bluuebunny/crossref_metadata_2025_split huggingface dataset:
Investigation Of The Effect Of Some Parameters In Miscible WAG Process Using Black-Oil And Compositional Simulators
Authors: Namani M.. , Kleppe J.. 
Published: July 2011

Abstract
Miscible gas injection in oil fields in general results in a better microscopic displacement efficiency compared to water injection; however, higher mobility ratio and lower macroscopic sweep of gas is a major disadvantage compared to water injection. Considering this situation, water alternating gas (WAG) was proposed and implemented as a method to improve macroscopic sweep efficiency of gas using cyclic water injection to reduce its high mobility ratio.
In this simulation study, a systematic parameter study was carried out to investigate the effect of different parameters in a miscible WAG process using a horizontal sector model and both black-oil and compositional simulators. The base model was first built using a black-oil simulator but a compositional model was later implemented in order to investigate the differences in results for the two models.
This study shows that WAG injection is advantageous compared to both water and gas injection in term of oil recovery factor. Changes of cycle time did not affect the recovery factor significantly while in this particular model recovery is sensitive to the changes of gas half cycle time. It is not possible to find a simple dependency between half cycle time and oil recovery factor but it is obvious that recovery factor is a function of both gas slug size and half cycle time and that an optimum value exists for each case. The effect on recovery by changes in water half cycle time is on the other hand not significant.
Injection of water through all layers improved the advance of stable front and improved final oil recovery for all cases. However, the gas injection interval needs to be optimized for each case based on the ratio of vertical and horizontal permeabilities of the reservoir, and thus the injection perforation strategy for gas must take this into consideration.
In the model used, which has no aquifer or gas cap, increased dynamic forces by simultaneous increase of field production and injection rates resulted in increased oil recovery.
There is good consistency between black-oil and compositional base models with only ±4% OIIP differences in term of field oil recovery.
EOR vs. Infill Well Drilling: How to Make the Choice?
Authors: Alusta Gamal , Mackay Eric , Fennema Julian , Collins Ian 
Published: July 2011

Abstract
It is a common observation that operating companies are reluctant to use EOR techniques when they have the option of infill well drilling instead. Reasons for this include the advances in technology that allow accurate prediction of where unswept reserves are located. Other factors include the quicker recovery of the investment, and the fact that oil companies are well experienced in judging the risk and possible returns associated with drilling wells, whereas quantification of the risk and possible returns from EOR projects is difficult to calculate in advance and to evaluate once in place. However, are the oil companies missing opportunities for maximising return on their investment, and are there limitations in the way in which risk is evaluated which inherently favour infill well drilling?
This study involved setting up a range of EOR scenarios, performing reservoir calculations to evaluate additional recovery and then making a comparison with infill drilling to maximise recovery from mature assets. This paper develops an understanding of how the economic comparison should be performed, since the timescales for investment and return on investment and the associated risks and uncertainties are different for EOR projects and infill well drilling. One driver is whether the oil price is relatively high or low. The method involves studying a range of scenarios, selecting appropriate EOR techniques and modelling the impact these techniques have on recovery, and then running calculations of the impact of various options. An economic assessment is made of the costs and risks of the various options together with expected return under a range of economic scenarios.
For illustration, a synthetic reservoir simulation model is developed to study the impact of polymer flooding vs. waterflooding. Various uncertainties are tested, and the results are fed into an economic model for an evaluation of sensitivity to various parameters.
This was done for polymer flooding, but the approach could be used for other EOR techniques also.
Recovery Processes of Extra Heavy Oil - Mechanistic Modelling and Simulation Approach
Authors: Foo Y. Y. , Chee S. C. , Zain Z. M. , Mamora D. D. 
Published: July 2011

Abstract
Heavy/ extra heavy oil has captured the global attention as an unconventional hydrocarbon resource which may satisfy the ever-increasing energy demand in the future. Heavy/ extra heavy oil is often characterized as viscous and immobile fluid with high content of impurities and heavy metals, such as Nickel and Vanadium. These inherited characteristics impose great challenges not only to oil recovery optimization, but also various costs pertaining to downstream processing. Due to this fact, reservoir modelling and simulation are commonly conducted to evaluate the performances of enhanced recovery processes at early project stage. In this paper, the conceptual models for Oilfield Alpha are developed using CMG STARS reservoir simulator. They are grouped into 3 categories, i.e. (I) Horizontal wells, (II) 5-spot pattern vertical wells and (III) Horizontal well pairs, based on the nature and well configuration of the recovery techniques. These techniques are Horizontal Well (HORZ), Steam Flooding (SF), Cyclic Steam Stimulation (CSS), Steam Assisted Gravity Drainage (SAGD), Vapour Extraction (VAPEX) and some of their variations. Performance indicators, typically the Recovery Factor (RF) and Cumulative Steam-Oil-Ratio (CSOR), for each model are evaluated and compared within the category. The simulation results generally show that, after 20 years of production, the thermal methods have prevalently higher oil recovery factor, i.e. 7 – 37 % of OOIP, compared to that of cold methods, i.e. 8 – 13 % of OOIP. Further sensitivity analysis on Expanding Solvent-SAGD (ES-SAGD) and VAPEX are also conducted in order to investigate the effects of injected fluid composition imposed on the process performance. From the results, 95 % of steam and 5 % binary components of C3 and C6 presents as the optimum injected fluid composition for ES-SAGD method. On the other hand, injected fluid comprising 60 % of C1 and 40 % of C3 delivers the best oil recovery factor for VAPEX method.
Application of Radioactive and Chemical Tracers for Offshore WAG Pilot Project
Authors: Abdullah Zaidi Zainal , Zain Zahidah M. , Anua Nor Aidil , Singhal Ashok 
Published: July 2011

Abstract
Malaysia’s oil predominantly comes from offshore fields. Malay Basin located to the East of Peninsular Malaysia contains most of the country's oil reserves. In the maturing oil fields of Malaysia, EOR options are being field-tested for enhancing and prolonging production. A Water Alternating Gas (WAG) pilot was implemented in the Dulang Field S3 Block during 2002–6. The S3 Block contained six wells (three producers and three injection wells) in two reservoirs namely E12/13 and E14.
This pilot project was the first EOR pilot in Malaysia. The main objectives of the pilot project were to design and develop the EOR scheme, and to evaluate the feasibility of WAG injection to maximize the oil recovery from this and other similar oil fields. A comprehensive monitoring was undertaken to assist in evaluation of pilot performance. Identification of optimal operating conditions, Dulang field-specific screening criteria and success indicators were perceived to be germane for future WAG implementation.
Oil bearing sands of the Dulang field were deposited under fluvial or near shore environments as parts of sand-shale sequences. These strata were subsequently folded and faulted, resulting in discrete compartments’ with uncertain flow continuity across various faults. Due to existence of numerous major as well as, minor faults and thinness of shale layers at certain places, the critical considerations for EOR were a) confinement of the injected fluids within individual compartments, and b) flow continuity between different injector and producer wells. It was therefore decided to use different water and gas phase tracers at each of the three injection wells within the S3 block. The data gathered were used for assessing internal communication, flow parameters and inter-well reservoir heterogeneity such as high permeability streaks. This paper discusses details of the tracer program and significant responses observed during the pilot implementation.
Evaluation of Oil Recovery by Water Alternating Gas (WAG) Injection – Oil-Wet and Water-Wet Systems
Authors: Zekri Abdulrazag Y. , Nasr Mohamed S. , AlShobakyh Abdullah S. 
Published: July 2011

Abstract
Water alternating gas injection (WAG) is normally employed to improve the volumetric sweep efficiency of miscible flooding processes. Literature search indicated a number of numerical studies investigated the effect of flooding rate, gravity forces, slug size, and heterogeneity on WAG processes performance. However there are very few numerical and experimental studies conducted on the effect of wettability on the efficiency of WAG processes. This work examines how to optimize WAG processes for carbon dioxide (CO2) floods above the minimum miscibility pressure (MMP) in both oil-wet and water-wet reservoirs. Stream tube simulation was used to assess the effects of WAG ratio, system wettability, flood pattern, solvent injection rate, project timing, and reservoir heterogeneity on the sweep efficiency and overall all recovery efficiency for oil-wet and water wet reservoirs. A series of secondary miscible carbon dioxide WAG displacement runs were performed employing WAG ratio’s of 1:1, 2:1, 1:2, 3:1, 1:3 and straight carbon dioxide.
The main conclusions of this research show that system wettability has a significant impact on the optimization of WAG ratio, solvent injection rate, project timing, and flooding pattern selection.
Study of Asphaltene Precipitation and Deposition Phenomenon during WAG Application
Authors: Khanifar Ahmad , Alian Sima S. , Demiral Birol , Darman Nasir 
Published: July 2011

AbstractPrecipitation and deposition of heavy organic materials such as asphaltene inside reservoirs, processing and transportation facilities is a major concern in the oil industry. Asphaltene precipitation is one the most common problem in many reservoirs and unfortunately may lead to many safety operational issues that in end affect’s oil recovery which assumes to be a major economical loss. The precipitation and deposition of asphaltene in porous media and their interactions with rock and fluids is a complex phenomenon which begs to be investigated under reservoir conditions. As yet, there have been many studies conducted on asphaltene precipitation but majority of them focused on determining precipitation onset point. It is believed, the first step in attempting to find an engineering solution to this deposition problem is to identify the conditions at which asphaltene precipitation takes place initially and conditions after that influences deposition.This paper presents an assessment of aspects that influences asphaltene precipitation and deposition. This research, attempts to understand the mechanism of asphaltene precipitation and deposition, parameters affecting the precipitation and deposition process, the effect of asphaltene precipitation and deposition on oil reservoir characteristics and performance. In addition, the research involves examining the existing thermodynamic models of asphaltene precipitation and deposition in porous media, reversibility of asphaltene precipitation and deposition, asphaltene deposition removal methods, and modelling and simulation of asphaltene by conventional simulators. Since this study is a comprehensive summary of the mentioned topics and contains all the essential information of asphaltene and its precipitation process, it therefore can be used as a reference for further exploration of this specialized field.The probability of asphaltene precipitation and deposition occurring during any EOR techniques and its effects on reservoir performance should be anticipated at earlier stages of any development project. Also it is believed that through a more comprehensive understanding of the mechanisms that lead to deposition in the first place; asphaltenes deposition if cannot be prevented fully may at least be controlled and managed.
Research on a New Profile Control Agent: Dispersed Particle Gel
Authors: You Qing , Tang Yongchun , Dai Caili , Shuler Patrick , Lu Zayne , Zhao Fulin 
Published: July 2011

Abstract
In order to achieve in-depth control of injection water and improve oil recovery, a new profile control agent called dispersed particle gel (DPG) is developed, which is significantly different from colloidal dispersion gel both in its preparation and its characteristics. The DPG is prepared by the tube shearing cross-linking method with polymer and cross-linker. Atomic force microscope (AFM) studies show that DPG is made of small pseudo-spherical particles and the sizes can be controlled from nm to mm by adjusting shearing rate in the tube. The particles have a ratio of major and minor axis length of near 1, and the larger the shear rate, the closer the ratio is to 1. Salinity has a minor effect on the micro-morphology and there is an aging aggregation phenomenon. The results on dynamic light scattering also support the conclusions above. The rotary viscometer measurements show that DPG has a low viscosity, and salinity has a minor effect on viscosity, and that the DPG has good shearing stability. Physical simulation experiments in this study demonstrate that DPG has good injectivity, the ability to control injection profile, and improve oil recovery. It can be concluded from this study that this new profile control agent has the potential for wide application.
Immiscible Foam for Enhancing Oil Recovery: Bulk and Porous Media Experiments
Authors: Andrianov Alexey , Farajzadeh Rouhi , Nick Mahmood Mahmoodi , Talanana Mohand , Zitha Pacelli L. 
Published: July 2011

AbstractThis paper reports a laboratory study of foam for improving immiscible gas flooding. The study is relevant for both continuous and Water Alternating Gas (WAG) injection schemes. The effect of oil on the longevity of nitrogen and air foams was studied in bulk for a selected set of surfactants. Foam heights were measured in a glass column as a function of time, in the absence and presence of mineral and crude oils. From the column experiments it was found that foam longevity increases as the carbon chain length in the oil molecule increases, i.e. foam is more stable for higher viscosity oils. A surfactant formulation that gave the most stable foam in the presence of oil was used in the core-floods. Oil recovery with CO2 and with N2 foams from natural sandstone cores was studied with the aid of X-ray Computed Tomography, varying the injection rates, foam quality and surfactant concentration. The core-floods revealed that foam increases the oil recovery by as much as 20% of the oil initially in place (OIIP) over water flooding while injection of gas increased oil recovery by 10% only. Thus, foam adds up to 10% additional recovery on top of gas injection. This confirms that foam is potentially an efficient Enhanced Oil Recovery (EOR) method.
Evaluation of the Impact of Relative Permeability Hysteresis and Three Phase Modeling on the Performance of Water Alternative Gas EOR Processes
Authors: Karkooti Hooman , Masoudi Rahim , Arif Anndy M. , Darman Nasir H. , Othman Mohamad B. 
Published: July 2011

AbstractThe complex physics of the displacement processes involved in three-phase flow in porous media in the tertiary oil recovery processes is yet to be understood. Three phase relative permeability are usually calculated from two phase experimental data due to the complexity of three phase measurements and its duration, hence introducing uncertainty in the adopted models. Pore-scale laboratory studies have shown strong irreversibility in the relative permeability among the successive drainage and imbibitions cycles and its path dependency, which is called hysteresis. Understanding this phenomenon and its effect play a major role in evaluation and success of any tertiary recovery processes such as WAG EOR. Several models have been proposed to predict this mechanism, three phase zone and predict the true residual oil saturation. To better evaluate and mitigate the risks involved, the impact of many parameters used in the current predictive tools and hysteresis models should be fully understood and investigated.In this work relative permeability hysteresis, three phase region and various involved parameters affecting the hydrocarbon recovery have been investigated. A heterogeneous sector model supported with actual SCAL data were used for the purpose of this study. The results of the study and the adopted methodology have been later compared and verified with the actual real field performance data under the same processes.Generally the results show significant difference in term of residual oil saturation whether or not a relative permeability hysteresis modeling is employed. The study also demonstrates the necessity of fine-tuning the hysteresis model parameters to the actual SCAL data to obtain more realistic parameters to be used in prediction phase. Reservoir heterogeneity play a major role in balancing the viscous and gravity forces as well as the three phase region size to achieve higher hydrocarbon recovery.
Flexibility Research of Hot-Water Flooding followed Steam Injection in Heavy Oil Reservoirs
Authors: Dong Xiaohu , Liu Huiqing , Zhang Hongling , Pang Zhanxi 
Published: July 2011

Abstract
With the accelerating of exploitation, a great number of heavy oil reservoirs or blocks have reached the intermediary and later stage of steam injection development. It is faced with changing the thermal development mode.
Aimed at the residual oil of thermal production, this paper studies the alternative development mode after steam injection. Using the physical simulation method, we study the development effect of converting into Hot-water flooding under different temperature and different moment, and investigate the oil displacement efficiency of Water-Alternating-Steam Process (WASP). Then the result of Nitrogen hot-water foam flooding is discussed. Furthermore, it also argues the optimal reservoir rhythm which is suitable to converting into Hot-water flooding, and optimizes the confinement of reservoir thickness and heterogeneity by the method of numerical simulation.
The obtained results indicate that Hot-water flooding with 120 °C will obtain a great recovery performance. The best converting moment of Hot-water flooding is when the heavy crude oil recovery was about 22%. In comparison with the Hot-water flooding, the capacity to enhance the sweep efficiency of WASP is more remarkable. Nitrogen hot-water foam flooding could reduce the water cut by 20% above, and enhance the oil recovery by 25% above. Due to the action of gravitational differentiation, a Reverse rhythm reservoir convert into Hot-water flooding will acquire a good result. That reservoir where the thickness is less than 5m, and the permeability coefficient of variation is less than 0.4 could yield a higher oil recovery.
These results could play an important guiding significance to switch the thermal development mode. In addition, they can also be used as a tool for the successful design of Hot-water flooding after steam injection to enhance crude oil recovery in heavy oil reservoirs.
A Case Study in Cased-hole Log-inject-log Techniques to Determine Residual Oil Saturation to ASP Injection
Authors: Schulz R. A. 
Published: July 2011

Abstract
The onshore Seria field in Brunei Darussalam has been producing oil for over 80 years and is approaching the end of primary production. Estimated remaining oil-in-place volumes are significant enough to consider enhanced oil recovery techniques. Alkaline-Surfactant-Polymer (ASP) flood is under investigation as a potential method to increase the recovery in the field. Sand pack and core flood experiments indicate that remaining oil saturations may be reduced sufficiently to warrant commercial application of ASP flood technology in the Seria field. To assess feasibility of this process under reservoir conditions, a single-well, multi-zone injection test using Log-Inject-Log (LIL) techniques was executed. The objectives of this test were to determine injectivity of ASP fluids and to estimate changes in residual oil saturation (Sor) in the near-wellbore region. This paper discusses the preparation, execution, and learnings associated with the LIL activities employed to assess chemical effectiveness of the ASP slug.
Standard open-hole logs were acquired in a newly drilled well to confirm static reservoir properties and to determine the current oil saturation. The original LIL logging program included Schlumberger’s Reservoir Saturation Tool (RST) in pulsed neutron spectroscopy mode (also known as carbon/oxygen or C/O logging) as the primary evaluation method to quantify changes induced by ASP flooding. This was initially supplemented by the slim Cased-Hole Formation Resistivity (CHFR) tool and further supplemented by RST sigma logging and additional cement bond logging to identify sweep outside of perforated intervals. The use of multiple logging tools and the integration of logging results provided corroborative evidence for reduction in oil saturation outside of perforated intervals resulting from acid/brine, polymer/brine and ASP/brine injection as well as valuable insight into changes in the near-wellbore region that would otherwise be missed using a single logging method.
Experimental PVT Data Needed to Develop EOS Model for EOR Projects
Authors: Shaikh Jawad Azeem , Sah Pashupati 
Published: July 2011

Abstract
Compositional reservoir simulations for fields undergoing gas injection are dependent on an Equation-Of-State (EOS) model that will correctly simulate the reservoir fluid phase behavior independent of concentration of injection gas. Such an EOS model will require extensive Enhanced Oil Recovery (EOR) PVT Experiments. It is important at the start of an EOR PVT project to define what experiments need to be undertaken. Only then will it be possible to define the sample volume needed to carry out all the EOR PVT experiments. The reservoir type will determine whether the samples can be taken from bottom hole or from the separator. Fluid samples at atmospheric conditions also need to be taken to carry out Carbon Number (True Boiling Point) distillation test. Different samples will generally have to be comingled to avoid compositional variations between samples used for different experiments.
Gas injection is most efficient if the reservoir pressure is higher than the minimum miscibility pressure (MMP). Miscibility develops through a critical point and therefore in addition to routine PVT data it is also important to measure EOR PVT data that will provide information about MMP and near critical phase behavior. The MMP is measured in a Slim Tube test while a Solubility Swelling Experiment will give the Px-diagram including the critical conditions and composition. It is also recommended to perform the Equilibrium Contact Mix and Multi Contact Studies to measure properties inside the phase envelope at near critical conditions. These two experiments need to be carefully designed to ensure to get the most out of them in the EOS modeling work.
The paper will outline design of EOR experiments, details to be aware of when carrying out the experiments and key data to be matched by the final EOS model.