bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Variable-Switching Method for Mass-Variable-Based Reservoir Simulators
Authors: Alpak Faruk O. , Vink Jeroen C. 
Published: October 2018

Summary
Field-scale simulations of complex processes often suffer from long simulation times. One of the main reasons is that the Newton-Raphson (NR) process used to solve each simulation timestep requires many iterations and small timestep sizes to converge. Because the selection of solution variables affects the nonlinearity of the equations, it is attractive to have a practical method to rapidly explore the use of alternative primary variables in general-purpose reservoir simulators.
Many reservoir simulators use pressure, saturations, and temperature in each gridblock as the primary solution variables, which are referred to as natural variables. There is also a class of reservoir simulators that uses pressure, total component masses (or moles), and internal energy in each gridblock as primary variables. These simulators are referred to as mass-variable-based reservoir simulators. For a given choice of primary variables, most simulators have dedicated, highly optimized procedures to compute the required derivatives and chain rules required to build the Jacobian matrix. Hence, it is usually not possible to switch between mass and natural variables. In this work, however, we establish a link at the numerical-solution level between natural- and mass-variable formulations and design a novel (nonlinear) block-local method that transforms mass-variable shifts (computed at each NR iteration) into equivalent natural-variable shifts.
We demonstrate on a number of simulation models of varying complexity that by use of the proposed approach, a mass-variable-based flow simulator can still effectively use natural variables, where the change of variables can be made locally per gridblock. Results indicate that in some models the total number of NR iterations, linear-solver (LS) iterations, and timestep-size cuts (caused by the nonconvergence of the NR procedure, also known as backups) are reduced when using natural variables instead of mass variables. However, the improvement is relatively modest and not generally observed. Our findings also signify that depending on the specific characteristics of the simulation problem at hand, mass-variable-based simulators may perform comparably or outperform natural-variable-based simulators.
The proposed variable-switching method can be used effectively to evaluate the effect of using different primary solution variables on problem nonlinearity and solver efficiency. With this method, the effect of interchanging primary solution variables on problem nonlinearity can be rapidly evaluated.
Surfactant/Polymer Flooding: Chemical-Formulation Design and Evaluation for Raudhatain Lower Burgan Reservoir, Kuwait
Authors: Al-Murayri M. T. , Hassan A. A. , AlAbdullah M. B. , Abdulrahim A. M. , Marlière C. , Hocine S. , Tabary R. , Suzanne G. P. 
Published: October 2018

Summary
Surfactant/polymer (SP) flooding is an enhanced-oil-recovery (EOR) process that can lead to incremental oil recovery through two mechanisms: reducing oil/water interfacial tension (IFT) to decrease residual oil saturation and increasing the viscosity of the displacing fluid to improve overall sweep efficiency. IFT reduction allows better oil recovery by overcoming capillary effects, while the increased viscosity of the displacing fluid allows a more-homogeneous sweep of reservoir oil. Implementing chemical flooding in reservoirs with relatively high temperature and in-situ salinity (&gt;200,000 ppm) is somewhat challenging. This paper describes the extensive laboratory work performed for the light-oil Raudhatain Lower Burgan (RALB) Reservoir (180°F/82°C) in Kuwait.
Reservoir fluids were thoroughly characterized to preselect the most-suitable chemicals for the SP process. Reservoir crude oil was analyzed and recombined with gases (C1 through C3) depending on the reported gas/oil ratio (GOR) to reproduce the oil in place (OIP) at original reservoir conditions in terms of pressure, temperature, and oil composition. A shift of the live-oil equivalent alkane carbon number (EACN) was compared with the dead-oil EACN.
Numerous surfactants were screened according to three main criteria: solubility in the envisioned injection brine, ultralow oil/water IFT, and chemical adsorption on reservoir rock. Different brine types were considered, and the use of adsorption inhibitors was also investigated. Furthermore, polymer screening involving temperature-resistant polymers was conducted by means of viscosity, long-term-aging, and adsorption tests. Polymer compatibility with the selected surfactants was also evaluated. The selected SP formulation was further evaluated through a series of coreflood experiments that were mainly dependent on chemical adsorption on reservoir rock and incremental oil recovery. An injection strategy was designed as a result of these experiments.
Laboratory results obtained thus far are encouraging and provide a systematic methodology to design SP injection in high-temperature, high-salinity, and light-oil reservoirs that are similar to the RALB reservoir. Additional technoeconomic evaluation is in progress in preparation for field-scale deployment of SP injection at RALB Reservoir.
An Experimental Study on Interactions Between Imbibed Fracturing Fluid and Organic-Rich Tight Carbonate Source Rocks
Authors: Liang Feng , Lai Bitao , Zhang Jilin , Liu Hui-Hai , Li Weichang 
Published: October 2018

Summary
Carbonate reservoirs dominate oil (70%) and gas (90%) reserves in the Middle East, and imbibition is the main mechanism for fracturing-fluid uptake during the hydraulic-fracturing stimulation process. Because of the highly heterogeneous nature of tight carbonate source rocks, it is crucial to understand the effects of imbibed fluid on the mechanical, morphological, and flow properties of carbonate rocks. Although the influence of imbibed fluids on the wettability of carbonate reservoir has been studied extensively, research regarding the effects of imbibed fluids on the texture and mineralogy of carbonate rocks is still very limited. This paper aims to provide a conceptual approach and work flow to characterize and quantify microstructure and mineralogy changes in carbonate rocks caused by imbibed fluids.
A thin section of a low-permeability organic-rich carbonate-rock sample [7×7×0.3 mm (length×width×thickness)] was used in the study. The sample was submerged into 2%-KCl (pH = 7.1) fluid from one end to simulate the spontaneous-imbibition process. A scanning electron microscope (SEM) was used to capture the sample's morphological changes before and after spontaneous imbibition. Energy-dispersive-spectroscopy (EDS) maps were measured before and after fluid treatment to investigate changes in various elemental distribution. In addition, inductively coupled plasma (ICP) equipped with an optical-emission-spectrometer (OES) detector was used to quantify dissolved-ion concentration in the treatment fluid. Permeability and porosity were measured using core plugs with dimensions of 1.0×1.5 in. (diameter×length) before and after fluid treatment. During the imbibition process, approximately one-half of the sample was submerged in the treatment fluid.
The SEM images for the thin-section sample showed three zones with distinct fluid-uptake characteristics. In Zone I, which was fully submerged in the testing fluid, a significant amount of mineral dissolution was observed. In Zone III, which was above the testing-fluid level, considerable mineral precipitation was detected. While in the transition zone just above the water/air interface (Zone II between the previous two zones), only a minor level of mineral dissolution was observed. Elemental-distribution changes resulting from the fluid treatment were identified by EDS analysis in all three zones. Gypsum and calcite crystals dissolved into imbibed fluids upon reaction. Gypsum was found reprecipitated on the rock surface in the zones above fluid level. The observed gypsum formation likely resulted from the dissolution of the gypsum from the rock matrix, then reprecipitation later from the imbibition experiment caused by water evaporation. Absolute-permeability and porosity measurements for core-plug samples have shown that both were increased after the imbibition process.
Wellbore-Stability Analysis Considering the Weak Bedding Planes Effect: A Case Study
Authors: Mehrabian Amin , Pérez Arturo Díaz , Santana Claudia 
Published: October 2018

Summary
Wellbore stability in shale is often hampered by the detrimental effect of existing weak bedding planes on shear failure of the rock surrounding the borehole. This paper presents results from an analytical solution to the wellbore-stress problem that incorporates rock failure along weak bedding planes. The solution is used for the case study of a highly inclined well section in a laminated layer of troublesome shale with a strike-slip faulting regime above the target formation in Latin America. Findings indicate improvement in the estimated margin for the wellbore-breakout limit of drilling-fluid density, and, more prominently, the safest drilling direction by accounting for the presence of weak bedding planes in the related wellbore-stability analysis.
Wellbore Modeling and Reservoir Characterization for the Application of Artificial Lift in Deep Horizontal Wells in the Unconventional Reservoirs
Authors: Pankaj Piyush , Patron Katherine Escobar , Lu Haidan 
Published: October 2018

Abstract
Several methods have been deployed for artificial lift in deep long horizontal wells completed in unconventional reservoirs. Some methods have been successful whereas some others have failed. In our study, we investigated the various lift mechanisms and derived an envelope for their application to such horizontal wellbores using a sensitivity study through a transient fluid- flow wellbore model.
A calibrated earth model from the Eagle Ford Shale basin with hydraulic fracture geometries in the horizontal wellbore was used for the sensitivity study. The wellbore profile was changed in the simulation model to four different types of profiles: toe up, toe down, toe up with hold trap, and toe down with hold trap. Other factors such as location of the artificial lift equipment in the wellbore, reservoir performance, and deliverability were considered for the deployment of the artificial lift method. Transient fluid-flow wellbore simulations and numerical reservoir simulations were used to determine the performance potential and effectiveness of the artificial lift mechanism for long-term productivity.
Multiphase fluid flow and transient flow phenomenon are critical modeling considerations for horizontal wellbores. It was found that the critical flow rate in horizontal wells can vary considerably when the well profile is considered. As the drilling dogleg severity increases, the chances of wellbore slugging and liquid holdup increase. Additionally, with producing time, the conditions change. In a gas lift well, if the gas injection rate is maintained above the critical rates as determined in this study, the production issues can be controlled. Therefore, it is clear from this study that the well trajectory and drilling uncertainty window must also account for the artificial lift method that is planned to be deployed. Adjustments to the artificial lift method placement in the wellbore would help offset negative impacts if the wells are poorly drilled.
Recommended practice for drilling, completion, and artificial lift can be derived from this study. Integration of the artificial lift selection to the earth model, drilling trajectory and landing, hydraulic fractures, and the completion model is paramount to improve the efficiency of artificial lift in the unconventional reservoirs.
Gas Lift Annulus Pressure
Authors: Decker Kenneth , Sutton Robert P. 
Published: October 2018

Abstract
Annulus pressure at depth is a primary requirement of any gas lift design. There are several methods of determining annulus pressure including reference to a monograph, density equation used to full depth with average pressure and temperature, and density equation used in small depth increments with average temperature and pressure within the increment. The choice of which method to use comes with limitations on the accuracy of the predicted pressure at depth.
When the annulus pressure at depth is calculated by use of a computer program, the choice of which correlation to use to model the critical properties of the gas and which compressibility factor correlation also affects the accuracy of the calculated pressure at depth.
As a gas lift well transitions from a geothermal temperature profile to a flowing temperature profile during the unloading and lifting process, the annulus pressure at depth will decrease even though the surface injection pressure remains unchanged.
Finally, the change in annulus pressure during the unloading process is governed by the volume of gas present in the annulus. A decrease in pressure is due to a reduction in gas volume. Traditional design techniques ignore this reality and substitute a theory of valve performance to explain annulus pressure changes during unloading. This simplified analogy of valve performance made it easy to design a gas lift well but incurred errors and misconceptions about how the annulus pressure changes during unloading.
This paper will address all of the above issues and provide advice on which method of annulus pressure prediction at depth is most appropriate for specific conditions, advise on the accuracy of the combination of different critical properties and compressibility correlations, offer an alternative design technique to account for changing annulus temperature during the unloading process, and finally, provide guidelines on how to accurately and realistically model the changes in annulus pressure during the unloading process.
Tuning VSDs in ESP Wells to Optimize Oil Production—Case Studies
Authors: Camilleri L. A. , Gong H.. , Al-Maqsseed N. H. , Al-Jazzaf A. M. 
Published: October 2018

Abstract
To maximize electrical submersible pump (ESP) uptime and production in North Kuwait's diverse reservoir conditions, it was necessary to combine variable speed drive (VSD) feedback control functionality with reservoir knowledge and real-time data and subsequently develop an operating strategy tailored to individual wells. The case studies in this paper show how well performance can be stabilized and production increased by incorporating motor current and downhole pressure into the VSD frequency control loop.
In North Kuwait fields, engineers studied wells with ESPs running in unstable condition or suffering frequent tripping due to underload or high temperature. Their ESP design datasheets, production test results, historical VSD running parameters, and downhole gauge data were used to calibrate pump and well performance models and identify the pump operating point. From these simulation results, the VSD feedback control loop function was optimized to minimize tripping and/or enhance stability, thereby increasing production.
The main causes of well instability and ESP downtime in North Kuwait are declining bottom hole flowing pressure and gas interference. The case studies illustrate how to select the appropriate VSD frequency feedback object function for each of these cases. For weak inflow, the VSD is configured to maintain constant intake pressure, especially where the intake pressure is less than 500 psia. For ESPs suffering from gas interference, constant current was implemented to avoid gas locking. The before and after results from the case study wells demonstrate the effectiveness of this technique for well stabilization and associated production increase. After the study, this method was implemented on 60 wells and resulted in a 21% reduction in the number of ESP trips over 6 months and an associated increase in uptime from 92% to 97%.
This case study describes a workflow that integrates ESP historical running data, reservoir knowledge, and VSD feedback control functions to increase well uptime by preventing ESP tripping. In addition, the workflow enhances ESP system operating stability and optimizes the reservoir drawdown, which offers the operator a viable option to achieve production objectives.
Quantitative Analysis of the Packer-Style Gas Separator Through Laboratory and Field Trials
Authors: Thompson Levins , Monk Alex , Oddie Gary 
Published: October 2018

Abstract
Projected gas production is a critical variable in well planning, and the downhole tools chosen for gas mitigation are vital to production performance. With sucker rod pumps, inefficiencies due to gas presence can reduce the time between pulls and negatively affect production rates. The packer-style gas separator (PSGS) has higher-liquid-volume capabilities than "poor-boy" gas anchor style tools. Packer-style gas separators have become an industry-recognized tool used to increase production in gaseous fluids on rod-lift wells by using volume restrictions to create pressure changes then filtering the free and entrained gases from liquids.
This study examines the operational parameters involved in the use of a PSGS in downhole gas separation. A flow loop laboratory test was conducted to evaluate the separator's qualitative properties. Additionally, two separate case studies were analyzed to understand the impacts of downhole gas separation on production rates, pump run time, and pump fillage.
The laboratory experiments used a transparent model in the flow loop for a visual analysis of the separation occurring during operation. A water-nitrogen solution of varying concentrations was run through the separator to examine drawdown parameters during inflow. The results showed that at 95% liquid capacity, the nitrogen inflow was successfully contained within the modeled tubing-casing annulus, preventing entry of gas into the simulated pump intake.
Two case studies were recorded in separate geographical regions to verify operational success. In south Texas, an operator successfully mitigated gas from five high-GLR wells. The PSGS in each well successfully separated 300 to 500 Mcf per day of gas from tubing production inflow. As a result, the total fluids output increased by up to 200%. In west Texas, an operator used the separator in nine different wells. On average, the fluid production increased by 61%, pump fillage increased by 11%, and pump run time increased by 33%.
Overall, through laboratory and field testing, the PSGS has proven its ability to handle a wide range of downhole conditions. By improving downhole gas separation before fluid enters the pump, gas interference effects are mitigated and overall rod lift system efficiency is enhanced.
One Company's Experience using Metal to Metal PCPs as the Primary Artificial Lift Method in a SAGD Operation
Authors: Becerra Oscar , Sheldon John 
Published: October 2018

Abstract
PetroChina Canada's Mackay River project is currently the largest SAGD operation where Metal to Metal PCPs (MMPCPs) are being used as the primary artificial lift method. Their simplicity and potential robustness in very high temperature applications were considered advantages in their selection for producing a reservoir that no other operator had developed before. Furthermore, their potential to reduce costs when converting wells from steam circulation to production was considered a key advantage over other potential forms of artificial lift. Subsurface monitoring was implemented to accelerate the learning curve and maintain optimum operating conditions for both the wells and the artificial lift systems. Real time data acquisition was used to track pump production performance and estimate wear within the MMPCPs over time.
At the time of this paper, 42 well pairs had been successfully converted from steam circulation to production, where 37 well pairs are actively being produced using MMPCPs. To date, 14 MMPCP system failures have occurred and an estimate of the downhole production system reliability is calculated. As well, Root Cause Failure Analysis investigations into three of the most common failure mechanisms are summarized. As the field is still in early stages of production, confidence in the reliability of the MMPCPs and understanding of the common failure mechanisms is expected to grow as more data becomes available.
Plunger Fall Velocity Studies in Vertical Wells
Authors: Acosta R.. , Pereyra E.. , Sarica C.. 
Published: October 2018

Abstract
The objective of this study is to experimentally investigate the fall velocities of several type of plungers in various stagnant liquids and at different dynamic operating conditions. Six different plungers were evaluated, namely, new and used brush, new and used dual pad, new and used spiral, and new two piece type plungers. The experimental studies were carried out using two different facilities.
First, a simple plunger setup was used to measure the fall velocity of different plungers. This experimental configuration allows the use of different liquids at stagnant conditions (water, water with flowing air and oil). The experimental results show that plunger fall velocity in water is about 4% of the plunger velocity in air. Under a bubbling column and for all plunger types, the fall velocity fluctuates as the air passes through the plunger yielding, in some cases, an average velocity similar to the water case. The fall velocities in low and medium viscosity oils are 60% and 42% of the average velocity in water, respectively. Second, a comprehensive experimental facility was designed and constructed to study the plunger under dynamic operating conditions (or cycles) and at different fluid pressures (air). When the plunger fall velocity was studied under a cyclic operating conditions, the resultant fall velocity is about 60% of the velocity observed in only air, but 30 times larger than the corresponding velocity in stagnant oil.
Comparatively, the fastest conventional plunger is the spiral type, whereas the conventional sealing types (pad and brush) are the slowest ones. In addition, the effect of pressure is substantial and the fall velocity of the plunger rapidly decreases as the gas phase (air) pressure increases. Based on the experimental observations and data analysis, it was found that the fall velocity depends mainly on the type of plunger, air phase pressure, thickness of the liquid film on tubing wall, viscosity of the liquid, and density of the gas phase.
Plunger lift is one of the most used deliquification method for gas wells. However, only a few experimental studies have been found in the literature. None of them attempt the comparison of different plungers. This study present a new set of data that helps to understand the behavior of the different types of plungers.