The propagation of foam in an oil reservoir depends on the creation and stability of the foam in the reservoir, specifically the creation and stability of foam films, or lamellae. As the foam propagates far from in injection well, superficial velocity and pressure gradient decrease with distance from the well. Experimental (
In our experiments, nitrogen foam is generated in a core of Bentheimer sandstone. The foamgeneration experiments consist of measuring the critical velocity for foam generation as a function of gas fractional flow at three surfactant concentrations well above the critical micelle concentration. Experimental results show that critical velocity decreases with increasing liquid fraction, as shown by previous foam generation studies (
Many oilfields in Russia and CIS countries are in late development stage with waterflooding being deployed for decades. Most of these fields have rapidly increasing watercut, decreasing injectivity and productivity. Various methods of production optimization are used including well stimulation techniques – conventional and novel. One of relatively new technologies is the wave stimulation when the wellbore and reservoir are treated by acoustic, seismic or other type of wave generated by different tools.
These technologies have short treatment time, simple-to-use tools and work in different formations and wells. Tool placement (wellhead or downhole), wave frequency and generated energy differentiate methods. In this paper we focus on seismic impact well treatment when the wave generator is installed at wellheads. Energy is generated on the surface with compressed gas, released into well instantaneously. Shock wave propagates through liquid-filled well column and transforms into seismic wave in-situ. This allows scale and deposits removal in wellbore and near-wellbore area, positive modification of injection or production profile. Deeper in reservoir, seismic wave propagates at high velocity and mobilizes oil trapped behind natural flow barriers.
The impact of seismic wave stimulation on permeability restoration and improvement, water injection profile and oil displacement have been modeled in laboratory experiments and modeled with the software. Few generations of tools have been used in the field operations. Recently, seismic stimulation has been combined with chemical treatment: acid, alkaline, surfactant, gas-generating agents or combination of these. Mechanistic supplement of chemical injection allows deeper and uniform distribution of chemical agent and larger contact zone. There is some synergy between seismo-chemical stimulation and enhanced oil recovery (EOR) methods. To date, injection and production wells (both vertical and horizontal) have been treated in various fields across Russia, Europe and Asia. There is a large range of temperature, salinity, perforation interval of treated wells; formation depth in these fields is up to 3.5 km, reservoir permeability from 5 mD. On average, stimulation of injectors increased injectivity by 85% for 18 months that led to incremental oil rate of 30% in treated pattern (around 45,000 bbl/treatment). Averaging producers’ treatment results gives 65% increase in oil rate (total 12,000 bbl/treatment), effect lasting for 22 months. Typical unit technical cost (UTC) in these operations was below 2$/bbl. As a rule of thumb, seismo-chemical treatments have larger UTCs and deliver higher increase in injectivity and productivity indices.
The mechanisms, experimental procedures, field application history of seismic and seismo-chemical well stimulation are reviewed and presented. With around 250 wells treated, there is a high success rate and oil production increase. New generation of this improved oil recovery (IOR) technique combines benefits of mechanistic well stimulation, acid and/or chemical enhanced oil recovery.
Zhang, Fan (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development, Beijing) | Luo, Wenli (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development, Beijing) | Yang, Siyu (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development, Beijing) | Zhang, Qun (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development, Beijing) | Zhu, Youyi (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development, Beijing) | Zhou, Zhaohui (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development, Beijing) | Tian, Maozhang (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development, Beijing)
Chemical flooding technique of alkali-surfactant-polymer (ASP) has been successfully applied in China for sandstone reservoir. However, challenges to develop chemical EOR formulations without alkali are significant and unique for both sandstone and carbonate reservoir. On the one hand, it is very difficult to achieve ultra-low interfacial tension and good oil displacement effect without the help of alkali. On the other hand, the oil types, rock mineral compositions, rock surface property, matrix pore structure and orientation are all different for sandstone and carbonate reservoir. In fact, the ASP technologies successfully used in Daqing sandstone oilfield cannot be simply extrapolated to SP combination flooding and carbonate reservoir. The key technology is development low cost and high efficiency surfactant and polymer.
In this paper, the new surfactant/polymer formulation has been developed, and show good properties for both sandstone and carbonate reservoir. The novel sulfobetaine with intellectual property has been obtained with raw material of cheap fatty acid, and the carbon-carbon double bond can improve the solubility and emulsifying property. The star-shaped polymer has been developed, and could effectively increase the rigidity of polymer molecular chain and the regularity of molecular structure, which can make the curliness of polymer chain become difficult, and increase the revolving hydraulic radius of molecular chain. The new surfactant/polymer formulation had wide adaptability and could achieve ultra-low interfacial tension (IFT, less than 1.0×10−2mN/m) in different sandstone and carbonate reservoir conditions, and the temperature were from 45 ℃ to 90℃, and the salinity were from 4,500 mg/L to 100,000 mg/L. The SP system has good long term stability at different reservoir conditions. The IFT results were in the range from 10−4mN/m to 10−3mN/m with duration of 180 days, and the retention rates of viscosity were more than 90%. The new surfactant/polymer formulation had good emulsifying capacity, and emulsion Winsor III was observed. It could change the wettability from oil wet to water wet, and had good stripping film capacity. The alkali-free SP formulation showed good oil displacement effect. After water flooding, it could increase oil recovery 21.5% (OOIP) in Daqing oilfield in China for sandstone reservoir; for carbonate reservoir, it could increase oil recovery 23.42% (OOIP) in the oilfield of Middle East.
The novel sulfobetaine with intellectual property has been obtained with raw material of cheap fatty acid, and the carbon-carbon double bond can improve the solubility and emulsifying property.
The star-shaped polymer has been developed, and could effectively increase the rigidity of polymer molecular chain and the regularity of molecular structure, which can make the curliness of polymer chain become difficult, and increase the revolving hydraulic radius of molecular chain.
The new surfactant/polymer formulation had wide adaptability and could achieve ultra-low interfacial tension (IFT, less than 1.0×10−2mN/m) in different sandstone and carbonate reservoir conditions, and the temperature were from 45 ℃ to 90℃, and the salinity were from 4,500 mg/L to 100,000 mg/L.
The SP system has good long term stability at different reservoir conditions. The IFT results were in the range from 10−4mN/m to 10−3mN/m with duration of 180 days, and the retention rates of viscosity were more than 90%.
The new surfactant/polymer formulation had good emulsifying capacity, and emulsion Winsor III was observed. It could change the wettability from oil wet to water wet, and had good stripping film capacity.
The alkali-free SP formulation showed good oil displacement effect. After water flooding, it could increase oil recovery 21.5% (OOIP) in Daqing oilfield in China for sandstone reservoir; for carbonate reservoir, it could increase oil recovery 23.42% (OOIP) in the oilfield of Middle East.
This paper presents the new alkali-free surfactant/polymer combination flooding green technology, which provide promising chemical EOR technique for both sandstone and carbonate reservoir.
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.
Kuwait Oil Company (KOC) has undertaken implementation of an Alkali-Surfactant-Polymer EOR pilot in probably the world's first carbonate reservoir in Sabiriyah Mauddud reservoir with billions of barrels in oil-in-place. This project in the North Kuwait area is being pursued with the help of industry experts in chemical EOR who are involved in conceptualization, pre-planning, pilot design and execution. A normal 5-spot, 5.5-acre pilot is presently operational since June 2017 with water injection in progress.
Encouraged by the excellent results of a series of Single Well Chemical Tracer Tests and of course and of course not unmindful of the risks, the company looks at this pilot as a ‘game changer’ with huge potential to enhance and sustain the North Kuwait oil production and reserve growth. It follows a path where an early lead could not only give it a distinct advantage in terms of achieving its goals but also create favorable conditions for commercial potential of this new technology. The decision to go ahead with this project is certainly backed an ambitious leadership with an appetite for entrepreneurial risk-taking and determination to succeed.
Commercial excellence in frontier technologies such as this would be determined after full evaluation of the ongoing or more pilots as necessary since there are no preexisting benchmarks for comparison.
The project continues to test and challenge the capabilities of individuals and the organizations alikeresearch financing, customization of chemical recipe for the reservoir, project logistics and economics being so demanding.
KOC views EOR as an opportunity to achieve its strategic medium and long-term objectives. The plan is to acquire and direct the cutting-edge technology of ASP flooding for unleashing the full production potential of its reservoirs to meet its 2040 strategy objectives.
It is well-established that smartwater flooding through tuning of injection water chemistry and ionic composition, has a significant impact on the recovered oil, but the exact underlying mechanism by which this occur, is not well understood, and is supposed to be caused by a complex interactions occurring at the fluid/fluid and fluid/rock interfaces. Most of the laboratory studies reported so far have been focused on characterization of crude oil/brine/carbonate system and wettability alteration at micro- and macroscale using classic measurements, including contact angle, IFT, NMR, zeta potential and coreflooding. However, those techniques depend strongly on carbonate heterogeneities, roughness and fluids distribution inside the pores. Thus, a direct visualization at pore scale is needed to identify fluids distribution in-situ, wettability state at pore scale and wettability alteration by injection water composition tuning. We used Broad Ion Beam slope-cutting in combination with Scanning Electron Microscopy under Cryogenic conditions (Cryo-BIB-SEM) to study crude oil/brine/carbonate interfaces. Direct imaging at nanoscale allows investigation of the porosity, in-situ preserved fluids and, combined with energy dispersive spectroscopy (EDS) identify crude oil and brine distribution and quantifies wettability state by measuring contact angle at pore level. In this study, we compare carbonate rocks that have been aged in crude oil and saturated with brines at high and low ionic strength brines. In both samples, we investigate oil and brine distribution in the carbonate porous matrix. Results show that ion milling at cryogenic conditions allows the preparation of a large smooth cross-section. The presence of pinning points contribute to the crude oil adherence to carbonate surface. Scanning electron microscope images indicate that in presence of high ionic strength brine, large trapped oil patches have an elongated shape, following the carbonate surface morphology. While oil droplets have a pseudo-spherical shape with low ionic strength brine in addition to a distinct boundaries between oil and brine phase. Statistical analysis of in-situ contact angle and carbonate/oil/brine interface demonstrate the sensitivity of cryo-BIB-SEM approach to sub-micron scale wettability alteration caused by ionic strength variations.
Kuwait Oil Company (KOC) is operating two Heavy Oil fields. Field A aims at production by Cyclic Steam Stimulation (CSS), followed by steam flood. Field B envisages primary recovery through cold production, followed by non-thermal Enhanced Oil Recovery (EOR). This requires drilling and completion of large number of wells. Implementing Well, Reservoir and Facilities Management (WRFM) and Smart Field approach will be a key requirement for operation excellence in these fields.
Currently both fields have some wells in production, mostly as single isolated wells or wells in 5-acre/10-acre spacing. These pilot projects aimed at de-risking the commercial phase, which is to follow in the coming years. These wells are the training ground for young KOC staff to learn how to work in integrated teams using WRFM processes.
WRFM processes are tailor-made for KOC's operating environment. These processes include Digital Oil Field based on Exception Based Surveillance (to flag out only those wells and facilities outside of their operating envelope and/or optimization window) and Production System Optimization. This would help to eliminate operational bottlenecks, leading to optimization in manpower to deal with large number of wells. It is expected to be achieved by combining existing best practices of International Oil Companies (IOC) with existing KOC applications, leveraging successful global practices.
The paper shall highlight the timeline, activities and organizational changes underway to effect the transformation from existing operation to a larger and more complex development that includes continuous drilling, completion and well intervention (CWI) and facilities installation occurring simultaneously.
The implementation of WRFM Processes along with Digital field will achieve the production and operation goals by reducing well, artificial lift, and facility downtime. This innovative production optimization system by enabling efficient decision-making process shall lower the cost per bbl. and reduce down time by implementing automated surveillance workflow.
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.
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.
The shortage and high cost of CO2 and/or HC gases makes chemical EOR a practical option for tertiary oil recovery in carbonate reservoirs. ASP formulations continue to evolve to withstand challenges in relation to reservoir heterogeneity, complex mineralogy, high temperature and high formation water salinity. This paper sheds light on the application of chemical EOR in carbonate reservoirs. The performance of chemical EOR in a Kuwaiti carbonate reservoir was evaluated through an ASP coreflood experiment using a composite core. This paper presents the modeling steps of this ASP flood, as well as the workflow to calibrate it with the resulted experimental data.
The carbonate composite core was first seawater flooded until residual oil saturation, Sorw, was achieved. The ASP coreflood started with low rate pre-flushing using softened seawater. The flood continued with the ASP slug, and ended by injecting multiple pore volumes of polymer solution for mobility control. This resulted in a 90% reduction in Sorw. A 1-D compositional model was developed to model the linear ASP coreflood using, CMG-GEM™ simulator. The study is composed of two parts, modeling the ASP chemical EOR process, and calibration of the model to the experimental results of the coreflood.
The modeling part of this paper captured the vital mechanisms involved in the ASP chemical EOR process. The modeling workflow captured the micro-emulsion phase behavior, surfactant solubility ratios and resulting IFT measurements, soap generation by naphthenic acids of the crude oil reacting with the injected alkali. Additionally, the workflow considered the effect of geochemistry, salinity gradient, surfactant and polymer adsorption on the process as well as the rheological behavior of polymer solutions.
The calibration part of this study followed a stepwise procedure to calibrate the model by first matching the water flood results followed by matching the ASP flood results. The paper discuss the required changes made on waterflood relative permeability curves to match Sorw and pressure differential resulted from the water flood stage. The paper also presents the changes on surfactant adsorption, micro-emulsion viscosity; the capillary number based relative permeability interpolation process, and the wettability modifications criteria to match the ASP flood results. The matched results included the flood oil recovery, oil cut, average oil saturation of the composite core, flow pressure differential, and the concentration of chemical effluents traced during the experiment.
This paper deals with coreflooding and modeling of ASP flooding in the difficult environment of carbonate reservoirs. The profile of ASP oil recovery in this carbonate composite core is more gradual, and it is different from those experienced in sandstone corefloods. This is accounted for by additional changes made to relative permeability curves moving from oil wet to water wet conditions.