bluuebunny/crossref_metadata_2025 huggingface dataset:
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

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

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

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

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

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

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

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.
Degradation (or Lack Thereof) and Drag Reduction of HPAM During Transport in Pipelines
Authors: Stéphane Jouenne , Jérôme Anfray , Philippe R. Cordelier , Khalid Mateen , David Levitt , Inès Souilem , Philippe Marchal , Lionel Choplin , Jonathon Nesvik , Waldman Tom E.
Published: June 2014

Rules of thumb that are used in the industry for polymer flooding projects, tend to limit the distance over which HPAM polymers can be transported in pipelines without undergoing significant degradation. However, in sensitive environments such as offshore facilities where footprint minimization is required, centralization of the polymer hydration process and longdistance transport may be desirable. More reliable rules are required to design the pipe network and to estimate mechanical degradation of polymers during transport in turbulent conditions.

In this work, we present evidence in the form of both empirical, large-scale pipeline experiments as well as theoretical development refuting the claim that polymer pipeline transport is limited by mechanical degradation. Our work concludes that mechanical degradation occurs at a critical velocity which increases as a function of pipe diameter. Provided the critical velocity is not reached in a given pipe, there is no limit to the distance over which polymer solution can be transported.

In addition, the drag reduction of viscous polymer solutions was measured as a function of pipe length, pipe diameter, fluid velocity and polymer concentration. An envelope was defined to fix the minimum and maximum drag reductions expected for a given velocity on larger pipes. For pipes with diameter varying between 14″ and 22″ at a velocity higher than 1 m/s, the drag reduction percentage is anticipated to be between 45 and 80%. A more refined model was developed to predict drag reduction with less uncertainty.

In conclusion, classical design rules applied for water transport (fluid velocity <3m/s) can be applied to the design of a polymer network. Therefor, for tertiary polymer projects, the existing water injection network should be compatible with the mechanical requirements of polymer transportation.
Colloidal Dispersion Gels (CDG): Field Projects Review
Authors: Manrique E. , Reyes S. , Romero J. , Aye N. , Kiani M. , North W. , Thomas C. , Kazempour M. , Izadi M. , Roostapour A. , Muniz G. , Cabrera F. , Lantz M. , Norman C.
Published: June 2014

Colloidal Dispersion Gels (CDG's) have been successfully tested in Argentina, China, USA, and recently in Colombia. However, questions remain whether CDG's can be injected in large volumes and propagate deep into the formation without reducing injectivity and also improve sweep efficiency.

This paper summarizes 31 implemented and ongoing CDG projects in Argentina, Colombia and the U.S. since 2005. Project summary review includes main reservoir properties, operating conditions, pore volume of chemical injected, general project performance, and especially, a detailed analysis of injection logs addressing the injectivity of CDG. Additionally, a general approach for history matching CDG floods is described.

CDG injection volumes in projects reviewed vary from a few thousand barrels to hundreds of thousands of barrels. Projects evaluated did not show injectivity reduction even after more than 600,000 barrels injected in one well. Polymer concentration and polymer: crosslinker ratios ranged from 250 to 1,200 ppm and 20:1 to 80:1, respectively. Aluminum citrate is the most common crosslinker used in field projects. However, chromium triacetate has been used in high salinity and hardness conditions. Key variables to sustain the injection of large volumes of CDG below maximum operating pressure are polymer: crosslinker ratios, polymer concentration, and injection rates to a lesser extent. CDG projects have evolved from small to large treatment volumes showing a positive impact on oil recoveries. Despite large volumes of CDG injected production of polymer in offset producers has rarely been detected. Wellhead pressure response, CDG viscosity, and adsorption/retention (RRF) represents the most important variables needed to match CDG floods.

This study provides the status of the technology and field evidence that CDG's can be injected in large volumes and can propagate into the reservoir without injectivity constraints. This review will also provide guidance to successfully design and evaluate CDG pilot projects. Lessons learned from operating and modeling CDG projects will also be presented.
The Effects of CO2 Concentration in Flue Gas Injection for Heavy Oil Recovery from Fractured Reservoirs during GOGD Process
Authors: Mohsenzadeh A. , Escrochi M. , Afraz M. V. , Ayatollahi Sh. , Karimi Gh. , Iran. Shiraz , Al-wahaibi Y.
Published: June 2014

Considerable heavy oil is accumulated in naturally fractured carbonate reservoirs, with very low oil recovery efficiency through costly production techniques. In this experimental study, the effects of different injecting gases on the performance of immiscible gas injection and the GOGD process have been investigated at reservoir conditions from full sized carbonate cores in a long fractured laboratory model. During this study on heavy crude oil, three different gases: pure CO2, pure N2, and their mixture as synthetic flue gas injection; were used to study the performance of isothermal GOGD process. It was found that the oil recovery before gas breakthrough was mostly from the fracture; however the injected gas mostly affected the amount of oil recovery and its rate from the matrix part. The piston wise displacement during N2 injection and oil swelling during CO2 injection were found to be the most important mechanisms affecting the oil recovery performance before gas breakthrough. On the other hand, It was found that the oil recovery efficiency for CO2 injection after gas breakthrough was mainly due to gas dissolution mechanism and for N2 injection it was because of high oil-gas density difference; both resulted in approximately 14% recovery efficiency of the remained OIP. However, flue gas injection activated both mechanisms simultaneously with their adverse effects and the recovery efficiency decreased to approximately 10% of the remained OIP. It was also concluded that the GOGD mechanism needs to be stimulated by other compatible techniques such as thermal methods, to increase heavy oil recovery from the matrixes of the fractured formations.
Performance Evaluation and Design Aspects of Polymer and Hot Water Co-Injection in an Offshore Heavy Oil Field under Challenging Conditions
Authors: Mukherjee Soujatya , Süss Michael Peter
Published: June 2014

The field discussed in this paper is a highly unconsolidated sandstone reservoir with medium oil viscosities and a large bottom aquifer. Earlier simulations predicted poor primary recovery and a water flooding scenario showed early water breakthrough owing to viscous fingering. As a result, oil recovery from water flooding was severely curtailed because of unfavourable mobility ratio resulting in a low ultimate recovery factor. Therefore, enhanced oil recovery (EOR) was thought of as a possible recourse to increase recovery of this field.

Preliminary polymer flooding study carried out on the basis of the initial geological model helped in identifying some of the key design aspects impacting polymer flooding outcomes. In order to remedy these aspects, the revised geological model focused primarily on reducing uncertainties concerning property modelling and facies distribution. Screening dynamic simulations were performed to construct a recovery distribution function. The P50 case was taken forward for a more in-depth analysis of the current polymer flooding scenarios.

However, polymer flooding a thin heavy oil reservoir with a large bottom aquifer is a highly challenging scenario. Polymer losses to the aquifer are to be expected, even more so because the vertical permeability in the reservoir formation is extremely high. Although simulation results show acceleration in oil production due to improved displacement efficiency resulting from polymer slugs, the polymer losses are quite substantial and probably would render such a process uneconomic. In addition, significant amounts of oil are pushed into the aquifer as a result of injecting viscous water phase into the oil. In an attempt to mitigate these losses, a hybrid scenario was studied, in which hot water and polymer flooding is performed simultaneously. It is shown that under certain operating conditions oil losses can be eliminated, and the absolute amount of polymer losses can be reduced substantially.
Solvent Stimulation to Restore Productivity of Polymer Pattern Producer Wells - A Case Study
Authors: al kalbani Ali , Chandan Thakuria , Kawthar Saqr , Ravula Chakravarthi , Choudhuri Biswajit , Hashmi Khalid
Published: June 2014

The first field scale Polymer flood project in the Middle East region is under operation in an oil field of The Sultanate of Oman since early 2010. The oil field discussed here contains viscous oil (90 cp) was discovered in 1956 and is located in eastern part of South Oman Salt basin. First commercial production started in 1980 from this field. The field has gone through different development phases in its 30 years of history prior starting tertiary recovery phase by polymer flooding.

This Polymer flood project comprises of 27 patterns coversing about one third of the total field IOIP (initial oil in place). It is worth mentioning that whole field is under water flooding and water injection was going on prior to initiation of Polymer flood in 27 injectors.

So far, this project has been running successfully with good performance contributing to significant oil gain. During this successful journey of about 4 years, the project has passed through many expected and unexpected challenges. The well and reservoir management team has been working actively in all those challenges with novel approaches to increase efficiency of this project.

One of the key challenges encountered is reduction in productivity of producer wells in comparison to earlier water flood with same injection volume. In a few polymer wells production rates even dropped by more than 50%. The main challenges for these wells seeing higher drop in liquid rate is that there is no or minimal oil gain in-spite of reduction in water cut due to disproportionate decline in liquid rate.

This reduction in production rate smay be attributed to decrease in producible fluid mobility, high fluid density with polymer slug and skin formation near wellbore. At the same pressure drawdown of the artificial lift pump withdraws less fluid due to increase in fluid density with polymer breakthrough. There are also possibilities of plugging as a result of moving solid fines from the more viscous fluids near the well bore. These caused more drawdown and less fluid produced and resulted in high gross reduction in some wells. In order to overcome these gross decline, chemical treatment using mutual solvent has been carried out in a few wells as trial and has given good result. A detailed analysis is going on to investigate possible causes and accordingly design suitable remedial actions. This paper describes briefly about the principles involved in this solvent stimulation jobs and results of field implementation with real field examples.
Chemical EOR for Heavy Oil: The Canadian Experience
Authors: Delamaide Eric , Bazin Brigitte , Rousseau David , Degre Guillaume
Published: June 2014

Chemical EOR methods such as polymer flooding and ASP (Alkaline-Surfactant-Polymer) are generally not considered suitable for oil viscosities over one or two hundred cp (polymer) or even less (SP/ASP). However this perception is changing, in particular due to field results obtained from a number of chemical EOR pilots or full field floods implemented in Canada in higher viscosity oil in the past few years.

Canada is a country well-known for its heavy oil production; recovery processes such as Cold Heavy Oil Production with Sand (CHOPS) and Steam Assisted Gravity Drainage (SAGD) have been invented there. However cold production is limited in terms of the level of recovery it can achieve and thermal techniques also have limitations in particular when reservoirs are thin. Thus Canadian companies have been pursuing chemical EOR to increase recovery in those types of reservoirs.

The aim of this paper is to review some of the Canadian projects for which public information is available. Several mostly unpublished projects will be discussed in details, and conclusions will be drawn on the applicability of chemical EOR methods in heavy oil.

The practical experience gained in Canada can be applied in other regions of the globe where chemical EOR has so far not been considered or has been screened out because of high viscosity.
Evaluation of Novel Surfactant for Nitrogen-Foam-Assisted EOR in High Salinity Carbonate Reservoirs
Authors: Bageri Ali S. , Sultan Abdullah S. , Kandil Mohamed E.
Published: June 2014

The use of Nitrogen in Foam Assisted Water-Alternating-Gas (FAWAG) can be an alternative to the use of polymer, especially in carbonate reservoirs which generally have low permeability and contain vugs and fractures, for improving the displacement efficiency in chemical-EOR process. In this process foam performs the role of a mobility control agent. By FAWAG process, reducing gas mobility can be achieved by creating more resistance to gas flow since gas bubbles are surrounded in foam by lamella. Oil displacement by foam is strongly dependent on reservoir temperature, pressure and crude oil composition. A number of surfactants have been tested with foam-assisted-N2 flooding. We are presenting a new class of surfactant.

Two approaches were applied to determine the favorable concentration of each surfactant studied: solubility test and foam stability. The effect of salinity was investigated to determine the optimum concentration surfactant. Phase behavior was evaluated and it was observed that oil-in-water micro-emulsion is Winsor Type I. It is believe that low IFT can be obtained at high solubility ratio for the optimum salinity concentration. The performance of foam flooding with nitrogen (N2) for oil recovery in limestone carbonate rocks was studied. The success of the FAWAG process was determined by evaluation of oil recovery, pressure response and effluent from coreflooding experiments. The effects of core permeability, alkaline, and type of surfactants on the performance of the FAWAG were evaluated as well. Maximum recovery of 47.7% of residual oil in place in low permeability was observed compared to 43% of residual oil in place on high permeability core. In addition, the more recovery was obtained when using surfactant without alkaline.
Impact on Crude Dehydration Due To Back Production Of Polymer
Authors: Al Kalbani H. , Al Mandhari M. S. , Al-Hadhrami H. , Philip G.
Published: June 2014

Polymer flooding is an enhanced oil recovery technique that can increase production and improve recovery from mature fields. As polymer flooding is usually considered after other production strategies have been employed, the produced fluids are usually processed through existing facilities. These facilities have not been designed specifically for handling produced polymer which can affect the facility performance. For a polymer flood field in the Sultanate of Oman, the impact on crude dehydration was identified as a major risk to the existing facilities. A series of tests on emulsion breaking and heater fouling were conducted to determine the potential impact and identify any means of mitigating them. Produced fluids from the field containing polymer were tested along with synthetic polymer designed to mimic the produced polymer properties. A polymer handling limit was established for emulsion breaking in the facilities as well as the fouling potential for the crude oil heaters and a temperature threshold above which fouling occurs.
Evaluation of Foaming Agents for EOR Applications in Carbonate Reservoirs
Authors: Fuseni Alhasan , Han Ming , Al-Aseeri Abdulrahman
Published: June 2014

Enhanced oil recovery applications in carbonate reservoirs present the unique challenges of high salinity and high temperature. For foam applications, foaming agents that have good stability at those harsh conditions are therefore desirable. Crude oil, especially light crude has been known to be a destabilizer for foams and therefore foaming agents need to be designed to handle reservoirs with such oil. In this work, we sought to improve our understanding of the de-foaming behavior of Arabian light crude oil on foams generated using an anionic foaming agent and an amine oxide surfactant. Potential anionic and amphoteric foaming agents dissolved in seawater were screened using the dynamic foam analyzer as well as the high temperature high pressure cell. The stability of foam in the presence and absence of crude oil was studied using both nitrogen and air. Foam decay curves were plotted as a function of time.

Foam decay with time for both types of surfactant fitted a log decay curve confirming the assumption of exponential decay behavior. A semi-log plot of foam decay revealed interesting phenomena along the decay curve. Three regions were shown by the semi-log plot representing liquid drainage, drainage and coalescence and coalescence alone. In general, foam decay was faster in the presence of oil than without oil as shown by the foam half-life calculated for each case. The effect of pressure on foam stability was also investigated at a temperature of 90°C. Generally, foam stability tended to be better at higher pressures in most cases. Foam stability parameters were also evaluated to indicate the relative stabilities of foams generated. The amine oxide, while having excellent solubility in seawater also had a longer liquid drainage section as well as a longer decay time in the presence of oil, than the anionic foaming agent. The harsh conditions of high salinity and high temperature present in carbonate reservoirs therefore favor the amphoterics as better candidates.
Microemulsion Flow in Porous Media: Potential Impact on Productivity Loss
Authors: Izadi Mehdi , Kazemi Hossein , Manrique Eduardo J , Kazempour Mahdi , Rohilla Neeraj
Published: June 2014

Surfactant-polymer (SP) flooding is an enhanced oil recovery (EOR) technique used to mobilize residual oil by lowering the oil-water interfacial tension, micellar solubilization, and lowering the displacing phase mobility to improve sweep efficiency. Surfactant-polymer flooding, also known as micellar flooding, has been studied both in the laboratory and field pilot tests for several decades. Traditionally, a tapered polymer solution follows the injected surfactant. However, in recent years co-injection of surfactant and relatively high concentration polymer solution has been used in several field trials. Despite significant increase in oil recovery in the early stage of surfactant-polymer flooding, in some projects, the early increase in oil productivity period has been short followed by significant reduction in well productivity. We believe productivity loss results from surfactant-polymer interaction and fluid rheology alterations near production well. To evaluate this hypothesis, we injected microemulsion (with and without polymer) in Berea core plugs at residual oil saturation, and chased the surfactant with polymer solution or water. The objective was to determine the cause of productivity reduction and to develop a numerical model for simulating SP flooding in the field.

To achieve our objective, we searched for causes of productivity loss in field when using SP flooding. The search indicated that polymer-microemulsion interactions lead to high-pressure drop and significant productivity loss at the production well. Numerical modeling of several core floods pointed to the same conclusions because the numerical model required a large residual resistance factor (RRF) or a highly viscous aqueous phase near the production end. This information will be used to improve the design of future ASP/SP fluid systems.
An Innovative Process to Unlock Heavy Oil Resources in a Highly Fractured Carbonate Field
Authors: Salmi Salim S. , Romeiro Pedro , Balushi Mohammed Al
Published: June 2014

Mukhaizna field is one of the old fields in Southern Central of Oman. It was discovered in 1975, where Gharif was the primary target. Since then, the oil production was solely coming from Gharif reservoirs. Due to regular evidence of potential presence of hydrocarbon in Kahmah and Khuf groups from conventional wireline logs and old mud logs. Therefore, by early 2010, petrophysics was used heavily to validate the status of Kahmah group in terms of reservoir properties, mobility, pay thickness, and productivity across block-53 in Mukhaizna. The outcome of this analysis, Kahmah group found to hold more than 500 million barrels of heavy oil in place. Later, the appraisal was executed in phases and productivity was validated by placement of horizontal wells within this group at different locations.

This paper will demonstrate the discovery process, appraisal results and focus on a very innovative thermal enhanced oil recovery technique introduced by Occidental Mukhaizna. This technique is expected to unlock similar resources of heavy oil in highly fractured carbonate in Oman and the region with estimated oil in place to be greater than 130 billion barrels.
Improving Condensate Recovery of a Rich Sour Gas Condensate Field by Gas Recycling
Authors: Cobanoglu M. , Khayrutdinov F. , Linthorst S. , Iqbal M.
Published: June 2014

This paper concerns a gas condensate reservoir located in the South of Oman. The field is characterized by compositional grading resulting in a CGR range of 500-1700 m3/MMm3. The field is sour containing approximately 3% H2S and 15% CO2. The reservoir is a dolomite stringer floating and encased in the Ara Salt at an average depth of 4000m. Gross thickness is approximately 100m and the average porosity is 11pu, average permeability is 25mD. The initial reservoir pressure is 470 bara and the dew point pressure (depth related) is 20-30 bara below the initial reservoir pressure. The aquifer is anticipated to be weak with high salt content of 280,000 ppm, which is a flow assurance concern for production. First production started in 2013.

The gas-condensate field is part of an integrated gas-oil project with 8 oil and 2 gas fields where some of the oil fields are planned to be developed by miscible gas injection using non-associated gas. Integrated modelling enabled the selection of a development concept that optimizes the UR of the oil and gas Fields, ensures the gas sales commitments, while making maximum use of the existing facilities and thereby maximizing the value of the project.

The subsurface complexity required a full field compositional modelling approach to address: Quantification of uncertainties on field performanceOptimization of the field development planSupport the appraisal/development drilling campaign

The Integrated dynamic model results show that the condensate recovery factor is increased from 18% (depletion) to 24% by partial recycling with first injection expected in 2020. The Field will be the first PDO gas field developed under partial gas recycling.

This paper presents a methodology to evaluate/optimize the rich gas condensate reservoir including gas recycling and will also cover modelling challenges of compositional gradient and condensate banking.
Polymer-Alternating-Gas Simulation—A Case Study
Authors: Li Weirong , Dong Zhenzhen , Sun Jianlei , Schechter David S.
Published: June 2014

Carbon dioxide has been used commercially to recover oil from reservoirs for more than 40 years. Currently, CO2 flooding is the second most applied enhanced oil recovery (EOR) process in the world behind steam flooding. Water alternating gas (WAG) injection has been a popular method to control mobility and improve volumetric sweep efficiency for CO2 flooding. Average EOR is about 9.7% with a range between 6 and 20% for miscible WAG injection. Despite all the success of WAG injection, sweep efficiency during CO2 flooding is a typical challenge to reach higher oil recovery.

We applied polymer-alternating-gas (PAG), in which polymer flooding is combined with miscible CO2 injection, to improve the volumetric sweep efficiency of the WAG process in TR78 of the North Burbank Unit. High heterogeneity and high permeability at the top layers are the two main challenges of the North Burbank Unit. Then, we compared PAG performance with WAG and continuous gas injection (CGI). Polymer concentration and injection slug patterns were optimized during the PAG process. Simulation results show that PAG would increase oil recovery about 14.3% compared with 7.3% for WAG in TR78.

This study can not only be used to guide the development of the North Burbank Unit, but also to demonstrate that encouraging recovery can be obtained in high-heterogeneity reservoirs by using PAG.
Opportunities and Challenges of Polymer Flooding in Heavy Oil Reservoir in South of Oman
Authors: Riethmuller Gaël , Abri Ali , Al Azri Nasser , Stapel Gerco , Nijman Sander , Subhi Wahab , Mehdi Rawa
Published: June 2014

Polymer injection has proven in many places to be a successful EOR technique. However, selecting the polymer injection as the Enhanced Oil Recovery technique to develop quite heavy oil reservoirs with strong bottom water drive has been always a challenge in the oil industry but at the same time it can unlock the opportunities with such unconventional reservoirs.

This paper describes the key opportunities and challenges associated with implementing Enhanced Oil Recovery process in which polymer is injected into a clastic reservoir with a strong bottom aquifer drive bearing heavy-oil (250-500 cP). The high reservoir permeability (2-5 Darcy) enables stretching the viscosity limit of a standard polymer application.

There are several opportunities associated with this project but the key once are using low salinity make up water for injection, recycle back produced polymer and using Alkaline Surfactant Polymer at later phase on the project. The use of low salinity make up water was identified as the most important opportunity as it has the potential to substantially improve the project economics by reducing the polymer consumption while obtaining the same subsurface results. It also has the additional advantage to potentially improve the field UR by reducing the Sor. A number of risks are associated with this opportunity, the main ones being in situ clay swelling, reservoir souring, and decreased polymer stability if mixing with formation water occurs.

Conversely, this project is quite challenging specially with the limited analogues in the oil industry. The key challenges are the impact of back produced polymer, work around the congested urban planning and most importantly make the subsurface concept work. Finally, this paper discusses the solutions and activities to address and mitigate these key risks.
Mukhaizna Steam Surveillance Logging
Authors: Al Shaibi Rashid A. , Al Habsi Ali B. , Al Touqi Wiam K. , Al Hamadani Adil , Al Salmani Al Ghalia
Published: June 2014

Assessing steam injection conformance is one of the challenges faced during developing a multi-zones steam flood project. Critical flow principle was used to develop downhole steam injection control techniques using Limited Entry Perforation and steam injection nozzles and orifices. Evaluating performance of these downhole completion accessories requires adopting and modifying several surveillance tools. Injection Logging Profile (IPL) Tools are used to monitor steam distribution in multi-zones steam injection wells and to investigate steam flow behavior in the wellbore. This paper reviews steam injector surveillance techniques in a giant steam flood field located in south Oman. The article will list advantages, limitations, and the challenges faced with the various interpretation methods including temperature logs, simple flow meters, radioactive tracers, and Pulse Neutron tool surveys. Steam quality estimation methodology will be presented employing logging data and semi-analytical wellbore heat transfer models.
Rheological Assessment of VES as an EOR Fluid in Carbonate Reservoir
Authors: Sultan A. S. , Azad M. S. , Hussein I. A. , Mahmoud M. A.
Published: June 2014

Mobility control is the most important phenomenon that contributes to the volumetric sweep efficiency in enhanced oil recovery processes. Polymers have been used by the industry to provide the required viscosity to the injection fluids. However, applicability of polymers has its limitation. Most of the polymers easily degrade under harsh reservoir conditions. In this work, we investigated the rheological aspect of viscoelastic surfactant (VES) as an alternative to the polymer in chemical EOR processes. VES self assembles at favorable conditions to form wormlike micelles whose length can vary significantly. The conditions ascertained in this work are concentration, shear rate, temperature, time; salinity etc. In addition, the efficiency of VES with the polymer at various conditions was compared. Results indicated that VES can generate higher viscosity at the extreme conditions of reservoirs. This might be beneficial for EOR point of view. Also, the comparative studies confirm the potential of VES over polymer as an EOR fluid.
Optimization of a Large Polymer Flood Using Full-field Streamline Simulation
Authors: Choudhuri Biswajit , Thakuria Chandan , Belushi Abdul Aziz , Nurzaman Zamzam , Hashmi Khalid , Batycky Rod
Published: June 2014

A field scale polymer flood has been in operation since early 2010 in a major oil field of the Sultanate of Oman. The project comprises 27 patterns where water flood was on-going prior to initiation of Polymer flood in 2010. A polymer flood project has high chemical operating expenditure (Opex). Thus, optimization of a polymer flood requires continuous tracking of mass of polymer injected per unit volume of incremental oil produced for individual polymer flood patterns and then polymer throughput in individual patterns needs to be dynamically altered. To meet this objective, a full-field streamline simulation model has been built, history matched and is being used for optimizing the polymer-flood. Full-field simulation allows the proper modeling of each pattern and their interactions with off-set patterns, and these simulations can be performed in a reasonable computation time because of the efficiency of streamline modeling. Computational efficiency of streamline simulation has facilitated use of the model for routine well and reservoir management decisions. This would not have been possible with a finite difference model because of excessive run time and inability to clearly establish injection-production relationship as in a streamline model.

The model has facilitated optimization of polymer flood patterns, specifically when to stop polymer injection, slug size, and slug concentration. Individual pattern performance can be visualized effectively and their efficiency can be compared. The model is also being used for ranking the existing water-flood patterns for the next phase of polymer-flood implementation and carrying out short term production forecast.
Status of Fluid Flow Mechanisms for Miscible and Immiscible WAG
Authors: Skauge Arne , Sorbie Ken
Published: June 2014

Water-Alternating-Gas (WAG) injection has become a well established gas EOR method since field applications were first reported in the late 1950s. WAG can be applied by injecting CO2 or hydrocarbon gases as a miscible process where the gas is (usually multi-contact) miscible with the crude oil (MWAG) or where it is immiscible (IWAG). However, we contend that, even in "MWAG" processes, most of the reservoir is actually "near miscible", which we refer to as nMWAG and this case is discussed in detail in this paper. In many cases, WAG has been regarded as a "large scale" EOR method targeting mainly sweep improvement. However, the fluid flow mechanisms are important both for improving macroscopic sweep and also for improved microscopic displacement efficiency.

Improved microscopic efficiency by lowering residual oil saturation in the three-phase zone can greatly add to the benefit of WAG injection. Indeed, we believe that the fluid flow properties at pore scale and core scale when appropriately upscaled lead to significant oil recovery at the reservoir scale. Therefore, the pore/core scale mechanism are key factors for estimating the recovery efficiency of WAG processes. This paper reviews recent development in our understanding of the mechanisms of both immiscible and miscible /near miscible WAG processes. The discussion connects pore scale physics and core scale observations and explains the implications of these smaller scale processes on the field scale oil recovery by IWAG, MWAG and nMWAG.