bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of Surfactants Wettability Alteration Using the Washburn Contact Angle Method
Authors: Fuseni Alhasan B. , Al-Zahrani Badr H. , Al-Shehri Ammar J. , AlSofi Abdulkarim M. 
Published: December 2018

Abstract
Changes in crude oil wetting of carbonate rock when treated with various surfactants was evaluated using the Washburn method by the sorption of crude oil into packed rock powders. This method served to circumvent the difficulties of direct contact angle measurements on rock-chips where the low interfacial tension between the crude oil and surfactant leads to the spreading and eventual escape of the oil droplet without being attached to the rock chip.
Four surfactants were used in the study including an anionic alfa olefin sulfonate, a cationic quaternary ammonium salt, an amphoteric surfactant and a nanosurfactant. Rock powders from a carbonate rock with a mesh size between 80 and 100 were coated with the tested surfactant solutions and compacted in a sample holder for the sorption experiments. Crude oil was raised to the bottom of the powder pack and allowed to rise into the powder by capillarity. A sensitive balance was used to measure the mass of crude oil imbibing into the powder until imbibition ceased. A plot of the square of oil mass against time enabled calculation of the contact angle using the modified Washburn equation. Earlier, a sorption experiment using n-hexane was used to deduce the rock constant for the grain packing, which was necessary for calculation of the crude oil contact angle.
The contact angle results demonstrated the surfactant solution's efficiency in altering the crude-oil wetting behavior. An increasing washburn contact angle through coating indicates that the carbonate rock is rendered less oil-wet, which implies better oil displacement. At ambient temperatures, the nanosurfactant gave the highest contact angle implying the least oil-wetting; in second place was the amphoteric surfactant. The anionic surfactant had little effect on oil-wetting while the cationic surfactant decreased oil-wetting to a lesser extent. At higher temperatures, the nanosurfactant maintained its superior effectiveness followed by the cationic and amphoteric surfactants. The anionic surfactant saw little change.
The use of sorption to obtain contact angle of crude oil for rock surfaces treated with surfactants eliminates the difficulties associated with direct contact angle measurements for low and ultra-low surfactant solutions where attachment an oil-droplet is almost impossible. With the Washburn method rapid evaluation of surfactants ability to change rocks wettability can be made to better guide further evaluations of such processes. As the washburn method measures contact angle between solids and a liquid surrounded by air, the contact angles obtained are not to be interpreted directly as those obtained in a liquid-liquid environment.
Bayesian Based Approach for Hydraulic Flow Unit Identification and Permeability Prediction: A Field Case Application in a Tight Carbonate Reservoir
Authors: D'Windt Adolfo , Quint Edwin , Al-Saleh Anwar , Dashti Qasem 
Published: December 2018

Abstract
Flow zonation and permeability estimation is a common problem in reservoir characterization; usually, integration of openhole log data with conventional and special core analysis solves the latter. We present a Bayesian based method for identifying hydraulic flow units in uncored wells using the theory of Hydraulic Flow Units (HFU) and subsequently compute permeability using wireline log data.
First, we use the F-test and the Akaike's criteria coupled with a nonlinear optimization scheme based on the probability plot to determine the optimal number of HFU present in the core dataset with the regression match giving the pertinent statistical parameters of each flow unit. Second, we cluster core data into its respective HFU by using the Bayes' rule. Finally, we apply an inversion algorithm based on Bayesian inference to predict permeability using only wireline data.
We illustrate the application of the procedure with a carbonate reservoir having extensive core data. The results showed the Bayesian-based clustering and inversion technique delivered permeability estimates in agreement with core data as well as with results obtained from pressure transient analysis.
Among the applications of the workflow presented are better productivity index assessments, enhanced petrophysical evaluations, and improved reservoir simulation models. Coupling of Nonlinear optimization with Bayesian inference proves a robust way for performing data clustering providing unbiased estimations
Application of Super-Critical Water for Heavy Oil EOR: A Case Study from Pilot Field Test
Authors: Dong Mingda , Yue Xiang’an , Qu Shiyuan , Sun Fengrui 
Published: December 2018

Abstract
Cyclic steam stimulation is one of the important ways to develop heavy oil. In the past research, saturated steam and superheated steam were mainly used as injected fluids. With the advancement of technology, supercritical water cyclic steam stimulation began to receive more and more attention.
Thermodynamic oil recovery is the main way of heavy oil development, and supercritical water as a displacement medium for thermodynamic oil recovery has high pressure, high thermal enthalpy value and low density which makes it easy to spread in formation. At the same time, supercritical water also has some special properties, its polarity will reverse under high temperature and high pressure, which is beneficial to the mutual solubility of supercritical water and crude oil, increasing the efficiency of oil displacement.
In this paper, a cyclic steam stimulation model is presented for estimating recovery factors and production rates of different injection fluids, and the corresponding parameters are derived by a pilot field test. Firstly, a steam stimulation model using different injection fluids is proposed based on the properties of supercritical water, saturated and superheated steam. Secondly, according to the established model, the effect of the state of injected water on production rate and recovery factor of cyclic steam stimulation was studied. Thirdly, using supercritical water as the displacement medium, the effect of injection rate on production rate and recovery rate of cyclic steam stimulation was studied. Finally, the optimal production rate is obtained by analyzing the results.
Results show that: (a) Supercritical water can better heat the formation during steam stimulation than saturated and superheated steam. (b) Supercritical water has better injection capacity than saturated and superheated steam. (c) Cumulative oil production when injecting supercritical water is greater than the injection of saturated steam and superheated steam. (d) Cumulative oil production of supercritical water injection increases as injection rate rises. (e) The higher the injection rate is, the higher the production rate at the same production time.
A New, Fast, and Efficient Method for Evaluating the Influence of Catalysts on In-Situ Combustion Process for Heavy Oil Recovery
Authors: Sadikov Kamil , Yuan Chengdong , Mehrabi-Kalajahi Seyed Saeed , Varfolomeev Mikhail A. , Talipov Sarvardzhon A. 
Published: December 2018

Abstract
The use of catalysts has been considered as an effective method to improve the efficiency of in-situ combustion (ISC) process for heavy oil recovery. In this work, we present a new small-scale combustion tube to quickly and effectively evaluate the effect of catalysts on ISC process. Different oil-soluble metal-based catalysts were evaluated for ISC process for heavy oil recovery using this small-scale combustion tube. These experiments can provide the information about the stability of combustion front, oil recovery, and in-situ oil upgrading information.
Using this device, ISC process was successfully simulated. It turned out that the ISC process itself can effectively improve heavy oil recovery up to about 70 % and simultaneously achieve an in-situ oil upgrading evidenced by a significant viscosity reduction and an API increase. The presence of oil-soluble iron-based, nickel-based and copper-based catalysts can achieve a further oil upgrading to the level of medium oil from heavy oil with a more significant reduction in the content of resins and asphaltenes. However, the in-situ oil upgrading in ISC process yielded by iron-based and nickel-based catalysts at the expense of an unstable combustion front and a lower oil recovery (about 10 % lower than that without catalysts). The presence of copper-based catalysts not only achieved a further oil upgrading, but also improved the stability of combustion front and yielded a higher oil recovery (about 5 % higher than that without catalysts).
The obtained results indicated that oil-soluble copper-based catalyst has a great potential for improving the efficiency of ISC processes for heavy oil recovery. The new small-scale combustion tube was proven to have the ability for a fast and effective evaluation of the influence of catalysts on ISC processes.
Study on the Characteristics of Production Performance and Steam Chamber of SAGD Considering Interlayer
Authors: Xia Yun , Huang Shijun , Chen Xiao , Cao Meng , Yang Lijie 
Published: December 2018

Abstract
Steam assisted gravity drainage (SAGD) is widely applied in the exploitation of oil sand reservoirs, however, the development process is affected by complex geological conditions, wherein the interlayer has a great impact. Specifically, it has a great influence on heat and mass transfer of steam and on the effective flow of crude oil. For this reason, the characteristics of steam chamber and the production performance were investigated in detail to clarify the influence mechanism of interlayer.
In this paper, based on the reservoir parameters of Long Lake oil sands, a series of numerical simulations were conducted to study the characteristics of SAGD process with interlayers. First of all, the numerical simulation method was used to study the influence mechanism of interlayer on heat and mass transfer. Then, based on the above analysis, we reclassified the production stages. Finally, we completed a series of numerical simulations with different parameters of interlayer to determine the influence level of main factors.
The results of temperature profile show that the upper zone of the interlayer is mainly heated by heat conduction, whereas the area far from the interlayer is heated by the coupling effect of heat conduction and heat convection, hence, the steam chamber above the interlayer develops slower and the steam chamber in the area without interlayer develops faster. At the same time, it can be seen from the oil saturation profile that a dead oil zone is formed near the formation just above the interlayer. In addition, the production stage is no longer the classic "three-stage", due to the interlayer, the oil production rate is fluctuating, appearing peak production. Finally, we summarized the regular of the influence of each parameters and determined the main parameters, we considered the location, size, porosity, permeability, and thermal conductivity of interlayer comprehensively, the results show that the influence of thermal conductivity is smaller than other parameters.
Development and Testing of an Effective Lost Circulation Pill to Cure Highly Permeable Formations
Authors: Alsaba Mortadha , Al Mejadi Mohammed , Fahmy Mohamed , Aldarakh Yousef , Farhat Ali , Majli Jaber 
Published: December 2018

Abstract
Drilling fluid severe losses through highly fractured or highly permeable formations is considered as one of the most critical problems while drilling through these problematic zones, which can result in a costly non-productive time (NPT), and might lead to catastrophic well control issue in worst-case scenarios. The effectiveness of LCM treatments is often evaluated in the lab prior to field application. The main objective of this paper is to present the development of an in-house testing apparatus that simulates and evaluate the effectiveness of a proprietary LCM pill in curing losses through highly permeable formation.
A testing apparatus was developed in-house to simulate and evaluate the effectiveness of a proprietary LCM pill in curing losses through highly permeable formation. The apparatus consists of a transparent testing cell, which simulates the filtration medium, to visualize the losses profile through a gravel bed with porosity up to 40%. Four different blends at different concentrations (between 9 – 17 lb/bbl) were mixed in a 7% bentonite mud and evaluated at 100 psi using the newly developed apparatus. The depths of fluid invasion, the fluid loss, and the filter cake thickness were measured accordingly to evaluate the effectiveness of the developed LCM pill.
The testing apparatus was successfully built, pressure tested up to 150 psi, and used to evaluate the developed LCM pills. The results showed that the developed blends were able to plug and seal the highly permeable filtration medium effectively. The evaluated LCM pills resulted in a depth of invasion ranging between 44 – 96 % of the total length of the filtration medium and a filtrate volume of less than 5 ml/30 min depending on the concentration of the additives used. The filter cake thicknesses ranged between 0.16 – 1.37 inches, where the best blend resulted in the thickest filter cake.
Based on the results, the blends showed a superior performance in terms of curing the losses in a short period of time, which in turns will contribute towards reducing the associated NPT and further unwanted consequences.
Use of Air with Different Solvents Mixtures for Improved Foam Stability and Cost Effective Heavy Oil Recovery
Authors: Basilio Enoc , Babadagli Tayfun 
Published: December 2018

Abstract
Foamy oil flow is commonly encountered in heavy oil production from homogeneous or heterogeneous (after cold heavy oil production with sands - CHOPS) reservoirs. This can be due to a drive mechanism in the primary production (depletion of methane saturated heavy-oil) and secondary stage (gas injection after primary production). In the primary stage, among other important parameters, pressure depletion rate has been reported to be the most critical characteristic to control this type of flow. In the secondary stage, gas amount and type (sole injection of methane, carbon dioxide, propane, or combination of these) and application conditions (soaking time on cyclic solvent injection durations, depletion rate) are critical. The cornerstone of the foamy oil behavior relies on its stability, which depends on parameters such as oil viscosity, temperature, dissolved gas ratio, pressure decline rate, and dissolved gas (solvent) composition. Although the process has been investigated and analyzed for different parameters in the literature, the optimal conditions for an effective and more economical process (mainly foamy oil stability) has not been thoroughly understood, especially for the secondary recovery conditions. In this study, air has been used as an ameliorative to improve foamy oil stability. Five pressure depletion tests divided into two cases were performed. Each pressure depletion test included eight independent pressure recordings obtained from pressure transducers distributed along a sandpack holder for 48 hours. In order to reach the optimal conditions of the applications, three different pressure depletion rates were tested at 0.23 psi, 0.51 psi/min, 1.53 psi/min, and air were tested as an ameliorative for foamy oil stability. We observed that increasing pressure depletion rates increase the formation of foamy oil, however, when pressure depletion rates were too high, it may cause a negative effect in the final oil recovery factor. We also observed that injecting air into the sandpack caused an increase in the heavy oil viscosity, and the subsequent injection of methane as a solvent became more effective in generating more stable foamy oil, which resulted in obtaining a higher oil recovery factor. This novel approach is expected to improve the understanding and the use of foamy oil mechanics and to achieve a higher foamy oil stability aiming to increase the final heavy oil recovery factor.
Optimization of Steam Injection for Heavy Oil Reservoirs Using Reinforcement Learning
Authors: Guevara J. L. , Patel Rajan G. , Trivedi Japan J. 
Published: December 2018

Abstract
Steam injection rate through life cycle optimization (e.g., the constant rate for a long period of time) could lead to the sub-optimal performance of a thermal heavy oil recovery process. On the other hand, finding the optimal steam injection strategy (policy) represents a major challenge due to the complex dynamic of the physical phenomenon, i.e., nonlinear, slow, high order, time-varying, and potentially highly heterogeneous reservoirs. To address this challenge, the problem can be formulated as an optimal control problem that has typically been solved using adjoint state optimization and a model-predictive control (MPC) strategy.
In contrast, this work presents a reinforcement learning (RL) approach in which the mathematical model of the dynamic process (SAGD) is assumed unknown. An agent is trained to find the optimal policy only through continuous interactions with the environment (e.g., numerical reservoir simulation model). At each time step, the agent executes an action (e.g., increase steam injection rate), receives a reward (e.g., net present value) and observes the new state (e.g., pressure distribution) of the environment. During this interaction, an action-value function is approximated; this function will offer for a given state of the environment the action that will maximize total future reward. This process continues for multiple simulations (episodes) of the dynamic process until convergence is achieved.
In this implementation, the state-action-reward-state-action (SARSA) online policy learning algorithm is employed in which the action-value function is continually estimated after every time step and further used to choose the optimal action. The environment consists of a reservoir simulation model built using data from a reservoir located in northern Alberta. The model consists of one well pair (one injector and one producer) and production horizon of 250 days (one episode) is considered. The state of the environment is defined as cumulative, oil and water production, and water injection and for each time step; three possible actions are considered, i.e., increase, decrease or no change of current steam injection rate; and the reward represents the net present value (NPV). Additionally, stochastic gradient descent is used to approximate the action-value function.
Results show that the optimal steam injection policy obtained using RL implementation improves NPV by at least 30% with more than 60% lower computation cost.
Non-Equilibrium Interactions Between Heavy Oil and Liquid Propane
Authors: Athar Khan Sameem , Yassin Mahmood Reza , Dehghanpour Hassan 
Published: December 2018

Abstract
In this study, we use a custom-designed visual cell to investigate nonequilibrium interactions between liquid propane (C3(1)) and a heavy oil sample (7.2°API) at 55°C. The heavy oil sample is taken from Clearwater Formation located in Western Canadian Sedimentary Basin (WCSB). We inject C3(1) into the visual cell containing the heavy oil sample (pressure buildup process) and allow the injected C3(1) to interact with the oil sample (soaking process). After the pressure buildup process, we observe three phases in the visual cell: 1) heavy oil (0.67 mol), 2) liquid C3 (C3(1),0.60 mol), and gaseous C3 (C3(g), 0.20 mol). We measure visual-cell pressure and observe the C3-heavy oil interactions during the pressure buildup and soaking processes. Nonequilibrium interactions occurring at the interfaces of C3(1)-heavy oil and C3(1)-C3(g) are recorded over time.
The results show that complete mixing of heavy oil with C3(1) occurs in two stages. First, upward extracting flow of hydrocarbon components from bulk heavy oil phase toward C3(1) phase form a distinguished layer (L1) during the soaking process. The extracted oil components become denser over time and move down (draining flows) towards the C3(1)-heavy oil interface due to gravity. The gradual color change of L1 from colorless to black suggests the mixing of hydrocarbon components from heavy oil. After L1 becomes homogenous, a second layer (L2) is formed at the upper part of the bulk C3(1) phase (above L1). Extracting and draining flows becomes active once again, leading to mixing of oil components from L1 into L2. At equilibrium condition, heavy oil and C3(1) are completely mixed and form a single homogenous phase.
Does Polymer's Viscoelasticity Influence Heavy Oil Sweep Efficiency and Injectivity at 1ft/Day?
Authors: Azad Madhar Sahib , Trivedi Japan J. 
Published: December 2018

Abstract
For heavy oil recovery applications, mobility control is more important than interfacial tension (IFT) reduction and therefore, importance should be given to the recovery of remaining mobile oil by enhanced sweep efficiency. While the relative role of polymer's viscosity and elasticity on capillary-trapped residual light oil recovery has been studied extensively, their role on the sweeping the mobile viscous oil has not been explored. Injectivity is vital for heavy oil recovery applications and polymer selection criteria are done solely based on shear rheology. In this paper, the influence of viscous (shear) resistance and elastic (extensional) resistance of viscoelastic polymer on the mobile heavy oil recovery and injectivity is investigated through the combination of bulk shear/extensional rheology and single phase, and multiphase core flood experiments at typical reservoir flooding rate of 1 ft/day.
Two polymer solutions with different concentration and salinity are selected such that low molecular weight (Mw) polymer (HPAM 3130) provides higher shear resistance than high Mw polymer (HPAM 3630). Extensional characterization of these two polymer solutions performed using capillary breakup extensional rheometer revealed that HPAM 3630 provided higher extensional resistance than HPAM 3130. The results show that the behavior of polymers in extension and shear is completely different. Two multiphase and two single-phase experiments are conducted at low flux rate to investigate the role of extensional viscosity on mobile heavy oil recovery and high flux rates on injectivity. After 1 PV of polymer injections, higher concentration and lower Mw HPAM 3130 contributes to ~17% higher incremental recovery factor over lower concentration and higher Mw HPAM 3630. The core scale pressure drop generated by HPAM 3130 is more than twice the pressure drop generated by HPAM 3630. Under low flux rate conditions at the core scale, shear forces dominate and displacing fluid with higher shear viscosity contribute to better sweep. HPAM 3630 exhibits shear thickening phenomenon and possess the apparent viscosity of ~ 90 cP at the flux rate of ~90 ft/day. Whereas HPAM 3130 continued showing shear thinning and has the apparent viscosity of around ~70 cP at ~ 90 ft/day. This signifies the role of extension rheology on the injectivity at higher flux rates.
Results revealed that while extensional rheological role towards sweeping the mobile heavy oil recovery at low flux is lesser when compared to shear role, its negative role on the polymer injectivity is very significant. Polymer selection criteria for heavy oil recovery applications should incorporate extensional rheological parameters.