bluuebunny/crossref_metadata_2025_split huggingface dataset:
Predicting Hydraulic Fracture Geometry and Well Performance in Unconventional Reservoirs using the Multilayer Discrete Fracture Network
Authors: Pankaj Piyush 
Published: October 2018

Abstract
Naturally fractured shale reservoirs are characterized by a complex 3D discrete fracture network (DFN). DFN density in different stratigraphic layers imposes variability in hydraulic fracture geometry as the hydraulic fracture propagates in the laminated shale reservoirs. The study presented in this paper aims to parametrically determine the hydraulic fracture geometry and consequent well production when varying densities of DFN interact with the propagation and growth of hydraulic fractures.
A 3D multilayer DFN (MDFN) is discretized in vertical grid elements distributed in layers of the formation. This is represented in a geocellular grid model with varying DFN sets in multiple layers. A new hydraulic fracture propagation model with stacked height has been utilized to determine the interaction of the hydraulic fractures with the DFN in all different layers. The vertical variation of the DFN causes more complex fracture propagation because it accounts for the fracture crossing criterion apart from the stress profile variation in layers and the stress shadow impact. Comparison of such complex hydraulic fracture geometry with the simplistic average 2D representation of the DFN reveals the geometry difference. This is further coupled to reservoir simulation in numerical engines to determine the difference in production performance. Finite element geomechanical simulations are made to predict microseismic events, which are then compared to the acquired microseismic data to validate the hydraulic fracture geometry.
Hydraulic fracture geometry was found to differ when an MDFN approach was taken as compared to simplistic single-layer DFN (SDFN) interaction. Production performance of the fracture geometry obtained by considering an MDFN was therefore more realistic. The simulated microseismic data also exhibited a much better match to the acquired microseismic data when an MDFN was used for modeling. Visual analytics tools for comparison of observed microseismic event distribution with predicted microseismic data in the model show errors ranging from 16% to 24% for different view representations. As a conclusion of this study, it was evident that wherever applicable, an MDFN approach should be used to determine the well completion performance. However, there is some scope for improving the modeling of hydraulic fracture interaction with natural fractures by incorporating the dip angle of the MDFN for computing the crossing criteria.
This study represents the first time a more-robust modeling of the interaction of hydraulic fractures with a 3D MDFN was achieved using complex fracture models to determine the impact on productivity. Finite-element-computed microseismic data allowed further validation. Operators can use the approach described in this study to predict their well performance more accurately in complex fracture reservoirs.
Modeling of Conformance Improvement through Smart Polymer Gels
Authors: Temizel Cenk , Canbaz Celal Hakan , Putra Dike , Najy Anas K. , Alklih Mohamad 
Published: October 2018

Abstract
Several studies have indicated polymer flooding to be an optimal enhanced oil recovery (EOR) strategy in fields with oil viscosities between 10 – 150 mPa.s. In the current oil price environment maximizing the output from exisiting fields, using the ideal EOR operation pertinent to each reservoir, is of increased importance. In addition, with almost half of the total global oil production for the coming decades projected to come from EOR operations, it is essential to select the right strategy for each field. For fields that have oil viscosities above 150 mPa.s, mobility ratio of the polymer containing injectant is an inhibiting factor to the polymers injectivity and pumping efficiency, and hence polymer flooding is not a viable EOR strategy in such fields.
Supramolecular systems are a viable alternative to conventional polymers used in polymer flooding, mainly due to their high resistance to temperature and salinity. A unique feature of these systems is its reversible viscosity, using which system viscosity can be adjusted from low values during injection to high values prior to oil contact within the reservoir. Supramolecular systems are highly resistant to degradation from shear and temperature due their inherent property of disassembling, when exposed to high shear and/or temperature, and re-assembling. This property is useful in restrictive environments such as flow through narrow channels, where supramolecular systems disassemble (molecular scission) and reassemble, thereby maintaining its molecular properties in a "self-healing" manner.
In this study, modeling and simulation of these "self-healing" supramolecular systems have been conducted to compare its displacement efficiency compared to conventional polymer systems. They have the potential to be applied to multiple types of reservoirs including those with thin layers and permafrost conditions. From the results of this study it is evident that supramolecular systems offers field operators considering polymer flooding a cost-effective, smarter and technologically feasible EOR strategy.
Diversion and Keys to Stimulation Success or Failure
Authors: Fragachan Francisco E , Huang Jian , Safari Reza , Aubry Eric , Thirion Aurelien , Benquet Jean-Claude 
Published: October 2018

Abstract
The ultimate goal of diversion applications is to enhance contact of the stimulation fluid with the reservoir rock in such a way to maximize the conductive reservoir volume. Unfortunately, intentions to simplify diversions with rule of thumbs, trial and error, and pump and hope have generated uncertainties and slowed the impact in stimulation efficiency and production enhancement that this technique is capable of generating.
Fluids introduced into a reservoir for stimulation typically take the path of least resistance and therefore frequently go into areas where there are open flow paths. In many cases, those existing flow paths are neither the areas you would want to stimulate for increased production, nor areas from which formation damage will need to be removed. The success of a hydraulic fracturing or acidizing operation depends on maximizing the contact between the stimulation fluid and the intact rocks. To achieve this goal, existing fluid paths must be efficiently plugged to divert the fluid towards intact or under- stimulated rock for efficient application, which in turn maximizes the BOE (barrels of oil equivalent) returned from the stimulation treatment relative to unit cost.
Although industry has been deploying this technology on a more widespread basis recently, they have not been as focused on the underlying mechanisms, physics and controlling parameters which ultimately govern the success of the stimulation event.
This paper will present a comprehensive discussion around missing factors associated with jamming and plugging efficiency, particle size, particle shape, frictional parameters, particle concentration, opening geometry, rate during placement, and particles ratio. It will clearly highlight the importance of understanding the physics and mechanisms associated with a complex diversion process requiring a rigorously engineered approach.
Multiple experiments were reviewed to quantify and understand the effect and importance of the different key factors that dictate the overall goal of a successful diversion treatment. In fact, an analytical model has been developed, verified with advanced numerical simulations and calibrated with experimental results to optimize the operational parameters required for efficient diverter displacement; including adjusting the displacement rate during diverter injection and also determining and adding the required volume of spacer to minimize particle dispersion, which ensures that the diverter pill arrives at the required site intact and as designed. The proposed numerical and analytical engines are presented within the design engineering process to better enable and achieve the necessary pressure buildup required for efficient fluid diversion.
Can Solvent Injection be an Option for Cost Effective Enhanced Oil Recovery?: An Experimental Analysis for Different Oil and Rock Characteristics
Authors: Babadagli T. , Cao N. 
Published: October 2018

Abstract
We performed a set of experiments on vertically situated sandpack models. Different slug sizes of water and solvent (heptane used in the experiments) were tested for 2,000 cp heavy-oil. As a benchmark, tests were also performed for 14 cp light oil for comparative analysis. In addition to the technical feasibility, an economic analysis was performed considering the amount of solvent injected and oil and solvent recovered. Experiments were repeated for oil-wet systems. For both light and heavy oils, starting the process with the solvent was feasible in the short run technically and economically. If the process starts with water, excess amount of it occupies the largest pores and hinders solvent-oil interaction for mixing and oil displacement. This was true especially if the rock is both oil-wet and heavy, which yielded faster recovery and higher ultimate recovery than the water-wet case. The time for switching to solvent injection is more critical in the heavy-oil case as it is more sensitive to the amount of existing water in the system. As oil becomes heavier and if the rock is water-wet, starting the process with waterflooding is not suggested. In this case, more solvent needs to be injected in the first cycle compared to oil-wet systems. Due to partial miscibility and more gravity stable nature, solvent retrieval and sweep with water can be more effective in case of heavy-oil compared to light oil (fully miscible case) and, as a result, can be even more profitable. This is highly critical in exploitation of heavy-oil reservoirs if thermal options are limited and greenhouse gas emission is a concern.
A Robust Nitrogen-Digestion Method to Determine the Concentrations of Polyacrylamide-Type Polymers
Authors: Hou Jian , Han Ming , Fuseni Alhasan 
Published: October 2018

Abstract
Polyacrylamide-type polymers are widely used in polymer flooding techniques for mobility control. To monitor the performance of a polymer flooding process in either field application or laboratory testing, it requires the accurate determination of polymer concentrations in the effluents. This paper presents a robust nitrogen-digestion method to determine the concentrations of various types of polymers such as hydrolyzed polyacrylamides, sulfonated polyacrylamides and cationic polyacrylamides.
Different from the classical nitrogen-bromination method used to identify polymer concentrations, the nitrogen-digestion method is based on the digestion of amide groups in the polymers as free nitrate ions using digestion device operated at 120ºC. The resultant solutions were measured by a visible light spectrophotometer. The nitrogen contents as measured by absorbance values of the solutions are used for the calculation of the polymer concentrations. The average testing time for each sample is less than 5 minutes.
Seven polymer samples from three different polymer types were investigated. The experimental results show good correlations between nitrogen content and absorbance values and the resulting concentration for each polymer sample studied. As the chemical structures of polymers might be altered in the application process, such as hydrolysis of amide groups to hydroxyl groups, the concentration results obtained could be interfered with. Therefore, the infrared (IR) method was used to revise the concentrations obtained by nitrogen-digestion method. A normalized correlation as a rule-of-thumb was set up to categorize the polymer type and determine the polymer concentration. In addition, it was also noted that the measurements of polymer concentration using the nitrogen digestion method are not influenced by the salinities of make-up brines.
This paper presents an accurate, portable, and fast way to determine the polymer concentrations in brines. It is of particular importance for field operations.
Carbon Intensity: Comparing Carbon Impacts of Middle East and US Shale Oils
Authors: Meehan D. Nathan , El-Houjeiri Hassan M. , Rutherford Jeffrey S. 
Published: October 2018

Abstract
Carbon intensity (CI) is a quantitative measure of the carbon generated per unit of energy and is a useful way to compare alternative sources of energy or even various crude oils. The CI of oil and gas production varies widely across global oil plays. Life cycle extraction from some unconventional plays (e.g., tar sands) have some of the highest CIs, but even many North American shale plays have relatively high carbon intensity. Middle East crudes range from some of the lowest to some of the highest global values of CI. Flaring and venting of associated or non-associated natural gas dramatically increases CI.
This paper applies peer-reviewed processes across broad averages of shale activity in North America and compares them with Middle East activity. We perform well-to-refinery calculations of CI for major unconventional oil plays in North America and Middle East major producing countries. This approach accounts for emissions from exploration, drilling and completions, production, processing, and transportation. The analysis tool is an open-source engineering-based model, developed at Stanford University, called the Oil Production Greenhouse Gas Emissions Estimator (OPGEE). OPGEE makes estimates of emissions by using up to 50 parameters for each modeled field. Data sources include government sources, technical papers, satellite observations, and commercial databases.
Applied globally, OPGEE estimates show the highest values are in areas with extensive flaring of natural gas and for very heavy crude oils. Heavy oils requiring large energy inputs (e.g., steam flooding) and/or the use of light hydrocarbon diluents for transportation have much higher values of carbon intensity. Saudi crude production, analyzed from public sources, has some of the lowest CI regionally and globally.
Examples illustrating how OPGEE can be used to evaluate the CI of public policy actions are provided. Further sensitivity analyses to pad drilling and improving well performance are shown, and the CI impacts associated with hydraulic fracturing.
While Middle East crude will remain vital to global supplies, unconventional production, especially from light tight oil (LTO), is the most significant new source of fossil fuels in the last decade. Under almost any conceivable carbon constraints, oil usage will continue for many decades and increase in the near term. Operators, governments and regulators must avoid "locking in" the development of sub-optimal resources and provide incentives for LTO operators to manage resources sustainably. Oil producers must prepare by eliminating development of marginal projects, eliminating flaring, optimizing hydraulic fracture treatments, increasing the use of pad drilling, using improved recovery methods (e.g., enhanced oil recovery using anthropogenic CO2), reducing energy use, and eliminating unnecessary gas waste.
Effect of Data Errors on Multiphase Flow Correlations
Authors: El-Moniem Mohamed A. , El-Banbi Ahmed H. 
Published: October 2018

Abstract
In absence of downhole permanent gauges, multiphase flow correlations are widely used to predict well flowing pressures and production under variety of conditions. They also have wide applications in nodal analysis and artificial lift optimization.
In our previous work (SPE-175805), we collected a large database of more than 3000 multiphase pressure points and tests. We used this large database to develop guidelines to select the most accurate correlations for different pipe and flow conditions. Typically, there are close to 20 input parameters used in the calculations of multiphase flow correlations. In this study, we used sensitivity analysis techniques with our large database to determine which input parameters affect the multiphase flow correlations results for different pipe and flow conditions. Among these important input parameters are producing gas-oil ratio (GOR), API, gas specific gravity and tubing roughness. For each of the important input parameters, we change the value of the input parameter within the measurement accuracy in the field and find out their effect on the calculated pressure in comparison with the measured pressure.
We categorized the large database into clusters representing different pipe and flow conditions, then used a commercial pipe flow software to model these wells. We then performed hundreds of sensitivity studies on almost all input parameters for oil wells. It was observed during the study that several parameters have significant effect on multiphase correlations results. These effects were different for low and high production rate wells and low and high GOR wells. For example, accuracy of API was found to have low effect on results. However, GOR had significant effect on results. Pipe roughness was found to be much less important in oil wells especially at low production rates and at low GOR.
Based on the results of the sensitivity studies for the large database, we developed guidelines for which parameters are important for which wells and under what conditions. The guidelines will help engineers working on developing multiphase flow models for wells focus on obtaining good values for the most important input parameters.
Well Data Transfer between Corporate Database and Vendor Database
Authors: Wei Xinwei , Amer Mustafa M. , Rushood Ibrahim S. , Alsinan Hadi H. 
Published: October 2018

Abstract
It is common nowadays in the O&G industry that operators maintain their own data repository for drilling and workover operations, develop applications on top of it. Meanwhile, operators still use service companies/vendors specialized applications for various business needs. Data integration becomes more important for utilizing existing data in operator’s data repository in vendor applications and vice versa.
An approach to transfer deviation survey data from corporate database directly to vendor database was attempted, it has gone through two major phases: from manual to automated process. The automated data transfer process synchronize deviation survey data between two databases on a daily basis for over a year and stable.
The success of deviation survey data transfer from corporate database to vendor database laid the foundation to establish common data structures and enable other data types to be added in the data transfer process. With more data available in vendor application database, engineers have changed the way they obtain well data information, and saved lot effort and time for data input for planning their wells.
Enhanced Heavy Oil Recovery by Thermal-Different Aqueous Ionic Solutions-Low Salinity Water Flooding
Authors: Al-Saedi Hasan N. , Flori Ralph E. , Brady Patrick V. 
Published: October 2018

Abstract
In this study, we propose to quantify a control of water chemistry on water-rock interactions and wettability alteration during Lo-Sal water-flooding of sandstone cores containing heavy oil. We intended to identify the dominant process of wettability alteration through considering all possible water-rock interaction mechanisms simultaneously. Water chemistry partially determines the dominant wettability alteration. This includes salinity, type of ions, and possibly pH.
The effect of the potential determining ion towards sandstone ‘calcium ion’ is presented in this work. The ultimate oil recovery for the core saturated in normal Ca2+ concentration at higher temperature was higher than the core saturated with double Ca2+ at the same temperature. The divalent cation (Ca2+) concentration was then doubled in the aging water, resulting in a lower oil recovery. The thermal technique seems to be related to the chemistry of the water, meaning that the injected hot water must be tuned to the proper chemical composition. Desorption of Ca2+ is associated with pH jump and thereby increased microscopic sweep efficiency, and it seems to have a large impact on LS water EOR heavy oil.
Zero Solid Invasion Water-Based Drilling Fluid
Authors: Jafarov Tural , Elkatatny Salaheldin , Al-Majid Abdulaziz , Mahmoud Mohamed 
Published: October 2018

Abstract
Reducing the filtrate volume and eliminating the solid invasion is very important and critical in drilling tight reservoir. This will eliminate water blocking which is the common problem in drilling tight gas formation.
The objectives of this study are to evaluate the effect of using sodium silicate, assess the changes of the rheological properties of water-based drilling fluid, determine filtrate volume and filter cake thickness, and optimize the concentration of sodium silicate to be used.
The obtained results showed that there was no effect of adding sodium silicate to the drilling fluid on density and pH. At room temperature, the optimum concentration of sodium silicate was 0.075 wt.% wt. which no change was observed in the yield point plastic viscosity ratio and at the same time, the plastic viscosity, yield point, and gel strength were enhanced. At higher temperature 120 and 170℉, the optimum concentration of sodium silicate was 0.075 wt.% which enhanced the rheological properties of the drilling fluid. Sodium silicate worked as a catalyst and as a result, it enhanced barite solubility at 200℉. The cumulative filtrate volume was decreased by 53% when using 0.075 wt.% of sodium silicate and the filter cake thickness was decreased by 65%. The retained permeability was 100% and the CT number before filtration and after removal was very closed, confirming no solid invasion was observed in the core.