bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Subsurface and Wells Emergency Response Organisation (ERO) Portal
Authors: Cormack Sarah , Yuile Jeanette 
Published: October 2014

Abstract
A Subsurface and Wells Emergency Response Organization (ERO) Portal has been developed to provide European subsurface and wells emergency response duty team personnel with immediate access to a critical, trusted subsurface and wells data set. The rapid availability of such a data set is linked to the speed and efficiency of the overall wellsite emergency response procedure.

The ERO Portal is a web based application. It is a simple and easy to use one-stop-shop that provides the subsurface and wells emergency response duty teams with access to 21 critical, high quality data types at field, well and wellbore level. The data types have been selected to provide a holistic understanding of the status of the assets (wellbores, wells, fields or Assets (groups of fields)), thereby enabling a highly informed emergency response based on the conditions of the assets involved.
The ERO Portal not only provides access to the 21 critical data types but differs from conventional data retrieval portals in that it indicates the availability or absence of each data type – thus saving time in the data gathering process. The user friendly home page connects to quality checked, published corporate data held and managed within corporate data stores.
On and offline back-up systems have also been developed to ensure full data availability at all times and duty team personnel are trained in how to use the tool.
The sustainability of the ERO Portal involves continual input from a number of teams throughout the year to ensure that data is quality checked and published in a timely manner into the corporate databases, that duty team personnel are trained in its use and that the IT technology is working at all times. However, there is no question that the investment in this tool is essential.
The ERO Portal is significant in that it offers an example of how providing a critical, trusted and quality checked data set from a single source in the event of a wellsite emergency can prove a vital step in a timely and well informed response to a wellsite emergency.
Impact of Maturity on Kerogen Pore Wettability: A Modeling Study
Authors: Hu Yinan , Devegowda Deepak , Sigal Richard 
Published: October 2014

Abstract
Kerogen wettability is essential to evaluate hydrocarbon storage and quantify reserves estimates, to develop models for multiphase and multicomponent transport especially in oil shales and to predict recoveries of fracture water as well as predict the placement of fracture water during re-fracture treatments. The widely held view for kerogen pores is generally hydrocarbon-wetting; however, some recent experimental work indicates the existence of water content in kerogen. The kerogen maturation process is associated with the loss of H/C and O/C ratios which may influence the wettability depending on the affinity of these functionalized molecules with water. In this paper, we provide a microscopic study of the role of kerogen maturity on wettability of organic pore systems.
Varying maturation degree of kerogen surfaces are built by grafting functionalized groups onto the traditional graphene model. We study a mixture of water and alkanes in organic pores with effective width of 5 nm. We find that water aggregates to form clusters, and the shape and the location of the water molecules are strongly linked to the density of the functionalized groups. By determining the contact angles, we are able to quantify the relationship of kerogen wettability with the maturity level.
We demonstrate that the wettability in kerogen is very likely to be heterogeneous. Depending on the maturity level, kerogen may be hydrocarbon wetting at high maturity, neutral wetting at intermediate maturities or even hydrophilic for organic surfaces of very low maturities. In addition, we also demonstrate the influence of surface heterogeneity and the distribution of polar molecules on kerogen wettability. Our results indicate that in kerogen there may be a critical local density of surface functionalized sites that may create optimal conditions for hydrophilic kerogen surfaces.
The Case for Utilizing Hydraulic Jet Pumps in the Bakken
Authors: Clark Chris W. , Griffin Larry , Pearson C. Mark , Strickland Stacy 
Published: October 2014

Abstract
The Bakken boom in North Dakota has been well documented. From a development perspective, the majority of the acreage has been drilled with an initial well to hold the acreage and the emphasis has shifted to infill drilling. In the early development stages, the primary goal was to prove up and hold leases. Now with the shift to full development, optimization of drilling, completion and production operations is the primary goal.
To date there has been a fair amount of discussion industry-wide regarding drilling and completion techniques as these are critical to play and area assessment. Little attention, however, has been paid to production techniques that optimize well performance and specifically artificial lift selection. This is a critical next step in order to maximize the value of these Bakken assets.
The vast majority of wells in the Bakken utilize sucker rod pumps as the method of artificial lift. This is largely attributable to the institutional knowledge and simplicity of the system. However, given the depth of the Bakken and high produced water density, sucker rod systems are not practically able to move the large volumes of fluid many wells are capable of delivering. Also, these systems will not optimally handle the large variations in deliverability as these unconventional wells rapidly decline in their early life. For wells within the study area with similar completion types, well deliverability greatly exceeds the installed sucker rod pump lift capabilities for more than a year, with measured fluid levels of 3,000′ to 6,000′ above the pump intake. This not only restricts production but creates operational issues with salt and scale deposition due to the high mineral saturations in the produced water seen in the Bakken where produced waters can approach 11 ppg densities.
In order to take full advantage of the authors’ advanced completion strategy utilizing plug and perf, slickwater, and 100% ceramic proppant, hydraulic jet pumps were chosen to get the wells closer to a "pumped off" state and to more optimally lift the wells during the early high-decline period where the deliverability is greatly changing. Thirteen installations were performed while Liberty operated properties in the Central Basin of the Bakken play. This paper discusses the superior production results achieved with jet pumps compared to sucker rod installations utilizing constant type curve parameters while varying initial production to fit the curve to production data. It also discusses the learning curve of the installations and operational advantages noted while applying this method for artificial lift.
Measurement and Analysis of 3D Stress Shadowing Related to the Spacing of Hydraulic Fracturing in Unconventional Reservoirs
Authors: Dohmen T. , Zhang J. , Blangy J. P. 
Published: October 2014

Abstract
Industry experience in unconventional plays shows that production performance does not scale up in simple increments when adding hydraulic fracture stages in closely spaced completions. That is, adding stages to a planned well by reducing the stage spacing does not proportionally enable additional hydrocarbon production on a per stage basis. Instead, closer stage spacing incrementally adds less hydrocarbon production per stage. Determining the appropriate stage spacing is an optimization step that the industry has approached by drilling statistically significant numbers of wells to separate the effects of completions from the effects of geologic variations. We propose leveraging and integrating microseismic data with associated measurements to analyze and model the effects of reduced stage spacing while drilling fewer wells.
Hess Corporation is using downhole geophones to monitor microseismic events associated with hydraulic fracturing in horizontal wells with different completion stage spacings in the Middle Bakken Play and the Utica Play. By constructing a small 3D structural model around each well, we create depth histograms of microseismic events. The events are measured in relation to a common stratigraphic boundary in order to identify how hydraulic fractures interact. Stage to stage analysis of these histograms shows a systematic interference phenomenon, which we demonstrate by applying 2D Fast Fourier Transform, correlation, and quantile analysis to the histograms.
A comparison of three horizontal wells stimulated with different stage spacing and in different plays shows that hydraulic fractures in closely spaced stages interfere with each other by cyclically bouncing out-of-zone. We find from microseismic observation that the stress shadowing induced by closely spaced stages exhibits a 3D behavior. That is, when hydraulic fractures develop in-zone, as planned, stress accumulates and forces subsequent completions preferentially upward, out-of-zone. As stress accumulates in the zone above, the following fractures reform and are back in-zone in a repetitive cycle. We believe that the physics controlling incremental hydrocarbon production per stage is related to this observed cyclical reduction of the in-zone fracture area. We then analyze the changes to in-situ stress induced by closely-spaced hydraulic fracturing, using a simple model. The concept uses geomechanical principles to explain the in-zone and out-of-zone phenomenon observed in multi-stage fracturing. In the future, we plan to apply 3D stress shadowing theory to our completion models to optimize the stage spacing of our production wells.
A New HLD-NAC Based EOS Approach to Predict Surfactant-Oil-Brine Phase Behavior for Live Oil at Reservoir Pressure and Temperature
Authors: Ghosh S. , Johns R. T. 
Published: October 2014

Abstract
Surfactant-polymer (SP) floods have significant potential to recover waterflood residual oil in shallow oil reservoirs. A thorough understanding of surfactant-oil-brine phase behavior is critical to design SP processes. Current practices involve repetitive laboratory experiments of dead crude at atmospheric pressure in a salinity scan that aims at finding an "optimum formulation" of chemicals for targeted oil reservoirs. While considerable progress has been made in developing surfactants and polymers that increase the potential of a chemical enhanced oil recovery (EOR) project, very little progress has been to predict phase behavior as a function of formulation variables such as pressure, temperature, and oil equivalent alkane carbon number (EACN). The empirical Hand's plot is still used today to model the microemulsion phase behavior with little predictive capability as formulation variables change. Such models could lead to incorrect recovery predictions and improper SP flood designs.
In this paper, we develop a new predictive phase behavior model and introduce a new factor β to account for pressure changes in the hydrophilic-lipophilic difference (HLD) equation. This new HLD equation is coupled with the net-average curvature (NAC) model to predict phase volumes, solubilization ratios, and microemulsion phase transitions (Winsor II−, III, and II+). The predictions of key parameters are compared to experimental data and are within relative errors of 4% (average 2.35%) for measured optimum salinities and 17% (average 10.55%) for optimum solubilization ratios. This paper is the first to use a HLD-NAC model to predict microemulsion phase behavior for live crudes, including optimal solubilization ratio and the salinity width of the three-phase Winsor III region at different temperatures and pressures. Although the effect of pressure variations on microemulsion phase behavior are generally thought to be small compared to temperature induced changes, we show here that this is not necessarily the case. The predictive approach relies on tuning the model to limited experimental data (say at atmospheric pressure) similar to what is done for equation-of-state modeling of miscible gas floods. This new equation-of-state-like model could significantly aid the design of chemical floods where key variables change dynamically, and in screening of potential candidate reservoirs for chemical EOR.
Utilizing Microseismic Stress Release to Identify Out-of-Zone Fracture Growth
Authors: Preiksaitis Mike , Bowman Sheri , Urbancic Ted , Baig Adam 
Published: October 2014

Abstract
Out-of-zone fracture growth can lead to inefficient stimulations and the loss of energy and injection fluids to surrounding rock formations. In unconventional shale resource plays, complexity in fracturing and lithology has a profound affect on the success of a completion program. In this paper we discuss the characteristic changes in seismic response associated with two case studies. The first study consists of out-of-zone fracture growth in inter-bedded sequences of shaley sandstone and carbonates. A zipper frac completion program was used on two stacked lateral treatment wells. A consistent stimulation program was utilized over all stages, however, following a shutdown interval of two days, upon re-initiation of the stimulation program, events migrated out-of-zone into the surrounding carbonate layers. These events were characterized by higher stress release values, consistent with the idea that fracturing was taking place in the carbonates and that more energy was required to activate fractures than typically seen in the fracturing of the shales. This suggests that during the shutdown interval, a relaxation in local stress magnitudes resulted in the re-orientation of the principal stresses into more optimal orientations to allow for fracturing within the carbonates. In a second case study, the stimulation of the Muskwa, Otter Park and Evie formations in the Horn River Basin, in Northeast British Columbia, resulted in localized out-of-zone growth for stimulations in all formations. These events were characterized by large stress release values, in contrast to the observed values for surrounding events within each formation. The evidence of high stress release within the formations suggests the activation of a fault that extended well below the target formations. Based on these observations of stress release, we postulate how additional seismic characteristics, such as stress release, can be used to identify out-of-zone growth in real-time.
Mitigation of Terrain Induced Slugging Using Mixer Devices
Authors: Brasjen B. J. , Veltin J. , Hansen J. H. 
Published: October 2014

Abstract
The present work focuses on experimental evidence of slug mitigation via various devices. The slug mitigation potential of a number of mixers was tested using a laboratory scale air/water setup to compare their effect on the incoming slugs just upstream of the separator inlet. Dedicated methods and key performance indicators were developed to characterize the slug properties and evaluate the mixers effectiveness.
Such mitigation is especially interesting for the purpose of producing oil and gas from thin oil rims, in which wells are often drilled following the geological structure of the oil-bearing layer. These wells consequently contain many long, near-horizontal sections, through which the transport of the oil gas mixture often takes the form of slug flow, i.e. large volumes of liquid travelling at the velocity of the gas phase. As the gas cannot bypass the slugs, they are generally produced to the topside facilities, where they have a detrimental effect on the mechanical integrity of the equipment and on the metering accuracy due to their large volume. Mitigating slug flow has therefore great potential in optimizing the production from thin-oil rims on the short term.
The present study shows that consistent reductions can be obtained on pressure fluctuations due to slugging, highlighting the benefit of these devices. It was observed that the slug speed could be significantly reduced, as well as the liquid hold-up within the slugs, especially when gas lift is used in conjunction with the devices. The physical mechanisms behind these effects are isolated, leading to optimization of the device geometry, for application to full scale.
The demonstrated potential of the mixer devices can yield a quantifiable reduction of the impact of slugging on mechanical integrity and metering accuracy. As a consequence, production limitations due to slugging problems can be alleviated, resulting in potential for increase in oil production rates from thin oil rims.
How to Improve our Understanding of Gas and Oil Production Mechanisms in Liquid-rich Shale
Authors: Alfi Masoud , Yan Bicheng , Cao Yang , An Cheng , Wang Yuhe , Killough John 
Published: October 2014

Abstract
Three phase oil, gas, and water flow in liquid-rich shale plays is investigated in this paper, using a state-of-the-art technique of dividing shale matrix into different sub-media. Shale reservoirs always present numerous challenges to modeling and understanding, from unintuitive, heterogeneous, and difficult to characterize rock properties, to limited understanding of the governing flow equations, lack of fundamental knowledge on related desorption mechanisms, and nearly impermeable formations with pores on the order of magnitude as the mean free path of gas molecules. This work proposes a partitioning scheme to divide porous media in shale into three different sub-media (porosity systems) with distinctive characteristics: inorganic matter and kerogen (in the shale matrix), along with fracture network (natural or hydraulic). The current model gives us the capability of better analyzing the complex nature of mass transfer in shale. Relative permeabilities in our model are accounted for by employing the functions specifically presented for shale reservoirs. Our model can also handle various flow and storage mechanisms corresponding with shales such as molecule/wall interactions and slippage of the gas phase, multicomponent desorption, and capillarities. Simulation results show that hydrocarbon production from shale reservoirs exhibits complicated dynamics that are controlled by a number of different factors. Because of very high capillary pressure in shale, water is observed to imbibe into the water-wet inorganic matter during the late production period. On the contrary, mass flow in the oil-wet kerogen is mostly limited to two-phase oil and gas flow. Although kerogen is considered to be a rich source of hydrocarbon, relatively high capillary pressure and very low rock permeability hinder oil production in organic-rich shale. We might be able to address such problems by employing an appropriate production enhancement technique compatible with the ultra-tight nature of such reservoirs.
Numerical Model for Mapping Thief Zones in Directional Wells while Drilling
Authors: Chen Yuanhang , Yu Mengjiao , Ozbayoglu Evren , Takach Nicholas 
Published: October 2014

Abstract
Failure to minimize lost circulation can greatly increase the cost of drilling and the risk of well abandonment. The main reason why some of the remedial procedures are not working as planned is the lack of information in loss zone locations. Inaccurate estimation of loss zone location prevents the treatment to be applied directly at the point of loss, results in low efficiency and extended nonproductive rig time.
This paper describes an approach for identifying the location of loss zones in directional wells using distributed temperature measurement while drilling. A transient thermal model for predicting the temperature profile in a directional well with mud loss is presented. The numerical solution under different lost circulation conditions, when used together with the distributed temperature measurement, can identify the location of mud loss. For a deep high pressure high temperature well with severe lost circulation, there is a significant change in the thermal behavior of the wellbore as mud loss continues. The characteristics of wellbore thermal behavior are evaluated and identified as good indicators of loss zone location. The distributed temperature measurement while drilling is enabled by a drilling microchip technology that has been developed and validated with successful field tests. By matching simulated results with the distributed temperature measurements at different timestamp, the depth of the loss zone can be accurately identified. Case Studies are given to show the practical applications of the method. The results are important in applying expandable tubular system, setting cement plug and spotting lost circulation pills. An additional application of this approach is the identification of highly permeable zones for reservoir or formation evaluation.
Development of Innovative and Efficient Hydraulic Fracturing Numerical Simulation Model and Parametric Studies in Unconventional Naturally Fractured Reservoirs
Authors: Ahn Chong Hyun , Dilmore Robert , Wang John Yilin 
Published: October 2014

Abstract
The most effective method for stimulating unconventional reservoirs is using properly designed and successfully implemented hydraulic fracture treatments. The interaction between pre-existing natural fractures and the engineered propagating hydraulic fracture is a critical factor affecting the complex fracture network. However, many existing numerical simulators use simplified model to either ignore or not fully consider the significant impact of pre-existing fractures on hydraulic fracture propagation. Pursuing development of numerical models that can accurately characterize propagation of hydraulic fractures in naturally fractured formations is important to better understand their behavior and optimize their performance.
In this paper, an innovative and efficient modeling approach was developed and implemented which enabled integrated simulation of hydraulic fracture network propagation, interactions between hydraulic fractures and pre-existing natural fractures, fracture fluid leakoff and fluid flow in reservoir. This improves stability and convergence, and increases accuracy, and computational speed. Computing time of one stage treatment with a personal computer is now reduced to 2.2 minutes from 12.5 minutes than using single porosity model.
Parametric studies were then conducted to quantify the effect of horizontal differential stress, natural fracture spacing (the density of pre-existing fractures), matrix permeability and fracture fluid viscosity on the geometry of the hydraulic fracture network. Using the knowledge learned from the parametric studies, the fracture-reservoir contact area is investigated and the method to increase this factor is suggested. This new knowledge helps us understand and improve the stimulation of naturally fractured unconventional reservoirs.