bluuebunny/crossref_metadata_2025_split huggingface dataset:
High-Resolution Studies of Polymer Flooding in Heterogeneous Layered Reservoirs
Authors: Shotton Mark , Stephen Karl , Giddins Marie Ann 
Published: March 2016

Abstract
The mechanisms of enhanced oil recovery by polymer flooding in stratified systems were investigated using reservoir simulation at a range of model resolutions. The objectives of this work were to understand the effects of grid refinement on the simulated flow behavior and, in light of this, to examine the validity of some seminal coarse-scale reservoir simulation studies reported in the literature.
Simplified one- and two-dimensional models, in which aqueous phase viscosity varied as a function of polymer concentration, were used to simulate the behavior of polymer floods and waterfloods in homogeneous and layered systems. Advanced visualization techniques enabled a detailed analysis of localized crossflow between layers. This provided a clearer understanding of flow behavior than was available in previously reported studies, in which localized flow patterns were inferred from the aggregate system responses obtained from reservoir simulation and laboratory coreflood experiments.
In common with the literature, results indicate that crossflow between layers is of central importance to the polymer flood recovery mechanism in stratified systems where the layers are in vertical communication. In addition to improving the fractional flow properties of the flood, the polymer crossflow enhanced the vertical volumetric sweep efficiency.
A one-dimensional polymer flood model demonstrated the mobilization of formation water, which was initially at irreducible saturation, to produce a water bank with the saturation profile of a shock front ahead of the injected polymer solution. Simulation results were analyzed in the context of Buckley-Leverett displacement theory. The variation in polymer concentration between injector and producer wells produced a fractional flow curve which, at intermediate concentrations, deviated from the characteristic "S-shaped" curve of a waterflood, and instead exhibited a linear profile of progressively increasing viscosity, consistent with the disperse polymer flood front that was observed behind the formation water shock front.
The high-resolution studies revealed additional features of the recovery that were not observed at the coarse scale, including a secondary oil bank, formed by oil crossflow ahead of the polymer slug, and fingering of chase water into the rear of the slug. The variation of grid resolution was observed to produce substantial changes in the distribution of incremental oil production between layers, but to have a more limited impact on cumulative production. In contrast to previous findings, the crossflow behavior of the polymer flood model was found to be highly sensitive to vertical, as well as horizontal, grid refinement. This demonstrates the importance of grid resolution to predictions of oil in place and to the forecast distribution of production between intervals in the well.
Application of Nanoparticles to Improve the Performance of Microwave Assisted Gravity Drainage (MWAGD) as a Thermal Oil Recovery Method
Authors: Al-Farsi Hajir , Pourafshary Peyman , Al-Maamari Rashid S. 
Published: March 2016

Abstract
There are many heavy oil reservoirs around the world, representing about 70% of the total oil resources. Primary heavy oil recovery is low, so enhanced oil recovery (EOR) methods are needed. Reducing the oil viscosity is a main mechanism of the recovery process, so thermal EOR methods are used. Conventional and unconventional thermal EOR methods face many challenges in recovering heavy oil, some of which can be overcome by nanotechnology.
In this study, nanoparticles were used to enhance the heavy oil recovery by the Microwave Assisted Gravity Drainage (MWAGD) Process. Two types of metal oxide nanoparticles were used: gamma alumina (γ-Al2O3) and titanium (IV) oxide (TiO2), at four different concentrations. Besides studying the effect of nanoparticles on the recovery, the effect of water saturation on the oil recovery and the influence of nanoparticles on the emulsion viscosity and the thermal conductivity of distilled water were also investigated. The tests were done by using a heavy oil sample of 19 API and glass beads as a porous medium with an average porosity of 22%.
The results showed that, in general, as the water saturation increases, the oil recovery from the MWAGD process rises, with optimum recovery occurring at a water saturation of 30%. In addition, the tests showed that recovery using microwave heating is higher than that with conventional heating. Also, each type of nanoparticle (γ-Al2O3 and TiO2) has its own trend in affecting either the emulsion viscosity or the water thermal conductivity due to variations in the physical properties of each nanoparticle such as shape and size. Al2O3 and TiO2 nanoparticles have the greatest effect on the oil recovery at low concentrations of 0.1 and 0.05 wt.%, respectively, during the MWAGD process.
The tests showed that nanotechnology can be used to improve the performance and to overcome challenges facing thermal EOR methods, especially the unconventional methods.
Oil Recovery Enhancement in Carbonate Reservoirs Via Low Saline Water Flooding in Presence of Low Concentration Active Ions; A Case Study
Authors: Mohsenzadeh A. , Pourafshary P. , Al-Wahaibi Y. 
Published: March 2016

Abstract
Different research reported that the main mechanism for low salinity water flooding in carbonate reservoir is multi ion exchange (MIE) which occurs when the concentration of active ions such as sulfate and calcium is high and the temperature of the reservoir is in the range of 90-110°C. In many cases, due to the reservoir condition and availability of the injection brine, meeting criteria for an effective ion exchange mechanism is not possible. In this study, the feasibility of LSW flooding for oil recovery enhancement from carbonated reservoir at low concentration of active ions was investigated.
Rock and fluid samples from an Omani oilfield were used for the experiments. Different experiments were conducted to study the rock/brine/oil interactions during the LSW process and the recovery improvement. Core flooding experiments were conducted to study the impact of different dilutions on the tertiary recovery. To investigate the effect of salinity changes on fluid-fluid interactions, IFT measurements between crude oil and different brine salinities were carried out at reservoir temperature. Also, effects of LSW (different dilutions) on the wettability alteration were examined by performing contact angle measurement tests as well as spontaneous imbibition tests.
The oil recovery results by core flooding experiments showed a noticeable improvement by switching to the diluted brines. Results of wettability study showed that, due to the lack of sufficient active ions and relatively low reservoir temperature, wettability alteration towards more water wet condition did not occur in this case. But, Interfacial tension measurements showed that brine dilutions reduced oil/brine IFT appreciably. Therefore, in this special case, observations proved that the IFT reduction is the main mechanism contributing oil recovery enhancement. Hence, low salinity water in carbonate reservoirs is recommended for similar cases even when the criteria of MIE mechanism are not met.
Case Study on a New Approach for Exploiting Heavy Oil Reservoirs with Shale Barriers
Authors: Yongrong Gao , Erpeng Guo , Jian Luo , Youwei Jiang , Hongyuan Wang , Yao Wei 
Published: March 2016

Abstract
Existence of shale barriers in heavy oil reservoirs is detrimental to the implementation of the EOR (Enhanced Oil Recovery) process with gravity drainage mechanism. Unfortunately, there is abundance of such reservoirs with shale barriers due to sedimentary conditions and reservoir heterogeneities. SAGD (Steam Assisted Gravity Drainage) pilot tests have been carried out in these reservoirs in China where the extensive distribution of shale barriers results in poor performance.
Taking the advantage of vertical wells in exploitation of thin reservoirs and reservoir with shale barriers, a new development approach combining gravity drainage and flooding process in heavy oil reservoirs with shale barriers was proposed. Laboratory experiment was carried out to verify its effectivity. Then the results of field application in two well groups were compared and discussed.
The results show that high recovery efficiency can be achieved in heavy oil reservoirs with shale barriers when combining the effect of vertical injectors and horizontal producers with the proposed approach. Laboratory results showed that when the shale barrier is not continuous, this approach is possible to combine flooding process and drainage process together. The recovery factor of the whole process with shale barriers can be higher than 50.5% (16% higher comparing to old approaches) with an average SOR of 3.5 in lab experiments. And with the 2 year field operation history data, the steam swept volume increased rapidly after application of this approach. The production rate was enhanced by 30%, and the SOR decreased by 28%.
The results of this paper are of great significance in that it has shown that heavy oil reservoirs with shale barriers can also be effectively exploited with the proposed approach in this paper. Also this approach can be used as complementary method for EOR in dual-horizontal well SAGD process.
Application of Fiber Optics in EOR Trials
Authors: Irvine-Fortescue Jamie , Battashi Fathiya , Rubalcava Daniel 
Published: March 2016

Abstract
In this paper, recent EOR field trials are discussed to demonstrate the value of in-well fiber optic (FO) applications. The trials are in a field in Oman that has been considered for an enhanced oil recovery (EOR) development. Polymer Flood and Steam Injection have been proposed as alternative EOR methods and both are being studied. A recent polymer injectivity test and steam trial were conducted in order to de-risk uncertainties in a full field development and this paper presents the application of FO in these EOR trials to help meet these objectives.
The fiber optic approach is viewed as an alternative technology to production logging and it provides the option of real time acquisition. In one area of the field, a shut-in well was converted to a polymer injection well and utilized for a single well injection test (SWIT). The test was carried out for six months to quantify the inflow profiles and injectivity to the reservoir under matrix conditions. For the steam trial in another area of the field, three producers and one injector with FO were utilized to demonstrate the feasibility of a horizontal well steam development and to evaluate the requirement and effectiveness of injection conformance.
FO analysis from both trials concluded that the Distributed Temperature Sensing (DTS) and Distributed Acoustic Sensing (DAS) combination can be successfully used for injection conformance profiling. DTS/DAS measurements were taken during the course of the polymer injection test. These indicated that conformance was incomplete from the onset and deteriorated during the course of the test, with a large proportion of fluids in-fluxing into the reservoir through a narrow section at the toe of the well. One of the main objectives from the steam trial was to measure and manage conformance along the horizontal steam injector. Use of FO helped demonstrate the importance of managing conformance in order to achieve satisfactory sweep efficiency.
This paper explains how these new technologies play a key role in reducing the uncertainties in reservoir performance in EOR developments. The combination of FO (DTS and DAS) data sets allowed the interpretation of data gathered to complement each other and provide more comprehensive conclusions.
Challenges and Learnings from Developing High Pressure Sour Reservoirs in Southern Oman by EOR MGI
Authors: Al-Hadhrami Abdullah , Schulz Ralf , Alawi Hamoud , D'Amours Mubarak Maskari , Barwani Shihab , Jabri Abdullah , Proot Michael 
Published: March 2016

Abstract
The commissioning of new Production Station (Station-H) in April 2012 marks the completion of the Phase 2AB project in the southern area of the Sultanate of Oman. The asset's liquid production has increased by 3 fold and contributes to more than 15% of Oman's production. This project is the world's largest Enhanced Oil Recovery (EOR) with Sour Miscible Gas Injection (MGI) integrating oil and gas field developments. Sour gas is processed through a state-of-the-art processing facility for sweetening and re-injecting gas under MGI to increase oil recovery up to 50%, (i.e. 6x increase over primary RF).
The timeline from discovery of the field-Z in 2002 to commissioning of Station-H in 2012 is top quartile for mega-EOR projects of this type, considering the challenges: deep, high pressure, and sour fluid. Despite the delayed start-up, the first on-stream milestone is considered a commendable achievement. Building a facility to handle the extreme mixture of high pressure, sour corrosive fluids and gas is a technical step-out for PDO.
One of the key challenges was maintaining the station's production despite 2 of the 3 production separators were deemed unsuitable due to compromised internal coating exposing the base material which was not NACE compliant. Therefore, there was no assurance against Sulphur Stress Corrosion Cracking (SSCC) in the event of any contact with sour fluids resulting in 40% capacity loss. A major shut-down of 4 months was recommended to complete several engineering activities (this could be shortened to 62 days by optimisation). Separator replacement was achieved safely resulting in reliable operation at design capacity after restart. The Turnaround was executed without any HSE incidents achieving GOAL ZERO, in total adherence to PDO HSSE standards.
As part of a phased development prior to the 2AB project, several fields were produced beginning in 2004 through Early Development Facilities (EDF) to a nearby Gathering station, capturing of critical information while producing significant early oil. This resulted in sufficient revenues to fund for 2AB and more developments in the area. Within less than 3 years since commission of Station-H, the 2AB project has already achieved return on the investment. The EOR project life will continue to deliver value to Oman for the next 30+ years.
The new station provides the infrastructure for long term development of the area and a number of follow-on projects, which will make use of these facilities: e.g. the already commissioned Phase 3 project in 2013 and Phase 4 development currently in execution and expected to be on-stream by 2019. This work will outline some of the key challenges on the phase 2AB project and how lessons learned were taken onboard to facilitate project delivery of the extended larger EOR/MGI development for follow-up phases and in similarly challenging projects in PDO.
Assessing Oil Saturation from Single Well Chemical Tracer Tests by Assisted History Matching
Authors: Huseby Olaf , Zarruk Gustavo A. , Callegaro Chiara , Bartosek Martin 
Published: March 2016

Abstract
Single-well chemical tracer test (SWCTT) is a unique method that can be used to measure in-situ remaining oil saturation in the proximity of a well. The method has been used extensively to quantify remaining reserves in oil fields worldwide. It is also frequently used to measure the effect of different EOR techniques. Using a SWCTT-EOR-SWCTT sequence, saturation is established by an initial SWCTT, followed by an EOR-technique, and saturation is determined with the final SWCTT. The potential in-situ gain in oil production provided by the EOR can then be assessed by comparing pre- and post-EOR saturations.
In ideal cases, a SWCTT provides tracer curves that can be interpreted by means of simplified numerical or analytical models. In many cases, a variation in reservoir properties, pressure differences or reservoir drift complicates the tracer transport enough that a proper reservoir simulation model must be set up and solved to interpret the results of a SWCTT. Such models are usually complex enough that assisted history matching is required to optimize the parameters required to describe the physics of the problem.
In this paper we describe how state-of-the-art parameter estimation can be used to optimize a SWCTT simulation and demonstrate the work-flow using SWCTT data from a recent EOR test in West Africa. The work-flow is generic and can easily be adapted to any reservoir and tracer simulation tools that handle the reactive tracer transport required for SWCTT-modelling. We demonstrate that assisted parameter estimation is an effective tool to improve the interpretation of SWCTT results and provides significantly better and accurate remaining oil saturation from single well chemical tracer tests.
Impact of Live Crude Oil Composition On Optimal Salinity of A Surfactant Formulation
Authors: Marliere Claire , Creton Benoit , Oukhemanou Fanny , Wartenberg Nicolas , Courtaud Tiphaine , Féjean Christophe , Betoulle Stéphane , Defiolle Denis , Mougin Pascal 
Published: March 2016

Abstract
The objective of surfactant formulation design is to achieve ultra-low interfacial tension (IFT) with the oil in place in reservoir conditions. Several parameters have to be investigated, the presence of dissolved gas in crude oil can greatly impact the surfactant/brine/crude oil microemulsion phase behavior and omitting it may degrade the formulation efficiency. We propose an experimental investigation of optimal salinity evolution as a function of live oil compositions and conditions varying the pressure independently to the gas to oil ratio (GOR), i.e. the amount of gas dissolved in crude oil.
A specific High Pressure - High Temperature (HPHT) sapphire cell with a mobile piston is used to separately study the impact on the formulation optimal salinity of: (i) the GOR by adding different amounts of C1 to C5 n-alkanes at the corresponding saturation pressure; and (ii) the pressure cell – up to 500 bar – by varying the cell volume (without changing the live crude oil composition). Experiments were performed at 40°C and at the saturation pressure or above.
Using the HPHT sapphire cell we show that GOR variations up to 135 Sm3/m3 induce important modifications of the {surfactant/brine/oil} microemulsion phase behavior. In the case of the studied fluid, experimental data indicate that the optimal salinity of the {brine/surfactant/oil system} decreases when increasing the amount of gas dissolved in the live crude oil. As a consequence, the equivalent alkane carbon number (EACN) of the live crude oil strongly depends on the gas to oil ratio. We demonstrate hereafter that the cell pressure– for a fixed composition (i.e. fixed GOR) –impacts neither the formation nor the stability of the microemulsion. Furthermore, preliminary results suggest that the composition of the dissolved gas has a slight effect on the microemulsion phase behavior.
In this work, using a specific HPHT sapphire cell, we are able to dissociate the impact of the amount of added gas from the impact of the cell pressure and to consider pressures up to 500 bar. Whereas the pressure alone has a negligible influence on the surfactant/brine/oil microemulsion phase behavior, the dissolution of gases in crude oil leads to a decrease of the optimal salinity and a variation of live crude oil EACN.
The Application of Cyclic Steam Stimulation in Heavy Oil Reservoir with a High Water Cut
Authors: Abdullah Al Shibli , Suleiman Al Hinai , Abdesslam Belghache , Sumaiya Al Habsi 
Published: March 2016

Abstract
"A" West field is a heavy oil field (17–25 deg API), discovered in 1972 in the South of Oman, with a 200 m thick oil column in Haradh formation. The field development started in 1984 by cold production with vertical and horizontal wells. In 2007, the steam drive concept through 10 acre inverted 7-spot patterns was selected for the full field development. Being part of the concept, two Cyclic Steam Stimulation "CSS" campaigns were executed between 2011 and 2014 to stimulate both the wells and the reservoir using a mobile steaming unit. Throughout the two campaigns, a number of optimizations have been implemented including: the deployment of Vacuum Insulated Tubing "VIT", the extension of the perforated intervals, the adjustment of the injection and production cycle durations and resources management.
The deployment of the 1000 m VIT during the steam injection phase confirmed the predicted oil gain, resulting from a reduction in wellbore heat losses. Along with CSS, a re-perforation campaign has been conducted on wells with low productivity index "PI" to maximize their gross offtake. After steam stimulating the re-perforated wells, it has been observed that higher oil to steam ratio "OSR" is obtained for thicker oil column exposed to steam. In addition, for highly depleted zones in the reservoir, it has been found that producing at the maximum possible rate and right after the end of the soaking period, leads to a better OSR. CSS proved also to have improved the steam conformance within the targeted pattern.
Based on the promising results from the CSS jobs a decision was made to build a permanent CSS capability in all future wells in "A" West. This will also enable a proper management of the lateral steam conformance.
Results & Interpretation of a High Viscous Polymer Injection Test in a South Oman Heavy Oil Field
Authors: Rubalcava D. , Al-Azri N. 
Published: March 2016

Abstract
This paper discusses the design and results of a polymer test in a field containing heavy oil. The field is located in the south of Oman and contains significant in place volumes of viscous oil (700cp) in sub Darcy reservoir. Due to unfavorable oil-water mobility ratio, the ongoing water injection will still leave significant volumes of stranded oil post water injection.
A "Paradigm Shift" from energy intensive thermal processes, high viscous polymer flood is currently being evaluated to target and recover stranded high viscosity oil. If successful not only would the oil recovery from the field be significantly increased but a reproducible process would be available to target other high viscosity oil reservoirs in Oman.
A single well injection test was conducted in 2014 representing the first foray into high viscous polymer flooding for the field. The driver for conducting the test was to de-risk polymer injection as a pre-courser to a full field expansion. To that end the following KPI's were identified. Matrix injection – can economical rates at design pressures be achievedLow salinity – clay swelling and subsequent loss of injectivityAlternate higher molecular weight polymer's – can injectivity be maintained or is polymer pluggingConformance – Applicability to full field / is conformance control requiredFracture pressure – Defining injection envelope for full filed expansion
The test comprised of a converted horizontal producer that was retrofitted with Disturbed Temperature and Acoustics (DTS & DAS) fiber optics. Modular polymer facilities capable of injecting high viscous polymer slugs at high rates were utilized; additionally a modular low salinity process was also used to drop the injected water and polymer salinity to 500ppm TDS.
The following have been identified as key learning's from the test: A lack of conformance was identified through DTS and DAS evaluation during initial water injection, prior to the injection of any polymerA loss of injectivity was also observed over a period of the test. This affected subsequent polymer and water injection periods.The behavior of in-situ polymer highlighted possible unexpected phenomena, particularly the effect on water injection post polymer injection.Low salinity, 500ppm TDS, water was injected with and without polymer with no adverse affect on injectivity.Additionally, the higher molecular weight polymer also was successfully injected.