bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of a New Treatment to Remove Calcium Sulfate Scale: Lab Studies and Field Application.
Authors: Farid Ibrahim Ahmed , Nasr-El-Din Hisham , Abd El-baqi Mohamed , Abdelhay Ahmed , Farouk Hossam , Aref Ahmed , Reda Ahmed , Rafaat Mohamed , Gamal Mohamed 
Published: April 2019

Abstract
Scale deposition has been a significant problem in the oil and gas industry. Scale deposition has an adverse impact on production and injection operations. The precipitation of scale in the near-wellbore area will diminish the productivity of the production wells and loss of the injectivity of water injection wells. This paper presents a new non-corrosive agent to remove calcium carbonate, and calcium sulfate scales.
Two sets of coreflood experiments were conducted to evaluate the chemical to remove anhydrite depositions. Coreflood experiments were conducted by using the new scale remover to stimulate dolomite cores with anhydrite content of 30 wt% at 250°F. Other experiments were conducted with the Bandera sandstone cores. Calcium sulfate was precipitated inside the pores and then the chemical was used to treat the cores to remove this damage. Effluent samples were collected and analyzed with ICP for sulfur and calcium concentrations. CT scan was used to detect the dissolution and the deposition of scale inside the cores. The chemical was applied on several oil wells from the Nukhul sandstone formation.
Coreflood results show increasing the permeability of the dolomite core to 4 times of its initial value and ICP results show 1:1 calcium to sulfur concentrations. The second coreflood experiments showed the ability of the dissolving agent to remove the precipitated scale completely with (final permeability =initial permeability) with no effect on clays. In the field case, the treatment was conducted and placed using a coiled tubing without using additional additives such as corrosion inhibitors, intensifiers, and iron control agents. The success of this treatment was realized by increasing the well production 4 times its initial oil production per day.
Field data and the lab results highlight that the de-scaling solution is an effective fluid for calcium sulfate scale.
The Use of Asphaltenes Precipitants and Environmentally Friendly Solvents During Solvent-Steam Processes
Authors: Ng Alwin , Vishnumolakala Narendra , Hascakir Berna 
Published: April 2019

Abstract
Steam flooding is the most widely used thermal enhance oil recovery (EOR) process to recover bitumen and heavy oil. This process has been proven to be reliable, thus, establishing itself as a favorite among other thermal EORs. However, the excessive water usage to generate steam causes environmental concerns such as air and water pollution. Thus, a noble idea to reduce the sole dependency on steam alone is to co-inject solvent with steam. Solvent will aid the oil recovery process by improving miscibility aside from the oil displacement mechanisms from steam itself.
Three core flooding experiments were conducted on a heavy oil sample from Texas; namely, steam flooding (E1), CO2 -steam flooding (E2), and CO2 - MS- steam flooding (E3). MS is a corn based environmentally friendly solvent which is tested for the first time for heavy oil extraction via solvent-steam injection process. Because CO2 is known as asphaltene insoluble solvent, asphaltene precipitation was also investigated on spent rock samples to determine the formation damage occurring during the process. An ASTM method was used to determine the amount of asphaltenes in initial oil sample, on produced oil samples, and on residual oil samples. Another flow assurance problem is emulsion formation which occurs widely in any steam processes. Hence, the emulsions formed during solvent-steam and steam experiments and the role of asphaltenes on emulsion formation are investigated.
It has been observed that CO2 enhances the asphaltene precipitation and results in consolidation of core samples which reduced significantly the oil production. The use of asphaltene insoluble solvent CO2 with an asphaltene soluble solvent (MS) enhanced the oil production, increased the sweep efficiency and decreased the water-in-oil formation.
With this study for the first time asphaltene soluble and insoluble solvents co-injected together with steam to recover a heavy oil from Texas. We also analyzed the oil displacement mechanism through asphaltene precipitation and emulsion formation.
Predicting and Applying Wellhead Temperatures for Steamflood Field Operation and Production Performance Monitoring
Authors: Yang Zhengming 
Published: April 2019

Abstract
Producer flow line temperatures (FLT) can be measured automatically with a thermistor on an emergency shut-down system (ESD), or manually on a specified spot on flow line with a hand-held unit. Measured FLTs can usually be mapped to represent the formation temperature distribution for steamflood reservoir management purposes (Hong, 1994). In the meantime, predicting the long-term flow-line temperature trend in steamflood operation is necessary for designing surface facilities for both oil dehydration/separation and produced water recycling. This predicted temperature will also be applicable for production performance monitoring. In addition to FLT, wellhead temperature (WHT) is another surface temperature. FLT and WHT are comparable for their close typical distance of 5-10 ft.
To predict the wellhead temperature, Hasan, Kabir and Wang (2009) derived a steady state analytical solution for calculating WHT from bottom hole temperature (BHT) under flowing conditions of a multiple section slant wellbore for the isothermal primary depletion process with both WHT and BHT being time independent for a given gross rate. This steady-state analytical solution has been extended to calculate steamflood producer WHT from BHT (both are time-dependent) by approximating WHT and monthly average of FLT measurements to a steady state solution consecutively. The monthly averaged FLTs are seasonally variable and higher in the summer months of July to September and lower in the winter months of December to February. Both WHTs (if measured) and monthly averaged FLT measurements depend on an annual ambient temperature cycle within the depth needed for reaching undisturbed ground temperature (typically 30-50 ft, Gwadera, Larwa and Kupiec, 2017). WHT prediction, however, are only process dependent and not seasonally variable due to the inability in describing seasonally undisturbed depth in the geothermal gradient. Therefore, WHT prediction can be validated with the monthly average of measured summer month FLTs. BHTs in this analytical approach is predicted by Lauwerier's analytical model (1955) and improved by calibrating with the available reservoir simulation model or several years’ FLT measurements for steamflood response timing.
A field case study for the South Belridge diatomite steamflood was investigated. WHT prediction is compared with FLT measurement for diagnosing and understanding the production performances such as water or steam premature breakthrough, interference by the waterflood on the steamflood boundary producers, as well as the FLT variation related to steam injection target rates. This diagnostic analysis approach combined with the Buckley-Leverett theory based displacement efficiency analysis, and injection pressure and rate signal, will help to develop an improved understanding of the displacement detail and form a decision base to optimize the production performance.
Polymer Flooding in Oil-Wet, 2D Heterogeneous Porous Media
Authors: Singh Robin , Song Haofeng , Mohanty Kishore K. 
Published: April 2019

Abstract
The displacement of viscous oils typically involves unstable immiscible flow. The microscopic and volumetric efficiency is further exacerbated if the reservoir is oil-wet and heterogeneous, respectively. The goal of this work is to systematically compare the performance of secondary vs. tertiary polymer flooding for viscous oil recovery in an oil-wet 2D, layered, heterogeneous system. It focuses on performing flow visualization to capture the effect of cross-flow and viscous fingering in both modes. First, contact angle experiments were performed to ensure that the reservoir crude oil results in oil-wet sand. Second, rheological analysis of HPAM polymer solution was performed to find the optimal injection concentration. Third, oil displacement experiments were performed in an in-house, custom-built 2D sandpack with the front face made of a transparent acrylic sheet for flow visualization. It was packed with two communicating layers of silica sand — bottom layer with 20-30 mesh and a top layer with 100-120 mesh, which resulted in a permeability contrast of 8:1. The system was vacuum-saturated with a viscous crude oil with a viscosity of 157 cp. Polymer floods were conducted in secondary and tertiary modes and the oil displacement profiles were continuously monitored using a camera. At the end of the experiments, the sandpacks were cut in 16-equal zones and were analyzed for the amount of crude oil using UV-Spectroscopy to quantify the residual oil saturation achieved in each zone. Finally, the results were compared with analogous floods in 1D sandpacks to understand the effect of heterogeneity. The contact angle experiments revealed that the reservoir crude oil used in the present work resulted in highly oil-wet sand after aging. In the oil displacement experiments in the layered sandpack, the secondary waterflood recovery after 1 PV was low (∼25% OOIP) due to channeling in the bottom high-permeability region, leaving the top low-permeability region completely unswept. Tertiary polymer flooding leads to improvement in sweep efficiency in both regions. It resulted in an incremental oil recovery of 53% OOIP with an ultimate recovery of 78% OOIP. Conversely, polymer flooding in secondary mode resulted in 46% OOIP in 1 PV injection. But the overall recovery was 69 % OOIP which was less than the tertiary mode. Different flow phenomena, such as, cross-flow, gravity segregation, and viscous fingering, were observed in these visualization experiments.
Saturation Dependent Errors in Interpreting Waterflood Diagnostic Plots
Authors: Wu Jun , Ershaghi Iraj 
Published: April 2019

Abstract
Various diagnostics plots related to examining injection pressure gradient requirements for maintaining injectivity have been used in waterflood management. Among these plots, Hall plots and the derivative of Hall plots are the most common approaches used in the industry. This paper includes an analysis of some errors associated with interpreting Hall plots and the derivative of Hall plots in monitoring waterfloods.
Based on observations from several waterfloods in California, in this paper we demonstrate by numerical modeling, that the cause of slope flattening can also be dependent on the state of saturation history around injection wells. We also show that the flattening can be compensated by skin build up resulting in misleading trends.
We conducted a series of numerical modeling work to examine these issues. From such modeling experiments, we considered cases of injection well behavior in virgin reservoirs as well as in mature waterfloods. We show that when new injectors are drilled, water saturation buildup tends to flatten the slope observed on the Hall Plot or the derivative of Hall plot. For new floods, drops in the slope observed can be associated with water saturation buildup caused by limited flooding history. When injection wells are drilled in flooded segments of a field, such saturation dependent flattening may not be observed.
This is a significant issue as it affects decisions related to restriction limits on injection gradient as well as unnecessary stimulation work. In summary, we conclude that interpretation of Hall plots without consideration of water saturation history can be misleading.
Pore Structure Characterization of a Shale Sample Using SEM Images
Authors: Zhang Yixin , Ghanbarnezhad Moghanloo Rouzbeh , Davudov Davud 
Published: April 2019

Abstract
We analyze a compiled stack of Scanning Electron Microscopy (SEM) images of an Eagle Ford shale sample to assess pore structure and complex pore connectivity. In recent years, shale and tight oil formations have played an important role as energy resource. However, uncertainties associated with pore structure and pore connectivity as an important parameter controlling the well productivity remain to be resolved; that is why, high-resolution image processing has been an emerging research tool.
In this study, 600 contiguous high-resolution SEM images of a 6 μm Eagle Ford sample is analyzed using an image processing software. We obtain 2D and 3D porosity and pore size distribution. In addition, we map out the connected pores to obtain the connected porosity from 3D volumetric fraction. Next, we analyze total and connected porosity as a function of sample size in both forward and backward sequences. Finally, results obtained from the shale sample is compared with a sandstone sample to determine differences in their pore structure properties.
We conclude that the connected porosity is 6.1% for the shale sample, smaller than that of the sandstone (19.6%). The attributed pore size distribution ranges from 0.01μm to approximately 0.1μm, while the sandstone’s pore radius size ranges from 1 μm up to 12.7 mm. Through evaluation of sandstone sample, it turns out that 3D total porosity of the sandstone sample is almost the same as the connected porosity. Moreover, although the connected porosity of the stacked images gradually and slightly decreases as the sample size increases. However, for the shale sample, total porosity remains almost constant as a function of sample size while the connected porosity significantly decreases from 13.3% to 6.1%. More interestingly, if the images are analyzed in the backward sequences, then both porosity and the connected porosity increase. Overall, the results suggest that for the studied shale sample, Representative Elementary Volume (REV) describing pore connectivity is around 4 μm.
The results from this study will provide a new insight into complex pore structure and help better understand the production performance of shale reservoirs. In addition, the outcome of this paper would have some implications on research work related to fluid flow in shale.
A Correlation for Estimating Biot Coefficient
Authors: Li Qi , Aguilera Roberto , Cinco Ley Heber 
Published: April 2019

Abstract
The objective of this paper is to develop an easy to use correlation for estimating Biot coefficient. This is important as Biot coefficient plays an important role in solving many practical petroleum engineering problems, including for example, design of hydraulic fracturing jobs and estimation of in-situ closure stress on proppant.
The procedure for developing the proposed empirical correlation uses data from various lithologies including limestone, sandstone, shale, marble and granite. Thus, the correlation has application in conventional and unconventional petroleum reservoirs. Use of the correlation requires knowledge of permeability and porosity, data commonly available in petroleum engineering (on the other hand Biot coefficient data is almost never available). The ratio of permeability and porosity, commonly known as process or delivery speed and pore throat aperture (rp35), are input for estimating Biot coefficient from the correlation proposed in this paper. The correlation is useful in those cases where sophisticated experimental work needed for estimating Biot poroelastic coefficient is not available.
Testing against various data sets indicates that the proposed correlation provides reasonable results. In the past, methods with different complexity levels have been used for estimating Biot coefficient. These have included, for example, (1) a method that requires knowledge of bulk modulus of the rock mineral and bulk modulus of the skeleton with no fluids in it, parameters that are not usually available for petroleum reservoirs, (2) a method that is based on knowledge of only porosity, (3) a method that is based on knowledge of only permeability, and (4) an approach that simply assumes that Biot coefficient is equal to 1.0 or some other number. The proposed correlation falls somewhere in the middle. It is not as simple as saying that Biot coefficient is equal to 1, or saying that it depends on only porosity, or only permeability. On the other hand, it is not as complex as requiring sophisticated laboratory work of the type mentioned in item (1) above.
The novelty of this work is the development of an original easy to use correlation for estimating Biot coefficient in conventional and unconventional (tight and shale) reservoirs based on knowledge of k/ϕ and rp35. The correlation is developed in such a way that it has also application for estimating Biot coefficient in the case of unconsolidated petroleum reservoirs and oil sands. The overall approach allows integration of geomechanics with flow units, geology, petrophysics, and reservoir engineering.
Improving Water Efficiency in the Wilmington Field Using Streamline-Based Surveillance
Authors: Kwong Ryan R. , Kellogg Ryan P. , Thiele Marco R. , Simmons David M. 
Published: April 2019

Abstract
This paper describes application of a streamline-based surveillance methodology to define injector-centered-patterns using streamlines, calculate pattern efficiencies, and propose target rates for injectors and producers to improve oil production, lower WOR, and reduce water cycling in the Wilmington Field.
The Wilmington Field is a faulted anticline structure in the Los Angeles Basin with alternating sand/shale sequences, which straddles offshore and onshore locations in Long Beach, California. It has been actively waterflooded since 1953 and currently injects over 1.6 million barrels of water injected (BWIPD) and produces at ~98% water cut. Due to the industrial port environment and history of subsidence, a minimum voidage replacement ratio (VRR) is required to sustain stable surface elevations. Given the scale of the Wilmington field, we focused on implementing two pilots to improve the flood performance by targeting different fault blocks/reservoirs: Fault Block 2 Tar Reservoir (Tar 2) and Fault Block 7 Ranger Reservoir (Ranger 7) which together represent 5% of total Wilmington oil production. Both surveillance models used a multi-layered numerical grid with geologic properties from existing 3D geomodels. The key objective for Tar 2 and Ranger 7 was to redistribute the current injected water volumes to improve oil production while maintaining VRR targets. Injection into the Tar 2 model was vertically refined to per-sand using pseudo-injectors in the modeling approach. Injection wells for the Ranger 7 model used a single path and injection volumes were allocated into each sand using permeability-height (kh) values. Rate changes suggested by the surveillance model for both pilot areas were made through choke adjustments and/or well shut-ins and required no pump size changes or workovers.
The Tar 2 and Ranger 7 pilots were monitored over a 6-month and 17-month period, respectively. The Tar 2 pilot area resulted in a decrease from 20% to 2 % annual oil decline rate while keeping a constant injection rate, while the Ranger 7 pilot area new rate target resulted in WOR from 52 to 47 and a decrease in annual oil decline from 15% to 5%. With the success of the waterflood management approach seen in Tar 2 and Ranger 7, a larger area in the Wilmington Field, Fault Block 6 Ranger (23% of total production) is now under a similar evaluation with the goal of reducing WOR and oil decline using the same surveillance methodology.
Irrigation efficiency and water withdrawal in US agriculture
Authors: Wang Haoying 
Published: April 2019

AbstractTo meet future food demand and sustainability requirements of society, the agriculture sector faces challenges in both the institutional dimension and the technological dimension. One of the main concerns regarding the current agricultural production pattern is the tremendous amount of water it requires to maintain and boost output. With a changing climate and increasing demand from civil uses, promoting both water allocation efficiency and water application efficiency becomes the focus of policy design. The unintended consequences of water policies, however, have led to extensive debates. This study addresses the key question of whether irrigation efficiency improvement leads to reduced per-area water use. The study assembles a national county-level panel data set on water withdrawal, irrigation technology, and farm operation and demographics. The empirical results show that a higher irrigation efficiency is associated with a lower per-area water application in US crop production. Two alternative efficiency measures are proposed. Depending on how the efficiency is measured, a one standard-deviation efficiency improvement (6–30%) in irrigation can reduce 6–11% of water withdrawal in US crop production. The water saving is about 0.06–0.12 mm/day given a county average irrigation water use of 1.07 mm/day.
The Opposite Effect of L-kynurenine and Ahr Inhibitor Ch223191 on Apoptotic Protein Expression in Pancreatic Carcinoma Cells (Panc-1)
Authors: Leja-Szpak Anna , Góralska Marta , Link-Lenczowski Paweł , Czech Urszula , Nawrot-Porąbka Katarzyna , Bonior Joanna , Jaworek Jolanta 
Published: April 2019

Background:L-kynurenine, derivate of L-tryptophan, is synthetized by indoleamine 2,3-dioxygenase (IDO). The effects of L-kynurenine depend on its binding to an aryl hydrocarbon receptor (AhR).Objective:The aim of this study was to investigate the changes within the apoptotic pathway in PANC-1 cells subjected to L-kynurenine or L-tryptophan considering the production of anti-apoptotic proteins from the IAPs and Bcl-2 family, as well as the regulation of NF-κB signaling.Method: :The investigated substances were added alone or in combination with the AhR inhibitor (CH223191) to cultures of PANC-1 cells. Cytoplasmic and nuclear proteins were analyzed by immunoblotting and cells were incubated with the investigated substances to determine cytotoxicity and proliferative effects.Results:Incubation of PANC-1 cells with L-kynurenine or L-tryptophan resulted in the increase in antiapoptotic cIAP-1, cIAP-2, XIAP and Bcl-2 expression and a decrease in pro-apoptotic Bax. These changes were accompanied by the reduction of active caspases -9, -3 and PARP-1. The treatment leads to translocation and enhanced production of nuclear NF-κB p50 and Bcl-3. Incubation of the cells with AhR blocker either alone or together with L-kynurenine or L-tryptophan resulted in the opposite effect, leading to the downregulation of IAPs and Bcl-2, upregulation of Bax and caspases expression.Conclusion:1) L-kynurenine and its precursor promote anti-apoptotic effects through the modulation of IDOdependent pathway and regulation of IAPs, Bcl-2 and NF-κB family members in pancreatic carcinoma cells 2) inhibition of AhR by CH223191 exerts an apoptosis-promoting effect, and this observation might suggest the potential use of this compound in pancreatic cancer therapy.