bluuebunny/crossref_metadata_2025_split huggingface dataset:
Laboratory Study of Injection Strategy for Low-Tension-Gas Flooding in High Salinity, Tight Carbonate Reservoirs
Authors: Das A. , Nguyen N. , Farajzadeh R. , Southwick J. G. , Vicent-Bonnieu S. , Khaburi S. , Al Kindi A. , Nguyen Quoc P. 
Published: March 2018

Abstract
It has been experimentally observed that Low-Tension-Gas (LTG) flooding can be a suitable enhanced oil recovery (EOR) method for low-permeability carbonate reservoirs with high salinity and hard formation brine. LTG flooding improves oil recovery by combining two effects: a reduction of the interfacial tension (IFT) between oil and water and mobility control through the formation of in-situ foam with an injected gas. However, the high cost of chemicals and/or the limited supply of gas can make this process economically challenging. In order to optimize the LTG process, an injection strategy has been designed such that the oil recovery can be maximized, using a minimum amount of the injected gas and the surfactant, thereby ensuring a more economically-viable recovery process. A low-permeable (&lt;10 md) Middle Eastern limestone reservoir with a high formation brine salinity (~200,000 ppm and hardness 19,000 ppm) is the target reservoir of this study. Surfactant injection strategy was optimized by varying the concentration and pore volumes of the surfactant slug injected. Nitrogen gas was co-injected during select time periods throughout the entire chemical injection in order to identify the significance of mobility control during the crucial phases of the LTG flooding. The coreflood results emphasized the significance of the injection of gas, even at lower foam quality, for the maintenance of mobility control. Ultimate oil recovery of over 60% (residual oil post waterflood) was achieved, even after reducing the surfactant concentration by 75% and inducing a different in-situ salinity profile as compared to earlier studies. An innovative method for measuring surfactant adsorption using Liquid Chromatography and Mass Spectrometry (LC-MS) was developed, which could provide individual dynamic adsorption data for each of the three classes of surfactants used.
EOR-The Business Unusual: North Kuwait's First ASP Pilot in a Carbonate Reservoir
Authors: Pathak Ashok , Tiwari Sanhita , Al-Ajmai Moudi 
Published: March 2018

Abstract
Kuwait Oil Company (KOC) has undertaken implementation of an Alkali-Surfactant-Polymer EOR pilot in probably the world's first carbonate reservoir in Sabiriyah Mauddud reservoir with billions of barrels in oil-in-place. This project in the North Kuwait area is being pursued with the help of industry experts in chemical EOR who are involved in conceptualization, pre-planning, pilot design and execution. A normal 5-spot, 5.5-acre pilot is presently operational since June 2017 with water injection in progress.
Encouraged by the excellent results of a series of Single Well Chemical Tracer Tests and of course and of course not unmindful of the risks, the company looks at this pilot as a ‘game changer’ with huge potential to enhance and sustain the North Kuwait oil production and reserve growth. It follows a path where an early lead could not only give it a distinct advantage in terms of achieving its goals but also create favorable conditions for commercial potential of this new technology. The decision to go ahead with this project is certainly backed an ambitious leadership with an appetite for entrepreneurial risk-taking and determination to succeed.
Commercial excellence in frontier technologies such as this would be determined after full evaluation of the ongoing or more pilots as necessary since there are no preexisting benchmarks for comparison.
The project continues to test and challenge the capabilities of individuals and the organizations alikeresearch financing, customization of chemical recipe for the reservoir, project logistics and economics being so demanding.
KOC views EOR as an opportunity to achieve its strategic medium and long-term objectives. The plan is to acquire and direct the cutting-edge technology of ASP flooding for unleashing the full production potential of its reservoirs to meet its 2040 strategy objectives.
An NPV-Based Comparison of Performance of Subsurface Conformance Materials in EOR
Authors: Temizel Cenk , Putra Dike , Najy Anas Khaled , Piñerez Iván , Puntervold Tina , Strand Skule 
Published: March 2018

Abstract
In water injection operations, oil is displaced from the heterogeneous porous media that increases recovery factors while providing pressure support. The most important parameter to be considered in such water flooding operations is the mobility ratio. For increasing the mobility ratio to maximize volumetric sweep of injectants, gelling agents (polymers) are added to the injected water. Extreme temperature and shear stresses can result in the degradation of these polymers, i.e., long chain macromolecules of the polymer are split into smaller chains. Therefore, it is of utmost importance to select the right type and amount of these viscosity reducing agents for each reservoir.
In this paper, synthetic polymer mechanisms have been compared to a natural polymer (Xanthan), using a commercial full physics reservoir simulator. The assumption made in the simulation is simplified gel kinetics that forms a microgel without redox catalysis. The injection schedule is as follows; Continuous water injection over all 6 layers for first 450 days, gel system injection in the bottom two layers for the next 150 days and water injection is continued for 4 years. Reservoir model consists of a high permeability streak at the bottom of the reservoir while the top 4 layers have high horizontal permeabilities. The simulator is also coupled to an optimizer and an uncertainty analysis tool in which control and uncertainty variables are set to investigate the sensitivity under this process.
Simulated model results show that the gel penetrates deep within the reservoir model and the high permeability bottom layers are blocked. The relative merits of synthentic ploymers to natural polymers are obtained from the sensitivity studies. These suggest that Biopolymers and xanthan polymers have better performance in terms of viscosity effects whereas resistance factor and in-situ gelation treatments are highlighted for synthetic PAM. Adsorption and retention of polymer and gel are permeability dependent.
Given the potential for the application of polymers in reservoirs worldwide, this study compares and highlights the relative advantages of different treatments in terms of different parameters for the same model while showing the significance of each control and uncertainty variable. The economics of injecting different conformance enhancers have been analyzed as well in this study.
Alkaline-Biosurfactant-Biopolymer Process and its Potential for Enhancing Oil Recovery in Omani Oil Field
Authors: Al-Ghailani Taher , Al-Wahaibi Yahya M. , Joshi Sanket J. , Al-Bahry Saif N. , Elshafie Abdulkadir E. , Al-Bemani Ali S. 
Published: March 2018

Abstract
In present paper we ereport the evaluation and the application of Alkaline-Biosurfactant-Biopolymer (ABsBp) applications for enhancing oil recovery. Generally Alkaline-Surfactant-Polymer (ASP) studies have been carried out using chemical surfactants and polymers. This experimental investigation was performed to evaluate the possibility of using a biosurfactant and a biopolymer with sodium carbonate as an alkali for ASP flooding for the oil field. The candidate example reservoir was selected having favorable properties such as high permeability (500-1000 mD), low oil viscosity (20-25 cp), favorable total acid number (0.1 mg KOH/g oil) and high residual saturation (&gt;20%). The current study was done to design an optimum composition of Alkali/Biosurfactant/Biopolymer (AbSbP) slug and apply it for enhancing oil recovery in both native reservoir cores and Berea sandstone core plugs. The interfacial tension (IFT) between various solutions containing alkali, biosurfactant and biopolymer was measured. Interfacial tension values in the range of 0.02-0.1mN/m were achieved at low biosurfactant and alkali concentrations. The interaction of the biopolymer with the brine, biosurfactant and alkali was investigated in terms of their effect on its viscosity at the reservoir temperature of 50°C. An AbSbP slug containing 1.1 wt.% sodium carbonate, 20 v/v% biosurfactant broth and 20 v/v% biopolymer broth was recommended for the final core flooding experiment. Core flooding experiments were conducted using reservoir cores and Berea cores by injecting the formulated AbS and AbSbP slugs after brine flooding. Maximum additional oil recovery obtained was 14% and 32% of oil initially in place (OIIP) from the reservoir cores and Berea cores respectively. Such difference in additional recovery was mainly due to the vast difference in the mineralogical composition of two rock types. This is the first report of application of Alkali-Biosurfactant-Biopolymer from Oman, showing additional oil from both native cores (from the Omani oil field) and Berea sandstone cores.
Scale Squeeze Implementation for an ASP Flood
Authors: Al Siyabi N. M. , Al-Farsi S. , Al-Hadhrami H. , Nadeem M. 
Published: March 2018

Abstract
This study is about scale squeeze application for ASP pilot that was carried at Marmul field. This is first kind of scale squeeze treatment for ASP application. High pH associated with the ASP slug injection and production (pH&gt;10.5) provides a rich environment for scale precipitation of metal ions when mixed with injection water. (1) Multiple activities associated with the scale squeeze treatment (evaluation, screening, modeling and application) were carried out from 2008 – 2016 in-house as well as with different vendors. It was quite challenging to find suitable scale inhibitor which is capable for scale inhibition at elevated pH and has longer squeeze life time.
The squeeze application was designed to start with a pre-flush stage to displace tubing fluids, acts as a spacer, condition the formation near the well bore and prevent water blocks/emulsions, followed by a main flush stage that has the highest concentration of SI in the mixed brine. Later on, a post flush stage was injected to displace the main flush further into the reservoir and increase adsorption. Finally, tubing displacement is injected which was about 5 m3 for each well.
The scale squeeze treatment for the four MM ASP production wells was completed prior to the ASP slug injection. A shut-in period for each well was applied to ensure adsorption of the chemical to the reservoir rock. Monitoring of the scale inhibitor return profile after the squeeze treatment for each well was carried out to determine the flow back characteristics and to evaluate the efficiency of the treatment. The monitoring evaluation has indicated that the scale squeeze treatment was successful in inhibiting the formation of scale in all of the four production wells and the concentration of the scale inhibitor was above MIC of 10 ppm. The scale inhibitor return profile concentration was also found to be in a very good alignment with the theoretical model and the treatment efficiency is passing the six months treatment life time period. This was successful implementation and proved the concept of appropriate propagation of SI from the formation to production system.
Investigating the Effect of Employing Inflow Control Devices on the Injection Well on the SAGD Process Efficiency Using an Integrated Production Modeling
Authors: Rahimbakhsh Aria , Rafiei Yousef 
Published: March 2018

Abstract
Hot steam preparation for so long as of in the Steam Assisted Gravity Drainage (SAGD) process has proved very costly. The "Fort McMurray" reservoir in Alberta, as a large Canadian heavy oil resource, has undergone SAGD, to reach acceptable production rates. The published data was used to investigate new methods, such as that introduced in this paper, for further enhancing this popular heavy oil recovery method.
Lack of a uniform steam distribution along the horizontal injection well has demonstrated itself as a major challenge since a considerable portion of hot steam enters the reservoir through perforations near the heel. Thus, regions connected to the toe section of the well do not receive the heat required for equally reducing the heavy oil viscosity. On the other hands, Inflow Control Devices (ICDs) have been used successfully to create a uniform pressure distribution along horizontal wells by providing an extra pressure against the fluid flow near the wellbore.
This paper is aimed at conducting the simulation of injection/production systems in the SAGD process on the "Fort McMurray" reservoir. Three scenarios were defined to accurately investigate the effect of employing ICDs on the cumulative oil production as the objective function. The first scenario was designed and run with only one production well to highlight reservoir's poor ability in naturally delivering the oil to the surface. In the second scenario, an injection well was introduced through which hot steam was to be injected, to simulate the SAGD process and in the final case; this injection well was equipped with ICDs. Finally, results indicated a dramatic rise from 3.96 to 6.39 MMSTB in the cumulative oil production as a consequence of implementing ICDs in the injection well in the end of the injection/production period. Moreover, the recovery factor, initially was equal to 40.5%, was improved to 65.2%. Toe temperature, as another parameter to be monitored, experienced an increase of almost 75 °F and reached 400 °F following the use of these devices.
In this study, ICDs that had been mostly used in production wells, were utilized to make a smart injection well in the SAGD process which according to simulation results, were successful. Moreover, an integrated production modeling approach saw the reservoir, wells and surface facilities taken into account simultaneously to monitor the effect of interaction of different parts of the production system on eachother.
Modelling the Impact of Reservoir CO2 on ASP Flood Performance in Aishwariya Field
Authors: Mishra Sudhakar , Pandey Amitabh 
Published: March 2018

Abstract
A procedure to model the impact of reservoir CO2 on chemical EOR (polymer/ASP) flood performance has been developed. The work which was initially developed for polymer flood modelling has been further extended and a simple approach has been presented to model the impact of reservoir CO2 on ASP flood performance.
Fatehgarh reservoirs in Aishwariya field, located in Barmer Basin of Rajasthan India, have very high CO2 content in reservoir fluid. The oil is moderately viscous and aqueous based chemical EOR techniques like polymer/ ASP flooding are being considered for production enhancement. The presence of high CO2 may impact aqueous based flooding processes planned in Aishwariya field. Three unconventional mechanisms occur in the reservoir: i). With injection of water, CO2 is stripped out of oil over time, this leads to increase in oil viscosity. ii). Since CO2 decreases pH of the system, polymer in-situ viscosity is decreased. iii). CO2 reacts with sodium carbonate (alkali) in aqueous medium leading to reduction in pH which may have an impact on ASP performance.
An advanced processes simulator was used initially to model the impact of CO2 on polymer flood performance. For simplicity, solution gas was assumed to be entirely composed of CO2. Waterflood followed by polymer injection was simulated in the model. CO2 was defined as an aqueous component instead of conventional oleic component allowing for modelling polymer viscosity dependence on CO2 concentration.
In order to model the impact of CO2 on ASP performance, reaction of CO2 with alkali was included in the model. The ASP simulation run could now capture all three unconventional mechanisms occurring in the reservoir due to presence of CO2: increase in oil viscosity, reduction in polymer viscosity and consumption of alkali due to reaction with CO2. Different simulation runs were then carried out both with and without the reaction of CO2 with alkali and the results were compared. Impact of grid refinement on the flood performance was also studied.
The developed approach could mechanistically capture the impact of CO2 on ASP performance in Aishwariya field. It was also observed that grid refinement has a major impact on the results; fine grid simulation is required to properly evaluate the impact of CO2 on ASP performance as it can appropriately capture impact of dilution and reaction based on CO2 concentration (moles) available.
The paper presents a step by step approach of modelling the impact of in-situ CO2 on ASP flood performance. The suggested approach helped in evaluating the impact of CO2 on polymer/ASP flood performance and adjusting the injection slug design appropriately.
Optimization of Steam Injection Processes in Reservoirs with Subsidence and Uplift
Authors: Temizel Cenk , Putra Dike , Najy Anas Khaled , Piñerez Iván , Puntervold Tina , Strand Skule 
Published: March 2018

Abstract
Bang-Bang theory provides on-off control of injection and production in hydrocarbon reservoirs and improves recovery by means of simply switching the wells or valves on and off at optimum cycles. In this study, we extend the concept to steamflloding along with including the geomechanics factor in softer formations where subsidence/uplift are observed along with injection or withdrawal of fluids.
In this study, to model the above-mentioned phenomenon and apply it to different types of reservoirs with varying geomechanical properties, a full physics commercial simulator has been used. The simulator has been coupled to an optimizer and uncertainty analysis tool to exhibit the significance and applicability of Bang-Bang Control. For a clear depiction of the simulation results for the reservoir model, a broad theoretical background of the approach is provided.
For robust reservoir managmentment to be taken, considering economically tight constraints, it is imperative to illustrate the cause-effect relationship or significance of every decision and control variable used for obtaining the results. For this purpose, results from the optimizer and uncertainty analysis tool proves valuable as it helps to accurately identify the injection-production strategies as well as optimum injection rates that increase the recovery rates. To further improve reservoir management strategies using Bang-Bang Control, it is understood that geomechanical behavior and reservoir response to different strategies must be clearly identified.
The use of optimal control theory (and Bang-Bang control) for steamflooding are not recent in the industry, but studies that include geomechanical effects during Steamflooding have not been widely undertake. Therefore, the authors aim to highlight the performance and potential of the application of this method for steamflooding in reservoirs that undergo subsidence and uplift at multiple levels.
Effect of Lithology on Pore-Scale Residual Oil Displacement in Chemical Flooding Using Nuclear Magnetic Resonance Experiments
Authors: Liu Zheyu , Cheng Hongjie , Xu Changfu , Chen Yukun , Chen Yihang , Li Yiqiang 
Published: March 2018

Abstract
Chemical flooding, as one of the most promising EOR techniques in both laboratory research and field practice has been widely applied to enhance residual oil displacement in conglomerate and sandstone reservoirs. To fully understand the displacement mechanism of chemical flooding in reservoirs with different lithologies, it is critical to understand the way residual oil is displaced from the pore-scale perspective.
In this study, three cores with similar permeability but different lithologies (sandstone, sandyconglomerate and poorly-sorted conglomerate) were selected for unclear magnetic resonance (NMR) experiments. Deuteroxide was used to replace water as aqueous phase to distinguish signals of water phase and oil phase. The lower size limit of workable pores was determined based on the relationship between mercury injection curves and NMR T2 spectrums. The distribution and migration patterns of residual oil in different flooding processes were evaluated by quantitatively analyzing the change of the relaxation time. The amounts of oil displaced from pores of different sizes after water flooding, polymer flooding, and surfactant/polymer (SP) flooding were calculated, respectively.
The ultimate oil recovery by chemical flooding in cores with different lithologies decreased in the order of sandstone, sandy conglomerate, and poorly-sorted conglomerate cores. Specifically, SP flooding achieved much higher oil recovery than polymer flooding, especially in the conglomerate core. It has been demonstrated that polymer solution could effectively mobilize residual oil in medium pores (1-10μm) in the sandstone core. Meanwhile, the incremental oil recovery during SP flooding was mostly attributed to the small and medium pores (0.25-1.6μm). But for the conglomerate core, polymer flooding was only to some extent effective in the pores with diameters ranging from 4.3μm to 25μm. Moreover, it was found that the lower size limit of workable pores by SP flooding decreased with the increase of heterogeneity. Generally, oil trapped in pores smaller than 4μm was hard to be mobilized.
First Successful Temperature and Pressure Profile Test for Horizontal Section of Thermal Wells in Offshore Heavy Oilfield China
Authors: Liu Hao , Liu Yigang , Han Xiaodong , Wang Qiuxia , Zou Jian , Zhang Hua , Wang Hongyu , Guo Erpeng 
Published: March 2018

Abstract
Steam huff-and-puff pilot has been conducted for 2 horizontal wells in Bohai Oilfield since 2011 with total enhanced production of 14.5×104bbl in comparation with cold production. However, owing to limitations of the platform space and wellbore configuration characteristics, real temperature and pressure parameters for horizontal section of thermal wells haven’t been acquired until the first coiled tubing test be successfully applied in C1h before and after steam injection in its second huff-and-puff cycle.
The primary objective of our work in this paper is to accurately grasp the degree of steam utilization along horizontal section through coiled tubing test. The test consists of four main units, that is, temperature test unit, pressure test unit, water cut unit and data recording and storage unit. Minimized facilities and specific dual sealing structure based on integrated system are designed and optimized with temperature and pressure resistance of 300°C and 21MPa in consideration of the platform space, HTHP working environment and test cost. The test procedure is elaborated in this paper.
One of the test is conducted before steam injection for the purpose of basic thermal field construction, and the other is in the soak stage after steam injection for the analysis of steam absorption profile along horizontal section. Pigging operation is necessarily conducted before the test. The first test results show that both the temperature and pressure distribute uniformly, with the highest temperature of 60°C and highest pressure of 9.69MPa, which could match well with well configuration. The second test results show that temperature rises up along horizontal section from 2000m to 2400m with the highest value of 238.6°C at 2400m as well as the pressure value ranging from 17.23 to 17.37MPa. The steam useage along horizontal section of C1h is relatively balanced and uniform according to the test results, which could be consistent with the real formation permeability distribution with the purpose of providing vertification in numerical model.
This is the first time that coiled tubing test is successfully put into trial for HTHP steam injection wells in offshore heavy oilfield. Test results in this paper could provide a basis for the prediction of uniform steam injection, the estimation of gas channeling location and the implement of profile control process in the next huff-and-puff cycle.