bluuebunny/crossref_metadata_2025 huggingface dataset:
Surfactant-Polymer EOR from Laboratory to the Pilot
Authors: Puskas S. , Vago A. , Toro M. , Ordog T. , Kalman G. , Hanzelik P. , Bihari Zs. , Blaho J. , Tabajdi R. , Dekany I. , Dudas J. , Nagy R. , Bartha L. , Lakatos I.
Published: March 2018

Central element of MOL Hungarian Oil and Gas Plc. (MOL) US strategy is to increase the hydrocarbon production at Hungarian oil and gas fields using technologies that are more efficient. The main goals of this activity are to increase the recovery factor in fields depleted with extensive water flooding, improving efficiency of recovery technologies. For this purpose, new materials and technologies should be developed and applied at both Hungarian and foreign matured oil fields. That is the biggest challenge of the research and development (R&D) activity of the MOL Upstream. The R&D project began more than ten years ago to meet these challenges and increase the oil recovery factor of the Algyo field, which is the largest Hungarian oil field. This paper describes how a countless number of surfactants, co-surfactants and their mixtures were synthetized, developed and tested in the laboratory to achieve the objective, developing a combined surfactant-polymer (SP) flooding technology. The most important properties of these complex fluids were the thermal stability at reservoir conditions (98°C and 170 bar), the colloid chemical stability in electrolyte medium (formation water) and the compatibility with reservoir rock and pore filling fluids. The primary findings of this job show that several surfactants were effective at high temperature; low salinity reservoir conditions and have good solubilisation and displacement effect and low interfacial tension and low reversible adsorption on reservoir rock. Synergetic effect was observed between surfactants and polymers therefore surfactant-polymer mixtures were produced and tested in core flooding tests. Based on numerous displacement tests on reservoir core plugs it can be stated that the calculated recovery factor was 20-25% using the developed SP mixtures. The successful laboratory displacement tests were also reproduced by numerical simulation on numerical core samples as well as the injectivity test on the new 3D reservoir model that was carried out to see the effect of developed SP mixture under real reservoir conditions. This paper will present the results of several years of research and development work for SP formulation targeting SP flooding in high pressure and high temperature reservoir. The field implementation through an injectivity test will also be presented demonstrating that injection of 2,000 m3 SP solution has huge effect on oil production even 3 years later. Based on the outstanding field results a SP flooding pilot was started in 2016.
Gelation Time Optimization of an Organically Crosslinked Polyacrylamide Gel System for In-Depth Fluid Diversion Applications
Authors: Alhashim Hassan W. , Wang Jinxun , AlSofi Abdulkareem M. , Kaidar Ziyad F.
Published: March 2018

Conformance improvement is crucial for heterogeneous reservoirs to ensure injected water and any EOR chemicals optimally contact the remaining oil with minimal throughput. Gel-based conformance control has been successfully applied on both sandstone and carbonate reservoirs. In this work, a laboratory study was conducted to investigate the applicability of an organically crosslinked polymer gel for in-depth fluid diversion practice at high-salinity and high-temperature conditions. The evaluated gel system was a polyacrylamide polymer crosslinked by organic crosslinkers, hexamethylenetetramine (HMTA) and resorcinol. The effects on gelation performance of polymer and crosslinker concentrations, brine salinity, and pH were investigated. Results showed that the gelation time of the studied gel system reached around three to four days at 95°C, with sufficient gel strength and long term stability. Gelation time became longer with decreasing either polymer or crosslinker concentrations, but there were lower concentration limits to form gel. The gel had a wide range of tolerance to brine salinity, but was sensitive to solution pH value. Decreasing pH resulted in faster gelation rate, and gel tended to be stronger. The gelation time slightly increased with increasing brine salinity in low pH range (< 6.0), or with decreasing brine salinity in neutral pH (6 to 8) environment. Varied laboratory techniques, dynamic rheology and low-field nuclear magnetic resonance (NMR) measurements, were also used to evaluate the gelation time of bulk gel. Rheological measurement and NMR technique, with minimum or no disruption to the gel structure, can determine the gelation time of a bulk gel sample that might be difficult to detect by bottle test. The determined gelation time by these two methods tended to be shorter than bottle test result.
Successful Implementation of a One-Spot Alkaline-Surfactant-Polymer ASP Pilot in a Giant Carbonate Reservoir
Authors: Al-Murayri M. T. , Al-Kharji A. A. , Kamal D. S. , Al-Ajmi M. F. , Al-Ajmi R. N. , Al-Shammari M. J. , Al-Asfoor T. H. , Badham S. J. , Bouma C. , Brown J. , Suniga Hernandez P.
Published: March 2018

A one-spot pilot was successfully performed in the Sabriaya-Mauddud (SAMA) formation in Kuwait to demonstrate the feasibility of using alkaline-surfactant-polymer (ASP) injection to increase oil recovery from a giant carbonate reservoir. Two Single Well Chemical Tracer (SWCT) tests were performed on the SAMA test well (Well A) to measure the effectiveness of ASP injection in mobilizing waterflood residual oil saturation. The first SWCT test (Test #1) measured the waterflood residual oil saturation (Sorw) after a 10 PV seawater injection. This was followed by the second SWCT test (Test #2) to measure the oil saturation (Sorc) remaining after ASP chemical injection, comprised of: a 0.12 PV alkaline pre-flush; a 0.22 PV injection of ASP; a 0.68 PV injection of polymer in alkali solution; and a 1.00 PV injection of polymer.

The difference in residual oil saturation from Tests #1 and #2 quantitatively determines the overall displacement efficiency of ASP injection. Tests #1 and 2 were performed post water and ASP flooding by injecting dilute SWCT tracer chemicals, including a hydrolyzing, partitioning ester (ethyl acetate) and two alcohols (n-propyl alcohol and isopropyl alcohol) that serve as a cover tracer and material balance tracer, respectively. Residual oil saturation post seawater injection was around 28% (+/- 3%) and following ASP flooding it was reduced to 4% (+/- 3%). These encouraging results confirm the effectiveness of ASP flooding in improving incremental oil recovery relative to waterflooding using seawater.

This paper demonstrates the feasibility of applying ASP flooding to increase oil recovery from carbonate reservoirs. The reported findings will be used to optimize and de-risk the implementation in multiwell/pattern ASP injection.
Nanoparticle-Fortified Emulsification of Heavy Oil
Authors: Arab Danial , Kantzas Apostolos , Bryant Steven L.
Published: March 2018

Chemical flooding has been suggested as an efficient conformance control technique to develop many of thin post-CHOPS heavy oil reservoirs in Western Canada. In-situ formation of oil in water emulsions due to the effect of surfactant/natural soap has been reported as the main mechanism behind chemical EOR. In this work, the effect of surface-modified silica NPs to enhance the efficiency of surfactant to emulsify heavy oil (14,850 mPa.s and 980 kg/m3 at 25 °C, from the Luseland field) in water has been investigated.

Bulk fluid screening experiments were conducted using different surfactants and surface-modified silica NPs for selecting the best heavy oil emulsifier. Complementary experiments such as interfacial/surface tension, NP zeta potential and size measurements, and elemental analysis were conducted to understand the interactions between NPs and surfactant molecules.

In the absence of NPs, concentration of both anionic and cationic surfactants should be tuned within a narrow window, near CMC, to create stable heavy oil in water emulsions. It was found that there is a threshold for IFT, obtained at the CMC, which should be met to have stable oil in water emulsions. The created oil in water emulsions break easily at surfactant concentrations higher than the CMC, yielding IFTs higher than the threshold. This observation was also seen in a system containing dodecane. At the CMC of both anionic and cationic surfactants, the IFT between dodecane and an aqueous phase is negative, producing stable dodecane in water emulsions for over three months.

In the presence of surface-modified silica NPs heavy oil emulsification is achieved at surfactant concentrations much lower than the CMC. In this case, IFT is remarkably (54 %) reduced, well below the threshold value, due to the combined effect of 2 wt. % negatively-charged silica NPs and only 0.1 wt. % anionic surfactant. These results suggest that the repulsive interaction between negatively-charged NPs and anionic surfactant may result in pushing the surfactant molecules back towards the oil-water interface to enhance IFT reduction.
Commercial Implementation of Chemical Flooding in Daqing Oilfield, China, and Its Future
Authors: Zhong Xun , Wang Yuhe , Pu Hui , Li Wei , Yin Shize , Ling Kegang
Published: March 2018

Chemical enhanced oil recovery(EOR) such as polymer flooding and alkali/surfactant/polymer(ASP) flooding have been applied throughout the world for more than several decades. However, few large-scale successes of these technologies have been reported, except in China. The annual crude oil production rate by chemical EOR in Daqing Oilfield has been kept over 10.0 million tonnes (~73.5 million barrels) per year for 16 consecutive years. Considerable experience has gained and lessons have learned on large-scale chemical flooding, including major factors that influence the recovery factor and methods to increase the oil recovery; measures to obtain the highest economic efficiency; and how to minimize the costs.

To date, incremental oil recovered by polymer flooding is over 10.0% OOIP. Due to some disadvantages of polymer flooding, like the existence of inaccessible pore volume and lack of the EOR mechanism of ultralow interfacial tension, some substitute technologies are needed, and ASP flooding is a promising one, which was reported and proved to have an ability of recovering more than 20.0% extra oil over water flooding. However, negative scaling problems caused by alkali are severe and problematic, as a result, weak-alkali ASP (WASP) and even surfactant-polymer (SP) flooding were developed or are under development. To alleviate the bad effets of scale and further improve the performance of ASP flooding, some new technologies such as refracturing and application of new anti-scaling chemicals like compound scale removal agent were applied. SP flooding is a theoretically feasible EOR technology, but there are few field test data available, and more effective surfactants are required.

In this paper, the development of commonly used chemical flooding technologies, normal problems that may merge during commercial implementation, together with the updated solutions are included. All the valuable experience obtained from commercial-scale application of chemical flooding in Daqing Oilfield is not only of great significance for the expansion of Daqing Oilfield itself, but also worth learning by other countries.
Polymer Injectivity Analysis and Subsurface Polymer Behavior Evaluation
Authors: De Simoni M. , Boccuni F. , Sambiase M. , Spagnuolo M. , Albertini M. , Tiani A. , Masserano F.
Published: March 2018

A robust analysis of a polymer flooding inter-well pilot has been performed. The main objective was to analyze the polymer injection performance and to confirm the in-situ designed viscosity of the polymer injected, necessary to estimate the expected EOR effect.

The adopted workflow focused on the integration of different sources of data and analyses. Indeed, several phenomena may occur during polymer injection, such as complex injectivity behavior due to polymer non-Newtonian rheological nature, formation damage caused by particles adsorption, fractures opening, and mechanical degradation of polymer. The injection performance analysis focused the following aspects: previous case history, polymer laboratory tests, shear stress through perforation evaluation, diagnostic plots, injectivity test interpretation, well test analysis, and fracturing investigation. Lastly, numerical simulation allowed us to integrate the different analysis, thoroughly capturing the subsurface polymer behavior. Main result is that injection under fracturing conditions occurred during pilot start-up. These small-scale fractures, localized in the near-wellbore zone, are not detrimental to polymer flooding and rather increase the well injectivity. Furthermore, no evidence of mechanical polymer degradation was detected.

The evaluation of the subsurface polymer behavior during an inter-well pilot is crucial to verify the correct polymer injection process. In this work different source of data and analysis have been integrated to understand the injectivity behavior. Robust reservoir monitoring is ongoing and preliminary promising effects are now being shown.
Overcoming Artificial Lift Failures in Polymer Flooding Oil Field in the South of Oman
Authors: Al-Sidairi Nada , Osman Mahmoud , Oritola Nasir , Ahmed Farsi , Zuhaimi Khalid , Amri Mohsin , Hinai Ghalib , Al-Mahrooqi Majid
Published: March 2018

Polymer flood as a mean of enhanced oil recovery was applied in a large sandstone heavy viscous (22API & 90cP) oil field located on the South of the Sultanate of Oman. The polymer flooding was commenced in 2010 with phase I covering 27 patterns, by means of inverted 9-spot pattern. In 2015, Phase I was followed by Phase II with additional 19 patterns. Full field polymer flooding is planned in the coming years.

Over 250 oil producers are benefiting from changing the recovery mechanism water flooding system to the increased viscosity flood system (polymer). Significant oil gain was achieved by improving the recovery factor. Around 92% of the total wells in the field are completed with the two main artificial lift systems, beam pumps BP and Progressive Cavity Pump PCP.

After circa three years of introducing the polymer flooding in the field, new trend of well failure rate was observed in which the artificial lift failure rate was increased by around 40% by end of 2014. This has massively increased work-over job frequencies and cost, and has significantly increased the crude oil production deferment. New type of failure mode was seen in the sucker rod and tubing of the BP & PCP. Severe eccentric wear of sucker rods and tubing in many vertical wells with pumping unit have accrued in which the coupling was worn out and broken from one side i.e. most of phase I & phase II wells experienced premature or frequent failure.

By end of May-2015, 83% of failure were associated to pump failures and it is more related to well conditions. Material analysis of the damaged sucker rod & plungers were conducted & the failure mechanism of both parts of the beam pump was investigated. Around 73% of the pump failures were found to be due to solids handling (sand, scale solids) & corrosion issues or combination of both, erosion & corrosion mode of failure. On the other hand, around 60% of rod failures of the polymer flooded wells were due to wear.

Set of trials and initiatives were conducted to improve the sucker rod run life and reduce the failure rate. For example, centralized molded sucker rod, continuous rod (pro-rod), GRE lined tubing and long stroke pump (roterflux).

Some good success was achieved in arresting the failure rate and improving sucker rod run-life. Material analysis studies & trials were also conducted to improve the barrel life. Evaluation of the various trails are currently ongoing and still at early stage to draw clear conclusions.

This paper will discuss the material analysis studies and the main practical trials that were conducted to reduce the pump and rod failures, and therefore improve well run-life in the field.
Surfactant Based EOR for Tight Oil Reservoirs through Wettability Alteration: Novel Surfactant Formulations and their Efficacy to Induce Spontaneous Imbibition
Authors: Patil Pramod D. , Rohilla Neeraj , Katiyar Amit , Yu Wanglin , Falcone Susan , Nelson Christopher , Rozowski Peter
Published: March 2018

The strongly oil wet nature of tight carbonate or shale reservoirs leads to rapidly declining oil rates during production stages. For fractured tight carbonate reservoirs, chemical flooding with surfactants has been shown to enhance oil production from water flooding (huff and puff method) due to spontaneous imbibition of water into oil-rich matrix, leading to oil displacement from tight pores and increased recovery. Success of such surfactant based EOR technology depends heavily on developing the optimal surfactant formulation for the field. The objective of this work is to identify the key mechanisms responsible for the improved performance of surfactant formulations and to characterize the interactions that can induce imbibition into an originally mixed-wet, tight, hydraulically fractured shale reservoir via laboratory evaluations. Wettability alteration formulations are first developed and screened for aqueous stability and phase behavior at reservoir conditions. Tailored hydrophobic surfaces are used to evaluate selected formulations for their potential to shift rock wettability through contact angle measurements. Water-oil interfacial tension behavior is investigated to elucidate the mechanism of oil recovery. Adsorption behavior of the chemicals is investigated on various rock minerals to identify formulations with minimal retention and component separation under static conditions. Finally, the candidates are comparatively tested for oil recovery performance in spontaneous imbibition experiments at simulated reservoir conditions.

The key factors considered in developing an optimal surfactant formulation are favorable phase behavior in reservoir fluids at reservoir conditions, the ability to shift the rock surface wettability to a more water-wet state, and minimal chemical losses on reservoir minerals. Also, the formulation should not form a stable emulsion which may pose an oil-water separation difficulty in oil production. The designed formulation was tested using forced imbibition test (core flood) and show significant incremental oil recovery. As part of our rigorous approach to design optimal surfactant formulations for improving oil recovery, we perform surfactant phase stability, surfactant retention and rock-surfactant interaction related to wettability alteration. Surfactant formulations designed in this work are unique and provide high temperature stability (above 70 °C and up to 120 °C) and high salinity tolerance (> 12% TDS and up to 22%). This study also highlights the underlying mechanism of surfactant induced wettability alteration of tight carbonate rock due to novel surfactant formulations.
Asphaltene Predictions Using Screening Methods and Equations of State
Authors: Boesen Rasmus Risum , Sørensen Henrik , Pedersen Karen Schou
Published: March 2018

Asphaltene data for 36 reservoir fluids from different geographical regions has been used to evaluate and compare the ability of four commonly used screening methods and three equations of state to identify fluids likely to present asphaltene problems during production. The screening methods are the de Boer method and three SARA based methods. The data covers asphaltene onset pressure data with and without gas injection at a wide range of temperatures. The evaluation showed that the Asphaltene Stability Index method is the most reliable of the tested screening methods, but all screening methods may fail to identify fluids with asphaltene problems. Analyzing asphaltene onset pressure data, it was seen that fluids precipitating asphaltenes by depressurization consistently seem to be causing asphaltene problems during production. The three equations of state tested were the SRK equation, the CPA equation and the PC-SAFT equation. None of the equations was able to predict asphaltene onset pressures in the absence of measured data, but all three equations could be tuned to match the development in asphaltene onset pressure with temperature and the impact of gas injection on the asphaltene onset pressure. The more complex CPA and PC-SAFT equations showed no advantage over a classical cubic equation of state. A newly developed algorithm for generating complete asphaltene phase diagrams helped explain why different trends in asphaltene onset pressure with temperature may be observed.
Squeezing Out the Last Drops - Long and Colourful EOR History of MOL
Authors: Ördög Tibor , Szelényi János
Published: March 2018

In 2017 MOL celebrated the 80th anniversary of the first HC discovery of Hungary within the current territory of the country. This long history is coupled with also a long history of different EOR experiments and projects. Laboratory tests already started in the fifties followed by field applications in the sixties. The objective of this paper is to introduce the currently ongoing EOR related projects based on MOL's EOR history by highlighting the key technologies and projects.
Investigation and Application of an Associative Polymer-Surfactant Binary System for a Successful Flooding Pilot in a High-Temperature, High-Salinity, Ordinary Heavy Oil Reservoir
Authors: Guo Yongjun , Zhang Jie , Zhang Xinmin , Hu Jun , Wang Wei , Liang Yan
Published: March 2018

Due to poor temperature resistance and salinity tolerance of conventional polymers, the chemical flooding for high-temperature and high-salinity reservoir faces enormous challenges. This work studies the comprehensive performance of a polymer-surfactant system based on an associative polymer and verifies its availability and feasibility in Guan-109 fault-blocked reservoir, Dagang (China), which is a typical high-temperature, high-salinity, ordinary heavy oil reservoir.

The viscosifying property of different polymers (including two associative polymers), interfacial activity of different surfactants and the interaction and compatibility between the polymers and surfactants are investigated to initially determine an associative polymer (AP-P7) and the petroleum sulfonate surfactant (PS-985) as suitable candidates. Then, the adsorption, shear resistance, aging stability, injectivity, and oil displacement capacity of the combination system containing AP-P7 and PS-985 are further studied to obtain the optimal binary flooding system. Moreover, the field application scheme for Guan-109 reservoir is further obtained through optimizing injecting concentration, slug size and slug combination of binary flooding system.

The lab tests show that, under the reservoir condition of 26983 mg/L salinity and 78 °C, the viscosity of associative polymer varies from 31.7 to 88.5 mPa·s in a concentration range of 1500~2500 mg/L, and the oil/water interfacial tension of the petroleum sulfonate is up to 10-3 mN/m order of magnitude in a concentration range of 0.05wt%~0.5wt%. At fixed polymer concentration (2000 mg/L) and surfactant concentration (0.3wt%), the binary system presents significant viscosifying capability, interfacial activity, adsorption resistance, shear resistance, aging stability, etc. Meanwhile, the system has good injectivity at a gas permeability of 210×10-3 μm2 and can generate a high resistance factor (105.1). After optimizing injecting parameters, in laboratory, the binary system can improve the oil recovery by 26.37% after water flooding. During the binary flooding pilot in Guan-109 reservoir (7 injectors and 12 producers), from December 2016 to December 2017, the system has been injected for 0.102 PV. Thus, the pilot achieves expected results. The liquid production enhances from 364 to 521.1 m3/d, oil production enhances from 27.7 to 51.7 m3/d, and the water cut decreases from 92.3% to 90.1% (the maximum decreasing amplitude is up to 3.4%).

Both lab tests and field pilot show that the binary system based on the associative polymer is hopeful to solve the challenges faced by chemical EOR in high-temperature and high-salinity reservoir. In addition, the pilot also provides much practical experience for the successful application of this novel system.
New Insights on the Characterization of Polymer Adsorbed Layers in Porous Media
Authors: Boujlel J. , Barré L. , Rousseau D.
Published: March 2018

The objective of this work was to bring new insights on Polymer Adsorbed Layers (PAL) in porous media. Irreversible permeability reductions and irreversible polymer retention were firstly determined versus polymer molecular weight, flow velocity and brine salinity and hardness. The presence of PAL was then evidenced by small angle neutrons scattering (SANS). This allowed proposing interpretations of permeability reduction in terms of PAL thickness and density.

This study focused on the adsorption of partially hydrolyzed polyacrylamide (HPAM) polymers on granular packs of silicon carbide (SiC). Polymer solutions were injected at fixed flow rate and concentration. Irreversible permeability reductions (Rk) were determined from changes in pressure drops and irreversible polymer retention (Г) from the difference of volume at breakthrough for two successive slugs. In-situ SANS experiments were performed under flow using the contrast matching technique: the pore space was filled with an H2O/D2O mixture with a scattering length density equal to that of the SiC. This resulted in a two-phase system whose scattering intensity was directly connected to the PAL (meso)structure.

Results showed an increase of Rk and of Г with salinity (0.2 to 80 g/L, with a stabilization trend towards high salinities) and molecular weight. When hardness was increased, Rk was not much affected but Г increased. The SANS experiments revealed a scattered intensity vs. wave vector q typical of PAL with self-similar concentration profile. From these results, it was possible to determine PAL hydrodynamic thicknesses of adsorbed layers (εH) using the Rk values and according to a simple capillary bundle model. εH and Г values were then combined to estimate the PAL density. The impact of salinity could hence be interpreted in view of classical charge screening effect observed for solutions of polyelectrolytes. The impact of molecular weight was found qualitatively consistent with the increase in radius of gyration. Regarding the impact of hardness, stable εH and increased Г translated in an increase of the PAL density: this could be due to the creation of bridges between polymer charged monomers and divalent cations. As for the impact of flow velocity, increases of Rk and hence of εH was generally observed. Such behavior is consistent with a change of conformation of PAL, from coiled to stretched.

This work stand as the first direct experimental evidence of "irreversible" PAL in three-dimensional porous media under flow. It also represents a consistent set of results summarizing the impact on PAL of parameters that are particularly relevant for field operations. The results and corresponding interpretations are meant to be used in reservoir simulation softwares to improve the predictability and economics of polymer flooding EOR.
New Tracers to Measure Residual Oil and Fractional Flow in Push and Pull Tracer Tests
Authors: Huseby Olaf , Galdiga Claus , Zarruk Gustavo A. , Hartvig Sven K. , Dugstad Øyvind
Published: March 2018

The well-established single well chemical tracer test (SWCTT), devised by Deans and co-workers in the 1970ies, has been used extensively to assess oil saturation after water flooding and as a method to measure the effect of EOR. The technique is based on separation of two different tracers; one oil/water partitioning tracer that partly hydrolyses in the reservoir to generate a secondary non-partitioning water tracer. Saturation is found from the time lag of the partitioning vs. the non-partitioning tracer and pre-measured partition coefficients. As an alternative to the commonly used tracers (e.g. Ethyl Acetate), a new family of reactive and partitioning chemical tracers was recently developed and field-tested. The new tracers, as well as their in-situ generated secondary non-partitioning tracer counterparts, are not naturally present in the reservoir, and can be analyzed using highly sensitive analytical methods, either on-site or in an off-site lab. The improved sensitivity implies that the required tracer amount can be reduced to a few hundred grams, i.e. about 1000 times less than in a conventional SWCTT. The reduced tracer amount has operational, HSE and several other benefits. In this paper, we review our field experience using the new tracers and explore how they improve and expand the single well tracer test methodology. Results reported in this paper show that off-site analysis is effective and accurate, which eliminates the requirement for on-site field analysis. The paper demonstrates that injecting several reacting and partitioning tracers can be used to measure saturation gradients in the near well zone. By injecting the new tracers in a well where movable oil is present (i.e. without extensive water flooding), information about the fractional flow of oil and water can also be gained. We explore this option and suggest a procedure for in-situ measurement of fractional flow of oil and water in the near well zone.
Practical EOR Agents - There is more to EOR than CO2
Authors: Dean Elio , French Josh , Pitts Malcolm , Wyatt Kon
Published: March 2018

CO2 EOR projects have experienced localized success in the United States due to past investments in CO2 infrastructure made possible by no longer existing government incentives. Many countries mistakenly look at these successful cases, along with the environmental benefit of carbon capture, and embarked on a quest for a CO2 EOR projects prior to securing a CO2 source. This paper discusses the available EOR agents beyond CO2.

This paper is based on efforts made to select EOR agents for a Rocky Mountain region reservoir, and uses a 10 MMBBL mechanistic model to assess EOR agents. Sourcing, purchase volumes, costs, infrastructure requirements, and a brief summary of the benefits and challenges are presented for the following EOR technologies: Carbon DioxideEthane + other Hydrocarbon GasesFlue Gas (90% N2, 10% CO2)NitrogenAlkali (different types)Surfactant (different types)Polymer (different types)Combinations of alkali, surfactant, and polymer

The logistic considerations identified in the evaluation of the Rocky Mountain region field are universal and can assist EOR agent selection in North America, the Middle East, and anywhere on Earth.
Chemical EOR in a Strong Aquifer Driven Reservoir: From Concept towards Reality
Authors: Tiwari Sanhita , AL-Mutairi Fahad , Al-Dhuwaihi Abdul-aziz , Al-Ajmi Moudi
Published: March 2018

North Kuwait has vision to increase oil production from its major reservoir and it is planned to be achieved by covering the major reservoirs under the umbrella of enhanced oil recovery (EOR). Sabiriyah Lower Burgan (SALB) is the biggest sandstone reservoir in Sabiriyah field with high permeability and strong aquifer support. Paper describes steps planned from present development strategy of simply infill drilling to EOR to improve the production scenario in future.

Primary recovery from reservoirs like SALB are expected to be good. Performance of the reservoir especially rise in water cut of SALB was analyzed which suggested that though primary recovery would be good but will take longer time to achieve. EOR screening was performed and suitable EOR methods were evaluated using mechanistic model. Screening considered target oil, water quality, permeability, oil viscosity, temperature, aquifer and injection capacity. Lab experiments were performed for the identified EOR processes and most suitable method was selected. EOR pilot area and pilot design performed to take it forward from concept stage towards reality.

SALB Layered part is an acceptable candidate for EOR process due to favorable mobility ratio which reduces the need for mobility control agents, reservoir being mixed wet system which is encouraging for improving unit displacement efficiency and reservoir rock properties are conducive to most forms of EOR. Low salinity water, CO2, N2 and Chemical EOR methods were evaluated. Mechanistic model based Estimated Recovery factor range for these EOR methods indicated Chemical EOR, (A) SP as most effective EOR method. Lab experiments were performed for CO2, N2 and ASP. In Lab, miscible N2 flooding was not found feasible whereas CO2 flooding was feasible for either as CO2 or a blend of CO2/NGL. Coreflood experiments suggested surfactant-polymer or alkaline-surfactant-polymer pilot flood as promising EOR methods for SALB. KOC has planned to proceed with Chemical EOR with its further evaluation through single well chemical tracer test (SWCTT) as first step. A multi-well pilot was also recommended assuming a successful single wells tracer test which would provide a better understanding of chemical solution injectivity, oil recovery potential, chemical retention by the reservoir, effect of the water drive on alkaline-surfactant-polymer flood potential and operational issues. Target layer and likely area was identified for EOR pilot.

EOR in a reservoir with strong aquifer drive has its own challenges but merits of SALB for enhancement of recovery are encouraging. The paper provides an insight of applicability of Chemical EOR in a large reservoir with strong aquifer that will pave the way for similar reservoirs in Kuwait and worldwide.
Evaluation of EOR Chemicals Impact on Topside Operations
Authors: Argillier J.-F. , Henaut I. , Darbouret M. , Jermann C. , Vinay G.
Published: March 2018

Water management has always been an important part of production operation but for chemical EOR it becomes one of the critical elements as the whole water cycle needs to be analyzed and adapted to the process. In particular one key aspect that is generally neglected concerns the impact of EOR chemicals on the produced water cycle. After the chemical breakthrough, part of the EOR chemicals (polymers and/or surfactants) will be back-produced and can induce heat exchanger fouling and strongly impact oil/water separation and water treatment surface processes. All these drawbacks may lead to skewed forecasts on economic performance of EOR projects.

Some of the key challenges with produced water treatments, that facility engineers and operators will be facing when preparing a chemical EOR project, will be highlighted in this paper. A focus on some experimental results obtained within the DOLPHIN JIP – supported by 14 oil companies – will be presented. A specific laboratory methodology dedicated to the study of the impact of ASP-type chemicals on heat exchanger fouling, oil/water separation and water treatment efficiency and which mimic actual surface processes, was designed.

Results presented will illustrate the operational conditions that favor deposit on heat exchangers when polymer is back-produced. Impact of having polymers and/or surfactant within produced fluids on oil/water separation (kinetics of separation and quality of both oil and water phases) and water treatment processes efficiency (evaluated by monitoring the concentration of remaining oil in water as a function of time) will also be outlined.

This work emphasizes that water management is a major challenge for chemical EOR that needs an integrated approach and should be studied upfront. Laboratory workflows and procedures could help the de-risking of operations and try to mitigate separation issues that could advantageously be integrated into the design of chemical EOR project.
Experimental Study of Crude Oil Emulsion Stability by Surfactant and Nanoparticles
Authors: Almohsin Ayman. M , Alabdulmohsen Zainab , Bai Baojun , Neogi Parthasakha
Published: March 2018

Surfactants and nanoparticles are materials being widely used for enhanced oil recovery (EOR). Surfactants are mainly used to reduce the interfacial tension between oil and water which could form a stable film of emulsion between these two immiscible fluids. Also, nanotechnology is a potential candidate to offer another solution to improve oil recovery. Nanoparticles can form a solid layer at the droplet's interface and stand as resistant stabilizer under harsh reservoir conditions.

This research investigates whether the combination of surfactants and nanoparticles can form a stable emulsion than surfactants only. Two parts of experimental study have been done in this research. First part was implemented using three types of surfactant: nonionic surfactant with no charge group on its head, an anionic type carrying negative charge, and, cationic surfactant carries positive charge on the hydrophilic portion of the molecules in water. Second part was conducted using combinations of same surfactants mentioned above with nanoparticles. These nanoparticles are aluminum oxide (Al2O3) and silicon dioxide (SiO2). These two parts of experimental work were done using different ratios of water to oil from 1-9.

Results showed that nonionic surfactant through water continuous phase could reach stability with heavy oils up to 40°C reservoir temperature while cationic surfactant through oil continuous phase could form stability reaching more than 60°C reservoir temperature. Meanwhile, anionic type could break the emulsion within a few hours. More emulsion stability could be achieved by adding Al2O3 and SiO2 nanoparticles to nonionic. Adding Al2O3 and SiO2 nanoparticles to anionic and cationic could form emulsion stability based on different water to oil ratio.
Integration of Solar Steam Facilities with Existing Steam Generation Systems
Authors: Nellist M. D.
Published: March 2018

This paper reports on the start-up of Phase 1 of a Solar Steam Generation facility (SSG) and its export to the existing steam headers of the Amal oil field, located in the south of Oman. Significant considerations within the SSG are reviewed and the impacts on the client's systems identified and discussed.

Operational performance indicators on SSG and Client facilities are studied, primarily based on process operating data and equipment stability records, to ensure that the supply of variable steam from solar generation does not create any detrimental effects on the existing facilities. Of particular interest is to assess the success of a variable rate steam injection mode and the impact this has on Client facilities: system pressures, conventional steam generator operation, and wellhead steam injection rates.

Previous simulation work has demonstrated that this mode of operation is essentially equivalent to fixed steaming rates provided the same daily equivalent of steam is injected in both cases. However, this has never been demonstrated in the field for extended periods.

Operational data showed that, as anticipated, the Client's systems were able to accomodate the cyclic swings in header pressure and the induced variable flows through their fixed, manual chokes. Data showed that the Client's conventional steam generators (HRSGs) continued to operate as normal without noted issue.

The changing pressure in the Client's steam header propagated back to the solar steam generation facility which was able to easily manage its operations automatically, causing no disruptions to its operations. No safety-related incidents arose, and all processes were well-managed on-site.

This study demonstrates for the first time the performance of large-scale solar steam generation facilities operating alongside conventional steam generation and distribution systems with the two disparate systems seamlessly integrated. It also demonstrates that variable rate steaming has practical application within this field. This highly dynamic process has been sympathetically and successfully added to an existing large, steady-state operation without introducing significant issues to either system.
Polymeric Surfactant for Enhanced Oil Recovery- Microvisual, Core-Flood Experiments and Field Application
Authors: Li Binhui , Liu Zheyu , Fei Chunguang , Lv Jianrong , Chen Xin , Li Yiqiang
Published: March 2018

Phase separation, which decreases the synergistic effect, are observed during amount of surfactant/polymer (SP) or alkali/surfactant/polymer (ASP) flooding field applications and laboratory experiments. The idea of adding hydrophobic groups to a water-soluble polymer is to make polymeric surfactant that could be applied in Enhanced Oil Recovery (EOR). However, pole-scale displacement mechanisms and field performances of polymeric surfactant have not been investigated throughtly. In this work, we synthesized two types of polymeric surfactants and evaluated their physi-chemical properties, including chemical structure, rheological characteristic, emulsification and salt tolerance. Beside these physi-chemical property tests, a micro-visual model and core-flooding tests were performed to investigate the efficiency of polymeric surfactant flooding to recover the bypassed or trapped residual oil after water flooding. Finally, field performances of polymeric surfactant were estimated by monitoring the production dynamics and development index from a pilot test in Daqing oilfield. Results show that the polymeric surfactant has characteristics of strong viscosity, salt-resistance and emulsification. The high viscosity of the polymeric surfactant gurantantees a better mobility control than the ordinary polymer. What's more, the enhanced swept volume, emulsifiability and high elasticity makes the polymeric surfactant flooding has higher recovery factor than traditional polymer during chemical flooding. The heterogeneous core flooding experiments show that extra 10% overall recovery can be obtained with polymeric surfactant flooding after traditional polymer flooding. The application of the two types of polymeric surfactants in the pilot area shows that polymeric surfactants make the middle and low permeability zones absorb more water than traditional polymer flooding. If the surfactants were injected after water flooding, oil recovery can be improved by more than 20%, and significant reduction in water cut. With these unique properties and good performances for trials in the pilot test, polymeric surfactants can be considered as a replacement to the traditional polymer in highly heterogeneous reservoirs after water flooding or polymer flooding.
Feasibility Study of a Steam-Foam Process Application in Kuwait
Authors: Al-Murayri M. T. , Al-Sabah H. M. , Kamal D. S. , Hassan A. A. , Cuenca A. , Suzanne G. P. , Batot G. , Chabert M.
Published: March 2018

Steam foam processes can improve the thermal efficiency and overall economics of steam-based oil recovery methods. Foam reduces steam mobility, thus mitigating steam channelling and energy loss, particularly in presence of thief zones. This paper describes an integrated EOR study to develop a steamfoam process for the Ratqa Lower Fars (RQLF) heavy oil reservoir in Kuwait with more focus on chemical selection, formulation design and reservoir simulation.

A variety of foaming surfactants were extensively evaluated in the lab based on the reservoir properties and operating conditions of the RQLF reservoir. This involved lab evaluation of thermal stability, adsorption, foam generation ability and foam rheology to select appropriate foaming surfactants. In parallel, multi-well/pattern steam-flooding simulations were performed to investigate the benefits of injecting foaming surfactants with steam. Different scenarios were considered and simulated mainly by varying the timing, duration and foaming surfactant concentration.

A fit-for-purpose foaming formulation was successfully developed for the RQLF reservoir. Thermal stability of the selected chemicals was validated. Furthermore, the adsorption of the selected foaming formulation on reservoir rock using injection water was found to be very low. Long-term foam stability was also confirmed in the presence and absence of crude oil. Based on these results, high foam apparent viscosity is expected in the planned core-flood experiments that will be performed to validate the ability of the selected surfactants to generate robust foam.

Simulation results showed that using foaming surfactants with steam can delay steam breakthrough and increase oil production, thus reducing steam-to-oil ratio. Furthermore, simulation results showed that it is beneficial to inject foam shortly prior to steam breakthrough rather than injecting it at the onset of steam injection. Basic economic evaluation was performed and the results indicate that foam addition to steam makes steam-flooding more cost-effective.

This paper discusses, for the first time, the results of an integrated study to evaluate the application of a steam-foam process for the RQLF reservoir in Kuwait. Valuable insights are presented on the design and simulation of foaming surfactants that can be used to improve the performance of steam-based oil recovery methods. The findings of this study are expected to pave the way for potential field trials in the future.
Experimental Study of Urea-SAGD Process
Authors: Erpeng Guo , Hongyuan Wang , Oilfield Liaohe , Youwei Jiang , Yongrong Gao , Junhui Shi
Published: March 2018

Improving recovery factor and heat efficiency of SAGD process has always been the main pursuit of EOR technology. This paper will provide the experimental study results of urea assisted SAGD process in reducing the steam consumption and improving the sweeping efficiency of SAGD process.

Based on previous 1-D flooding test results, this paper futher discussed the advantage of urea-SAGD process with series of 2-D experiment. After evaluation of heat loss effect for SAGD with numerical simuatoin approach, 2-D high experimental study on urea-SAGD process experiment plan were carefully designed. 3 groups of 2-D SAGD experiment with different additives (including ammonia, CO2, urea) were run to evaluate the influence to SAGD process. The performance of different additives were compared. The effects of different products from urea were analyzed in detail.

Study reveals that SAGD process can be greatly influenced by urea. Urea can gradually decompose into ammonia and CO2 over 150℃. Great solubility of ammonia in water can effectively increase sweeping efficiency and decrease residual oil saturation. CO2 is soluble in crudes and can improve the oil water mobility ratio. The 2D experimeint results shows that CO2 can stay in the higher position of the model and drive the oil down to the producer. And ammonia-SAGD experiment also shows that the ammonia can imrove steam efficiency when pure steam can not sustain production in the experiment. Urea SAGD process shows and comprehensive advantage over conventional SAGD process. The decomposed CO2 and NH3 can jointly improve the sweeping volume and sweeping efficiency in SAGD process. The recovery factor of urea-SAGD process can as high as 75% while other runs (including CO2-SAGD, ammonia-SAGD and pure steam SAGD) of experiment no more than 50%. The improvement of ammonia to SAGD process is comparable with CO2, both of them can improve about 10~12% comparing to conventional SAGD process. With the result of this paper, urea can reduce the consumption of steam by 1/3 and improve the oil production by 30% when it was co-injected with steam in SAGD process.

This study provides a new and effective approach of improving SAGD performance with inexpensive chemical products.