bluuebunny/crossref_metadata_2025_split huggingface dataset:
Influencing Factors Analysis in the Combination of Gel Treatment and Low Salinity Water Flooding Using Sensitivity Analysis
Authors: Alhuraishawy Ali K. , Alfarge Dheiaa , Wei Mingzhen , Bai Baojun , Almansour Abdullah 
Published: March 2018

Abstract
Gel treatment is often used to control the excessive water production in fractured reservoirs. Combined technology has drawn a great interest in the oil industry over the last decade. Recently, gel treatment combined with low salinity waterflooding brought a significant attention in reservoir engineering. It has been reported that low salinity waterflooding can improve displacement efficiency. Gel treatment has been proved to plug fractures and improve sweep efficiency. The objective of this paper is to provide a deeper understanding of this combined technology by applying experimental and simulation approach (sensitivity analysis). The purpose of sensitivity analysis is to determine how sensitive the oil recovery factor obtained at different conditions to different parameters.
The experimental results found that the low-salinity water can improve oil recovery factor by 6% and plugging efficiency was also improved. The sensitivity analysis results showed that the initial oil saturation, oil viscosity, porosity, and matrix permeability were the most important parameters affecting improved oil recovery when combined technology applied. The matrix permeability was the most important parameter impacting the obtained oil recovery, and the oil saturation was the lowest. The performance of using low-salinity water increased when matrix permeability increased, and porosity decreased. Identifying the parameters which have a significant impact on oil recovery would give a good prediction for combined technology success or failure depending on reservoir properties.
Real-Time Fiber-Optics Monitoring of Steam Injection in Unconsolidated High Viscous Formation
Authors: Gonzalez Santiago , Al Rashidi Hamad , Pandey D. C. , Al-Mula Yousef , Safar Abdualaziz , Al-Kandari Jassim , Abdalla Waeil Abdelmohen , Gorgi Sam , Patel Dipen 
Published: March 2018

Abstract
Kuwait Oil Company (KOC) is running two pilot projects in South Ratqa Field to evaluate steam injection using cyclic steam stimulation (CSS) and steam flooding (SF) methods. These projects are the first of their kind in KOC history and one of the major milestones in the North Kuwait Heavy Oil Development.
Two large-scale thermal pilot (LSTP) projects are located north and south of the South Ratqa Field, with the north running two different areas of 10 and 5 acres and well completion and the south running one area of 5 acres.
KOC has been injecting steam in these pilots in an unconsolidated high viscous formation since 2015, beginning with a CSS process that migrating to SF during the second half of 2017. A fundamental goal to help ensure success with this type of project is carefully monitoring the injected steam per well and per formation layer by installing fiber optic distributed temperature sensing (DTS) and pressure gauges in a portion of the wells; this goal was defined at the beginning of the project. For this purpose, 12 wells were drilled as observation wells and 6 idle wells were used for fiber-optic deployment to monitor the reservoir 24 hours a day, 7 days a week for the injection life of the pilots. The observation wells with DTS and pressure gauges were distributed along the pilots to cover a large predetermined observation area for the pilots.
The observation wells with DTS and pressure gauges in the north and south LSTP areas were also distributed along these pilots to cover a large area. The benefits of installing this technology in the pilots are to:To develop an understanding of steam breakthrough zones along the pay-zone interval of production wellsTo help improve the understanding of the steam injection profile for steam-injector wellsTo help improve the real-time temperature profile along the length of producer’s wellboreTo develop an understanding of heat management during steam flooding
This paper discusses the success story between two companies installing DTS and thermal pressure gauges and includes a description of DTS, the installation procedure of downhole and surface equipment, real-time data transfer, and data analysis.
Design of a Combined Foam EOR Process for a Naturally Fractured Reservoir
Authors: Chevallier Eloise , Chabert Max , Gautier Serge , Ghafram Hamid , Khaburi Saja , Alkindi Abdullah 
Published: March 2018

Abstract
This paper presents laboratory studies to apply a new approach based on combined foam EOR processes to a naturally fractured carbonate reservoir (NFR) located in Oman. Applications of EOR techniques in fractured reservoirs, despite their attractive potential, have always been challenged by the inability to efficiently control EOR fluid mobility in fractures, which results in inefficient flooding of the reservoir matrix and poor economics of the process. This work discusses the maturation of efficient foam EOR processes for NFRs. The foam is aimed at blocking aqueous solution flow in fractures on the one hand while allowing low interfacial tension (IFT) solution to enter the matrix on the other hand.
We use an extensive experimental workflow to develop such solution in the challenging salinity conditions of the considered reservoir. Using robotics, we first combine low-IFT and foam boosting surfactants to come up with the most adapted chemical cocktail in terms of solubility, IFT with crude oil and foaming properties in hard brine. The selected formulation is then quantitatively characterized for IFT with crude oil, phase behavior with live oil, foam stability in reservoir pressure and temperature conditions, and foaming properties in model porous media. Dedicated coreflood experiments mimicking flow in fractured reservoirs are finally used to quantitatively evaluate the process using the designed formulation. This includes evaluation of foam-induced pressure drop, effluent fluid composition and oil recovery in artificially fractured cores.
The designed combined foam EOR formulation is perfectly soluble in hard brine and yields an IFT with crude oil well below 10-2 mN/m at 65°C. It is able to generate and stabilize foam both in absence and in presence of crude oil. Process evaluation in artificially fractured core shows good control by foam of aqueous solution mobility in fracture, and efficient imbibition of aqueous solution from fracture to matrix. Interestingly, a filtration effect is observed whereby only aqueous solution enters the matrix from the fracture, while foam only exists in fracture. This, combined with the sensitivity of foam to presence of oil, enables an efficient production of oil from the matrix through the fracture, as measured during recovery experiments.
This paper presents the first steps toward a potential pilot application of a new process aimed at making chemical EOR in fractured carbonate technically and economically feasible. The approach presented here allows the design of a performing process in challenging conditions of water salinity and hardness.
Enhanced Aquifer Pump-Off Strategy for a Steam Flooding Development, A West Field, Sultanate of Oman
Authors: Belghache Abdesslam , Van Doren Jorn , Shibli Abdullah , Tromp JP , Hilali Ali , Bahri Sultan , Yazidi Rashid , D'Amours Kevin 
Published: March 2018

Abstract
One of the key challenges of the "A" West reservoir thermal development is the presence of an active bottom aquifer. If unmanaged, high aquifer pressures relative to the oil reservoir would have a detrimental effect on the ongoing thermal Enhanced Oil Recovery (EOR) process. Consequently, the "A" West development strategy includes an Aquifer Pump Off (APO) system.
The key APO management objectives are:Lower the reservoir pressure and hence:a.Improve injectivity.b.Improve heat efficiency (more latent heat).c.Prevent quenching of the injected steam.Secure the feed water for the steam generation.
In order to meet the above objectives, the following methods were used to evaluate the targeted pump off rate:Material Balance analysis.History matched full field model.History matched regional aquifer model, whereby several aquifer pump-off scenarios have been explored to further deplete the aquifer pressure in "A" West.
A high APO capacity is initially required for an accelerated aquifer pressure depletion to match the currently low reservoir pressure caused by historical cold production of the upper half of the reservoir. This initial APO capacity is only required until the target aquifer pressure is achieved, after which, aquifer pump off rate will be gradually reduced to avoid oil cusping into the aquifer. To monitor oil cusping, water samples are collected from APO wells and facilities and analyzed for oil contamination. Moreover, three observation wells were drilled for real time reservoir/aquifer pressure gradient monitoring. These observation wells will also ensure an optimum pressure differential between the reservoir and the aquifer.
The produced APO water is partly used as feed water for steam generation, with the remainder relocated to a shallow aquifer via a separate relocation system. To ensure oil free water, APO wells are located 100m below the OWC. In order to avoid well integrity issues and heat losses through the produced water, well trajectories have been designed to evade penetrating the steamed formation. An additional opportunity was realized by re-routing a portion of the excess water to a northern water-flooding project to maintain its reservoir pressure.
This paper will focus on the integrated APO strategy, which meets the reservoir management objectives of the "A" West steam flooding project, and the PDO water management strategy.
Fracturing Fluid Encapsulated Breaker: High Temperature up to 330°F
Authors: Al-Hulail Ibrahim , Al-Khabbaz Haidr , Al-Janabi Yahya , Rahal Raed , Dahlan Mohammed , Al-Marshad Khaled 
Published: March 2018

Abstract
Water-based gelled fracturing fluids with guar and guar derivative polymers are used for viscosity development, leakoff control, and proppant transport during hydraulic fracturing operations. After placement, the polymers' mass should be extensively degraded with breakers, such as acids, enzymes, and oxidizers, to help maximize fracture conductivity and minimize residual damaging materials. Without a mechanism to delay their activity, these types of breakers react quickly in most downhole environments, some even at low temperatures, and can degrade the fracturing fluid at an undesirable rate or too early in the treatment.
Oxidizers, such as ammonium peroxydisulfate, are widely used breakers. Oxidizer performance depends on many factors, such as time, temperature, breaker concentration, and polymer loading. Optimal breakers should generate minimum or no unbroken gel residues to help prevent formation damage or damage to the propped fracture. With wells being drilled deeper and at higher temperatures, a high-temperature encapsulated breaker is important for optimum fracturing fluid performance. The high-temperature encapsulated breaker discussed in this paper helps control gel breaking time, enables crosslinked fracturing fluid stability for a longer time than designed, and minimizes residual mass.
This paper presents a high-temperature encapsulated breaker that works at temperatures up to 330°F. The new breaker was thoroughly tested in a laboratory testing scheme that included rheology testing up to 330°F. Testing also included a comparison between the current industry oxidizer and the new high-temperature encapsulated breaker. Additionally, a high-pressure/high-temperature (HP/HT) filter press study of current fracturing fluids and the new breaker was conducted although not included here.
This study highlights the high-temperature encapsulated breaker performance when added to zirconate crosslinked fracturing fluids and compares it to a control fluid without breaker. Also reported for each case are the results from using the same oxidizer without being encapsulated for the same testing conditions.
Study on Development Well Pattern of Combined Steam Drive and Gravity Drainage in a Reservoir with Interbeds and its Application: A Case Study
Authors: Hu Changhao , Zhang Tiantian , Wang Zhongyuan , Han Bing , Zhou Guangxing , Ge Mingxi , Zou Zhaoyu 
Published: March 2018

Abstract
SAGD with combination of vertical and horizontal well has been commercially applied in Liaohe Oilfield. The medium-depth massive super heavy oil D-X reservoir with edge and bottom water is the object of this study. As there exist several extensive interbeds above the horizontal section, the steam chamber is not able to spread to the oil zones above them, resulting low producing degree of the reservoir, and the indicators of development plan cannot be met. To overcome the present problems, a novel SAGD well pattern was proposed, in which oil is drained vertically and swept horizontally at the same time.
A high temperature and high pressure physical model was used to simulate the process of SAGD with combined steam drive and gravity drainage (hereinafter refers to as "CSDGD") in a reservoir containing interbeds. It was observed that the steam chamber fully spread when steam is injected and oils produced above the interbed using vertical wells while producing the reservoir with SAGD under the interbeds. In this way, reserve in the model was sufficiently produced. The width and length of interbeds and its distance to horizontal well are the main factors affecting development effect. The further step is to build numerical model of interbeds of different width, length and vertical position to investigate the effects of interbed distribution and development on SAGD. Finally, screening criteria were proposed for CSDGD and well pattern of steam flooding above the interbed was optimized as well.
At present this technique has been applied in 19 well groups in D-X Reservoir. Well temperature monitoring data shows that reservoir temperature above the interbeds was increased significantly from 70°C to 250°C. The oil production rate of well group was increased from 15t/t to 30t/t; the oil-steam ratio was increased by 0.02 ~ 0.03. Vertical producing percentage was increased by 20%.
A new SAGD well pattern was proposed for the reservoir with interbed in this paper, and the mechanism is revealed. This technique has been successfully used in D-X reservoir to overcome the unfavorable effects of interbeds on steam chamber forming. The study results can be applied to the SAGD development block that cannot meet economic indicators due to the effects of interbeds.
The Role of Synthetic Polymer on Rock-Fluid Interactions and the Resulting Change in Ionic Composition and Viscosity of the Polymer Slug for a cEOR Flood in the Sultanate of Oman
Authors: Berge A. B. , Lenchenkov N. , Wever D. A. , Farajzadeh R. , Al-Mjeni R. , Glasbergen G. 
Published: March 2018

Abstract
Low salinity polymer (LSP), in which the salinity of the make-up water is significantly lower than of the formation water, is an attractive alternative to conventional polymer flooding because of the reduced amount of polymer required. Viscosity loss due to cation exchange with the rock surface however is a significant risk. In this paper, the influence of partially hydrolyzed polyacrylamide (HPAM) polymer on the rock-fluid interactions has been studied by analyzing produced fluids of several core flooding experiments. It was found that all produced fluids containing polymer show elevated levels of divalent cations (mainly Ca2+ and Mg2+) compared to the produced fluids of slugs of brine injected without polymer. This was observed for both high (formation water) and low salinity polymer solutions. The divalent cation levels typically remain elevated for at least several pore volumes of polymer injection. Additionally, produced water from a field on polymer flood was found to contain elevated levels of divalent cations as well.
These results confirm that polymer affects the rock-brine equilibrium and tends to attract divalent cations, which are provided by the rock surface. In our experimental results, the concentration of divalent cations could increase by as much as a factor of 5 compared to the equilibrated brine. The expected viscosity loss varied from no loss (even for LSP) to a loss of ~30%. The extent of cation exchange and viscosity loss strongly depends on the rock-fluid system, in which the charge ratio (CR) of positive charges on the divalent cations in the solution to negative charges on the polymer as well as the divalent to monovalent cation mass-action-ratio (MAR) appear to be important and predicting parameters.
In-Situ Microemulsion-Assisted Fluid Recovery with Blend of Anionic-Cationic Surfactants in Super High Temperature-Extra Low Permeability Formations
Authors: Li Yingcheng , Li Qiang , Zhang Weidong , Meng Yong , Jin Jun , Bao Xinning , Sha Ou , Shen Zhiqin , Yang Yiqing 
Published: March 2018

Abstract
The main challenges for extra low permeability reservoir are injectivity decline and high tubing head pressure (THP) which caused the decreases in hydrocarbon production. The most common causes of deterioration in the reservoir permeability and formation damage include the buildup of in-situ emulsions due to crude oil interaction with drilling and completion fluids, water blockage, asphaltene and paraffin deposition and alteration of near-wellbore wettability. In new wells, near-wellbore formation damage may be caused by emulsion blockages when the whole mud, mud filtrate or completion fluids interact with the formation fluids.
Traditional chemical treatments have been widely used to remediate damaged formations for removal of non-aqueous fluid. Various approaches to tackle this problem have been adopted. For example, acid, solvents and mutual solvents have been applied to improve the reservoir permeability, with varying degrees of effectiveness. Microemulsion fluids with unique propertie such as an ultra-low interfacial tension (IFT), high solvency and compatibility with formation fluids has received great interests and shows great potential to effectively remove emulsion blockages, remove precipitated crude oil macromolecules, and reverse wettability to enhance hydrocarbon production.
In this paper a new in-situ microemulsion formulation consisting of blend of anionic-cationic surfactants (Sa/c) has been developed to assist the fluid recovery for extra low permeability reservoir at dilute concentrations. Ultra low IFT of 3×10−4 mN/m, solubilization parameters of 18, and ultra low critical micelle concentration of 6.8 mg/L were obtained. Freezing point of crude oil was decreased by 18%, together along with 84.5% viscosity reduction by formation of microemulsion. In addition, wettability alteration was also observed.
Lab data shows that the in-situ microemulsion is highly effective in fluid recovery and relative permeability enhancement when applied in stimulation treatments at dilute concentrations.
Filed test by using in-situ microemulsion-assisted fluid recovery with Sa/c was tested in super high temperature-extra low permeability formations (reservoir temperature: 116°C, permeability: 4.5 mD) to demonstrate how this novel technology can significantly enhance hydrocarbon production in poorly producing wells.
Enhancing Oil Recovery from Dolomitic Reservoirs- Investigation of Temperature Limitations
Authors: Puntervold Tina , Strand Skule , Torrijos Iván D. , Hopkins Paul , Austad Tor 
Published: March 2018

Abstract
EOR by Smart Water injection in calcite, CaCO3, is dependent on factors like initial wetting, injection brine composition and temperature. Because of the chemical difference between CaCO3 and dolomite, CaMg(CO3)2, the relationship between EOR effects and the above-mentioned factors could be different. Smart Water EOR potential was experimentally tested for two dolomitic reservoir systems, at low and high reservoir temperature, to determine if there was a temperature limitation for observing EOR effects by Smart Water injection.
Oil recovery tests by spontaneous and forced imbibition experiments were performed to evaluate initial wetting and wettability alteration from two dolomitic reservoir systems. A fractured reservoir system at 65 °C was investigated by spontaneous imbibition tests, while a non-fractured system at 115 °C was investigated by forced imbibition tests. The reservoir cores were saturated with their respective formation waters and crude oil, then imbibed with diluted seawater or modified seawater brines. Oil recovery responses at the different temperatures and by using different imbibing brines were evaluated and compared.
Spontaneous imbibition tests, performed in the fractured reservoir system, showed that a diluted seawater brine increased the oil recovery from the dolomitic core material at 65 °C. When a modified seawater brine, which is a Smart Water for CaCO3, was used, there was no EOR effect observed. Forced imbibition tests with diluted seawater brine showed increased oil recovery for a non-fractured dolomitic reservoir system at 115 °C, while a modified seawater resulted in no extra oil produced.
The results showed that there was no temperature limitation for observing EOR effects in dolomitic reservoir core material within the temperature range 65 - 115 °C. It was confirmed that diluted seawater brines altered the initial core wettability towards more water-wet conditions and enhanced oil recovery was observed both in spontaneous imbibition and forced imbibition experiments. Due to the differences in mineralogy between CaCO3 and dolomite, CaMg(CO3)2, and in their chemical reactivity, the optimal injection water, i.e. Smart Water compositions, were different.
Smart Water EOR effects by wettability alteration in dolomitic reservoir material were observed both at low and high reservoir temperatures. The final oil recovery was dependent on the injection brine composition. Increased oil recovery was experienced in both spontaneous and forced imbibition tests.