bluuebunny/crossref_metadata_2025_split huggingface dataset:
Heavy Crude Oil Recovery Enhancement and In-Situ Upgrading During Steam Injection Using Ni-Co-Mo Dispersed Catalyst
Authors: Shuwa S. M. , Al-Hajri R. S. , Mohsenzadeh A. , Al-Waheibi Y. M. , Jibril B. Y. 
Published: March 2016

Abstract
Steam injection has become commercially available thermal enhanced oil recovery methods for recovering heavy crudes. Recently, there has been increase in research interest in in-situ catalytic upgrading. In this work, experimental investigations on the application of a new submicron dispersed trimetallic catalyst based on Ni-Co-Mo for enhanced recovery and upgrading of Omani heavy crude oil was conducted. The catalysis effect of the ultra-dispersed Ni-Co-Mo metals generated in-situ from water-in-oil emulsion was studied in the presence of sand packed bed as a porous medium in a steam simulation process. The results from the recovery tests showed a higher oil recovery (15% OOIP) in the presence of the catalyst than base steam injection case. Substantial improvement in quality of produced oil was observed as there was a tremendous reduction in oil's viscosity of about 25% with significant reduction in sulfur (26%), and increase in API gravity (10%). This enhancement of the quality of Produced liquids in terms of increase in API gravity, viscosity and sulfur reduction, is an indication of successful in situ upgrading of the oil. Analysis of solid and gaseous products recovered from the experimental runs conducted with the catalyst showed thermal expansion and viscosity reduction due to catalytic hydrocracking as the dominant mechanisms for oil recovery.
Representation of Phase Behavior and PVT Workflow for DME Enhanced Water-Flooding
Authors: Groot J. A. , Chernetsky A. , Te Riele P. M. , Dindoruk B. , Cui J. , Wilson L. C. , Ratnakar R. 
Published: March 2016

Abstract
DME (di-methyl-ether) is a water-soluble solvent with clear potential for enhanced oil recovery (EOR) through its use in DME enhanced water-flooding (DEW). DEW is a novel technology where DME is dissolved in the brine that is injected in the reservoir. Upon contact with oil, DME preferentially partitions into the oil (hydrocarbon) phase. This results in swelling and viscosity reduction of the oil, hence enhancing oil production.
Recovery enhancement for DME enhanced water-flooding (DEW) strongly depends on the phase behavior of the system. Therefore, it is imperative to accurately describe the phase behavior in the dynamic DEW models. This paper presents the PVT experiments and workflow used to model the phase behavior in DEW processes.
The PVT modelling workflow consists of the following steps. Gather basic experimental data for the DME-brine and DME-crude phase behavior required to model phase behavior during the DEW displacement process.Characterize, tune and lump the hydrocarbon fluids using the SRK (Soave-Redlich-Kwong) EoS (equation-of-state).Model the interaction between hydrocarbons, brine and DME using the CPA (Cubic-Plus-Association) EoS.Generate composition dependent partitioning coefficients (K-values) and phase properties based on mixing rules.
Experimental data required as input for the workflow includes routine PVT data, DME-brine solubility data and DME partitioning data between reservoir fluids. This paper provides an overview of how experimental data is obtained and utilized to represent the phase behavior in the modeling workflow. The essential elements of the modeling workflow fall into two segments: representation of the phase behavior with a proper fit-for-purpose model,utilization of the phase behavior representation for dynamic reservoir modeling.
The phase behavior during the DEW displacement process is represented using the CPA EoS. CPA combines SRK with an association term to account for the interaction between DME and brine. As it is relatively computationally costly to run DEW simulations with the CPA EoS, the proposed modelling workflow is based on compositionally dependent partitioning coefficients.
In simulation studies the phase behavior is represented using a K-value model. The K-value model is validated for light and heavy oils in various reservoir models by comparison with conventional water-flooding simulation based on a black-oil PVT description. Results show that the K-value model is accurate for reasonably constant phase compositions, numerically stable and computationally efficient. Furthermore, it is shown that differences in history match obtained with the black-oil model and the K-value model are marginal, as the compositional path is far away from the critical locus. The results give confidence that the K-value model can be used to assess DEW performance in full field models.
Carbonate Reservoir Field Experiments in Extreme Steam Conditions, Bahrain Field
Authors: Smith Scott , Parakh Sameer 
Published: March 2016

Abstract
Starting late 2011, high temperature and high-pressure steam pilots were initiated in two Bahrain carbonate reservoirs. The first thermal pilot started in December 2011 within the heavy oil Rubble Reservoir, in a 7 well horizontal and vertical well configuration, covering 1 to 3 acre spacing. The second pilot started in December 2012 within the light oil Mauddud Reservoir with a 9 well horizontal and vertical test configuration covering 5 acres. Both carbonate thermal pilots progressed through pilot expansion or modification phases over the last 4 years, and were both technically successful in mobilizing and recovering oil and successfully reduced residual oil to expected thermal recovery end points. Currently, the Rubble and Mauddud thermal projects are undergoing expansion for field economic appraisals.
The focus of this paper is on the Mauddud Steam Pilot. The paper will describe the geologic environment, initial pilot design, changes made to the pilot through systematic analysis, and timely achieved final technical success results. The systematic analysis permitted successful pilot execution, pilot technical success and initiation of economic appraisal expansion in the amazingly short time period of approximately 2.5 years. Most astonishingly, this pilot is unconventional thermal recovery; there are no suitable analogs to tight fractured carbonate light oil thermal recovery.
A New Insight on the Impact of Individual Ions on Fluid/Fluid Interactions and SmarWater Recovery
Authors: AlGeer M. A. , Gmira A. , Al-Enezi S. M , Yousef A. A. 
Published: March 2016

Abstract
SmartWater flooding (SWF) has been proven as an effective and successful recovery method for carbonates, in which the injected water alters the carbonate rock wettability to produce incremental oil. Core-scale displacement experiments have demonstrated significant incremental recoveries of SmartWater in both secondary and tertiary modes. Single-well chemical tracer tests have demonstrated this potential in the field at a scale larger than those examined in the laboratory. Still, the underlying mechanisms responsible for SmartWater wettability alteration of carbonates are not well understood. The objective of this work is to understand the effects of individual mono and divalent ions on brine-oil interactions and their role in the observed alteration of carbonate wettability.
In previous studies, we have investigated liquid-rock interactions and their role in wettability alteration. At fixed salinities, mono and divalent ions were found to have different effects on the calcite surface potential. Here, we investigate SmartWater effects on liquid-liquid interactions. We perform interfacial tension (IFT) measurements between oil and brines of fixed salinities but varying ionic compositions, and we collect IFT data at different temperature conditions.
The different SmartWater recipes, at fixed salinities, have exhibited different IFT values indicating the varying effects of ions on fluid-fluid interactions. SmartWater recipes composed exclusively of magnesium cations exhibited a remarkably low level of IFT values. In contrast, SmartWater recipes with sodium or calcium cations exhibited comparable IFT stabilization levels, while SmartWater recipes that are solely composed of sulfate anions have resulted in higher IFT values. The low IFT values obtained with Mg2+ ions can be attributed to weaker bond dissociation energies and quicker ion accessibility in MgCl2 when compared to the other salts.
In the next stage, these results will be integrated with Zeta potential and contact angle data acquired at similar brine salinities and composition. This systematic integration will allow for a better understanding of individual ion effects, which would eventually help to further optimize the SmartWater recipe for higher oil recovery.
Synergy Between Low Salinity Water Flooding and CO2 for EOR in Chalk Reservoirs
Authors: Hamouda Aly Anis , Pranoto Arif 
Published: March 2016

Abstract
Low salinity water (LSW) flooding as an enhanced oil recovery (EOR) method is receiving attention from most oil field operators. Incremental oil recovery reported by different researchers is encouraging. While it is generally accepted that LSW changes rock wettability, the mechanism(s) by which this occurs remains debatable. CO2 flooding is a known EOR method and has been applied in different reservoirs. Synergy between LSW and CO2 are addressed in this paper.
Three major aspects are investigated: identifying the ion content boundary for the LSW which maximises oil recovery, assessing the ion ranking with LSW alternating CO2 injection (LSWACO), and assessing the synergies for oil recovery from applying LSWACO. Throughout the paper, ion tracking and pH are monitored using CMG GEM and Phreeqc Interactive 3.0 for simulating the fluid rock interactions recovered. Published EOR data for LSW and the simulation of core flooding which combines LSW and CO2 may shed light on the possible mechanism(s). Three dilution ratios of seawater (LSW5D, LSW10D and LSW25D) are investigated and ranked on the basis of the obtained incremental oil recovery.
It is interesting to see that the higher the dilution, the slower the oil recovery response from chalk reservoirs. The simulation also showed that the highest incremental recovery was obtained from LSW10D.
CO2 injection coupled with LSW (LSWACO) had a positive effect on oil recovery. It was interesting to observe that different LSW dilution ratios during LSWACO injection yield similar recovery response times and ultimate oil recovery. However, the order of the various LSW dilutions differs from that without CO2.
Learnings from Reservoir Souring Assessment on an Offshore Malaysian Field
Authors: Zhu Feibai , Kuijvenhoven Cor , Borhan Noorazlenawati Bt , Dickson Sara-Jane , Lomans Bart 
Published: March 2016

Abstract
MY01 is an offshore field located in Malaysia. Although souring mitigation by nitrate injection was applied from the start of the seawater flood, hydrogen sulphide (H2S) has been detected in several producers after injected seawater breakthrough. The objectives of this work are to understand the causes of reservoir souring in MY01 and to provide key considerations for improving souring prediction in low temperature reservoirs, as generalised from the learnings from this field.
Reservoir souring potential was assessed using a Joint Industrial Project (JIP) developed program (SourSimRL). SourSimRL is a reservoir model post-processor which simulates the microbial generation, scavenging, adsorption and transport processes of H2S in fields subjected to waterflood, based on fluid dynamics, reservoir conditions and water chemistries as dictated by the reservoir model. The MY01 reservoir model was split into two parts: (i) a history matched model that allows calibration on reservoir souring simulator input parameters; and (ii) a forecast model on which souring development is predicted. Extensive sensitivity studies were conducted to define key factors promoting or inhibiting H2S production to match the actual H2S levels seen in the producers. Furthermore, the application of microbiological analysis to understand the reservoir souring behaviour, including screening of bacteria present using DNA-based techniques is also discussed.
The simulations demonstrated that carbon is the souring limiting factor in MY01. To match the H2S field data, other metabolisable carbon sources should be available in addition to the volatile fatty acids (VFA's) in the formation water. The souring development in such field could be driven by the mechanism of the carbon supply. Therefore, it is critical to identify the type and quantify the level of dissolved organic carbon, including oil-derived BTEX or microbial degradation products. Since MY01 reservoir conditions are favourable for souring activities, microbial development is likely to take place both in the biofilm that forms at the injector face as well as at flood fronts deeper into the reservoir.
Study On Thermal-GAS EOR Method in In-Depth Extra-Heavy Oil Reservoir in China
Authors: Guo Erpeng , Jiang Youwei , Gao Yongrong , Wang Hongyuan , Wei Yao 
Published: March 2016

Abstract
SAGD(Steam Assisted Gravity Drainage) is commercially adopted as a main thermal recovery method for heavy oil reservoirs. How to improve the recovery effect and the heat efficiency of SAGD process draws the attention of all the heavy oil reservoir engineers, especially under low oil price circumstance. This paper aims to utilize gas as additives to reduce the steam demand of SAGD projects, hence to improve the recovery efficiency of this method.
In this paper, study on improving recovery efficiency of steam injection process with gas additives in reservoir with great depth was carried out. Laboratory tests were carried out to quantify the properties of different gas additives with heavy oil. Also flooding experiment were carried out to compare the relative permeability curve before and after gas additives were included. Then simulation were done to evaluate the influence of gas additives on SAGD process. SAGD processes with different gas additives were compared and the influences of different gas additives on recovery process were analyzed in detail.
The study reveals that the SAGD recovery process can be greatly influenced by gas additives. All of gas additives can sharply reduce the steam demand for SAGD process. It was shown that CO2 can improve the production effect of SAGD because of their great solubility and viscosity reduction effect. In the CO2 case the drainage threshold temperature was decreased by 17.1°C in comparison to the pure steam SAGD process with the help of viscosity reduction. Addition of CH4 will impair SAGD process because CH4 overrides faster than steam and hinders the development of steam chamber. N2 can accelerate the oil recovery rate but has no effect on improving recovery factor. On the contrary the viscosity reduction effect of CH4 and N2 is much less than CO2. With the results of this paper, the recovery factor of SAGD process can be improved by 8% and SOR can be improved by 14.7% when CO2 was co-injected with steam.
The results of this paper are of great significance in that it combines the advantage of steam injection process and gas injection process. The heat assumption in SAGD process can be sharply decreased and the recovery factor can be enhanced with the help of soluble gas additives. Also the greenhouse gas emission can be lowered down.
Application of Cyclic Steam Stimulation on XYZ Formation in Sultanate of Oman
Authors: Al Raqmi Mohammed , Al Saadi Hassan , Mirza Muhammad , Al Bahlouli Shihab Said , Arham M. Aidil , Setiawan Hari Sudono , Al Amri Bader 
Published: March 2016

Abstract
Medco LLC has initiated cyclic steam stimulation of XYZ formation in one of a green field located at South Oman. The fields contains under-saturated and waxy medium to heavy oil (18 °API) with initial viscosity ranging from 650cp to 1200cp at reservoir conditions. The reservoir is unconsolidated sand with average porosity and permeability of above 30% and 3 Darcy respectively.
The XYZ formation are continental deposits with thick units of coarse-clastic channel fills including conglomerates with high clay matrix content, rapid (proximal) deposition, and rare lignitic sediments indicating perhaps a more arid rather than humid environment. The unit is confined to South Oman in an approximately 300 km long NE-trending depositional low. This is associated with salt withdrawal along the Eastern Flank of the South Oman Salt Basin.
Samples from the core well indicated dominantly quartzarenitic sandstone. Quartz grains are dominantly moderately sorted with few poorly sorted sections that are mostly bioturbated. Overall digenesis is dominated by generally moderate compaction, infiltration of detrital clay, precipitation of quartz overgrowth. Calcite cements present as typically pore-occluding developments, with common effect on overall porosity. Primary intergranular pores are common; dissolution porosity is noted with dissolution of grains or cement.
Horizontal wells typically yield a higher primary recovery than vertical wells due to their larger contact area with the reservoir. The original expectation for primary production performance of these wells has not been achieved for three reasons: high oil viscosity, formation damage and sand accumulation around the liner during the early production. Following performance during period of primary production, it was considered to utilize vertical wells configuration under thermal stimulation using cyclic steam, with the use of steam as both heating and lifting agent; additional recovery is expected to be achieved.
Cyclic steam stimulation has been implemented in three selected wells spread over the field to give a better understanding of various reservoir characteristics response to stimulation process. The treated wells are vertical wells at 800 TVDSS / 1150 MD with initial reservoir temperature and pressure is 55 °C and 11000 kPa respectively. The total steam injection varies from 2000 to 3600 ton of steam with 85% steam quality in order to acquiring the valuable data and operation experience. Actual results are better than predicted in simulation studies with CSOR (cumulative steam-oil ratio) of about 0.5 to 1.0.
This paper described the started from the completion design, cold production performance, preparation and the execution as well as well evaluation of the practical application of CSS are the main keys to understanding reservoir performance and identifying that opportunities of steam stimulation will improve the ultimate recovery.
Laboratory Support of Heavy-Oil Polymer Flood Project
Authors: Al-Maamari Rashid S. , Al-Hashmi Abdulaziz , Al-Azri Nasser , Al-Riyami Omaira , Al-Mjeni Rifaat , Dupuis Guillaume , Zaitoun Alain 
Published: March 2016

Abstract
A Polymer Flooding pilot trial has being implemented in a heavy oil field, in the South of Oman. A joint team composed of personnel from Sultan Qaboos University, Poweltec and Petroleum Development of Oman provided full laboratory support which included polymer products screening, and core-flooding experimental tests. The reservoir under investigation is a high-permeability sandstone with oil viscosity of around 500 mPa.s, brine salinity of around 5,000 ppm TDS and a subsurface temperature of 50°C. The reservoir characteristics are within the upper boundaries of known polymer flooding applications worldwide. This is further compounded by the presence of a strong bottom aquifer drive which requires the optimization of well placement.
Laboratory work consisted of both bulk and core-flood testing, in which different commercial hydrolyzed polyacrylamides were submitted to rheology, filtration and stability tests, from which one product was qualified. An intensive coreflood program was executed, consisting of rheology, adsorption and displacement experiments. Due to mild reservoir conditions (low salinity and temperature), the main focus was on filtration quality of the products. Following on from the filtration tests, coreflooding programs were implemented with very long sequence of polymer injection at a rate representative of polymer propagation in the reservoir.
Adsorption was found to be quite low (around 20 µg/g) for all the tested products. In-situ rheology was correlatable to the viscosity trends. The program of tests finally qualified a product with molecular weight of around 20 million Dalton. Above this level, long-term filtration becomes questionable with a slow but continuous ramp up of pressure noticeable after about 50 Pore Volumes.
Combined Water/Sand Control Polymer Treatments in Offshore Gas Wells
Authors: Dupuis G. , Bouillot J. , Zaitoun A. , Caremi G. , Burrafato G. 
Published: March 2016

Abstract
An original polymer technology, successfully used in Underground Gas Storage (UGS) wells, has been recently applied in offshore gas producing wells. Many gas wells in this area are facing combined water and sand problems due to reservoir depletion, water entries and clayey formation. To avoid critical problems connected to water/sand production, the most common action has been so far to reduce gas production by choking down the wells.
The new technique consists of bullhead injection of water soluble polymers with the main objective to form an adsorbed polymer layer on the surface of the rock, thus providing stabilization. In addition, the products have RPM properties (Relative Permeability Modifiers). They have little impact on gas permeability while strongly reducing water permeability. The combination of both effects will result in a reduction of water and sand production.
Laboratory studies were performed to optimize polymer formulation and evaluate flow properties in reservoir cores. Because of the low reservoir rock permeability (around 10-20 mD), high focus was put on polymer injectivity and RPM effects.
Since 2013, nine offshore gas wells have been treated with polymers. Treatments have shown positive results combining gas rate increase up to 100% and water reduction around 50% while stopping the sand. Details regarding well and polymer selection, job design, execution and production data are provided.