bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Simple Technique to Determine the Strength of Millimeter-Sized Particle Gel
Authors: Muhammed Farag A. , Bai Baojun , Al Brahim Ali 
Published: June 2014

Abstract
Millimeter-sized superabsorbent polymers (SAPs), also called preformed particle gels (PPGs), are gaining attention and popularity for use in conformance-improvement treatments. The strength of PPGs is important to the optimization of their performance as plugging agents. Conventional gel strength has always been measured by applying load to single, isolated sample with certain geometry. However, determining the strength of sugar-like PPGs with irregular shapes is a challenging task. Previous publications have proposed different methods to evaluate gel strength. However, those methods are not suitable for rapid quantitative evaluation of PPG strength on site. We designed a simplified experimental apparatus to evaluate gel strength in the laboratory or on site during gel treatment. It consists of a positive displacement hand pump and a specially designed piston accumulator. The top cap of the accumulator has a hole connected to the pump by tubing and fittings. The bottom cap is a stainless steel screen plate with multiple holes. During the experiments, we placed swollen PPG on top of the screen plate and below the piston, gradually increasing the pressure to push the piston until gel particles passed through the plate holes. The minimum pressure needed to push gel particles out of the holes was considered as the threshold pressure of a gel particle moving through a pore throat, which provides quantitative indication of the gel strength. The apparatus also can be used to evaluate gel rheology in terms of its apparent viscosity as a function of the shear rate. We observed that the PPGs are prone to stiffen as the brine salinity increased which caused the threshold pressure to increase. Also the PPGs threshold pressure depended chiefly on the brine salinity, the screen hole size, and the holes density per screen plate. Additionally, the PPGs threshold pressure correlated excellently with their elastic modulus which was measured using a rheometer. PPGs injection pressure did not increase significantly with the injection rate. This behavior is consistent with the real-time injection pressure and injection rate change which has been often observed during PPG treatments in oilfields. This method can serve as a simple, fast, and practical technique to quantitatively evaluate particle gel strength in the laboratory and on site during a PPG treatment process.
Rapid Analysis of Tracers for Use in EOR Flood Optimization
Authors: Sharma Abhinav , Shook G. Michael , Pope Gary A. 
Published: June 2014

Abstract
Tracer testing is a powerful tool for reservoir surveillance. Conducting and analyzing an interwell tracer test before starting an EOR flood provides the specific information required to balance the pattern's swept pore volume and optimize chemical or solvent use. Tracer testing also plays an important role in EOR by establishing a baseline for estimating incremental volume swept and recovery factor.
A key limitation to tracer testing is the time required to obtain a complete interpretation of the test results. Conventional interpretation methods require observing exponential decline in the tracer concentration from all producers; depending on the pattern size and processing rate, this can take many months or years. Meanwhile, the EOR flood is delayed, thereby eroding its value and reducing the remaining oil target. We have developed a method for analyzing tracer data from relatively early times based in part on a new way to extrapolate the tracer data, providing timely information to optimize flood performance. The extrapolation can be done shortly after the peak concentration is observed in the well with the slowest response. We illustrate the extrapolation procedure using a synthetic yet realistic dataset showing that the new methods result in a good approximation at much earlier times. We then compare swept pore volumes using early time data with the (correct) swept pore volumes using the complete tracer dataset. We also discuss how early time approximations can thus provide the opportunity to optimize chemical flood performance and field start-up of EOR floods in a timely fashion.
A Laboratory Study to Investigate CO2 Potential to Mobilize Paleo Oil
Authors: Aleidan Ahmed A. , Zhou Xianmin , Kwak Hyung , Kokal Sunil 
Published: June 2014

Abstract
All reservoirs contain a transition zone below the oil water contact (OWC) which varies in thickness depending on the reservoir rock properties. In some reservoirs that have undergone geological and hydrodynamic titling, there could be an additional, sometimes significant, residual oil zone (ROZ) below the transition zone. This zone sometimes referred to as the ‘paleo’ oil zone and may contain significant quantities of hydrocarbons. Traditionally, this has not received much attention as its oil is immobile and does not normally produce through primary and secondary recovery methods. However, paleo oil has the potential to be mobilized by CO2 injection.
The objective of this study is to show the ability of CO2 injection to mobilize paleo oil in the ROZ. Different laboratory experiments on actual reservoir sponge cores from wells intersecting the ROZ have been conducted at reservoir conditions. The study includes static CO2 saturation (PVT cell) and dynamic CO2 coreflooding experiments, and Nuclear Magnetic Resonance (NMR) analysis. The mobility of paleo oil by CO2 flooding was investigated using both static and dynamic CO2 injection experiments on sponge cores containing paleo oil. The static experiments showed, through images and videos, how the CO2 can mobilize the paleo oil in the cores. The coreflood experiments showed the potential to mobilize the original oil in cores from these two wells intersecting the ROZ. It was found that CO2 soaking is a critical factor to mobilize oil because it allowed more time for the CO2 to interact with the available components. Core samples were further analyzed microscopically using NMR analysis (before and after CO2) to complement coreflood interpretations. NMR showed the exact places in the core where the oil was mobilized by CO2 and the type of components extracted after the experiments (mostly intermediate).
Full-Field Simulation and Optimization Study of Mature IWAG Injection in a Heavy Oil Carbonate Reservoir
Authors: Bender Serdar , Yilmaz Mustafa 
Published: June 2014

Abstract
Bati Kozluca Field is a heavy oil carbonate reservoir discovered in 1985; it is located in the South East of Turkey, close to Syria border. The reservoir began primary production in 1985, developed with 41 wells producing 12.6 API oil. Main constraints for oil recovery are the low aquifer support, low solution gas oil ratio and high oil viscosity which is 480 cp at reservoir conditions. In order to increase 5% recovery, full field continuous immiscible CO2 injection had been implemented from 2003 to 2007 and full field IWAG injection had been implemented from 2007 to 2012. These projects increased the oil recovery from 5% to 6.7% and increased the daily oil production two times. In 2012, it was decided to re-develop the field to increase the 6.7% recovery.
This paper first gives the results of the CO2 and IWAG applications in the Batı Kozluca Heavy Oil Field and then describes the field-wide simulation study conducted to predict the future reservoir performance of the black oil simulation model under various operating and development strategies. First, available data is screened and quality of the data is evaluated; then, dynamic model is built. The model has been successfully history matched with 27 years of production, injection, saturation and pressure history on both the field and the well scale. The history matched model is used to decide the methodology and to determine the infill well locations, injection pattern and injection schemes to increase the oil recovery. Simulation results show that recovery can be increased from 6.7% to 9% with the current injection pattern and without any investment by continuing the project with the optimized injection parameters. However, injection pattern needs to be modified to increase the volumetric sweep efficiency and oil recovery.
Frontal Stability Analysis of Surfactant Floods
Authors: Tavassoli Shayan , Pope Gary A. , Sepehrnoori Kamy 
Published: June 2014

Abstract
Recent surfactant flooding experiments have shown very efficient oil recovery can be obtained without mobility control when the surfactant solution is injected below the critical velocity required for a gravity-stable displacement. The purpose of this study was to develop a method to predict the stability of surfactant floods at the reservoir scale based on gravity-stable surfactant flooding experiments at the laboratory scale. The scale up process involves calculation of the appropriate average frontal velocity for the reservoir flood. The frontal velocity depends on the well configuration. We have performed systematic numerical simulations to study the effect of key scaling groups on the performance of gravity-stable surfactant floods. We simulated three-dimensional heterogeneous reservoirs using a fine grid and a third-order finite-difference method to ensure numerical accuracy. These simulations have provided new insight into the behavior of gravity-stable surfactant floods and in particular the importance of the microemulsion properties. The capability to predict when and under what reservoir conditions a gravity-stable surfactant flood can be performed at a reasonable velocity is highly significant. When a surfactant flood can be done without polymer (or foam) for mobility control, cost and complexity are significantly reduced. Advantages are especially significant when the reservoir temperature is high and the use of polymer becomes increasingly difficult. Our simulations show that gravity-stable surfactant floods can be very efficient using horizontal wells in reservoirs with high vertical permeability.
Alkaline Surfactant-Polymer Formulation Evaluation in Live Oil Conditions: The Impact of Temperature, Pressure and Gas on Oil Recovery Performance
Authors: Oukhemanou Fanny , Courtaud Tiphaine , Morvan Mikel , Moreau Patrick , Mougin Pascal , Féjean Christophe , Pedel Nicolas , Bazin Brigitte , Tabary René 
Published: June 2014

Abstract
An Alkaline-Surfactant-Polymer / Surfactant-Polymer (ASP/SP) design study generally includes intensive work. Hundreds formulations have to be tested to screen phase behavior and typically a dozen of corefloods are performed to select the best formulation and further optimize the injection strategy/slugs design to match economic criteria.
To be extrapolated to the field, it is critical to perform these tests in conditions as close as possible to real reservoir conditions: reservoir temperature, injection brine, reservoir pressure and reservoir oil. Specifically, dissolved gas and high-pressure tend to significantly impact crude oil properties, and subsequently formulation behavior and performance, even when limited amount of gas is present. Ideally, this parameter should be considered from the beginning of the formulation design. However, considering the high number of tests to perform, as well as the relatively high cost and technical challenges associated with live oil experiments, it is unrealistic to routinely perform all the required experiments in high-pressure environment.
We will present here the methodology developed to design surfactant based process by mimicking the impact of reservoir gas and pressure on the reservoir stock-tank oil.
First a thermodynamic model based on an equation of state is fitted to reservoir PVT data (Gas/Oil Ratio or GOR, stocktank oil and associated gas composition analysis, bubble pressure and volumetric factor Bo) to predict consistent thermodynamic behavior and properties of the live oil. This step allows us to validate the reservoir conditions. A recombination of stock-tank oil with gas should be then performed to obtain the fluid in the reservoir conditions. Then we will illustrate through case studies how to combine a high-throughput robotic platform and a high-pressure/high-temperature cell to determine a representative crude oil matching live oil main properties, namely viscosity and Equivalent Alkane Carbon Number (EACN). This representative crude oil is obtained from the reservoir stock-tank oil which has been adjusted, using solvents or alkanes, to present the same characteristics as the reservoir live oil. This oil will therefore be used for an exhaustive formulation design and process optimization. Finally, we will compare oil recovery performances with the representative crude oil and with the reservoir live oil.
Reservoir In-Depth Waterflood Conformance: An Offshore Pilot Implementation
Authors: Choudhary M. , Parekh B. , Solis H. , Meyer B. , Shepstone K. , DeZabala E. , Prostebby C. , Manrique E. , Izadi M. , Larsen D. 
Published: June 2014

Abstract
Ebano field is a high permeability slope-channel turbidite reservoir located offshore Equatorial Guinea, West Africa. Oil production from this field started in May 2009 and water injection began in July 2009. Currently, the field operates with two wells; one injector and one producer with a well spacing of 1.5 km. Water breakthrough was observed approximately one year after water injection began, which was much earlier than the original prediction suggesting presence of water injection thief zone(s). Several reservoir management strategies to improve sweep efficiency were considered for implementation in this field including a reservoir in-depth waterflood conformance technology using a thermally active polymer (TAP).
This paper will summarize the TAP pilot design, implementation, and performance interpretation based on a comprehensive surveillance program. The paper will also describe the workflow utilized to evaluate the technical feasibility of TAP technology (supported by detailed engineering, laboratory, and simulation studies).
Engineering and laboratory studies to evaluate the technical feasibility of TAP started September 2010 and TAP pilot implementation commenced April 2011. Injection of TAP treatment was done from a barge requiring significant coordination between offshore and onshore to ensure safe handling and injection of chemicals. A total of 48,000 bbl of TAP were injected at an injection rate of 6,000 bbl/d, using a concentration of 15,000 ppm (4 cp injected). This treatment has been one of the largest offshore implementation using TAP technology. A detailed surveillance plan was put in place that included gathering and detailed analysis of injection/production data, injection pressure, produced water compositional analysis, production logs (PLT), and Fall-Off Tests (FOT) before and after the TAP treatment.
Ebano pilot results validated TAP displacement and activation away from the injector. PLT data showed that the injection profile remained unaltered post treatment. Time-lapse FOT proved to be very useful in monitoring TAP performance. Uncertainties relating to how far away from the injector TAP was fully activated, injection pressure response (simulation vs. field), and production performance will also be addressed.
Pilot Test of Indigenous Microorganism Flooding in a Heavy Oil Reservoir
Authors: Cui Qingfeng , Yu Li , Dong Hanping , Huang Lixin , Dai Xuecheng 
Published: June 2014

Abstract
Indigenous microbial flooding technology injects nutrients (sometimes mixed with air), activates the useful indigenous microbes which multiply and metabolize rapidly, and oil recovery enhanced. The technology was carried out through in Dagang oilfield in China from 2001 and mostly used in high temperature oilfield. Generally, the technology injects only basic nitrogen source mixed with air and utilizes residual oil in the reservoir as carbon source. Whereas, exgenous microbial flooding tests carried out in the past mostly inject carbon source, nitrogen source and no air.
Based on the research of reservoir geology, the analyses of development situation and study of nutrients, the pilot test was conducted in a low temperature(20°C) heavy oil(80mPa• S) reservoir in a trial block with 4 injection wells and 7 production wells. The test is different from the past MEOR tests in injecting molasses as carbon source, nitrogen source and air at the same time. It injected 0.05 pore volume and lasted for 2 years.
Field performance monitoring and product ion tracking results show: ① the indigenous bacteria were activated with the number increased 2-3 orders compared with pre-test, and microbial population structure changed apparently; ②properties of formation water were changed, the content of HCO3- in formation water varied greatly, and emulsion was found; ③Although CO2 can be generated when molasses is decomposed and activity of producing methane was strengthened, the content of CO2 and CH4 in the gas of oil well changed slightly; ④oil produc increased in wells, and total oil increase was 5, 626t up to Jun., 2013. ⑤That the crude oil is emulsified by microbes is the primary mechanism of Indigenous Microbial Flooding Technology and that biogas generated by microbes is not the primary mechanism were determined.
Indigenous Microbial Flooding Technology injecting organic carbon source, nitrogen source and air simultaneously was appiled successfully in a low temperature heavy oil reservoir, which would serve as an example for similar reservoirs in high water cut stage.
Pilot to Full-Field Polymer Application in One of the Largest Onshore Field in India
Authors: Prasad Dhruva , Pandey Amitabh , Kumar M. Suresh , Koduru Nitish 
Published: June 2014

Abstract
The paper discusses the full-field polymer flood implementation plan post successful pilot result in one of the largest onshore fields in India. Mangala field contains multi-Darcy sandstones that have high porosity and very low connate water saturation and low temperature (65 degC). The connate water salinity is low (~6500 total dissolved solids), The crude is waxy and viscous, which results in unfavorable mobility for water-flooding, Chemical flood was identified as a potential EOR method during a screening study.
A normal 5 spot polymer flooding pilot has been conducted and results are encouraging in terms of additional oil recovery and reduction of water cut. Additionally much has been learnt about how to optimize the surface facility, polymer preparation, and polymer quality monitoring.
Following the successful completion of the pilot, it is planned to implement a polymer flood for the fullfield. All the lab results and pilot learnings have been incorporated to minimize the uncertainty and risks. Different subsurface injection pattern concepts have been evaluated based on the reservoir characteristics. Various parameters like pattern and number of wells, polymer viscosity, tapered vs. fixed concentration, polymer slug sizes and other variables have been optimized and are discussed in the paper. Sensitivities to capture the impact of polymer adsorption, implementation schedule, conformance in injectors, visco-elastic effect of polymer, polymer shear thinning characteristics etc. on recovery have been studied. Learning from pilot has been used in selecting the surface facility, well design, pumping facility, selective completion for conformance control, surface pressure requirement, and designing to minimize the viscosity loss across the completion and sand face.
Surface facilities concepts have been finalized to prepare concentrated polymer at a single location and pumping it to each well for injection. Polymer flooding has the potential to significantly improve the sweep efficiency in the field and to increase expected ultimate recovery (EUR). The project is one of the largest in the world in terms of scale, polymer usage, and related facility and logistics.
Multiple Mixing Cell Method for Three-Hydrocarbon-Phase Displacements
Authors: Li Liwei , Khorsandi Saeid , Johns Russell T. , Ahmadi Kaveh 
Published: June 2014

Abstract
Low-temperature oil displacements by CO2 involve complex phase behavior, where three hydrocarbon phases can coexist. Reliable design of miscible gas flooding requires knowledge of the minimum miscibility pressure (MMP), which is the pressure required for 100% recovery in the absence of dispersion or as defined by slim-tube experiments as the "knee" in therecovery curve with pressure where displacement efficiency is greater than 90%. There are currently no analytical methods to estimate the MMP for multicomponent mixtures exhibiting three hydrocarbon phases. Also, there are no reliable numerical methods to estimate the MMP using compositional simulation largely because of robustness issues of three-phase equilibrium calculations, inaccurate three-phase relative permeability models, and phase identification and labeling problems that can cause significant discontinuities and failures in the simulation results. How miscibility is developed, or not developed, for a three-phase displacement is not well known.
We developed a new multiple three-phase mixing cell method that gives a relatively easy and robust way to determine the pressure for miscibility or more importantly the pressure for high displacement efficiency. The procedure that moves fluid from cell to cell is robust because it is independent of phase labeling (i.e. vapor or liquid), has a robust way to provide good initial guesses for three-phase flash calculations, and is also not dependent on three-phase relative permeability (fractional flow). These three aspects give the mixing cell approach significant advantages over using compositional simulation to estimate MMP or to understand miscibility development. The approach can be integrated with previously developed two-phase multiple mixing cell models because it uses the tie-line lengths from the boundaries of tie triangles to recognize when the MMP or pressure for high displacement efficiency is obtained. Application of the mixing cell algorithm shows that unlike most two-phase displacements the dispersion-free MMP may not exist for three-phase displacements, but rather a pressure is reached where the dispersion-free displacement efficiency is maximized. This is the first paper to examine a multiple mixing cell model where two- and three-hydrocarbon phases occur and to calculate the MMP and/or pressure required for high displacement efficiency for such systems.
One-Spot Pilot Results in the Sabriyah-Mauddud Carbonate Formation in Kuwait Using a Novel Surfactant Formulation
Authors: Carlisle Charlie , Al-Maraghi Eissa , Al-Saad Bader , Britton Chris , Fortenberry Robert , Pope Gary 
Published: June 2014

Abstract
Kuwait Oil Company has recognized the implications of the recent technological advances that are very likely to transform the oil industry and make chemical enhanced oil recovery methods such as alkaline-surfactant-polymer (ASP) flooding a hallmark of enhanced oil recovery. An ambitious program to apply chemical EOR to both sandstone and carbonate oil reservoirs in Kuwait is already underway. In this paper, we present the first field results of this effort. First we discuss the approach used to design a novel surfactant formulation for a high-salinity, high-temperature, highly heterogeneous carbonate reservoir, the Sabriyah-Mauddud in Kuwait, and the evaluation of the ASP process in three one-spot ASP pilots (i.e., three two-stage single well chemical tracer tests). We summarize the results of the surfactant laboratory experiments used to select the final ASP formulation and we present detailed results and interpretation of the subsequent single-well chemical tracer test (SWCTTs) results using ASP chemicals as well as details of the field operation including quality control measurements performed in the field lab. The residual oil saturations measured before and after the injection of the ASP slug and polymer drives clearly show that the chemical solution was effective in mobilizing and displacing residual oil saturation following injection of water. The injectivity of high molecular weight polyacrylamide polymer was excellent despite the low permeability of the formation.