Jahanbakhsh, A. (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University) | Sohrabi, M. (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University) | Fatemi, S. M. (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University) | Shahverdi, H. (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University)
Gas/oil interfacial tension (IFT) is one of the most important parameters that impact the performance of gas injection in an oil reservoir. The choice or design of the composition of the gas injected for EOR is usually affected by the gas/oil IFT. In conventional reservoir simulation, IFT does not explicitly appear in the equations of flow and therefore its effect must be captured by the shape and values of relative permeability curves. A few studies have been previously reported for IFT effect on two-phase flow but very little have been done to investigate gas/oil IFT effect under three-phase flow conditions. The objective of this study is, firstly, to investigate the impact of gas/oil IFT reduction on two- and three-phase relative permeabilities using coreflood experiments. Secondly, to investigate the effect of changing gas/oil IFT value (immiscible and near-miscible) on the performance of WAG injections and residual oil saturation reduction at laboratory scale.
Two- and three-phase (WAG) coreflood experiments have been performed on water-wet and mixed-wet cores at three different gas/oil IFT conditions. These experiments were conducted on Clashach sandstone cores with a permeability of 65 and 1000 mD. The two- and three-phase relative permeabilities were estimated from the results of the coreflood experiments using our in-house software (3RPSim) and were compared with each other on the basis of their gas/oil IFT values. Moreover, the impact of gas/oil IFT reduction on the performance of gas and WAG injection and in particular on the reduction of residual oil saturation was investigated. The results of our studies were also compared with the existing literature on the laboratory investigation of WAG injection.
The results show that in two-phase gas/oil systems, the relative permeability of non-wetting phase is more affected by a reduction in the gas/oil IFT compared of the relative permeability of the wetting phase. Comparing the curvature of the gas and oil relative permeability curves shows that although the curvature decreases by a reduction in gas/oil IFT but it is still far away from straight line even at ultra-low IFT values. In three-phase flow system, reduction of gas/oil IFT affects the relative permeabilities of all the three phases (gas, oil and water).
The results show that at high gas/oil IFT or immiscible WAG injection, the most reduction in residual oil saturation is achieved in the first injection cycle and further WAG cycles do not result in a significant additional reduction in oil saturation. On the contrary, at low gas/oil IFT or near-miscible WAG injection, the residual oil saturation keeps decreasing as the number of WAG cycles increases. Moreover, the reduction in residual oil saturation was more effective when the immiscible WAG experiments started with gas injection (secondary WAG).
Piñerez T., Iván D. (University of Stavanger) | Austad, Tor (University of Stavanger) | Strand, Skule (University of Stavanger) | Puntervold, Tina (University of Stavanger) | Wrobel, Stanislaw (University of Stavanger) | Hamon, Gérald (Total E&P)
Low salinity water injection in sandstone is an emerging technology just on the verge of being implemented full field in the UK and in Alaska, USA. Laboratory studies are important for providing relevant and well interpreted data before performing the field trial. However, laboratory investigations show varying results on low salinity EOR, most probably because of a limited understanding of the nature of the process. Recently we have published a "Smart Water" EOR mechanism where pH changes at the rock surface is inducing the wettability alteration, improving positive capillary forces and microscopic sweep efficiency. Researchers have experienced rather poor low salinity EOR effects from 17 different sandstone outcrops from the USA.
In this work we have investigated 6 of the same 17 outcrops, and according to our chemical understanding, some factors are more important for observing LS EOR effects in sandstone. It is the increase in pH, ?pH, obtained when the high salinity (HS) formation water is displaced by the low salinity (LS) injection water, and it is the initial pH and the amount of active cations (Ca2+) in the formation water that are related to the initial wetting.
We have established a link between the poor low salinity EOR effect from all 6 outcrops and the corresponding pH change observed when switching from high salinity to low salinity injection water. The presence of different types of minerals such as clay, feldspars and anhydrite will influence the pH change, and must be taken into account. Additionally, we have seen that the formation water composition has strong influence on the low salinity EOR effect. Using a formation water with salinity like seawater (FW1 ~35 000 ppm) showed only a minor tertiary low salinity EOR effect, 0.74 %OOIP, corresponding to a low pH gradient of 0.5. While experiments using a high salinity formation water (FW2 ~100 000 ppm) showed a 5 % OOIP recovery, corresponding to a larger pH gradient of 2.0.
The results observed are in agreement with the suggested chemical mechanism for the low salinity EOR effect, confirming that it is the pH gradient that triggers the low salinity EOR effect. In addition, the pH screening test used in this work proved once again to be a reliable tool to evaluate the low salinity EOR potential.
Wu, Xingcai (Research Inst. of Petroleum E&D, RIPED, CNPC) | Yang, Zhongjian (Qinghai Oilfield Company, QOC, CNPC) | Xu, Hanbing (RIPED) | Zhang, Lihui (QOC) | Xiong, Chunming (RIPED) | Yang, Huazhen (Huabei Oilfield Company, HOC, CNPC) | Shao, Liming (RIPED) | Kang, Bo (Chengdu North Petroleum E&D Technology Co. Ltd.) | Fu, Yaxiu (HOC) | Tian, Xiaoyan (Startwell Energy Co. Ltd) | Cao, Huiqing (HOC)
Though polymer flooding is widely considered as a good EOR method for heterogeneous fields, it's always a difficulty to be applied in high temperature and high salinity reservoirs, limited by polymer property. GS-E31 reservoir in West China has ultra-high temperature, 258.8°F (126°C), and ultra-high salinity, 18×104mg/L. It is highly heterogeneous, developed with flowing channels. Starting in July 2012, a new polymer (SMG) flooding was pilot tested, with success technically and economically.
Before SMG injection, tracer test was conducted in the pilot, figuring out the distribution position and direction of prevailing flowing channels. The microscopic pore structure and size were studied. The temperature and salinity resistance of the new particle-type polymer under reservoir condition was tested. The oil displacing effect was simulated on parallel dual core model. For the pilot test, two slugs with different particle sizes were designed. To guarantee the flooding effect, a preposed PPG (preformed particle gel) slug with larger size was designed to inhibit prevailing flow channels.
The lab studies showed the new polymer particles kept stable appearance within 100 days under the reservoir temperature and salinity, denoting high capacity of temperature and salinity resistance. And by physical simulation it could obtain EOR of 12.3%. The pilot test was started in July 2012 and ended in December 2013, and the total liquid injection amount was 12.2×104m3, which was 0.1 PV. During operation, the polymer particle size and concentration were adjusted based on the observing data. As a result, the monthly oil rate of the pilot was increased from 1313 t to 2049.6 t, with increase of 736.6 t; and the water cut was decreased from 91.7% to 84.1%. The cumulative oil incremental was 1.03×104t, and the cumulative water production decrease was 4.79×104m3. The input-output ratio was 1:2.09. Though the economical result was not ideal, it was still acceptable under such severe reservoir conditions. Besides, the surveillance showed the preposed channeling inhibition slug did not perform well, which affected the NPF effect, and especially led to the quick water cut rising in the follow-up water injection phase.
Summarizing the lat studies and pilot tests, the new particle-type polymer has obtained a large breakthrough for temperature and salinity resistance comparing to traditional polymer, and the EOR mechanism is different. The matching relationship between particle size and formation pore size is very important for polymer flooding effect. To further study on lab evaluation method and plan optimization is needed. The technology has important referencing meaning for efficiently developing high temperature and high salinity fields.
Guo, Hu (China University of Petroleum) | Li, Yiqiang (China University of Petroleum) | Gu, Yuanyuan (China University of Petroleum) | Wang, Fuyong (China University of Petroleum) | Yuliang, Zhang (Research Institute of Xinjiang Oilfield Company, CNPC)
ASP flooding is one of the most promising EOR technologies. Lots of laboratory studies and pilot tests have been finished in Daqing oilfield which is the largest oilfield in China. Comparison of two typical strong alkali ASP (WASP) and weak alkali ASP (SASP) pilots are presented with detained information.
ASP flooding could not only remarkably improve displacement efficiency but also improve sweep efficiency due to the low interfacial tension effect and mobility control technique with help of viscosity enhancement and emulsification effects. The incremental recovery of two ASP was near, while in peak oil production period after the injection took effects, WASP had high oil production rate than SASP. The emulsification effects in weak alkali ASP was weaker than strong one. The chromatographic separation was different in two pilot tests, in which weak alkali ASP had alleviated chromatographic separation. The constitution production sequence was both polymer first, then alkali and finally surfactant. The time gap between surfactant and polymer was about 0.0606 PV for strong alkali ASP, while a respective value of 0.1281PV for weak alkali ASP. Scaling was different and thus anti-scale technique adopted in two pilot tests were a little different. The overall input-output ratio for two tests was different and weak alkali ASP performed much better. Comparison was first made between strong alkali and weak alkali based ASP flooding from field tests perspective. Weak alkali based ASP is proven the development trend.
MEOR (microbial enhanced oil recovery) is known as one of the emerging low-cost EOR technologies, which uses in-situ microorganisms living in the oil field. Some of the most promising microbial-induced mechanisms include production of extracellular polymeric sugars (EPS), biofilms as well as selective plugging caused by cell growth. However, there is limited data available concerning the way microbes and biofilms behave in contact to surfaces in porous media in the context of MEOR. The aim of this work was to investigate bacterial growth and biofilm production in the framework of an ongoing MEOR project conducted by Wintershall and BASF. We used various approaches to investigate cell behavior of a halophilic bacterial community derived from a Wintershall oil field. Bacterial growth was conducted in both batch cultures and under dynamic conditions. To visualize cell adhesion and also exopolymers occuring in biofilms we used specific fluorescent dyes. During incubation of the microbes over several weeks we could visualize different types of EPS under the microscope. This observation fits perfectly to a concurrent viscosity increase of the surrounding media. Modelling approaches were applied to estimate the potential contribution of these effects on additional oil recovery. The observations including cell clumping, sorption and polymer production were geometrically quantified and the effect of the modifications on permeability profile and resulting flow characteristics was numerically investigated with fluid dynamic simulations of the petrophysical changes. The potential implications of the observed changes on EOR capability by conformance control and wettability modification were further estimated with analytical approaches. With the developed methods for visualization and modelling of the microbes and biofilms in both batch and dynamic conditions, we are able to monitor the clumping and sorption behavior of the cells, which will help to interprete data obtained during an upcoming MEOR field trial.
Alkan, H. (Wintershall Holding GmbH) | Klueglein, N. (BASF SE) | Mahler, E. (BASF SE) | Kögler, F. (Wintershall Holding GmbH) | Beier, K. (Freiberg University) | Jelinek, W. (Wintershall Holding GmbH) | Herold, A. (BASF SE) | Hatscher, S. (Wintershall Holding GmbH) | Leonhardt, B. (Wintershall Holding GmbH)
This paper provides an update on a microbial enhanced oil recovery (MEOR) project conducted by Wintershall and BASF. Overall nutrient development and planning of a single well field trial (huff'n'puff, HnP) including risk management are described. A nutrient solution is tailored to stimulate growth and metabolite production of a reservoir community of various indigenous microbial species in a Wintershall operated oil field with challenging reservoir characteristics, including high salinity (160,000 ppm). Up-scaled imbibition experiments performed with sandstone cores using MEOR-oil systems are compared with injection brine-oil systems and assessed for the implications on incremental oil. The results of sandpack and coreflood experiments performed with optimized nutrient solutions are discussed regarding incremental oil recovery and responsible EOR mechanisms. A MEOR modelling concept developed using STARS/CMG is used to estimate additional oil production under various feeding strategies after the calibration of the EOR mechanisms assigned.
As the laboratory and numerical works have indicated the feasibility of the MEOR field application, emphasis has been put on risk issues ranked in the register of the project. The key risk is potential souring of the reservoir due to the activation of the sulphate reducing bacteria (SRB) growing on the metabolites generated by the MEOR target community. Conventional mitigation measures have been tested in short and long-term experiments. An innovative solution had been developed to assure H2S free application without any consequences to the reservoir and to the MEOR application.
A single well pilot application is planned in a pre-selected well of the Wintershall field studied with two main objectives: (1) proof of the concept of risk mitigation and (2) stimulation of growth and metabolite production. Identification of operational issues as well as data gathering to improve the forecasting methods towards full-field predictions are secondary objectives. A monitoring plan has been initiated to establish a baseline in terms of microbiological and petro-dynamic parameters. Temperature and volumetric distributions have been predicted based on the results of an injectivity test performed in the well. The data is used to design the HnP operation and the surface setup for the injection rate of 100 m3/day nutrient solution under well-defined conditions.
Imqam, Abdulmhsin (Missouri University of Science and Technology) | Wang, Ze (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology) | Delshad, Mojdeh (The University of Texas at Austin)
Preformed particle gels (PPG) have been successfully applied as a plugging agent to solve the conformance problem in fractured reservoirs. They are injected to plug fractures and then divert displacing fluid into poorly swept zones and areas. However, PPG propagation and plugging mechanisms through open fractures have not been studied thoroughly. This paper investigated the influence of some factors (particle size, brine concentration, heterogeneity, injection flow rate, and brine salinity) on gel injectivity and plugging performance for water flow through opening fractures. Five-foot tubes were used to mimic opening fractures. Three models were designed to gain understanding on how fracture geometry and PPG properties affect gel injection and plugging efficiency, including (1) single fracture with uniform fracture width, (2) single fracture with different widths, and (3) two parallel fractures with different width ratios between each other. Results from single uniform fracture experiments showed that PPG injection pressure was more sensitive to gel strength than gel particle size. When large PPG size and high gel strength were used, high injection pressure and large injection pore volume were required for PPG and brine to reach fracture outlets. Results from single heterogeneous fracture model experiments showed PPG injection pressure increased as the fracture heterogeneity in sections increased. Particle gel accumulated at the choke point within each fracture and caused injection pressure to increase accordingly. Furthermore, results showed that having a lower salinity within a fracture, which was less than the brine salinity that was used to prepare PPG, would improve the PPG plugging efficiency for water flow. Parallel fracture models results showed that when weak PPG was used, a large volume of PPG flowed into a large fracture width and a small portion of the gel particle volume flowed into small fracture width. However, with increased gel strength and fracture width ratio, PPG only flowed through larger fracture widths. This paper demonstrates important impact elements of gel propagation and water flow for different opening fracture situations.
SmartWater flooding through injection of chemistry optimized waters by tuning individual ions is recently getting more attention in the industry for improved oil recovery in carbonate reservoirs. Most of the research studies described so far in this area have been limited to studying the interactions at rock-fluids interfaces by measuring contact angles, zeta potential, and adhesion forces. The other widely reported interfacial tension data at oil-water interfaces do not consider the formation of interfacial monolayer and the interfacial tension is estimated as an average parameter relying on the properties of two individual bulk phases. As a result, such measurements have serious shortcomings to provide any details on complex microscopic scale interactions occurring directly at the interface between crude oil and water to understand the SmartWater flood recovery mechanism.
In this study, two novel interfacial instruments of interfacial shear rheometer and surface potential sensor were used to study microscopic scale interactions of various individual water ions at both air-water and complex crude oil-water interfaces. The measured interfacial rheology data indicated totally different interfacial behavior at crude oil-water interface when compared to air-water interface due to presence of crude oil functional groups. Viscous dominated response was observed at crude oil-water interface for all brine compositions. These interfaces behaved like a viscous fluid without exhibiting viscoelastic solid like properties. Lower interfacial viscous modulus was observed for certain key ions such as calcium, magnesium, and sodium. The interfacial viscous modulus was found to be substantially much higher for sulfates, besides exhibiting some elasticity. The surface potential was gradually decreased by replacing seawater with calcium only brine. The better surface activity with seawater can be attributed to adsorption of more key water ions at the surface.
The interesting results observed with certain water ions at fluid-fluid interfaces are expected to work in tandem with rock-fluids interactions to impact oil recovery in SmartWater flood. At first, they play a role to control the accessibility of active water ions to approach the rock surface, interact with it and subsequently alter wettability. Next oil droplets adhering to the rock surface will be detached and released due to favorable interactions occurring at rock-fluids interfaces. The interfacial film between oil and water can then quickly be destabilized due to less viscous interfaces observed with certain ions to promote drop-drop coalescence and easy mobilization of released oil droplets. This coalescence process is sequential and it would continue until the formation of small oil bank.
This is the first study that showed added importance of fluid-fluid interactions in SmartWater flood by using direct measurements on individual water ions at crude oil-water interface. In addition, a new oil recovery mechanism was proposed by combining both the interactions occurring at fluid-fluid and rock-fluids interfaces. The new fundamental knowledge gained in this study will provide an important guidance on how to synergize water ion interactions at fluid-fluid interfaces with those at rock-fluids interfaces to optimize oil recovery from SmartWater flood.
Microemulsion properties significantly impact any EOR process that relies on surfactants or soaps to generate ultralow interfacial tension to displace trapped oil. Unfavorable microemulsion viscosity can lead to high chemical retention, low oil recovery, and overall unfavorable performance across all modes. Controlling microemulsion properties is important in conventional approaches like surfactant-polymer (SP) and alkaline-surfactant-polymer (ASP) flooding, in addition to new applications like gravity stable displacements, spontaneous imbibition in fractured carbonates and unstable floods of viscous oil. Despite the central importance, microemulsion viscosity and rheology remain poorly understood.
This paper describes the results of an extensive experimental microemulsion study. We evaluated the effect of polymer on microemulsion viscosity in different microemulsion phase types (i.e. oil in water, bi-continuous, water in oil emulsions). We measured microemulsion viscosities across a broad salinity range for several crudes from light (API >30°) to heavy oils (API<14°) and observed Newtonian rheology for all phase types. The effect of cosolvents on microemulsion viscosity was also evaluated. Finally, we evaluated microemulsions with and without alkali to help understand potential differences between ASP and SP microemulsions.
We include many observations consistent with earlier literature using recently developed surfactants and report the microemulsion viscosity details for many high performance surfactant formulations across a wide range of conditions. We have also describe several observations, including polymer decreasing the required time to achieve equilibrium in microemulsion pipettes and the qualitative change in microemulsion behavior with and without polymer in Windsor Type III microemulsions.
CO2 miscible injection is generally one of the most efficient enhanced oil recovery (EOR) methods and widely used in the conventional oil reservoirs. The applicability of CO2 EOR technology for unlocking the resources from unconventional tight and shale formations and the mechanisms of miscible flooding in these reservoirs still remain unclear. An important parameter used to evaluate the feasibility of CO2 miscible flooding is the minimum miscibility pressure (MMP). Even though experimental approaches, empirical correlations and theoretical methods have performed well in measuring or predicting MMP between CO2 and crude oil in conventional reservoirs, they may not be suitable for unconventional formations as phase behavior and MMP can be significantly affected by confinement effect in small pores (e.g., nanopores) in such formations.
In this study, a new MMP prediction model based on the modified Parachor Model associated with the Perturbed-Chain Statistical Associating Fluid Theory (PC-SAFT) is developed to determine CO2 MMP both in the bulk phase and nanopores. The Parachor Model is modified to account for the confinement effect of nanopore walls on the equilibrium interfacial tension (IFT). The Equilibrium IFT reduction in nanopores is related to a temperature-dependent and slit pore width-dependent modification term. The parameters of the new Parachor Model are determined by matching the vapor-liquid surface tension values for CH4, C2H6, C3H8,
The newly developed model successfully reproduces MMP in bulk phase as compared with both other methods and experimental data. The overall average absolute relative deviation (AARD) for MMP is within 8 %. The calculated equilibrium IFT for liquid-vapor phase has a good agreement with molecular simulation results. For Bakken oil-CO2 system, if the slit pore width is larger than 10 nm, MMP is independent on pore width; otherwise, it decreases significantly with the decrease of the pore width. If pore width decreases to 3 nm, 67.5 % decrease in the IFT is observed and 23.5% reduction is achieved for MMP between Bakken oil and CO2 stream, indicating that it is easier to reach miscibility in nanopores, and CO2 miscible flooding might be a promising enhanced oil recovery (EOR) technology for tight oil and shale oil reservoirs. Furthermore, MMP increases with an increase of temperature in bulk phase, whereas IFT and MMP decrease with an increase of temperature in nanopores.