bluuebunny/crossref_metadata_2025_split huggingface dataset:
Acoustic Measurements Aid Mechanical-Damage Characterization in Proppant Packs
Authors: Wilson Adam 
Published: October 2016

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 18092, “Mechanical-Damage Characterization in Proppant Packs Using Acoustic Measurements,” by Aderonke Aderibigbe, SPE, Clotilde Chen Valdes, and Zoya Heidari, SPE, Texas A&M University, and Tihana Fuss, Saint-Gobain Proppants, prepared for the 2014 International Petroleum Technology Conference, Kuala Lumpur, 10–12 December. The paper has not been peer reviewed.
The strength and conductivity of proppant packs are key parameters for assessing their performance. Mechanical damage of proppants usually is analyzed by crush tests. However, measurements from these tests remain questionable because of discrepancies in procedures and test results. This paper introduces a new technique based on interpretation of acoustic measurements to quantify mechanical damage in propping agents.
Introduction
Mechanical damage that leads to compaction and crushing is studied for sands by measuring ultrasonic velocities. Elastic properties can be estimated from compressional- and shear-wave velocities calculated from acoustic measurements. The elastic properties of unconsolidated sands usually are studied by use of effective-medium models for granular media. Effective- medium-theory approaches such as the Hertz- Mindlin model are often used to derive the effective elastic moduli of packings of identical and spherical granular materials. This model combines the Hertzian contact model, which is used to estimate the normal (compressional) stiffness for two identical spheres, and the Mindlin contact model, which is used to estimate the tangential (shear) stiffness of the spheres.
Work investigating the relationship between the ratio of compressional- to shear-wave velocities and pressure as a result of preconsolidation and sorting in unconsolidated sands showed that the Hertz-Mindlin model overestimated the shear moduli and underestimated the pressure dependence of the moduli and the velocities of the unconsolidated sands when compared with experimental data from ultrasonic measurements. The discrepancy was attributed to the inability of the model to account for rotation of grains and slip at their boundaries. The work applied a modified Hertz-Mindlin model, in which it is assumed that there is no friction between the grains (hence, the tangential stiffness is negligible), to obtain a reasonable match between the model and experimental results. The disparities were attributed to the angularity of the sand grains and the assumption of no slip at the grain contacts. The disparities were modified by introducing an average- angularity parameter and assuming slip at the grain contacts.
Previous publications documented applications of effective-medium models for assessment of elastic properties in rocks and unconsolidated sands. However, effective-medium models have not been applied in the assessment of elastic properties of proppant packs.
Optimizing Spacing of Multistage-Fractured Horizontal Wells in Gas Reservoirs
Authors: Carpenter Chris 
Published: October 2016

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 171688, “Optimizing Spacing of Horizontal, Multistage-Fractured Wells in Gas Reservoirs,” by Maryam Alghannam and Zillur Rahim, Saudi Aramco, prepared for the 2014 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 10–13 November. The paper has not been peer reviewed.
The growing demand for gas in Saudi Arabia and the availability of multistage-fracturing (MSF) horizontal-well technology have spurred the development of tight gas reservoirs throughout the country. Draining the reservoir efficiently by use of MSF strongly depends on well spacing, especially for low-permeability reservoirs. This paper gives the recommended MSF horizontal-well spacing for several development scenarios in Saudi Arabian gas-reservoir environments.
Theoretical Background
There are four different flow regimes for multiple-fracture systems without wellbore storage: early linear, early radial, formation linear, and pseudoradial flow (Fig. 1). The initial flow period observed is the linear flow, where fluid flow toward the fractures in the formation is perpendicular to the fracture planes. This flow exists when each fracture behaves independently and most of the fluid entering the wellbore comes from the fractures (when the fracture-tip effects have not yet affected the pressure behavior). After the start of the flow into the fracture tips, the early radial flow develops while there is still no communication between fractures. This flow regime may occur briefly or it may not occur at all, depending on the fracture length and spacing. Subsequently, formation linear flow develops after the fracture interference has been felt and the flow becomes normal to the horizontal well. Finally, the pseudoradial-flow regime develops in the formation, where the flow appears radial toward the entire well/fracture system. During this flow period, the composite fracture system behaves as if it were a single fracture. The flow eventually will reach pseudosteady state when it hits the reservoir boundaries or interferes with surrounding wells.
The rate at which the flow regime develops, from the start of production under transient conditions until it reaches reservoir depletion under pseudosteady state, is highly dependent on well spacing and well and reservoir characteristics.
Controlled-Freeze-Zone Technology for the Distillation of High-CO2 Natural Gas
Authors: Carpenter Chris 
Published: October 2016

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 171508, “Controlled-Freeze-Zone Technology for the Commercialization of Australian High-CO2 Natural Gas,” by Jaime A. Valencia, Robert D. Denton, P. Scott Northrop, Charles J. Mart, and Ransdall K. Smith, ExxonMobil, prepared for the 2014 SPE Asia Pacific Oil and Gas Conference and Exhibition, Adelaide, Australia, 14–16 October. The paper has not been peer reviewed.
The simple separation of carbon dioxide (CO2) from natural gas by distillation would involve cryogenic temperatures at which CO2 solidifies. Most CO2-separation processes instead use solvents that bind to CO2 molecules. For solvent regeneration, the binding process is reversed. The technology described by the authors provides the simplicity of a single-step distillation process for the separation of CO2 from natural gas. The technology has shown the potential to separate CO2 and other impurities from natural gas more efficiently and more cost-effectively.
The Process
In the gas industry, separations based on differing relative volatility and phase behavior are relatively simple, easy to implement, and widely used. The significant difference in relative volatility of methane and CO2 makes this system an ideal candidate for separation by distillation, were it not for some cold-temperature conditions leading to solidification of CO2. At 600 psig, conventional distillation is interfered with, for liquid-methane concentrations between approximately 25 and 85%, by the presence of this solid phase. Raising the pressure to 800 psig shifts the operating conditions away from the solidification boundary but into a new limitation: critical conditions. The critical pressure of pure methane is 667 psia; thus, methane-rich mixtures become supercritical. A high-purity methane-product stream cannot be obtained by distillation at 800 psig, and the overhead product purity is limited to 80 to 85% methane with a residual CO2 content of 15 to 20%. This is the basis for CO2 bulk fractionation.
The technology described in this paper, rather than avoiding the solidification of CO2, allows CO2 to freeze, though under carefully controlled conditions and in a specially designed section of an otherwise conventional distillation tower.
The tower normally incorporates three zones: the specially designed section that addresses the solidification region and two conventional distillation sections, one for rectifying and one for stripping, which cover the vapor/liquid areas above and below the CO2-solidification region. The relationship between the three sections of the column and the methane/ CO2 phase diagram is illustrated in Fig. 1.
A Real-Field Multiscale Black-Oil Reservoir Simulator
Authors: Kozlova A.. , Li Z.. , Natvig J. R. , Watanabe S.. , Zhou Y.. , Bratvedt K.. , Lee S. H. 
Published: October 2016

Summary
Simulation technology is constantly evolving to take advantage of the best-available computational algorithms and computing hardware. A new technology is being jointly developed by an integrated energy company and a service company to provide a step change to reservoir-simulator performance.
Multiscale methods have been rapidly developed during the past few years. Multiscale technology promises to improve simulation run time by an order of magnitude compared with current simulator performance in traditional reservoir-engineering work flows. Following that trend, the two companies have been working in collaboration on a multiscale algorithm that significantly increases performance of reservoir simulators.
In this paper, we report the development of multiscale black-oil reservoir-simulation technology in a reservoir simulator used by the industry, as well as the performance and accuracy of the results obtained by use of this implementation. The multiscale method has proved to be accurate and reliable for large real-data models, and the new solver is capable of solving very-large models an order of magnitude faster than the current commercial version of the solver.
Cold CO2 Injection for Balancing Interfacial Tension Decrease and Viscosity Increase
Authors: Hamdi Zakaria , Awang Mariyamni , Bataee Mahmood , Kamyab Mohammadreza 
Published: October 2016

Abstract
CO2 injection has been used for decades in the petroleum industry as a successful tertiary recovery method. The main impact of CO2 on the reservoir is interfacial tension (IFT) reduction between the crude oil and CO2 which leads to better sweep. Decrease in the temperature can cause lower IFT between CO2 and hydrocarbons. Yet, lowering the temperature will cause an increase in oil viscosity which negatively affects the oil recovery. In this study, we have calculated the change in IFT and viscosities of crude oil and CO2 to examine if a low IFT optimum point does exist where a low viscosity ratio between the two fluids is observed.
To obtain IFT between CO2 and crude oil, the Parachor model is used. Viscosities of the fluids are calculated using a commercial simulator. Then, simulations of CO2 injection is conducted as a tertiary recovery method to calculate the overall recovery as well as investigating the existence of the optimum point.
The results show that based on the composition of the crude oil, there is an optimum temperature beyond which the IFT would not decrease as well as the viscosities are at the optimum point suitable for recovery. Therefore, it is concluded that IFT has a more important role in the ultimate recovery than the viscosity of the fluids.
An Investigation of Fe2O3 Nanoparticles Diffusion into Oil for Heat Transfer Optimisation on Electromagnetic Heating for Well Stimulation and EOR
Authors: Santoso R. K. , Rachmat S. , Resha A. H. , Putra W. D. , Hartowo H. , Setiawati O. 
Published: October 2016

Abstract
The use of iron oxide nanoparticles in electromagnetic heating application has been proven through several investigations to increase the electromagnetic absorption properties of reservoir, then, significantly increase the generated temperature. A factor that affects the temperature build-up is nanoparticles transport mechanism. When the nanoparticles carrier fluid is in contact with oil, it is possible for mass transfer to occur. Thus, nanoparticles can diffuse from its carrier fluid to oil in the reservoir. This mechanism is advantageous in increasing the oil temperature because it reduces the heat loss. In this study, we investigate the diffusion mechanism of iron oxide nanoparticles from brine to oil. We used 1% NaCl solution as the brine and nanoparticles carrier. The experiments are done with variation of the type of oil, nanoparticles concentration and sonication time. Heavy and asphaltic oil creates barrier for nanoparticles to diffuse, therefore, diffusion of nanoparticles from brine to oil is very small. Increase in nanoparticles concentration and sonication time provides more driving force for nanoparticles to move to oil. However, it is not always as ideal as those conditions, interaction among nanoparticles, such as aggregation creates various unpredictable results in the experiments.
When to Refrac? Combination of Reservoir Geomechanics with Fracture Modeling and Reservoir Simulation Holds the Answer
Authors: Pankaj Piyush , Gakhar Kush , Lindsay Garrett 
Published: October 2016

Abstract
A workflow has been developed for a shale play in North America for the strategic deployment of refracturing in an unconventional reservoir. Although it is clearly understood in the industry that refracturing in tight unconventional reservoirs can have a dramatic impact on the productivity and longevity of economic production, until now there has been no workflow that could be counted on to deliver consistent results. The impact of production and stress re-orientation plays a significant role in adding a fourth dimension of time to the existing three-dimensional problem of hydraulic fracture modeling in these reservoirs.
We examined the re-orientation of reservoir stress and the change in stress magnitude with production in a case from the Eagle Ford. The stress redistribution occurring due to poroelastic effects was simulated using a finite element geomechanical simulator and then tied back to predict the new hydraulic fracture growth. Fracture geometry as it relates to draining the unstimulated domain was found to play a significant role in fracturing success. The impact of adding new perforations in the wellbore and application of a suitable diversion technique were also considered in the study. Our numerical investigation of the potential increase in productivity with selection of the optimum refracturing treatment timing and technique led to development of a methodology that solves the complex four-dimensional problem.
By adopting the guidelines from the case study application of the end-to-end workflow, operators can avoid the futility of too early or too late fracturing and thereby maximize their return on investment.
Electric Impulse Technology: Less Energy, Less Drilling Time, Less Round Trips
Authors: Voigt Matthias , Anders Erik , Lehmann Franziska 
Published: October 2016

Abstract
The paper presents a new drilling technology. With the Electric Impulse Technology it is possible to drill boreholes with less energy demand, more drilling speed and less drill bit changes. Drilling results, calculations und further steps will be presented.
The new technology uses high voltage impulses to destroy rock with almost no wearing of the drill bit. Engineering a drill bit with this technology will advance the drilling activity for oil and gas as well as geothermal drilling and mining. The objective is to develop a whole drilling system suitable for a conventional drilling rig. Within the first step an impulse voltage generator including a drill electrode was engineered, tested and evaluated. Drill performance under pressure with OBM was investigated. Next steps will include the developing of the energy supply for the system and field tests.
The impulse voltage generator designed as a downhole tool was developed to drill bore holes with a diameter of 12 ¼ inch in hard rock with a drill speed of 1 to 2 m/h which is comparable to conventional drilling bits. Furthermore it withstands temperatures up to 200 °C and pressures of 1000 bar. The components of the generator have a lifetime about 350 h, so a bit could be used almost seven times longer than a conventional drilling bit. In laboratory tests a block of granite was drilled on a length of 50 cm with a diameter of 12 ¼ inch. Additionally further materials like limestone, sandstone, marble and iron ore were successfully destroyed. Pressure tests up to 500 bar with WBM and OBM were performed and analyzed. The whole design process of the generator and the electrodes was accompanied by network analysis and FEM calculation.
The paper presents the new results of the development of a drill bit based on the Electric Impulse Technology. After the engineering of the impulse voltage generator and promising results the development of the power supply get into focus. The pressure tests show that the Electric Impulse Technology will work under borehole conditions. In addition to early processing the drill bit will be configured for drilling with WBM concerning environmental and financial issues.
Physical Simulation of Storage Threshold of Shale Oil
Authors: Jin Xu , Bi Lina , Wang Xiaoqi , Sun Liang , Li Jianming , Liu Xiaodan 
Published: October 2016

Abstract
In this contribution, a nano-pore template with controllable pore size was used to simulate pore-throats in shale. Considering the wettability at the solid-liquid contact, the seepage of oil in channels with different pore sizes was examined to figure out the effect of pore diameter on oil storage capacity scientifically and systematically for the first time. The simulation shows that the lower threshold of pore-throat to store oil can be 20nm under certain conditions. The new threshold value of pore size for oil storage has brought about revolutionary changes in the estimation of geologic reserves, recoverable reserves and economically recoverable reserves of shale oil.
Production Surface Network Modelling and De-Bottlenecking Analysis for Gathering Center in Kuwait
Authors: Almohammad Humoud , Al-Saqabi Mishari 
Published: October 2016

Abstract
One of the major challenges facing Kuwait mature oil fields is to maintain their current production and maximize recoverable reserves; to achieve Kuwait 2030 target: 4 MMSTBO. The challenging production environment in the selected area from Kuwaiti fields is not an exception, where high pressure and H2S wells are existing. Connecting wells, to the same processing facility, with varying in reservoir pressure, high, medium and low, create bottlenecks in the surface network.
To find bottlenecks in flowlines and have an optimum distribution of wells; the engineers have built and studied flowline network model in-house using a commercial steady-state multiphase flow simulator for the wells connecting to one of Kuwait companys' Gathering Centre (GC). GC-XY was considered as its eight headers are ranging between high and low pressure headers, and receiving production from several fields in Kuwait. The project started by data collection, followed by quality check the flowing conditions for each well and reservoir fluid models. Next, the physical network model was built using the simulator. After that, the flowing correlations factors were tuned.
The modeled results were compared with the actual testing results. The results findings show a significate potential of bottlenecks in 15 wells out of 83 oil production wells, mainly in the high pressure headers. Also, a possible production enhancement, of approximately 30,000 barrels per day. That to be achieved by implementing the explained optimum well distribution between the high pressure headers and low pressure headers. Furthermore, asphaltene and bitumen deposition are existed and deposited over time in the flowlines, making it essential to flush the flowlines with a solvent mixture to clean the inner flowing section. To successfully implement the flushing job, it is also required to have an awareness of the backpressure existence in the flowlines, which was achieved using the simulated model.
The project explains a complete procedure to build a reliable network model, to identify bottlenecks and minimize production loss. Bottlenecks in flowline can increase wellhead pressure; hence, it is crucial to find bottlenecks to detect and reduce backpressure effect on the flowline network. Implementing flowline flushing job successfully is important to maximize the production deliverability and prevent flowline blockage and backpressure; which will also cause the existing electrical submersible pumps to trip.
Oil Well Cement Static Gel Strength Development Comparison Between Ultrasonic and Intermittent Rotational Measurement Methods
Authors: Ashraf Shameed , Hamilton Paul , Salehpour Amir Gheisar , Azwar Cinto , Bogaerts Martijn 
Published: October 2016

Abstract
Disclaimer: This paper includes forward-looking statements, Actual future conditions...
The publication of the API Standard 65-2 "Isolating Potential Flow Zones During Well Construction" places strong emphasis on measuring the Critical Gel Strength Period (CGSP). The CGSP is the time period starting from when laboratory measurements indicate the slurry has developed Critical Static Gel Strength (CSGS), to when it has developed strength of 500 lbf/100ft2. As per the API standard, CGSP of 45 minutes or less has proven effective in isolating zones with severe flow potential therefore, the CGSP has been identified as a crucial parameter to qualify slurry systems for many oil and gas operators. The API 10B-6 "Recommended Practice on Determining the Static Gel Strength of Cement Formulations" indicates there are three measurement methods; continuous rotation, intermittent rotation, and ultrasonic-type static gel strength. This paper will review a comparative laboratory- based study between two measurement devices commonly used in the industry to measure the CGSP. One device uses the intermittent rotation, and the other uses the ultrasonic method.
The slurry systems selected for the study covers a density range of 11.5 to 18 lbm/galUS within the temperature range of 27 to 121 deg C. The selected slurries comprise of Class G cement, silica flour with extenders or weighting agents paired with antifoam, fluid loss additives, dispersant and retarder to represent the typical slurry systems used in cementation of potential flow zones. Additionally, each slurry system is designed for two scenarios; one is to cover a short placement time(3 to 4 hours) and the other for a longer placement time (7 to 8 hours). While some of the slurry systems passed the CGSP criteria based on the ultrasonic method of measurement, they did not pass the criteria when measured by the intermittent rotation method. Possible reasons for this mismatch are further explained in this paper.
Results of this study are applicable to all oil and gas service operators involved in cementation of potential flow zones. One would expect that both of these methods would predict the same slurry behavior in either passing or failing the CGSP criteria, however and on the contrary that was not observed on all of the slurry systems selected for this study.