loamy sand and sandy loam soils, respectively. The model predicts that for these soils under these cropping systems, denitrification constituted the majority of the N2O flux only in the silt loam soils. However, across all soil textures, locations, and years, denitrification explained the most variation (74–98%) in total N2O emissions. Our results suggest that soil texture is an important factor in determining a range of N2O emission characteristics and is critical for estimating future N2O emissions from agricultural fields.

Core Ideas

Soil texture influences agricultural N2O emissions and emission factors.

Soil texture influences absolute and relative rates of nitrification and denitrification.

Understanding soil texture effects is vital to estimating N losses via N2O.
Fifteen Years of Nitrogen Leaching from a Kentucky Bluegrass Turf
Authors: Frank Kevin W. , Crum James R. , Bryan Jeff M. , Hathaway Aaron D.
Published: September 2016

Most research on nitrate‐nitrogen (NO3–N) leaching in turfgrass was conducted on recently established sites and indicates that leaching poses little risk to the environment. The potential for greater NO3–N leaching from mature turf sites is relatively unknown. Nitrogen (N) leaching from a Kentucky bluegrass (Poa pratensis L.) turf was measured for 15 yr using monolith lysimeters. From 1998 through 2002, half of the lysimeters were treated annually with urea at a high rate of 245 kg N ha−1 (49 kg N ha−1 application−1) and half of the lysimeters were treated at a low rate of 98 kg N ha−1 (24.5 kg N ha−1 application−1). Flow‐weighted mean NO3–N concentrations in leachate for the low N rate were below 5 mg L−1 for every year but one of the 15 yr of research. For the high N rate, NO3–N concentrations in leachate for many dates from 2000 through 2002 were higher than the drinking water quality maximum contaminant level of 10 mg L−1. Due to high concentrations of NO3–N in leachate, the high N rate was reduced from 245 to 196 kg ha−1yr−1 in 2003. From 2004 through 2013, there was a decline in NO3–N leaching. For both N rates, the flow‐weighted mean NO3–N concentration in 2013 was less than in 1998, when the research was initiated. This research indicates that, as a turfgrass system ages, there is a critical annual N rate, above which NO3–N concentration in leachate may exceed the maximum contaminant level, and below which there is minimal risk.