bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Laboratory Study of Ionic Effect of Smart Water for Enhancing Oil Recovery in Carbonate Reservoirs
Authors: Awolayo Adedapo , Sarma Hemanta , AlSumaiti Ali M 
Published: June 2014

Abstract
Enhanced oil recovery by smart waterflooding represents an implementable and attractive emerging oil recovery technology. For sandstone reservoirs, smart waterflooding has shown an outright incremental oil recovery in most laboratory and field tests while some promising experimental data have been presented from carbonates. It seems more difficult to assume a favorable performance for some reservoir formation a priori while dismissing the other, so more data and better understanding of the underlying mechanism in carbonates are needed.
This paper describes a series of experiments on Middle East carbonate core plugs designed to determine the impact of formation water and different versions of seawater (which has its sulfate concentration increased in the ratio (0.5:1:2:4:8) on oil recovery, wettability and surface charge modification. The results obtained lead to the following conclusions:
Coreflooding experiments at 2300F and 3000psi with formation brine and various versions of seawater coupled with spiking sulfate concentration executed on carbonate core aged showed an incremental recovery of about 10% OOIC; An increasing concentration of sulfate in the seawater makes a Crude Oil/Brine/Rock system less oil-wet; The higher the sulfate concentration, the greater the repulsive forces in the electrical double layer, thereby forming an aggregate and detaching the oil from the rock surface, while increasing the sulfate concentration beyond four times seems ineffective as it gave a swift increase in pH and rock surface charges;
The results obtained are therefore discussed within the framework of mechanisms previously described for smart water's ability to enhance oil recovery. The study concluded that a relatively economical modification of injection brine composition could considerably increase oil recovery.
Predicting Interfacial Tension Of Multiphase Systems Based On Computational Single-Molecule Quantum Mechanics And Thermodynamics Applying Four Different Physical Models And COSMO-Theory
Authors: Bennetzen Martin V. , Andersson Martin , Mogensen Kristian 
Published: June 2014

Abstract
Reduction of interfacial tension is of key importance for mobilising residual oil trapped by capillary forces during a secondary waterflood. The Conductor-like Screening Model (COSMO) and its extension COSMO-RS, developed over the last decades, enables prediction of thermodynamic properties of mixtures. Molecular charge distributions and associated charge distribution properties, so-called sigma moments, can be calculated and used as input parameters for various physical models to predict IFT of fluid mixtures.
In this paper we present and compare four different and complementary approaches to predict IFT based on single-molecule properties derived from COSMO-RS theory. The first method is based on predicted liquid-liquid extraction (LLE) phase-specific mole fractions using a formalism suggested by Apostoluk and Szymanowski (1996). The second method relies on a Taylor-like approximation of chemical potentials of mixtures using a realisation of Method of Moments (MoM) as described by Klamt and co-workers. The third method, recently described by Andersson et al., relies on LLE calculations as well as free energies for molecules present at the interfaces in multiphase immiscible systems. The fourth method, the so-called GSM-model recently described by the authors of this paper, relies on non-linear statistical relations between COSMO-derived energy descriptors and IFT.
By conducting a comprehensive comparative analysis we show that each of the four models estimates IFT with significant accuracy, that these models are complementary and that the models should be chosen based on the specific system of interest as well as the present available system information. Moreover, we demonstrate that COSMO-RS theory, when used in combination with physical models, provides a powerful tool for EOR research enabling fast, accurate computational prediction of IFT of multiphase fluid mixtures. Hence the models presented here may be used for systematic laboratory testing of e.g. surfactants and co-solvents for EOR processes as well as for predicting properties of multiphase fluid systems.
Potential of Alkaline Surfactant Polymer (ASP) Flooding in a Medium-Light Oil Reservoir with Strong Bottom Aquifer
Authors: Al-Sulaimani Hanaa , Stoll Martin , Wunnik John Van , Faber Rien , Arkesteijn Fred 
Published: June 2014

Abstract
A central Oman oil field was evaluated for the potential of an ASP flooding development. The field is a sandstone reservoir containing medium to light oil of 33° API with a viscosity of 9cP.
Till today, the field is under natural depletion with, lately, pressure supported by water injection into the aquifer at the NW and SW flanks. The recovery factor is already high and currently the field water cut is at 97%.
Recently, an EOR screening study was conducted on PDO's fields and the subject field was found to be one of the potential candidates for ASP flooding. Several lab experiments were conducted on reservoir rock and fluid samples to assess the potential of an ASP application. The ASP formulation was tested on two wells in this field through the Single Well Chemical Tracer (SWCT) test technique where the residual oil reduced from 20% to 4% for one well and from 15% to 8% for the other.
Different development scenarios were evaluated: a scenario that makes use of the strong bottom aquifer in combination with horizontal injectors near the OWC was found to be a technically viable development option. The liquid rate forecasts were subsequently used in the project economics showing that the company's screening criteria were met.
The full field development versus phased development approaches were also evaluated where the latter was found to be favorable as it allows for early starting and proper de-risking for following phases. The subsurface feasibility study for this reservoir revealed that there is an opportunity of increasing the Recovery Factor of this field by more than 10%.
This paper will describe in detail the study and the overall de-risking strategy with its various phases namely; lab experiments, single well tests, full field evaluation and showing of commercial attractiveness and finally the optimized implementation through phasing.
Shifting to a New EOR Area for Sandstone Reservoirs with High Recovery, No Damage, and Low Cost
Authors: Attia M. , Mahmoud M. A. , Al-Hashim H. S. , Sultan A. S. 
Published: June 2014

Abstract
Experimental investigations and field applications showed an increase in oil recovery by using low salinity water injection. The mechanisms leading to the increase in oil recovery by low salinity water injection are debatable. Furthermore, low salinity water injection requires relatively fresh water to dilute sea water which is not available in many areas around the world especially the Arabian Gulf region. Using low salinity water as an enhanced oil recovery process is a costly process because it requires a lot of fresh water to dilute the sea water.
In this study we introduce an economic and new chemical enhanced oil recovery fluid capable of recovering additional oil from sandstone reservoirs after the primary water flooding stage. The new chemical enhanced oil recovery fluid utilizes high pH chelating agents at low concentrations prepared in sea water without any dilution. Coreflood experiments were performed using Berea sandstone cores at 100°C to test the effectiveness of this new EOR fluid system.
The results of the coreflooding experiments showed that the new fluid system is able to recover additional oil up to 30% from the initial oil in place after sea water flooding. Zeta potential measurements were performed using the new fluid system and crushed Berea cores to identify the mechanism leading to this additional oil recovery. The results of the zeta potential revealed more negative values for the new system more than the sea water and low salinity water, confirming that the rock wettability is altered to a more water-wet condition. This changed in rock wettability could be due to rock dissolution and the chelation of the different ions such as calcium, magnesium and iron ions. The new fluid system very attractive as its cost is low compared to the cost of diluting the sea water in the case of low salinity water flooding.
Microbial Enhanced Oil Recovery at High Salinities using Biosurfactant at lower concentrations
Authors: Souayeh M. , Al-Wahaibi Y. , Al-Bahry S. , Elshafie A. , Al-Bemani A. , Joshi S. , Al-Hashmi A. , Al-Mandhari M. 
Published: June 2014

Abstract
This study investigates the ability of lipopeptide biosurfactant produced from Bacillus subtillis W19 isolated from oil contaminated Omani oil field soil samples to recover the residual oil at reduced concentration. The biosurfactant reduced the interfacial tension to 1.8 mN/m and also altered the wettability to more neutral wettability. The biosurfactant is stable over wide range of pH and temperatures. The minimum biosurfactant concentration required to make the process economically feasible was determined by performing core-flood experiments at various critical micelle dilutions using 200-300 mD Berea sandstone cores with porosity of 22%. The fluids used in the work are 32° API crude oil, and brine with 7-9% salinity collected from the field of interest. All core-flood experiments were conducted at the reservoir temperature, 60°C. It was found that even after 20 times dilution biosurfactant can maintain an extra recovery of 14% of residual oil after water flooding. These results revealed that the biosurfactant is still effective even at concentration as low as the CMC value (0.1 g/L). Furthermore, the performance of 20 times diluted biosurfactant was improved by mixing it with commercial chemical surfactant to the ratios of 50% biosurfactant: 50% chemical surfactant and 25% biosurfactant: 75% chemical surfactant, and, resulted in extra recovery of 28% and 27% of residual oil after water flooding respectively. Salinity studies show that this biosurfactant has high turbidity point, and maintained a relatively low interfacial tension values over wide range of salinities. When the salinity was increased to 20%, the biosurfactant was still successful in reducing the water flooding residual oil saturation by 12% even when diluted by 10 times. Economical evaluation showed that using this biosurfactant at low concentration would produce appreciable amount of trapped oil with minimum cost.
Horizontal Well Stimulation : A Pilot Test in Southern Oman
Authors: Mirza M. , Aditama P. , Al Raqmi M. , Anwar Z. 
Published: June 2014

Abstract
This paper presents the thermal stimulation project for two horizontal wells, 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.
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 decided that these wells should be stimulated using cyclic steam, with the use of steam as both heating and lifting agent; additional recovery is expected to be achieved. The well completion designs utilized thermal compliance equipment with cost effective considered and to focus the efforts on the new stimulation processes with the use of thermal completions.
Based on the screening result and taking into account the reservoir characteristic and preliminary calculation of oil recovery and requirement, thermal method is considered as the appropriate EOR method for B field. The viability of thermal recovery in B field was tested with Cyclic Steam Stimulation (CSS) in K sand.
The wells selected for the pilot are B1 and B2, both are horizontal well and thermal compliance well. They are around 400 m of horizontal length. A portable steam generator was utilized to produce steam with steam quality of 87 %
The total cumulative steam injected in well B1 was 5000 tons and estimated energy injected at reservoir was 2.9 BBtu. The effective day of soaking period was 10 days which included hoist and hook-up activity. The initial oil gain was 124% gain and it is as per reservoir model prediction. The temporary steam-to-oil-ratio (SOR) as of 2013 is 4.2 ton/m3.
On the other hand, the plan for CSS in B2 was cancelled due to well problem. The plan for steam injection was shifted to 2014.
Making Field-Scale Chemical EOR Simulations a Practical Reality using Dynamic Gridding
Authors: Hoteit Hussein , Chawathé Adwait 
Published: June 2014

Abstract
Many IOR/EOR recovery processes such as chemical, miscible and steam flooding are often associated with complex flow mechanisms that manifest at the displacement front. Viscous fingering, polymer/surfactant dilution and mixing effects are some of these mechanisms. Accurate modeling of these phenomena requires simulations on high resolution grids to properly capture the physics in the vicinity of the displacement front. Unfortunately high grid resolutions incur longer simulation times. Thus, past efforts at running full-field gas or Chemical EOR simulations were frequently deemed impractical.
The advancement in computational power from software, hardware and parallelism has indeed pushed the limits towards higher resolution simulations. However, this may not be practical in workflows that require simulations on many models to manage uncertainties. Dynamic gridding is one approach that attempts to adjust the grid resolution as needed during the run time. No a priori knowledge is assumed regarding the fluid flow pathways. The simulator can track the location of the displacement front, refine the neighborhood cells, and later coarsen them back as the front progresses. The advantage is reducing the number of grid-blocks, and therefore the computational time, compared to the fully refined grid, while preserving the fluid-flow physics. Although this technology is not new in reservoir simulation, there are persisting challenges in the existing methods related to the computational overhead associated with cell re-mapping, transmissibility re-calculation, and grid up-scaling and down-scaling.
A new dynamic gridding functionality has successfully been implemented into our in-house simulator. The key achievements are: 1) eliminate grid re-mapping and transmissibility re-calculation at the run time, 2) capture heterogeneity associated with all levels of grid refinements, 3) model complex geology with non-uniform gridding, and 4) track multiple fronts associated with surfactant/polymer and chase water slugs. We discuss how we overcame the bottlenecks to leverage this technology from prototypes to complex cases. We also demonstrate our method on prototypes and pilot cases under CEOR recovery processes.
Experimental Evaluation of Simultaneous Water and Gas Injection Using Carbon Dioxide
Authors: Shetty Shrinidhi , Hughes R. G. , Afonja Gbolahan 
Published: June 2014

Abstract
Miscible CO2 injection is one of the most common enhanced oil recovery processes employed worldwide to recover the residual oil left behind after waterflooding. Although continuous miscible CO2 injection (CGI) floods have excellent microscopic displacement efficiency, they often suffer from poor macroscopic sweep efficiency due to mobility effects. In order to mitigate these sweep issues, processes like Water Alternate Gas (WAG) and Simultaneous Water and Gas (SWAG) injection were developed. WAG is the most common mobility control technique employed in the industry and is well understood. However the SWAG process has had fewer studies and is not well understood. There has been very little published either evaluating the performance of SWAG under miscible conditions or comparing the performance of these EOR processes under consistent experimental conditions. This paper presents the results of corefloods used for evaluating the performance of CGI, WAG and SWAG processes using CO2 under conditions that are as consistent as possible to make meaningful comparisons. A series of experiments were carried out to evaluate tertiary coreflood performance: CGI, a 1:1 WAG with slug size of 0.25 pore volumes and the SWAG process at four values for the fractional flow of gas (fg). The SWAG process with an optimal gas fractional flow recovered the most residual oil. CGI had the second best recovery followed by WAG. SWAG floods with suboptimal fg values recovered slightly lower amounts of residual oil. Gas utilization was the least for the SWAG process with optimal fg values followed by CGI.
Recovery Factor Estimation in EOR Polymerflood Project: Field Case
Authors: Al-Saadi F. S. , Al-Subhi H. A. , Al-Siyabi H. 
Published: June 2014

Abstract
A chemical Enhanced Oil Recovery process by means of polymerflooding has been implemented successfully in a large sandstone field in the south of Oman since 2010. To date, very good response was observed from the polymer flood due to improved sweep efficiency. A common measure of success for such a chemical EOR process is the incremental oil Recovery Factor over the existing mature waterflood.
One of the challenges in this EOR project is the estimation of the incremental oil reserves attributed to polymer flooding. The difficulty is due to the lack of analogue fields where polymer flooding is implemented. Furthermore, polymer flooding has been implemented over a mature waterflood making it difficult to allocate the remaining oil reserves.
This paper is presenting the oil reserves estimation methodology for the chemical EOR project. The definitions for estimation, classification and reporting of petroleum resources are based on the society of Petroleum Engineers (SPE) Petroleum Resources Management System (SPE-PRMS). This methodology is based on calculation of patterns STOIIP and range of recovery factors extrapolated from different sources (simulations, pilots, corefloods, analytical analysis). Furthermore, the oil reserves estimation was supported by full field 3D dynamic models where the initial period of polymerflood has been used for calibration. It was concluded that the polymerflood can give incremental recovery factor of about 10% on top of the waterflood recovery.
Advanced, High Temperature, Multi-Parameter Coiled Tubing Surveys for Live Thermal Recovery and EOR Well Surveillance
Authors: Padberg M. , Sanders P. , MacDougall T. , Eyre M. , Kamalipour M. , Sayce P. 
Published: June 2014

Abstract
Successful steam operations in thermal recovery are a function of reservoir quality, steam distribution in injection wells, temperature distribution in production wells, and hydrocarbon mobility, so it is important to include reservoir monitoring to provide critical information of the subsurface for effective operations. Real-time well data profiles benefit project economics, safety, and viability by monitoring downhole temperature, pressure, and acoustic data. As such, an advanced coiled tubing based survey string designed for thermal, as well as EOR, well surveillance has been recently introduced in Oman. The survey string incorporates 315°C rated instrumentation by integrating fiber optics, point pressure and temperature sensors, and e-line within coiled tubing to allow data acquisition under live well conditions. Data profiles are graphically presented through a graphic user interface where locations of steam injection, pressures, and fluid ingress points can be interpreted. This representation can assist in production optimization, determining existence and locations of mechanical failures due to steam break through and subsequent liner wash-out to the slotted liners, and immediate identification of downhole heat sinks and reservoir heterogeneities affecting steam chamber development. Advances in integrating real time, full wellbore fiber optic data allows new insight especially when applied in horizontal wells under live operating conditions. This data demonstrates a significant advancement in thermal well surveillance. Novel high temperature well control technology and completions design enable live well surveys in dynamic thermal production and steam injection wells. This paper will review key aspects of the tool qualification for live thermal well surveys. Example data shows the ability to locate and track the flow of fluids and characterize the reservoir response to well operations.
Alkaline-Free Surfactant Polymer Process for Heavy Oil
Authors: Hocine S. , Magnan A. , Degre G. , Rousseau N. , Rousseau D. 
Published: June 2014

Abstract
Chemical EOR methods have become an increasingly attractive option for heavy oil reservoirs where thermal methods (such as SAGD) cannot be applied, like in thin reservoirs. Polymer flooding in heavy oil recently proved to be a viable recovery method. The use of surfactants for heavy oil is reported only in a limited number of cases and mostly in combination with alkali to benefit from the generation of in-situ surfactants. However, operational issues (such as scale or corrosion) associated to the use of alkali as well as negative impacts on project logistics are often reported. Objective of this work is to demonstrate at lab scale the efficiency of alkali-free surfactant/polymer process in the context of heavy oil reservoirs.
The present investigation was focused on a Canadian heavy-oil (14°API and 1400 cP) in representative reservoir conditions (high permeability sandstone, temperature of 35°C, low salinity). A dedicated synthetic surfactant formulation was designed using a screening methodology based on a robotic platform. Ultra-low interfacial tensions were evidenced from phase behavior and confirmed by spinning-drop tensiometry. Oil recovery performances of the surfactant formulation were then evaluated in corefloods.
Cores at Swi were first polymer flooded until no oil is produced to reach a pseudo-residual oil saturation. A surfactant-polymer formulation was then injected after the polymer flood. Results show that additional oil was produced as a continuous oil bank, corresponding to 90% ROIP. This indicates that the surfactant was able to mobilize most of the residual oil. The results of this exploratory investigation show that alkaline-free surfactant-polymer processes could be applied to heavy oil reservoirs while minimizing operational issues. Complementary work are also be presented on optimization of the process including injection strategy improvement and surfactant dosage reduction.