bluuebunny/crossref_metadata_2025 huggingface dataset:
Experimental Comparison between WASP and LSASF in Bartlesville Sandstone Reservoir Cores Bearing Heavy Oil
Authors: Al-Saedi Hasan N. , Long Yifu , Alameedy Usama , Al-Bazzaz Waleed , Research Kuwait Institute , Flori Ralph
Published: December 2018

Low salinity (LS) water flooding is a promising EOR method which has been examined by many experimental studies and field pilots for a variety of reservoirs and oils. This paper investigates applying LS flooding to a heavy oil. Increasing the LS water temperature improves heavy oil recovery by achieving higher sweep efficiency and improving oil mobility by lowering its viscosity. Steam flooding projects have reported many problems such as steam gravity override, but override can be lessened if the steam is is alternated with hot LS water. In this study, a series of reservoir sandstone cores were obtained from Bartlesville Sandstone (in Eastern Kansas) and aged with heavy crude oil (from the same reservoir) at 95°C for 45 days. Five reservoir cores were used in this study, and five treatments were performed. They were flooded with (a) steam; (b) formation hot water (FHW); (c) low salinity hot water (LSHW; (d) steam + FHW; and (e) steam + LSHW (so-called LSASF). The laboratory experiments showed that basic water flooding using FW recovered approximately 50% of OOIP. After that initial flood, upon switching to the various steam, FHW, LSHW, steam + FHW, and steam + LSHW treatments, the incremental oil recoveries were 5, 3.1, 6.3, 7.5, and 12% OOIP, respectively. The contact angle measurements showed that injecting steam + LSHW alters the wettability considerably more than using steam + FHW. The results of this work show that water flooding using LSHW in reservoir cores could improve oil recovery significantly because it both reduces oil viscosity and alters the rock wettability towards more water-wet. The results also showed using LSHW alternated with steam is more beneficial than using steam only or alternated with regular water due to the combined benefits of reducing gravity override and altering the wettability. Using LSHW water is more economical than using steam and gives significantly improved oil recovery, and using LSHW is more beneficial than ambient temperature LS water.
Exploring Resilience in the Oil Industry: Theory vs. Practice
Authors: Capello Maria Angela , Passalacqua Alessandra
Published: December 2018

Adversity and continuous change challenge leaders, and even the most resolute and determined feel discouragement along their path in the corporate or entrepreneurial worlds. How do oil and gas organizations and the industry leaders build, foster and grow their resilience to cope with difficult periods and maintain the necessary focus on the ultimate goals in comparison with what does the theoretical approaches describe, is the matter of this paper.

Leadership has to be grounded on resilience, as one skill cannot shine without the other. Resilience has been characterized as the ability of a person or an organization to recuperate, recover, bounce-back, adjust or even thrive following adversity, and is widely acknowledged as a complex, dynamic and multi-dimensional phenomenon (Waugh and Koster, 2014). Our paper highlights how resilience takes form in individuals and organizations, comparing theory and practical stands. The BP Deep-Water Horizon Oil Spill is one of the examples selected to illustrate how resilience in the organizations takes shape before, during and after a catastrophic event. The three factors of resilient organizations will be exposed as the realization of vulnerability, the willingness to cooperate, and the power to act courageously (Oudhuis & Tengblad, 2018). The individual resilience will be exemplified by examples of how this quality and skill is strengthened throughout the careers of experienced individuals in private, public and not-for-profit organizations related to the oil industry, establishing a comparison between theoretical viewpoints about resilience, and practical developments.

A summary of findings will support the understanding of the theoretical basis related to the resilient profiles, and how they cope with the four elements that affect resilience: neuroticism, mindfulness, self-efficacy and coping, for adjustments in the workforce. Then, the analysis will propose a series of conclusions derived from the analysis of how resilient leaders in oil and gas from different organizations built their resiliency, taken from a series of published resources and direct interviews. A comparative analysis about these practical approaches in relation to theoretical research on leadership and resilience, is offered, in relation to the oil sector workforce, specifically for the managerial and executive contexts.

The conclusions about how, why and when the shaping of resilient profiles and organizations occurs, on theoretical and practical grounds provides a useful understanding about the positive impact that boosting resilience in the workforce has the potential to offer to enable more positive outcomes, less turn-over, less burn-out individuals and better performance.
A Cost-Effective Water Management Strategy for Developing Large Heavy Oil Field in Northern Kuwait
Authors: Al-Ballam Shaikha , Pandey Dharmesh , Pallath George , Kuijvenhoven Cornelis
Published: December 2018

A cost-effective water management strategy for the thermal development should ensure the availability of right quality and quantity of water during the lifetime of the field. This paper presents an actual case for field water management, which includes availability, use, re-use and safe disposal of both source and effluent water.

Thermal projects are notorious for their large volume of produced water through the life of the field. While treatment of produced water is a major issue; in a country like Kuwait where water is scarce, part of the produced water need to be recycled and re-used for steam generation. The methods and procedure followed are based on the practices used in the current Large Scale Thermal Pilots (LSTPs). The process involves field observations and performance, facility set-up and limitations, technical analysis and mitigation plan; so as to reach to an efficient water management plan and deliver better quality water.

Heavy oil field development in Northern Kuwait is currently one of the few thermal "mega-projects" in the world. The development started initially with Cyclic Steam Stimulation (CSS), followed by Steam Flood (SF). These projects need dedicated used water disposal wells. Water disposal wells, initially completed, showed poor injectivity even after CTU acid stimulation with 15% HCl. Based on lab test results and analysis, injectivity was restored with suitable anti-scalant injection and precipitate removal.

Another aspect of these wells was the injection casing shoe-setting depth. A multi-disciplinary team reviewed and established the optimum placement interval for shoe that meets the regulatory and design criteria. The new shoe setting-depth eliminated repeated well interventions during the life of these wells. The learnings were disseminated to various other projects within the company. Quality of source water was also a focus area for the team. Water quality of the source water at various depths were analyzed and tested. Based on the results, optimum well depth and location was ascertained which resulted in improved water quality and quantity.

A novel approach, with key focus on competitive scoping and sustainable development and the combined effort from various stakeholders through an integrated approach have enabled significant savings to reduce the cost of this project. The learnings gathered, and the uniqueness of the project will add significant value to similar projects elsewhere in the world.
A Computational Fluid Dynamics Model for Simulating the Rotating Disk Apparatus
Authors: Kotb Abdelrahman , Ali Mahmoud , Aziz Ezzat Ahmed , Elwany Alaa , Nasr-El-Din Hisham
Published: December 2018

Reaction kinetics between calcite and acid systems has been studied using the rotating disk apparatus (RDA). However, simplifying assumptions have been made to develop the current equations used to interpret RDA experiments to enable solving them analytically in contrast to using numerical methods. Experimental results revealed inadequacy of some of these assumptions, which necessitates the use of a computational fluid dynamics (CFD) model to investigate their impact on the RDA results. The objectives of the current work are threefold: (1) develop a CFD model to simulate the reaction in the RDA, (2) Identify the error associated with the assumptions in the original equations, and (3) develop a proxy model from the results that can accurately represent the reaction in the RDA.

In developing the CFD model, the averaged-continuum approach was used to simulate the chemical reaction on the disk surface. Both Newtonian and non-Newtonian fluids were studied to investigate the adequacy of the equations’ assumptions. To validate the model, simulations were compared with experimental results. Experiments were run at 0.25, 0.5, 1, and 1.25M HCl with marble using the RDA at 250°F. Rotation speeds of 200, 400, 600, and 1,000 rpm were tested at each acid concentration. The diffusion coefficient was then calculated. Parameters of the CFD model were then adjusted to match the rock dissolved throughout the RDA experiments.

The rock dissolved in the disk from the CFD model matched the results from the RDA experiments. The transition from mass-transfer to the kinetics-limited reaction behavior was captured by the CFD model. The velocity and viscosity profiles for both Newtonian and non-Newtonian fluids showed the effect of the container's boundaries on the flow. Results indicate that this effect is pronounced in the case of Newtonian fluids at high rotational speeds. Moreover, the impact of varying viscosities in the case of non-Newtonian fluids resulted in errors in estimating the reaction kinetics. Finally, a proxy model was obtained to reduce the computational time involved in accurately simulating the experiments.

The present work developed the first CFD model to accurately evaluate reaction kinetics and diffusion coefficient in the RDA with minimum assumptions. More specifically, the model relaxes the infinite acting, constant fluid properties, and constant reaction surface area assumptions. Finally, the proxy model obtained results in reduced computational time with minimal compromise on accuracy.
An Prediction Model of Steam Front of Horizontal Steam Flooding for Thin Heavy Oil Reservoirs
Authors: Huang Shijun , Xia Yun , Cao Meng , Chen Xiao
Published: December 2018

Steam channeling is an important factor affecting the steam flooding, for thin heavy oil reservoirs, the steam overriding in the vertical direction is not as severe as the thick heavy oil reservoir, and often can form a regular shape of the steam front which can directly reflect the extent of steam overriding. it also can determine the steam swept volume, steam breakthrough time. Therefore, the study of steam front is of great significance.

In this paper, a series of works are conducted to study the characteristics of steam front of horizontal steam flooding. Firstly, the equation of steam front and the equation of motion are established. Then, coupled with energy conservation equation and mass conservation equation, a comprehensive model is established. The model is solved with method of characteristics and the predicted results are compared against field data and previous models.

The results show that: (a). The new model is applicable to predict different shapes of the steam front according to the production conditions. (b). The comparison between experimental results and model results showed that this new model can predict the steam front well. (c). The comparison of steam front among different shapes indicated that linear-shape was the best, followed by the concave-shape, and the convex-shape was the worst, usually causing severe steam overriding and the severity will increase over time, the development effect can be improved by forming a proper shape of steam front.
Resolving Contract Mangement Challenges in Research Collaboration Agreements
Authors: Chaturvedi Sandeep
Published: December 2018

Objective

Research and innovation have become necessary for sustainability and profitability in Oil and Gas industry in present times. Oil and Gas Companies (Companies) have established procedures and contract templates for commercial contracts. Research Collaboration Agreements (Agreements) have very different requirements and pose Contract Management challenges. This paper deals with the resolution of such challenges.

Method/Procedure/Process

In process of developing this paper, a number of Research Collaboration Agreements have been studied with respect to their (i) objectives, (ii) Research Collaborators Concerns, (iii) Research Collaborator's business model and expectation from the Agreement (iv) major issues which contradict with the Oil and Gas Company's contract templates and procedures and (v) mutually acceptable resolution to various issues.

Based on the study, this paper has been developed to systematically analyse the issues and share the successful strategies and mutually acceptable provisions of the Agreement.

Result/Observation/Conclusion

In commercial contracts, we deal with conventional contractors. In Research Collaboration agreements, contractors are Research Collaborators. The Research Collaborators have unique requirements, which are different from conventional contractors. They have different business models, pricing expectations, legal sensitivity and risk tolerance capabilities.

Further, the Research Collaboration Agreements need to be flexible in terms of scope of services, contract period, resource requirements, payment methods etc., so that the researchers can exploit even their intermediate and unforeseen findings to arrive at meaningful outcome. This is in contrast to conventional contracts, which have definitive requirements.

While required flexibility needs to be built-in the Agreements, the Company needs to ensure that it has suitable controls in the Agreement to ensure value for its investment.

In course of time, contracting strategies and Agreement provisions have been developed to:build up flexibility in the Agreements without deviating from basics of contract management andaddress the unique requirements of Research Collaborators without compromising the objectives and control of Oil and Gas companies.

Efforts have been made by the author to share the resolution of contract management challenges through contracting strategies and contract provisions, developed for Research Collaboration Agreement.
Surfactant-Polymer Flooding: One-Spot EOR Pilot Design for a Middle-Eastern Heavy Oil Reservoir
Authors: Al-Murayri Mohammed Taha , Hassan Abrahim Abdulgadir , Al-Mahmeed Narjes , Suzanne Guillaume , Sanchez Juan-Pablo
Published: December 2018

This paper sheds light on the design of a one-spot surfactant-polymer (SP) flooding pilot in a reservoir with oil viscosity greater than 1000 cP using a vertical well. The results of this pilot will be important to optimize the selected chemical formulation and finalize the recommended injection sequence with the purpose of de-risking subsequent multi-well surfactant-polymer flooding deployment.

Based on systematic screening, preliminary laboratory evaluation and reservoir simulation, SP flooding was identified as a promising EOR method for the Ratqa Lower Fars (RQLF) reservoir in Kuwait. This was followed by extensive laboratory work to design a robust chemical formulation based on specific reservoir properties and operating conditions. The performance of the developed chemical formulation was validated by means of simulation. Thereafter, a one-spot EOR pilot, which is also referred to as a Single Well Chemical Tracer Test (SWCTT), was designed to assess the effectiveness of the selected chemical formulation mainly in terms of injectivity and oil desaturation.

It was envisioned that the injectivity of a lab-optimized SP formulation for the RQLF heave oil reservoir needs to be confirmed in connection with oil desaturation using a one-spot EOR pilot due to the relatively high reservoir oil viscosity and low injection pressure to maintain cap rock integrity. Assuming favourable injectivity, incremental oil recovery in a one-spot EOR pilot is represented by the difference in residual oil saturation after water flooding and after chemical (SP) flooding. However, achieving low oil saturation as a result of waterflooding in a heavy oil reservoir takes a long time and requires large water volumes that are not applicable to full-field deployment. Therefore, the objective of the one-spot EOR pilot that is discussed in this paper was adjusted to validate oil desaturation as result of polymer and surfactant injection upon confirming water injectivity within a 3ft radius of investigation as outlined below: Initial water injectivity testPolymer solution injectionMeasurement of oil saturationSurfactant-polymer injection followed by polymer driveMeasurement of oil saturation

This paper describes a methodical approach to de-risk surfactant-polymer flooding in a heavy oil reservoir using a one-spot EOR pilot. There is limited reference in the literature, if any, to field deployment of surfactant flooding in heavy oil reservoirs with an oil viscosity of more than 1000 cP. The findings of this study can be used to evaluate and potentially improve the techno-economic feasibility of chemical EOR in heavy oil reservoirs with similar properties.
New Insights of Low Salinity Water Flooding in Low Permeability-Low Porosity Clay Rich Sandstone Reservoir
Authors: Alhuraishawy Ali K. , Bai Baojun , Wei Mingzhen , Al-Bazzaz Waleed H.
Published: December 2018

One of the EOR technologies is low-salinity water flooding (LSWF) is an EOR method that operates at a lower cost than other EOR methods, which makes it a preferred area of interest for oil industry economists, who continue to call for EOR costs to come down. The aim is to minimize the possible cost to recover as much oil as possible. The performance of low salinity waterflooding in decreasing residual oil saturation in low permeability- porosity clay-rich sandstone reservoir.

Porosity test, core flooding test, XRD and scanning electron microscopy (SEM) tests were achived in this study. Salinity effect on the porosity, oil recovery, and injecton pressure was established. The results showed that low salinity waterflooding resulted in improving oil recovery and porosity with permeability reduction and decreased the clay content. SEM results results showed that the flowing direction will be restributed during low salinity waterflooding by realizing some sand particle and minerals and increased the porosity. Therefore, low salinity water flooding can modify both porosity and permeability and, in turn, improve oil recovery factor.
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

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

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

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

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

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

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

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

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

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

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.
HSE Challenges in Thermal Operations Used for Heavy Oil Recovery
Authors: Qabazard Ahmed , Al-Qattan Ghadeer , Ketavarapu Sridhar Raju , Khan Nadeem Waris
Published: December 2018

Lower Faras Heavy Oil Project in Ratqa, North Kuwait of Kuwait Oil Company is one of the Major Projects in the upstream business in the Middle East. Heavy oil production from a large field is a significant challenge and involve process, which are not common for normally well-developed onshore upstream production operations personnel. There shall be a Limited/No Flow from a heavy oil well as the viscosity is high and to ensure extraction of hydrocarbon in a most possible efficient manner, thermal operations (including the steam injection) is the best option available. This additional process and associated equipment, their associated hazards are not available in the conventional oil & gas production.

Though the option of having a horizontal well with no additional steam/heat given to the reservoir, the flow from such wells can recover hydrocarbons, however it is not feasible for a commercial production. As a result, for commercial production, the reservoir is injected with steam (either cyclic or flooding) to recover the hydrocarbons in the most economical method. The steam injection method comes with a few challenges and the crux of success in Heavy oil production is to manage these hazards.

There have been several accidents that occurred worldwide in heavy oil production and related experimental activities. The root cause of accidents is generally the lack of awareness during the operation and maintenance activeness of the workforce personnel. Different incidents from world over, from the hazard identification and the operability studies undertaken during the project, suggest the various challenges that are underlying in the heavy oil operations. The challenges had been addressed systematically and design enhancement to enhance the robustness of the systems were considered whilst developing the project.
Optimization of Outflow Control Devices Placement and Design in SAGD Wells with Trajectory Excursions
Authors: Sidahmed Anas , Nouri Alireza , Kyanpour Mohammad , Nejadi Siavash , Fermaniuk Brent
Published: December 2018

Canada has enormous oil reserves which ranks third worldwide with proven oil reserves of 171 billion barrels. Alberta alone contributes with 165.4 billion barrels found in oil sands. However, the oil in oil sands is extremely viscous, and only 10% is recoverable through open-pit mining. In-situ thermal recovery methods such as Steam-Assisted Gravity Drainage (SAGD) have been developed and adopted as an efficient means to unlock the oil sands reserves.

Different reservoir geological settings and long horizontal wells impose limitations and operational challenges on the implementation of SAGD technology. Wellbore trajectory excursions or undulations- unintentionally generated trajectory deviations due to suboptimal drilling operations- are some of the complications that lead to non-uniform steam chamber conformance, high cumulative Steam-Oil Ratio (cSOR) and low bitumen recovery.

Conventional dual-string completion scheme (a short tubing landed at the heel, and a long tubing landed at the toe) has been widely adopted in most of the SAGD operations. Such configurations allow steam injection at two points: the toe and the heel sections of the horizontal well. However, these completions have demonstrated poor efficiency when reservoir/well complications exist. Tubing-deployed Flow Control Devices (FCD's) have been introduced to offer high flexibility in delivering specific amounts of steam to designated areas (such as low permeability zones) and ensure uniform development of steam chamber in the reservoir. The work in this thesis presents the results of a numerical effort for optimizing the design of Outflow Control Devices (OCD's) in SAGD wells for different scenarios of well pair trajectory excursions.

A coupled wellbore-reservoir SAGD simulation model was constructed to optimize the placement and number of ports in every single OCD. Three different cases were generated from the constructed basic SAGD model with each case having a specific well pair trajectory which causes variable lateral distances between the well pair.

Results of the optimized OCD's cases demonstrate a higher SAGD efficiency compared to their corresponding conventional dual-string cases. Those enhancements resulted in a higher steam chamber conformance, a higher cumulative oil production, and an improved Net Present Value (NPV).