bluuebunny/crossref_metadata_2025_split huggingface dataset:
Duvernay Proppant Intensity Production Case Study and Frac Fluid Selection
Authors: Leshchyshyn Tim , Thomson Jim , Larsen Cory 
Published: September 2016

Abstract
The hundreds of Duvernay wells near Fox Creek, Alberta, Canada are usually fracture stimulated with either slickwater or hybrid slickwater-crosslinked water treatments with a large acid spearhead. There is a 14.6% higher 3-year average cumulative production total for slickwater treated wells versus hybrid fluid system treated wells. Additionally, the slickwater systems have an average 53.8% lower frac chemical cost compared to the 50/50 slickwater-crosslinked water hybrids frac stimulation systems. There is a very linear trend between the total volume of fluid pumped to the total 2 year BOE production; the higher the treatment fluid volume, the greater the stimulated reservoir volume (SRV) and the higher the resulting production. The production case study shows that wells treated with an average of 25,000 m3 of water have an 80% higher average 2-year cumulative production result compared to wells that only use an average of 13,000 m3.
The average proppant tonnage per stage varies with 140 tonnes per stage outperforming 100 tonnes per stage by 31.6% cumulative BOE production per stage at 2 years. However larger tonnes per stage showing a diminishing benefit when looking at the 2 year BOE production totals. The total production versus total proppant used (1000 tonnes to 3500 tonnes per well) is also examined showing an overall total well production benefit. Comparing the total proppant placed versus cumulative BOE is shows a positive. It does appear that the more proppant that is placed the higher the production rate and total long term production.
Complementary Surveillance Microseismic and Flowback Data Analysis: An Approach to Evaluate Complex Fracture Networks
Authors: Xu Yanmin , Ezulike Obinna Daniel , Zolfaghari Ashkan , Dehghanpour Hassan , Virues Claudio 
Published: September 2016

Abstract
This paper presents an integrated workflow which complementarily utilizes flowback data analysis and surveillance microseismic analysis to characterize fracture networks and stimulated reservoir volume (SRV). The workflow helps to 1) differentiate !"effective" and "ineffective" SRV and fracture half-length (ye) respectively, 2) understand how effective fracture volume (Vf) changes during flowback, and 3) explore the effects of key operational parameters on the fracture network created after well stimulation. The workflow comprises four main steps: 1) estimating SRV and fracture parameters from surveillance microseismic interpretation and flowback data analysis; 2) comparative analysis of estimated SRV, ye and Vf values; 3) Calculating volumetric ratios (e.g. flowback load recovery) to evaluate the effectiveness of fracturing and flowback operations; and 4) investigating possible relationships between operational designs and estimated reservoir and fracture parameters.
The application of this workflow on an eight-well pad completed in the Horn River Basin (HRB) shows that the SRV and ye from microseismic interpretation are generally several times larger than those from flowback data analysis. This indicates that over half of the stimulated rock does not contribute to gas production. Besides, a large percentage of the effective fracture network closes during early-time (the first 200 hrs) flowback. The results show that SRV increases as total perforation clusters increases, and this relationship appears to be formation-dependent. Also, the estimated Vf seems to be smaller for wells that are opened later for flowback. This observation might be due to inter-well communication and wellbore storage effects.
Compositional Rate Transient Analysis in Liquid Rich Shale Reservoirs
Authors: Alharthy Najeeb , Teklu Tadesse , Kazemi Hossein , Graves Ramona 
Published: September 2016

Abstract
Conventional rate transient analysis (RTA) is based on the solution of single-phase diffusivity equation, derived from mass balance with an assumption that fluid and rock compressibility are small and constant. The conventional technique also provides accurate practical results for gas and black oil reservoirs in engineering applications because (1) the mass balance is conducted at standard conditions of pressure and temperature, and (2) it is assumed that the gas and oil composition remains the same at standard conditions—thus, the viability of volume balance technique. On the other hand, for reservoirs with highly composition-dependent fluids, the invariance of composition at standard conditions is not accurate. For example, oils produced from liquid-rich shale reservoirs exhibit large variation in produced oil and associated gas composition with production time. In this paper we address these issues and present a compositional model for liquid-rich unconventional reservoirs using an improved compositional volume balance technique. Specifically, we reduce the component flow equations to a single pressure equation using partial molar volumes as weighting factors. This pressure equation is the unique feature of this paper and is used to analyze pressure and rate transient tests (RTA) to determine various flow regimes and reservoir properties in liquid-rich shale reservoirs.
In addition, the model is an excellent tool to forecast long-term production. The diagnostic models we have generated include: (1) a numerical model of flow for a well that has been stimulated by multi-stage hydraulic factures, and (2) an analytical composition-dependent model for the rate transient analysis (RTA) of light oils. The numerical model is a 2-D, three-phase, dual-porosity simulator, which uses compositional volume balance method. The algorithm decouples the hydrocarbon and aqueous phases in the matrix and fracture which reveals the clarity of underlying mass transport concepts and ease of coding.
Because of the explicit nature of the phase saturation calculations, we introduce a molar mass balance correction term to minimize the material balance errors of the computation. Furthermore, we validated our partial molar volume algorithm against published experimental data of Wu and Ehrlich (1973) and with the CMG GEM compositional simulator. Finally, unsteady state permeability measurements of several unconventional shale reservoirs were performed. These measurements show that tighter core with abundant micro and nano fractures exhibit a more stress dependent matrix permeability characteristics.
Downhole Fluid Sampling and Analysis in Challenging Reservoirs Using 3D Radial Probe Case Study from Deepwater Gulf of Mexico
Authors: Mishra V. K. , LeCompte B. , Gendur J. , Chen L. , Garcia G. D. , Dumont H. , Cantwell W. , Agarwal A. 
Published: September 2016

Abstract
In order to reduce reservoir uncertainties, downhole fluid analysis (DFA) and the acquisition of highest quality reservoir fluid samples are of utmost importance, especially in deepwater Gulf of Mexico fields. While focused sampling technique has achieved these objectives in the most efficient and cost-effective manner for a wide range of the reservoirs, there are certain conditions where focused probe or conventional probes don't perform the best. Some of these challenging reservoirs include low permeability or laminated reservoirs, highly unconsolidated formations and reservoirs with highly viscous oil. A newly designed 3D radial probe provides sampling and DFA solutions in such challenging reservoirs. Large inlet flow area of the 3D radial probe facilitates efficient pumping and sampling in low mobility or laminated reservoirs. Conventional probe faces challenge of loss seals in unconsolidated reservoir which is overcome by radial probe due to its large sealing surface area.
A case study from deepwater Gulf of Mexico is discussed in which complex reservoirs are tested for DFA and sampling using a 3D radial probe. Formation density, spectral gamma ray and neutron logs determine formation porosity and presence of shale. Triaxial resistivity identifies laminated zones and a laminated sand analysis is performed to add about 35% hydrocarbon pore thickness when compared to conventional, non-laminated analysis. This data was coupled with the latest generation microresistivity imager which allows accurate identification of geologic features, from very thinly-laminated bedding to faults and fractures.
Fluid sampling and downhole fluid analysis are performed with wireline formation tester tool configured with conventional probes as well as 3D radial probe. Several pumping stations are performed, and 3D Radial probe enables sampling in thin low mobility rocks providing low contamination samples confirmed with the laboratory analysis. Insitu fluid analysis data was used for sample optimization, detailed downhole fluid characterization and reservoir connectivity assessment. The 3D radial probe also allows high quality pressure transient data for better permeability estimation. In addition, a vertical interference test (VIT) is performed with sink and observation probe configurations for vertical permeability and connectivity assessment.
Additional inelastic and capture spectroscopy measurements were taken about two weeks after the well was cased, which validated critical petrophysical measurements. The spectral data was also used to further characterize the formation mineralogy.
The Effect of Brine Concentration on Asphaltene Stability
Authors: Demir A. Birkan , Bilgesu Ilkin H. , Hascakir Berna 
Published: September 2016

Abstract
The stability of asphaltenes is a critical parameter which may affect the flow in porous media significantly. This study investigates the change in the stability of asphaltenes after the interaction of asphaltenes originated from five different reservoirs with reservoir components? namely sand, clay, water, and brine. Asphaltenes are polar like water and brine. Hence, the initial lab-scale sensitivity studies were carried out first with asphaltene-water and asphaltene-brine systems. Then, the impact of porous medium has been investigated on asphaltene stability? asphaltenes are mixed with either sand or sand+clay mixture and then exposed to water or brine. Since, both sand and clay show water-wet behavior, the effect of water-wet rock surface on asphaltene stability has been aimed to understand. Moreover, different brine types and concentrations on asphaltene stability have been tested. A divalent and a monovalent salts were used to prepare brine solutions at 2%, 4%, 6%, and 8% concentrations. All laboratory tests were achieved under optical microscope and the interaction has been examined overtime. Our experimental results suggest that asphaltenes from all five crude oil samples are dispersed in water and they aligned themselves within water due to polar nature of asphaltenes and water. In asphaltene-brine systems, the monovalent salt (NaCl) interacts more with asphaltenes than divalent salt (CaCl2). This is due to higher water uptake capacity of CaCl2 than NaCl. The microscopic images revealed that a water layer is formed around CaCl2 inhibits the direct interaction of asphaltene-CaCl2. This behavior is enhanced within the porous media; salt crystals form bridges between the sand grains, clay and asphaltenes contribute to the formation of those bridges. The impact of brine has been observed more significantly at high concentration of the brine solutions. The asphaltenes-brine interaction also shows variations among different asphaltenes. Thus, all asphaltene samples have been analyzed for their elemental compositions to check if cation exchange is possible between the salts and asphaltenes. These experiments revealed that for the asphaltenes rich in calcium and sodium content, their interaction with brine is greater than for the asphaltenes poor in calcium and sodium content. Moreover, this interaction contributes to the formation of bigger asphaltene clusters which decreases the asphaltene stability and promotes more asphaltene precipitation. This study provides some general trends observed in asphaltene-water and asphaltene-brine systems and explains the reasons why some outliers do not fit the trends by examining the differences in the chemical composition of asphaltenes. Hence, this study enriches our knowledge towards asphaltene behavior in porous media.
A Technical Investigation on the Ongoing Evolution of the Market of Offshore Installation Vessels
Authors: Li Rui , Hansen Kevin , Beltrami Francesco 
Published: September 2016

Abstract
The offshore installation market is presently undergoing great changes: new high-performance offshore installation vessels are being delivered while older ones are decommissioned. This paper investigates the current status of installation vessels worldwide, providing reliable and up-to-date information on the vessels effectively available and reporting about their technical capabilities (selected key features only).
There are only a limited number of technical papers that investigate the status of the offshore installation vessels worldwide and discuss their capabilities providing a comprehensive picture of this evolving market. Focusing on the technical capabilities of the offshore installation vessels will benefit future projects in multiple ways: (a) to ensure that field development planning and the design of subsea equipment take into account what installation vessels can do in a given location, and to create components that are reasonably easier to handle and install, thus reducing installation costs; (b) to enable project teams to be more aware of what the installation vessels market is offering now and in the near future, in order to make a more informed decision on the vessels to be selected for a given project.
The main technical contributions offered by this paper are: (a) the systematic gathering of information available, but dispersed, in the public domain; (b) the elaboration and critical discussion of the technical data collected and the identification of the current installation capabilities; and (c) the use of the numerical results obtained to identify opportunities to reduce installation costs. The information presented in this paper may not be completely new, but the way it is presented and discussed is original and novel.
A Model for Optimizing Energy Investments and Policy under Uncertainty
Authors: Al-Ahmadi Hasan A. , McVay Duane A. 
Published: September 2016

Abstract
An energy producer must determine optimal energy investment strategies in order to maximize the value of its energy portfolio. Determining optimal energy investment strategies is challenging. One of the main challenges is the large uncertainty in many of the parameters involved in the optimization process. Most existing large-scale energy models are deterministic and so have limited capability for assessing uncertainty. Modelers usually use scenario analysis to address model input uncertainty.
In this paper, we describe a coarse probabilistic model developed for optimizing energy investments and policies from an energy producer's perspective. The model uses a top-down approach to probabilistically forecast primary energy demand. Distributions rather than static values are used to model uncertainty in the input variables. The model can be applied to a country-level energy system. It maximizes portfolio expected net present value (ENPV) while ensuring energy sustainability. The model is built in MS Excel® using the @RISK add-in, which is capable of modeling uncertain parameters and performing stochastic simulation optimization.
The model was applied to synthetic data for a typical fossil-fuel-dependent country to determine its optimum energy strategy. For this synthetic case, the model suggests that the subject country should increase its oil production capacity slightly higher than its current level, increase its gas production, and meet most of its future power generation (electricity) demand using alternative energy sources—nuclear, solar, and wind.
A primary contribution of this work is rigorously addressing uncertainty quantification in energy modeling. The model could be applied, with minor modification, by either companies or countries to assist in determining optimal energy investment strategies.
Protecting and Commercializing Advanced Petroleum Technology: The Role of Intelligent Energy Law in 2016
Authors: Fraser H. G. , Dodd J. 
Published: September 2016

Abstract
The world of energy sustained a threefold shock to the system as the industry rolled into 2016. First, the impact of the COP21 Agreement reached on 12 December 2015 in Paris stressed the need to focus on the reduction of carbon emissions had arrived definitively. This brought sharply into focus the International Energy Agency's proposed a "Bridge Scenario" which, it is claimed, could deliver a peak in energy-related emissions by 2020, relying solely on proven technologies and without changing economic development prospects of any region by virtue of five key initiatives: increased energy efficiency; the progressive reduction and phasing out of inefficient coal-fired power plants; phasing out fossil fuel subsidies by 2030; reducing methane emissions in oil and gas production; and increasing investment in renewable energy technologies from US$270 million in 2014 to US$400 billion in 2030.
Second the declaration, following the confirmation of the International Atomic Energy Authority, on 15 January 2016 that Iran had satisfied the conditions for the implementation of the Joint Co-operation Plan of Action signaled the return of one of the world's few three million plus barrels per day suppliers of petroleum to the international market. The Iranian supply side impact paralleled with recurring concerns about the health of the Chinese economy and the impact on the demand side as the industry grappled to understand the longer term impact of the 30% downward lurch in the value of listed Chinese shares in July 2015.
Thirdly, no doubt influenced by the above developments, the price of oil slumped to US$27 a barrel dispelling hopes of an early recovery in 2016 and raising existential fears for those in the industry focused on higher cost exploration and/or production segments of the industry such as deepwater, shale gas and tar sands/heavy oil. The North Sea, with a cost base in the US$50 to US$60 dollars a barrel range breathed in and held its breath. Although the OPEC nations committed not to raise production levels, it was clear that the current down turn was no simple repeat of 1986 and 1998 and different dynamics and forces were at large.
A New Method to Calculate Effective Permeability of a Naturally Fractured Carbonate Reservoir from Seismic Attributes
Authors: Li D. , Alharbi M. S. , Ottinger G. , El-Awawdeh R. T. , Brunhuber P. , Al-Jasmi S. M. 
Published: September 2016

Abstract
Modeling permeability of naturally fractured reservoirs for simulation studies and field development planning is very challenging since the data required for characterizing the magnitude and distribution of reservoir fracture permeability is very limited. Fracture permeability is traditionally measured from cores and/or estimated from well tests. These estimations usually work adequately at well locations for permeability modeling but poorly between wells. Modeling fracture permeability distribution between wells and/or away from wells is a very important step to build a reliable reservoir simulation model for business needs.
This paper presents a new method/workflow for modeling effective permeability of a naturally fractured carbonate reservoir from seismic attributes. The new method directly converts fracture textures and distributions from seismic attributes into permeability for reservoir simulation. Core and log data are used to create fracture regions and the distribution of fracture density; well test data are applied to generate isotropic permeability; and seismic attributes (e.g., ant-tracks, curvature, and anisotropy) are utilized to model the fracture network and permeability anisotropy. New equations are created to calculate effective permeability of the reservoir by scaling up and down between core/well test and seismic data. Two history match parameters (fracture network connectivity and permeability anisotropy) are introduced to assist the history match process within the guidance of seismic and geologic data.
The new method/workflow has been successfully applied to solve the history match challenges of a naturally fractured reservoir in a Middle Eastern field for which no history matched model was achieved before. Applying the new method has significantly improved water movement matches in all producers of the field.
Numerical and Experimental Investigation of Polymer-Induced Resistance to Flow in Reservoirs Undergoing a Chemical Flood
Authors: Hoteit Hussein , Alexis Dennis , Adepoju Olaoluwa O. , Chawathe Adwait , Malik Taimur 
Published: September 2016

Abstract
Polymers are commonly used in chemical EOR flooding to provide mobility control to the injected fluid slugs. Water-soluble polymer injection in porous media usually results in polymer entrapment in the subsurface formation from adsorption, mechanical trapping, and hydrodynamic retention. These different entrapment mechanisms lead to permeability reduction (Rk). The term resistance factor (RF) is used to measure the impact of permeability reduction and viscosity enhancement from the polymer. The residual resistance factor (RRF) represents the residual permeability reduction to chase fluids (usually water) following a polymer flood. These phenomena are more prevalent in high molecular weight polymers. The effects of RRF are also sometimes evident when polymer injection is suspended (e.g., operational issues) and other fluids are injected in the formation instead.
Post-polymer chase water injection is considered a viable option to improve economics of a polymer flood. Current models validate this optionality because they overestimate the efficiency of the chase water flood. Lab and field observations indicate that chase water after chemical flood can cause rapid breakthrough, and therefore it is generally not recommended. The shortfall lies in the assumption that permeability reduction during polymer flood is an irreversible mechanism and therefore the existing simulation models assume that the permeability reduction during and post-polymer flood is the same. In this work, we show that the permeability reduction mechanism can be somewhat reversible, and therefore the current models underestimate chase water injectivity, and more seriously can overestimate the efficiency of chase water displacement. For optimizing the slug size, over predicting chase water displacement efficiency has a critical impact on the project economics and it may wrongly indicate premature switching time from chemical to water injection.
We provide an alternative permeability reduction model that does not assume irreversibility. The new model decouples permeability reduction during polymer flood from RRF during chase water flood. We validate the model using experimental data. Several test cases are provided to compare the two models and we finally demonstrate the applicability of the proposed model in an onshore polymer flood pilot. The new model also highlights the seriousness of the inefficiency of the post-polymer chase water injection.