bluuebunny/crossref_metadata_2025 huggingface dataset:
New Steady-State Technique for Measuring Shale Core Plug Permeability
Authors: Zamirian M. , Aminian K. , Ameri S. , Fathi E.
Published: September 2014

This paper introduces a new, fast and robust technique that measures permeability of shale plug samples under steady-state condition. A laboratory set-up was designed and assembled which has a resolution of one millionth standard cubic centimeters per second for gas flow rate and one hundredth cubic centimeters for pore volume measurement. Extremely accurate differential transducers are used to measure the flow of gas passing through the core samples under in-situ conditions. The in-situ conditions are achieved by maintaining isothermal conditions and the application of the confining stress on the core sample. The laboratory set-up is fully automated to eliminate any human error and more importantly maintains the temperature stable within the enclosed unit. In this technique, the permeability is determined under wide range of pore and confining pressure. Klinkenberg and modified Klinkenberg methods can be then applied to evaluate the absolute permeability. When adsorbent gases such as CO2 and CH4 are used, this technique can provide the permeability hysteresis for adsorption and desorption processes. Finally, the laboratory set-up can be used to measure porosity, based on Boyle's law, formation compressibility and the sorption parameters. In this study, the laboratory set-up was used to measure permeability and porosity of Marcellus Shale core samples under wide range of pore and confining pressures using Helium as a non-adsorbent and Nitrogen and Carbon Dioxide as adsorbent gases. Both Klinkenberg and modified Klinkenberg techniques were applied to the gas permeability measurement results to obtain the absolute permeability. The permeability and porosity of the samples were found to be significantly impacted by the net stress. In contrast to porosity, the permeability exhibited hysteresis with respect to net stress.
Hydraulic Fracturing: A Marcellus Case Study of an Engineered Staging Completion Based on Rock Properties
Authors: Lim Pascal , Goddard Peter , Sink John , Abou-Sayed Ibrahim
Published: September 2014

In multi-fractured horizontal wells, the wellbore is segmented into stages that are stimulated separately. This segmentation is traditionally geometrically based on a specific stage length ("geometric staging"); which is usually determined by trial and error including cost and production history considerations. However, this approach does not take geological and geomechanical properties into account. An alternative method for staging ("engineered staging") uses these properties to determine the wellbore segmentation by grouping intervals with similar rock properties together; theoretically promoting a higher percentage of stimulated clusters and subsequently better production. This alternative method is not commonly used as data acquisition can be costly for a large group of wells.

In Pennsylvania, two pairs of wells were completed in order to understand the added value of engineered staging design. In one of them, a comprehensive suite of openhole logs was run in the horizontal leg of a dry gas well. The staging was then designed according to the measured rock properties and the well was stimulated using slickwater with plug and perf. Finally, a production log was run in the well after a year in order to determine the downhole contribution of each stage and cluster. After 400 days of production, the well cumulative production outperforms its offset with geometric staging by around 5 to 7%, potentially attributable to the engineered design but still within the expected statistical regional deviation between wells. Long term impact is yet to be determined.

In the other pair, no openhole log other than MWD Gamma-ray was run. However properties were projected from a nearby vertical pilot hole with logs onto the horizontal section of a well which was then completed using the engineered staging method. Here again production figures after a year are showing a potential benefit; but this time without the cost of data acquisition in the lateral.

This paper describes the process that was applied to achieve the engineered staging of these wells. It details the initial geological and geomechanical data acquisition or projection; then describes the design of the hydraulic fracturing engineered staging and finally discusses the performance of the wells.
Factors Controlling Fluid Migration and Distribution in the Eagle Ford Shale
Authors: Ramirez John , Aguilera Roberto
Published: September 2014

Production of shale and tight oil is the cornerstone of the United States race for energy independence. According to the U.S. Energy Information Administration (EIA) nearly 90% of the oil production growth comes from six tight oil plays. The Eagle Ford is one of these plays and accounts for 33% of the oil production growth with a contribution of 1.3 million barrels per day.

A geological challenge in the Eagle Ford shale is the unconventional fluids distribution: shallower in the structure there is black oil, deeper and to the south condensate appears, and at the bottom dry gas can be found. Differences in burial depth, temperature, and vitrinite reflectance are used to explain this unique distribution. A similar fluid distribution occurs in other reservoirs (e.g. Duvernay shale in Canada).

The above observations led to the key objective of this paper: to identify the main factors that control fluid migration (due to buoyancy of gas in oil) from one zone to another. This was done by constructing a conceptual cross sectional simulation model with NW to SE orientation that allowed the study of fluid migration and distribution throughout one million years while maintaining computational time within reasonable limits.

The input data used for the model were gathered from published work in the geoscience and petroleum engineering literature. Results show that although there is some gas migration through fractures to the top of the structure, fluids in the matrix remained with approximately the same original distribution. This fluid migration through fractures could be responsible for higher initial gas production in some oil wells in the top of the structure.

Results show that ultralow permeability, low porosity, and low natural fracturing are the main restrictions for fluid migration in the Eagle Ford shale.
In-Situ and Induced Stresses in the Development of Unconventional Resources
Authors: Han H. , Higgins-Borchardt S. , Mata D. , Gonzales V.
Published: September 2014

Multistage hydraulic fracture stimulation of horizontal wells often results in asymmetric hydraulic fractures, which are suboptimal for draining reservoirs. Field observations suggest that hydraulic fractures grow further than expected toward, and sometimes up to and beyond, adjacent producing wells. Such interference from nearby wells is of increasing importance in densely drilled unconventional reservoirs, where hydraulic fracturing is common. Eventually, the underlying mechanism needs to be factored into well spacing plans and hydraulic fracture treatment designs, which can either mitigate the undesired consequences of the nonvirgin conditions, or take advantage of them.

An integrated approach has been developed to quantify depletion-induced stresses. In this approach, a three-dimensional (3D) Mechanical Earth Model (MEM) is constructed using the finite-element method to initialize the in-situ stresses. Coupled simulation between the dynamic reservoir model and the geomechanical model is used to quantify stress variation, induced by pressure depletion of the parent well. The altered stress profile is then used as input to a hydraulic fracture design.

The methodology has been applied to an unconventional resource play in the Williston Basin in North America. In this example, three adjacent horizontal wells were hydraulically fractured and put on production sequentially within four years. The analysis indicated that the minimum horizontal stress decreased in the area between a newly drilled well and the nearby producing well; whereas the area on the opposite side of the new well showed no obvious stress variations. Formations above and below the depletion zone experienced an increase of minimum horizontal stress as a balance effect of the finite-element calculation. Fracture modeling using the depletion-induced stresses showed that the effective half-length of the fracture directed toward the depleted well can extend up to two times the length of the hydaulic fracture in the opposite direction.
Building Meaningful Upstream Representations for the LNG Supply Chain
Authors: Kirk Graham , Wieclawek Kristian , Cameron P.
Published: September 2014

Over the last decade, breakthroughs in new oil and gas technologies have helped access untapped resources and allowed for their economic production. Through horizontal drilling and new completion techniques, gas trapped in low permeability tight shales is now accessible. Higher world gas prices have made gas liquefaction economic, facilitating transport of liquefied natural gas (LNG) to overseas markets. Technology, coupled with supply and demand, has initiated a new generation of mega-projects around the globe. These projects encompass the entire supply chain, from field development to pipelines feeding the LNG facilities, to shipping the product to market. As the global market for natural gas continues to grow, there is tremendous investment potential. However, due to complexities involved, accurate modeling is critical to understand the best investment strategy and to minimize risk.

This paper will explore the intricacies involved in modeling upstream field development and the scenarios required to provide reasonable estimates of the upstream asset that will feed the rest of the LNG chain. We will look at the entire upstream asset from the investor's point of view, including investment required, growth potential, and long-term sustainability. We will compare how different decisions in field selection and development rate impact overall value. This paper will highlight the importance of using technical expertise, high quality data and specialized modeling software to produce a meaningful representation of an upstream development plan.
A Flowback-Guided Approach for Production Data Analysis in Tight Reservoirs
Authors: Ezulike O. D. , Dehghanpour H. , Virues C. J. , Hawkes R. V.
Published: September 2014

One key limitation of conventional production data analysis (PDA) is non-uniqueness of solution. This can cause huge uncertainty in reservoir parameter estimates and hydrocarbon forecasts. Hence, there is need for an alternative approach to PDA. This paper tackles this issue using flowback data analysis (FDA) as a constraint to guide PDA. We recently extended the existing linear dual-porosity model (DPM) to develop a flowback analysis model (FAM). Here, we intend to i) test the accuracy of FAM to predict gas production in the field, and ii) investigate how the results from its application on flowback data could reduce the uncertainty associated with conventional PDA.

This study applies FAM to history match 2-phase flowback data from three multifractured shale-gas wells completed in the Horn River Basin. The history match estimatesFAM estimates effective half-length and initial gas-volume in hydraulic-fractures before flowback. It is also used to forecasts post-flowback gas production. This forecast is verified by comparing it actual post-flowback production data. An independent single-phase PDA on post-flowback production data from the same shale-gas wells overestimates hydraulic fracture(HF) half-lengths compared to the FAM history-match results. This could be a result of the presence of water plugged secondary fractures with negligible communication interface with the hydraulic fractures during flowback. The interface significantly increases during post-flowback production periods as water gives way to gas from the matrix. One key result of this study is that HF half-lengths from PDA could significantly differ from those from post-flowback PDA.

It is more appropriate to interpret both flowback and production data using a single multiphase model. FAM is an example of such models that captures the "necessary" physics for both flowback and production operations. PDA without considering flowback data could lead to inaccurate results. This study shows how to perform a robust flowback-data-analysis that complements PDA for comprehensive fracture/reservoir characterization. These results encourage the industry to start careful and accurate measurement of rate + pressure immediately after opening wells for flowback.
Well Spacing Optimization in Eagle Ford
Authors: Lalehrokh F. , Bouma J.
Published: September 2014

Due to the ultra-low permeability in shale reservoirs, hydraulic fractures are developed to provide secondary permeability to increase production in horizontal wells. Well spacing is a key factor in maximizing the net present value (NPV) of a shale reservoir utilizing horizontally fractured wells. The dilemma is that the wells should be spaced close enough together to maximize the total stimulated area and drain the entire section in a timely manner, yet on the other hand, far enough from each other to minimize the chance of fracture hits by offset wells or overlapping the drainage area of a nearby well to avoid over-capitalization.

The Eagle Ford shale has become a major resource play in North America and has become the focus of exploration and drilling activity for several oil and gas operators. Numerous studies have been performed to optimize well placement in shale gas reservoirs but unfortunately few have been conducted in reservoirs with multi-phase flow of oil and gas. The purpose of this paper is to find a balance between maximizing the stimulated area without over-capitalizing the play. Three distinctively different, real scenarios have been selected to study the effect of well spacing on estimated ultimate recovery (EUR) and ultimately on NPV. Also, a sensitivity study has been performed to analyze the effect of reservoir permeability and fracture half-length on optimal well spacing. The dimensionless metric, discounted profitability index (DPI), is also used in conjunction with NPV to ensure that while trying to maximize the NPV of the asset, the incremental investment decision still meets corporate economic thresholds and competes for capital within the portfolio.

Based on the reservoir simulation and economic analysis, well spacing of 330 ft and 400 ft maximizes the NPV of a black oil Eagle Ford reservoir by assuming 50 nD reservoir permeability and fracture half-length of 100 and 150 ft, respectively. Well spacing of between 400ft and 450 ft maximizes the NPV in the retrograde gas case study. Detailed results are also provided to illustrate the effect of fracture half-length, reservoir permeability as well as oil price variation.
Improvement in Permeability Models for Unconventional Gas Reservoirs and Model Selection Using Statistical Analysis
Authors: Haghshenas B. , Clarkson C. R. , Bergerson J. , Chen S. , Pan Z.
Published: September 2014

Unconventional gas reservoirs have complex storage and transport properties that are difficult to characterize and are dynamic. The large internal surface area of nano-scale organic pores gives them the capability to store adsorbed gas along with free gas, with the amount of free gas storage changing as a function of adsorption/desorption. Further, diffusion and slippage mechanisms compete with compression and possibly matrix shrinkage effects to alter absolute permeability of the organic matter pores. An additional factor controlling permeability change, which has not been previously considered, is the change of effective radius of organic matter pores as a function of adsorption/desorption. A statistical study is required to fully explore the overall effect of the above mentioned parameters on unconventional gas well production performance, along with other properties such as total carbon content, pore connectivity configuration, adsorption capacity, pore size distribution, and natural fracture intensity.

In this study we investigate two sets of matrix pore sizes thought to represent a reasonable range observed in unconventional gas reservoirs. Pore size affects the interaction between the gas molecules and pore walls and results in a distribution of adsorbed phase thickness. Therefore, the adsorbed layer modifies the effective hydraulic radius for flow of gas which in turn alters the effective permeability to the gas phase in organic matter pores. This complexity can be captured by combining the simplified local density model and apparent permeability approaches. The contribution of compression and matrix shrinkage to fracture permeability change with pressure is also investigated and compared to changes in apparent permeability in the matrix caused by diffusion and slippage mechanisms.

A commercial reservoir simulator is used to study the effects of pore size and pore size alteration, and consequent permeability changes, on unconventional gas well performance. A screening statistical method is used to quantify the relative importance of each factor.

The results of this study will help the engineers evaluate the relative importance of all of the permeability-altering processes that can affect unconventional gas well performance, and make appropriate simplifying assumptions. This will enable them to prioritize history matching parameters for real production data analyses and forecasting, which in turn decreases the time required for a complete field simulation study.
Understanding the Origin of Flowback Salts: A Laboratory and Field Study
Authors: Zolfaghari Sharak Ashkan , Noel Mike , Dehghanpour Hassan , Bearinger Doug
Published: September 2014

Several past studies have focused on the saline flowback water to evaluate the hydraulic fracturing operations. The origin of the salts in the flowback water is important for the assessment of the flowback process. In this study, laboratory and field analyses are performed to provide a better understanding about the origin of the flowback salts.

The field study analyzes the total salt concentration (salinity) and ion concentration data measured during the flowback process for the Muskwa (Mu), Otter-Park (OP), and Evie (Ev) formations. The concentration profiles of both the barium and chloride during the flowback process, whereas the iron concentration declines after experiencing an initial increase.

The laboratory study encompasses contact angle, XRD, imbibition, individual ion concentration, surface element, and adsorption isotherm experiments for samples from the OP and Ev formations. To investigate the effects of fluid-rock interface area on the liquid uptake and diffusion rate of individual ions, a series of imbibition experiments are carried out for different values of surface to volume ratios (specific surface or "Asp"). The electrical conductivity and individual ion concentrations are measured during the imbibition process. XRD data is analyzed to determine the mineralogy of the samples. SEM-EDX analysis is performed to determine the distribution of the elements on fresh break and natural fracture surfaces of the samples (in addition to a sample from the Lower Keg (LK) formation). Finally, since both ion transfer and water adsorption processes occur during the imbibition experiment, an adsorption isotherm experiment is carried out to prevent the ion transfer into/out of the rock in order to solely study the water adsorption process. The laboratory results show that barium is mainly concentrated in the natural fractures; and therefore the shape of the barium concentration profile in the flowback water maybe an indication of the complexity of the fracture network.
Understanding the Optimum Fracture Conductivity for Naturally Fractured Shale and Tight Reservoirs
Authors: Gu Ming , Kulkarni Pandurang , Rafiee Mehdi , Ivarrud Endre , Mohanty Kishore
Published: September 2014

With the development of unconventional shale and tight reservoirs, stimulation treatments that place multiple transverse fractures have received a greater attention in recent years. The post-frac productivity of such low-permeability reservoirs is largely determined by the matrix-fracture contact area with appropriate fracture conductivity. Although it is often anticipated that the fractures are infinitely conductive, the general belief is that the production increases with the proppant amount injected.

This paper presents an approach to assess the optimum proppant amount injected by determining the post-frac conductivity. First, using three-dimensional finite difference reservoir simulations in a naturally fractured reservoir, which has both the hydraulic fracture and natural fractures modeled explicitly as discrete grid blocks, we find cumulative production as a function of fracture conductivity. For a fixed propped length and production time, we observe a critical conductivity beyond which the production is insensitive to the conductivity. The critical conductivity is then obtained as a function of the propped length and production time. The numerical results show that the critical conductivity increases with propped length and decreases with production time. The effect of stimulated natural fracture properties (intensity and permeability) on the critical conductivity is then investigated. For reservoirs with matrix permeability in the range 20-1000 nD, natural fractures increase the short-term critical conductivity but decrease the medium to long-term ones. The paper also evaluates the influence of water production, cluster spacing, and BHP flowing pressure on the critical conductivity.

This study demonstrates that Agarwal type curves based on linear flow are not appropriate for naturally fractured reservoirs and lead to errors in estimation of critical conductivity. The results of this study can be useful for selecting the type and amount of proppant for stimulation of unconventional reservoirs.
Interrelationship of Weak Organic Acids, Bases, pH and HPLC Analysis Method in Produced Waters
Authors: Weissenberger Markus C. , Dhillon Sukhmeet
Published: September 2014

Weak Organic acids, such as acetic or formic acid, are ubiquitous in produced waters from petroleum-producing basins. Although the absolute concentrations of individual short-chain acids vary over many orders of magnitude the concentration can reach up to 1000 mg/L or more. It is known that weak organic acids influence the pH and alkalinity of a given water significantly, because they act as a buffer. Therefore the hydration and gelation of Guar based fracturing fluids could be affected. As the industry trend is to use more produced water as a base fluid for fracturing fluids, it is of interest to measure the concentration of different weak organic acids in produced waters and determine their influence on the hydration and gelation of fracturing fluids.

The chosen measurement system was a HPLC system with a standard hydrophobic C18 column and sodium dihydrogen phosphate as mobile phase. The method was calibrated for formic acid, acetic acid, propionic acid and butyric acid, as these for weak organic acids are the most common naturally occurring species. With this analytical method we were able to detect and determine the weak organic acid concentration in different produced waters up to a few mg/L. The high concentration of sodium and chloride ions could cause a matrix problem and hinder the correct analysis. In order to eliminate this influence the reversed-phase method was chosen. By this it was possible to detect also low concentrations of organic acids in high salinity produced waters.
Integrating Active and Passive Seismic Data to Better Predict Hydraulic Fracturing
Authors: Castillo G. , Chesser K. , Bouziat A. , Oliver G. , Ly C. V. , Kuo L. , Bathellier E.
Published: September 2014

Although drilling has slowed substantially from its peak in 2010, steadily improving natural gas prices coupled with the promise of demand from liquefied natural gas and gas to liquids facilities have renewed interest in the prolific Haynesville shale gas play in NW Louisiana. A consensus of opinion among operators in the field will agree that only a fraction of the Haynesville potential has been developed to date. As is the case in most shale plays, production from wells has been highly variable, leading to the use of 3D seismic reservoir characterization studies for the determination of sweet spots, well placement and completion strategies where seismic anisotropy has been proven to be an important factor in understanding the shale plays. This paper illustrates a workflow (Figure 1) integrating reservoir and geomechanical properties obtained from pre-stack seismic inversion and incorporating stress and fracture information extracted from azimuthal analysis of the seismic data. Eight wells in the area targeting the Haynesville and mid-Bossier reservoirs were used for calibration of surface seismic measurements of reservoir and geomechanical properties. A variety of seismically derived attributes are used to estimate production potential in the field. This paper shows the application of global azimuthal inversion, a technology for extracting the azimuthal anisotropy. Above all, the workflow makes quantitative use of microseismic and SEM (Scanning Electron Microscope) derived mineralogy data to validate the seismic-derived attributes.

Figure 1 Integrated geoscience workflow for a shale play, incorporating numerous discipline to high-grade the survey area to identify ‘sweet spots’ and optimize drilling locations and completions.
Multiphase Rate Transient Analysis in Unconventional Reservoirs: Theory and Applications
Authors: Eker Ilkay , Kurtoglu Basak , Kazemi Hossein
Published: September 2014

In unconventional reservoirs, production data is generally analyzed using rate transient techniques based on single-phase linear flow models. Such linear flow models use rate-normalized pressure, which is pressure drop divided by reservoir flow rate versus square root of time. In practice, the well fluid production includes water, oil and gas. The oil can be light oil, volatile oil, and gas-condensate as in Bakken, Eagle Ford, and Barnett. Thus, single-phase analysis needs modification to account for production of fluid mixtures.

This paper presents a new approach to analyze multi-phase flow in single and dual-porosity models of unconventional reservoirs. In addition to oil, gas and formation brine, the method accounts for gas condensate production, and the flowback of the injected hydraulic fracturing fluid. Overall, the proposed approach is more comprehensive than the single-phase models but maintains the simplicity of the conventional methods.

The paper includes a workflow and several diagnostic plots for light oils to gas condensates in unconventional reservoirs. Flow rate transient data from two Bakken and Eagle Ford wells will be presented to demonstrate the usefulness of our models. In addition to the mathematical analysis of flow rate and pressure data, we will explain well stimulation configuration and fluid lift methods influence the flow rate history of the Bakken and Eagle Ford wells.
Influence of Friction Reducer on Scale Inhibitor Performance and Scaling Tendency in Slickwater Fracturing
Authors: Ozuruigbo Chioma Q. , Fan Chunfang
Published: September 2014

Slickwater fracturing generally contains approximately 95% sand and 5% other production chemicals, such as scale inhibitor (SI), friction reducers (FRs), surfactants, etc. It is important to study the effect of FRs on SI inhibition performance because of the interactions between both chemicals when pumped together during slickwater fracturing treatments.

Most FRs used in the industry are usually a combination of polyacrylamide- (PAM-) based polymers, acrylic acids, and acrylamido-methyl-propane sulfonate polymer (AMPS) copolymers, which readily interact with components of SIs. This paper examines the effect of FRs on SI performance and the scaling tendency of produced water. Conclusions drawn regarding static bottle tests, dynamic tube blocking tests, and inductively coupled plasma (ICP) analysis of data from a series of performance tests under reservoir conditions are discussed. The laboratory methods used to qualify and measure the performance of the SIs during these tests are also discussed.

Tests were conducted using produced water brine from the Rulison field in Colorado. The testing results demonstrated diminished performance of SI when combined with a FR. Five SIs of different chemistries were run to observe the resulting performance effects of the SIs with and without FRs. Static bottle tests conducted using only SIs exhibited a minimum effective concentration (MEC) of ≥ 20 to 50 ppm for complete scale control. With the addition of 0.25 gpt of FRs, the MEC increased to approximately 100 to 250 ppm for the different SIs based on ICP elemental analysis data. Additionally, the test results demonstrate that a denser amount of solid precipitation occurs with the combination of both FR and SI. Results obtained from this study provide more awareness to the resulting effects of combining these fracturing fluids during slickwater fracturing. This work provides insight into making proper scale control decisions, particularly when SIs and FR are pumped simultaneously, thereby helping reduce damage.
Integrated Characterization of Hydraulically Fractured Shale Gas Reservoirs Production History Matching
Authors: Nejadi Siavash , Leung Juliana Y. , Trivedi Japan J. , Virues Claudio.J. J
Published: September 2014

Advancements in horizontal well drilling and multistage hydraulic fracturing have made gas production from tight formations economically viable. Reservoir simulation models play an important role in the production forecasting and field development planning. To enhance their predictive capabilities and capture the uncertainties in model parameters, stochastic reservoir models should be calibrated to both geologic and flow observations.

In this paper, a novel approach to characterization and history matching of hydrocarbon production from a hydraulic fractured shale gas is presented. This new methodology includes generating multiple discrete fracture network (DFN) models, upscaling the models for numerical multiphase flow simulation, and updating the DFN model parameters using dynamic flow responses. First, measurements from hydraulic fracture treatment, petrophysical interpretation, and in-situ stress data are used to estimate the initial probability distribution of hydraulic and induced micro fractures parameters, and multiple initial DFN models are generated. Next, the DFN models are upscaled into an equivalent continuum dual porosity model using either analytical (Oda) or flow-based techniques. The upscaled models are subjected to the flow simulation, and their production performances are compared to the actual responses. Finally, an assisted history matching algorithm is implemented to assess the uncertainties of the DFN model parameters. Hydraulic fracture parameters including half-length, shape, and conductivity are updated together with the length, conductivity, intensity, and spatial distribution of the induced fractures are optimized in the algorithm.

The proposed methodology is applied to facilitate characterization of fracture parameters of a multi-fractured shale gas well in the Horn River basin. Fracture parameters and stimulated reservoir volume (SRV) derived from the updated DFN models are in agreement with estimates from micro-seismic interpretation and rate transient analysis. The key advantage of this integrated assisted history matching approach is that uncertainties in fracture parameters are represented by the multiple equall-probable DFN models and their upscaled flow simulation models, which honor the hard data and match the dynamic production history. This work highlights the significance of uncertainties in SRV and hydraulic fracture parameters. It also provides insight into the value of micro-seismic data when integrated in a rigorous production history matching workflow.
Benefits of Controlled Hydraulic Fracture Placement: Theory and Field Experiment
Authors: Desroches J. , Lecampion B. , Ramakrishnan H. , Prioul R. , Brown E.
Published: September 2014

Today, shale reservoirs are completed with multiple hydraulic fractures. For efficiency reasons, hydraulic fracturing is typically "staged", each stage comprising of multiple perforation clusters with the aim of initiating one hydraulic fracture per cluster. Cluster spacing is an important parameter to optimize, but the following is still unanswered: What is the minimum spacing that can be achieved between hydraulic fractures, given that both formation heterogeneity and stress shadow play a governing role? This paper uses a new model for the simultaneous initiation and propagation of hydraulic fractures from a horizontal well. Based on this model and observed field results from a well completed with 92 single-entry fracture treatments, new insights on the lack of robustness associated with multiple cluster plug-and-perf completion are presented. Without a large perforation friction pressure drop, there is a minimum spacing of clusters below which, fractures are "shut down" by the stress shadow effect. The stress shadow can, however, be mitigated with a large perforation pressure drop when there is no stress variation between clusters. Moreover, significant stress variations along clusters can be overcome by engineering the limited entry technique (choking down clusters in low stress zones), provided that the corresponding stress variations are known.

The limited entry technique however fails to enable hydraulic fracture initiation and development from all of the perforation clusters if there is a significant variation of near-wellbore pressure drop associated with the complexity of the fracture geometry in the near-wellbore when re-orienting toward the far-field in-situ stress direction.

Downhole pressure measurements from an experimental well completed with 92 single-entry fractures show large variations in near-wellbore pressure drop, highly correlated with the variations in breakdown pressures even though the stress variation estimated from the mineralogy are very small along the lateral. Had this well been completed with stages of 4 clusters each, a significant portion of the clusters would not have initiated and most of the slurry would have been taken by less than half of the clusters. Using the single-entry fracturing technique, each of the perforation clusters has initiated and propagated fractures as designed.
Successful Application of Horizontal Through Pipe Petrophysical Technology to Model the Montney Formation
Authors: Kramer Hermann , Yaxley Tiffiny , Williams Jay , Nevokshonoff Glen , Haysom Steve
Published: September 2014

Worldwide the oil and gas industry acknowledges that technology is, and will continue to be, the driving force in allowing oil and gas producers and service companies; to continue to deliver results that will improve production performance in a safe, environmentally sound and cost-effective manner. This is especially true for unconventional producers who are also faced with unlocking the technical challenges of unconventional reservoirs.

To aid in evaluating the Montney liquids-rich resource play, a new through pipe well logging technology was utilized to provide reservoir formation log data through drill pipe on new horizontal wells and through casing on a vertical well. This technology was run in the 7GEN KAKWA 13-24-65-5W6 cased vertical well, then compared to open hole well logs and to core data, both standard and special core analysis. The same through drill pipe logs were run in 14 horizontal wells in the Kakwa and Karr fields. The data collected in the horizontal wells was compared to the vertical core well and to the strip log data on each well. Calibration of the vertical though casing log data to core analysis provides an accurate determination of the reservoir properties in the lateral section of the horizontal wells.

The cost / benefit of utilizing through pipe technology was analyzed. The analysis took into consideration direct and indirect costs associated with data collection and risks associated with horizontal data collection.  By evaluating the associated costs and risks it was determined that through pipe data acquisition provides much lower risks and costs less than other data acquisition methods.
Carbon Dioxide and Nitrous Oxide Emissions Impacted by Bioenergy Sorghum Management
Authors: Storlien Joseph O. , Hons Frank M. , Wight Jason P. , Heilman James L.
Published: September 2014

Modern bioenergy feedstocks, such as bioenergy sorghum [Sorghum bicolor (L.) Moench], are being developed to supply future cellulosic biofuel demands. How these cropping systems impact greenhouse gas (GHG) emission of CO2 and N2O from the soil is unknown and field research is necessary to elucidate the effects of agronomic management practices on soil trace gas emissions. We studied the effects of N fertilization (0 vs. 280 kg urea‐N ha−1), residue management (0 vs. 50% of sorghum biomass returned), crop sequence (corn [Zea mays L.]–sorghum vs. sorghum–sorghum), and their interactions on CO2 and N2O emissions from bioenergy production scenarios on a Weswood (fine‐silty, mixed, superactive, thermic Udifluventic Haplustept) silty clay loam soil in central Texas. Gas fluxes were measured approximately weekly throughout the 2010 and 2011 growing season and at a reduced rate during the fallow season with a photoacoustic gas analyzer integrated with a static chamber. Overall, CO2 and N2O fluxes were relatively higher than those observed by others in the United States despite drought conditions throughout much of 2010 and 2011. Highest emissions of both gases were observed during the growing season, often following a precipitation–irrigation event and shortly after N fertilization. Residue return increased cumulative CO2 emissions each year, probably due to increased heterotrophic microbial activity. Nitrogen addition significantly increased cumulative emissions of N2O both years but only impacted cumulative CO2 emissions in 2011. While crop rotation impacted biomass yield, it had no significant effect on cumulative CO2 or N2O emissions. Additional research is needed to identify the optimal N and residue application rates that provide high yields with minimal soil GHG emissions and aid in sustaining long‐term soil quality.
The impact of digital elevation model and land use spatial information on Hydrologic Simulation Program-FORTRAN – predicted stream flow and sediment uncertainty
Authors: Wang Huiliang , Li Xuyong , Li Wenzan , Du Xinzhong
Published: September 2014

The Hydrologic Simulation Program-FORTRAN (HSPF) model is widely used to develop management strategies for water resources. The spatial resolution of the input data used to parameterize the HSPF model may lead to uncertainty in model outputs. In this study, we evaluated the impact of the spatial resolution of the digital elevation model (DEM) and land use data on uncertainty in HSPF-predicted flow and sediment. The resolution of DEMs can affect stream length, watershed area, and average slope, while the resolution of land use data can influence the distribution of land use information. Results showed that DEMs and land use maps with finer resolutions generated higher flow volumes and sediment loads. There was a non-linear relationship between changes in resolution of the DEM and land use data and changes in the uncertainty of predicted flow and sediment loads. Relative error was used to describe model uncertainty and the probability density function was used to estimate these uncertainties. The best-fit distributions of uncertainty in modeled flow and sediment related to DEM and land use data resolution were the generalized Pareto distribution and the Johnson SB distribution, respectively. The results of this study provide useful information for better understanding and estimating uncertainties in the HSPF model.
Optimising the modelling of eutrophication for Bohai Bay based on the cellular automata – support vector machine method
Authors: Dongsheng Zheng , Xianquan Xiang , Jianhua Tao
Published: September 2014

With the development of marine economy, eutrophication has become one of the key issues in the marine environment. In this paper, a eutrophication model for Bohai Bay based on the cellular automata-support vector machine (CA-SVM) has been established by applying the soft computing approach with a large quantity of remote sensing data to the marine environment. In order to optimise the coupled model further, two main tasks have been done in this study. First, to choose reasonable influence factors as the input parameters of the model, nine series of training and simulation exercises were conducted based on nine different types of input parameter combinations. A reasonable input parameter combination was selected, and the eutrophication model (the basic model) was established by the comparative analysis of the simulation results. Second, according to Shelford's Law of Tolerance, an optimised model was developed. It is combined of nine special models and each model corresponds to a stage of sea surface temperature and the chlorophyll-a concentration, respectively. The comparison between the optimised model and the basic model indicated that prediction accuracy was improved by the optimised model. By this study, it can be observed this model could provide a scientific basis for the prediction and management of the aquatic environment of Bohai Bay.
Multi-objective rehabilitation of urban drainage systems under uncertainties
Authors: Vojinovic Z. , Sahlu S. , Torres A. S. , Seyoum S. D. , Anvarifar F. , Matungulu H. , Barreto W. , Savic D. , Kapelan Z.
Published: September 2014

Urban drainage systems are subject to many drivers which can affect their performance and functioning. Typically, climate change, urbanisation and population growth along with aging of pipes may lead to uncontrollable discharges and surface flooding. So far, many researchers and practitioners concerned with optimal design and rehabilitation of urban drainage systems have applied deterministic approaches which treat input parameters as fixed values. However, due to the variety of uncertainties associated with input parameters, such approaches can easily lead to either over-dimensioning or under-dimensioning of drainage networks. The present paper deals with such issues and describes a methodology that has been developed to accommodate the effects of uncertainties into the design and rehabilitation of drainage systems. The paper presents a methodology that can take into account uncertainties from climate change, urbanisation, population growth and aging of pipes. The methodology is applied and tested on a case study of Dhaka, Bangladesh. The urban drainage network optimisation problem is posed as a multi-objective problem for which the objective functions are formulated to minimise damage costs and intervention costs. Two approaches were evaluated and the results show that both approaches are capable of identifying optimal Pareto fronts.
Detection of Legionella by cultivation and quantitative real-time polymerase chain reaction in biological waste water treatment plants in Norway
Authors: Lund Vidar , Fonahn Wenche , Pettersen Jens Erik , Caugant Dominique A. , Ask Eirik , Nysaeter Åse
Published: September 2014

Cases of Legionnaires' disease associated with biological treatment plants (BTPs) have been reported in six countries between 1997 and 2010. However, knowledge about the occurrence of Legionella in BTPs is scarce. Hence, we undertook a qualitative and quantitative screening for Legionella in BTPs treating waste water from municipalities and industries in Norway, to assess the transmission potential of Legionella from these installations. Thirty-three plants from different industries were sampled four times within 1 year. By cultivation, 21 (16%) of 130 analyses were positive for Legionella species and 12 (9%) of 130 analyses were positive for Legionella pneumophila. By quantitative real-time polymerase chain reaction (PCR), 433 (99%) of 437 analyses were positive for Legionella species and 218 (46%) of 470 analyses were positive for L. pneumophila. This survey indicates that PCR could be the preferable method for detection of Legionella in samples from BTPs. Sequence types of L. pneumophila associated with outbreaks in Norway were not identified from the BTPs. We showed that a waste water treatment plant with an aeration basin can produce high concentrations of Legionella. Therefore, these plants should be considered as a possible source of community-acquired Legionella infections.
In vivo genotoxicity of treated water containing the cylindrospermopsin-producer Cylindrospermopsis raciborskii
Authors: Fonseca A. L. , Da Silva J. , Nunes E. A. , Azevedo S. M. F. O. , Soares R. M.
Published: September 2014

Cylindrospermopsin (CYN) is an alkaloid commonly produced by some cyanobacteria that has been implicated in outbreaks of human illness. The aim of this study was to investigate the genotoxicity of Cylindrospermopsis raciborskii cellular content (including CYN) and its byproducts resulting from chlorination during water treatment. DNA damage in blood and liver cells was analysed by the comet assay and micronucleus test (MN). Mice were injected intraperitoneally with the following treatments: (a) physiological saline, (b) treated water, (c) treated water plus C. raciborskii extract (CYN producer strain, CYPO-011 K), (d) C. raciborskii extract (CYN producer strain, CYPO-011 K), (e) C. raciborskii extract (CYN non producer strain), and (f) treated water plus C. raciborskii extract (CYN non producer strain) extract. After 48 h, samples were taken to perform tests (blood and liver cells to the comet assay and bone marrow to MN test). The CYPO-011 K had a genotoxic and mutagenic effects on liver and bone marrow cells. The group that received chlorine-treated water plus CYPO-011 K also exhibited genotoxic effects in the liver, as well as in the blood, and a mutagenic effect in blood marrow cells. The results emphasise the need of improving CYN monitoring in waters bodies in order to reduce the risk of human exposure.
Factors involved in sustained use of point-of-use water disinfection methods: a field study from Flores Island, Indonesia
Authors: Roma E. , Bond T. , Jeffrey P.
Published: September 2014

Many scientific studies have suggested that point-of-use water treatment can improve water quality and reduce the risk of infectious diseases. Despite the ease of use and relatively low cost of such methods, experience shows the potential benefits derived from provision of such systems depend on recipients' acceptance of the technology and its sustained use. To date, few contributions have addressed the problem of user experience in the post-implementation phase. This can diagnose challenges, which undermine system longevity and its sustained use. A qualitative evaluation of two household water treatment systems, solar disinfection (SODIS) and chlorine tablets (Aquatabs), in three villages was conducted by using a diagnostic tool focusing on technology performance and experience. Cross-sectional surveys and in-depth interviews were used to investigate perceptions of involved stakeholders (users, implementers and local government). Results prove that economic and functional factors were significant in using SODIS, whilst perceptions of economic, taste and odour components were important in Aquatabs use. Conclusions relate to closing the gap between factors that technology implementers and users perceive as key to the sustained deployment of point-of-use disinfection technologies.