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.
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.
Reduction of heat injection rate is a common practice in steam flood projects to reduce fuel cost and extend project economic life. Fuel consumption reduction can be achieved either by reducing the injected mass rate at same steam quality or reducing steam quality at same mass injection rate. This paper presents literatures review on this topic, analysis and observations from field data in a major steam flooding project south of Oman. Injectors wellhead temperature and pressure was used to identify saturation status of injected fluid and correlate count of hot water injectors with changes in surface pipelines steam quality. Portable steam quality measurement units were utilized to obtain numerous surveys to analyze changes in injectors wellhead steam quality as results of field average generated steam quality. In addition, conceptual pattern simulation model was created for purpose of investigating the impact of reducing surface steam quality compared to reduction of injected mass with total injected head preserved. Results and conclusions are presented to illustrate the impact of the compared steam optimization methods. Clear correlation was observed from both, field data analysis and reservoir modeling work and produced water cut changes. Comprehensive analysis is presented to demonstrate the relation between steam quality distribution at injectors' wellheads and changes in surface injection lines average steam quality and the count of sub-saturated water injectors.
This paper presents laboratory studies to apply a new approach based on combined foam EOR processes to a naturally fractured carbonate reservoir (NFR) located in Oman. Applications of EOR techniques in fractured reservoirs, despite their attractive potential, have always been challenged by the inability to efficiently control EOR fluid mobility in fractures, which results in inefficient flooding of the reservoir matrix and poor economics of the process. This work discusses the maturation of efficient foam EOR processes for NFRs. The foam is aimed at blocking aqueous solution flow in fractures on the one hand while allowing low interfacial tension (IFT) solution to enter the matrix on the other hand.
We use an extensive experimental workflow to develop such solution in the challenging salinity conditions of the considered reservoir. Using robotics, we first combine low-IFT and foam boosting surfactants to come up with the most adapted chemical cocktail in terms of solubility, IFT with crude oil and foaming properties in hard brine. The selected formulation is then quantitatively characterized for IFT with crude oil, phase behavior with live oil, foam stability in reservoir pressure and temperature conditions, and foaming properties in model porous media. Dedicated coreflood experiments mimicking flow in fractured reservoirs are finally used to quantitatively evaluate the process using the designed formulation. This includes evaluation of foam-induced pressure drop, effluent fluid composition and oil recovery in artificially fractured cores.
The designed combined foam EOR formulation is perfectly soluble in hard brine and yields an IFT with crude oil well below 10-2 mN/m at 65°C. It is able to generate and stabilize foam both in absence and in presence of crude oil. Process evaluation in artificially fractured core shows good control by foam of aqueous solution mobility in fracture, and efficient imbibition of aqueous solution from fracture to matrix. Interestingly, a filtration effect is observed whereby only aqueous solution enters the matrix from the fracture, while foam only exists in fracture. This, combined with the sensitivity of foam to presence of oil, enables an efficient production of oil from the matrix through the fracture, as measured during recovery experiments.
This paper presents the first steps toward a potential pilot application of a new process aimed at making chemical EOR in fractured carbonate technically and economically feasible. The approach presented here allows the design of a performing process in challenging conditions of water salinity and hardness.
Erpeng, Guo (Research Institute of Petroleum Explortaion & Development, CNPC) | Yongrong, Gao (Research Institute of Petroleum Explortaion & Development, CNPC) | Youwei, Jiang (Research Institute of Petroleum Explortaion & Development, CNPC) | Yunjun, Zhang (Research Institute of Petroleum Explortaion & Development, CNPC) | Zhigang, Chen (Changqing Oilfield, CNPC) | Yao, Wei (Development Management Department, Liaohe Oilfield CNPC)
Thermal recovery process is widely adopted in exploitation of heavy oil reservoirs. But for extra-heavy oil reservoirs with bottom water and depth more than 800m, effective recovery is not achieved with steam injection. SAGD (Steam assisted Gravity Drainage) process is tested in such reservoirs but showed poor performance because of high reservoir pressure and bottom water. This paper proposed a new approach which is utilizing super critical hydrocarbon gas to replace most part of steam during steam injection and SAGD process for exploitation of such reservoirs.
Calculations of heat distribution along the steam injection tube were carried out. The solubility of supercritical hydrocarbon gas in heavy oil was tested with PVT apparatus. Also the viscosity reduction effect of super critical gas is also tested. SAGD simulation with high mole percent of gas injection was carried out with theoritical model. Different operation strategy including pure steam, supercritical CO2 and steam co-injection, wet gas and steam co-injection was compared with numerical simulation.
The main theory of this approach is that injected gas can greatly decrease partial pressure of steam hence reduce the heat loss and drawdown of quality during injection. The results shows that the heat loss can be decreased by 40% in steam injection tubing. At super critical conditions, solubility of gas in heavy oil is almost 100m3/m3. Viscosity of heavy oil saturated with gas will be lower than 200mPa.s at 150℃which is 80% less than that without gas. The viscosity is already low enough for drainage process. High pressure SAGD experiment shows that temperature decreases gradually from the inner part to the out range of steam chamber when injected mole percent of gas is 20%. This means the decrease of steam saturation pressure related to partial pressure of steam because injected gas will take the corresponding pressure in steam chamber. The recovery process shows high recovery factor which is similar to SAGD process. And steam oil ratio is 0.8~1.2 which is much lower than any existing pure steam injection SAGD process. Simulation results shows that during the operation process bottom water will not flux into steam chamber after the balance between reservoir and bottom water was achieved.
This paper provides an effective approach to exploit the heavy oil reserves with great depth which is meaningful for reducing the steam consumption and operation cost for oil industry.
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.
Wever, D. A. Z. (Shell Global Solutions International) | Bartlema, H. (Shell UK) | ten Berge, A. B. G. M. (Shell Global Solutions International) | Al-Mjeni, R. (Petroleum Development Oman, Sultanate of Oman) | Glasbergen, G. (Shell Global Solutions International)
Polymer retention in porous media can significantly delay the arrival of the oil bank. This delay erodes value and affects the economics of any potential polymer project. In this paper, the
The results of the coreflood experiments demonstrate the effect of the presence of oil on the retention of polymer in porous media. Corefloods without oil show polymer retention values that are much higher than values in the presence of oil.
This suggests that injecting polymer slugs below the oil-water contact could potentially result in a delay in the breakthrough of polymer and the arrival of the associated oil bank, which in turn could have significant detrimental effects on the economics of a commercial polymer project. In the experimental program to de-risk polymer flooding for full field commercial projects comprising polymer injection in oil legs, corefloods to assess polymer retention should always be executed with (residual) oil present.
The objective of this paper is to present the learning and the challenges from operating the largest offshore high pressure water alternating hydrocarbon gas injection (HC-WAG) pilot, with injection capacity of approximately 100 mmscf of gas injection per day in the giant Al-Shaheen field offshore Qatar. The paper also aims to share the methodology for analyzing the current HC-WAG pilot and optimizing the future development scenarios for extending the HC-WAG to the field scale.
Al-Shaheen field, offshore Qatar, is a giant complex carbonate oil field characterized by thin oil column, low permeability, and large lateral variations in fluid properties, see Reference [
Although WAG has been around for some time, the industry focus has been mainly on miscible WAG, and the vast majority of these WAG fields have been onshore, see references [
This paper summarizes the learning from evaluation of production and optimization strategy of the HC-WAG pilot based on various parameters related to operating such a pilot. The main evaluation parameters included are GOR constraints, WAG cycle lengths, composition of injected gas and the overall length of the project with regards to project economics. We will show that optimizing HC-WAG operations results in significant benefit for operating an offshore immiscible HC-WAG. The benefits are quantified in terms of incremental oil recovery & managed GOR from an optimized HC-WAG versus an un-optimized HC-WAG. The paper quantifies the impact of incremental oil based on WAG cycle length, the total WAG project duration, the WAG ratio, the total injectant slug size, tapering of the WAG cycle and injected gas composition. This paper is the first attempt to present the learning and challenges from one of the largest offshore high pressure HC-WAG pilot, currently being carried out in Al-Shaheen Field offshore Qatar, which has never been presented previously to the best of author's knowledge.
The paper is divided into two parts, first part of the paper details the on-going WAG pilot and its background and the details of the lesson learnt from operating current WAG patterns. Second part details the strategy for optimizing future WAG developments in the field for full field WAG implementation.
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.