A Comprehensive Scheme for Application of Low Salinity Waterflooding Technique in Mature Fields

A new generation improved oil recovery methods comes from combining techniques to make the overall process of oil recovery more efficient. One of the most promising methods is combined Low Salinity Surfactant (LSS) flooding. Low salinity brine injection has proven by numerous laboratory core flood experiments to give a moderate increase in oil recovery. Current research shows that this method may be further enhanced by introduction of surfactants optimized for lowsal environment by reducing the interfacial tension. Researchers have suggested different mechanisms in the literature such as pH variation, fines migration, multi-component ionic exchange, interfacial tension reduction and wettability alteration for improved oil recovery during lowsal injection.In this study, surfactant solubility in lowsal brine was examined by bottle test experiments. A series of core displacement experiments was conducted on nine crude oil aged Berea core plugs that were designed to determine the impact of brine composition, wettability alteration, Low Salinity Water (LSW) and LSS flooding on Enhancing Oil Recovery (EOR). Laboratory core flooding experiments were conducted on the samples in a heating cabinet at 60 °C using five different brine compositions with different concentrations of NaCl, CaCl2 and MgCl2 . The samples were first reached to initial water saturation, S wi , by injecting connate water (high salinity water). LSW injection followed by LSS flooding performed on the samples to obtain the irreducible oil saturation.The results showed a significant potential of oil recovery with maximum additional recovery of 7% Original Oil in Place (OOIP) by injection of LS water (10% LS brine and 90% distilled water) into water-wet cores compared to high salinity waterflooding. It is also concluded that oil recovery increases as wettability changes from water-wet to neutral-wet regardless of the salinity compositions. A reduction in residual oil saturation, S or , by 1.1–4.8% occurred for various brine compositions after LSS flooding in tertiary recovery mode. The absence of clay swelling and fine migration has been confirmed by the stable differential pressure recorded for both LSW and LSS flooding. Aging the samples at high temperature prevented the problem of fines production. Combined LSS flooding resulted in an additional oil recovery of 9.2% OOIP when applied after LSW flooding.Surfactants improved the oil recovery by reducing the oil-water interfacial tension. In addition, lowsal environment decreased the surfactant retention, thus led to successful LSS flooding. The results showed that combined LSS flooding may be one of the most promising methods in EOR. This hybrid improved oil recovery method is economically more attractive and feasible compared to separate low salinity waterflooding or surfactant flooding.

A new generation improved oil recovery methods comes from combining techniques to make the overall process of oil recovery more efficient. One of the most promising methods is combined Low Salinity Surfactant (LSS) flooding. Low salinity brine injection has proven by numerous laboratory core flood experiments to give a moderate increase in oil recovery. Current research shows that this method may be further enhanced by introduction of surfactants optimized for lowsal environment by reducing the interfacial tension. Researchers have suggested different mechanisms in the literature such as pH variation, fines migration, multi-component ionic exchange, interfacial tension reduction and wettability alteration for improved oil recovery during lowsal injection. In this study, surfactant solubility in lowsal brine was examined by bottle test experiments. A series of core displacement experiments was conducted on nine crude oil aged Berea core plugs that were designed to determine the impact of brine composition, wettability alteration, Low Salinity Water (LSW) and LSS flooding on Enhancing Oil Recovery (EOR). Laboratory core flooding experiments were conducted on the samples in a heating cabinet at 60 °C using five different brine compositions with different concentrations of NaCl, CaCl2 and MgCl2. The samples were first reached to initial water saturation, Swi, by injecting connate water (high salinity water). LSW injection followed by LSS flooding performed on the samples to obtain the irreducible oil saturation. The results showed a significant potential of oil recovery with maximum additional recovery of 7% Original Oil in Place (OOIP) by injection of LS water (10% LS brine and 90% distilled water) into water-wet cores compared to high salinity waterflooding. It is also concluded that oil recovery increases as wettability changes from water-wet to neutral-wet regardless of the salinity compositions. A reduction in residual oil saturation, Sor, by 1.1–4.8% occurred for various brine compositions after LSS flooding in tertiary recovery mode. The absence of clay swelling and fine migration has been confirmed by the stable differential pressure recorded for both LSW and LSS flooding. Aging the samples at high temperature prevented the problem of fines production. Combined LSS flooding resulted in an additional oil recovery of 9.2% OOIP when applied after LSW flooding. Surfactants improved the oil recovery by reducing the oil-water interfacial tension. In addition, lowsal environment decreased the surfactant retention, thus led to successful LSS flooding. The results showed that combined LSS flooding may be one of the most promising methods in EOR. This hybrid improved oil recovery method is economically more attractive and feasible compared to separate low salinity waterflooding or surfactant flooding.

Low Salinity waterflooding is an emerging Enhanced Oil Recovery technique in which the salinity of the injected water is controlled to improve oil recovery vs. conventional, higher salinity waterflooding. The objective of this work is the evaluation of low salinity water injection as EOR process in an on-shore field in West Africa. The field is heavily faulted and highly heterogeneous. The reservoir fluid is light crude oil; very different productive behaviours are present in the field. An experimental work was performed to verify the effectiveness of the process and make deeper investigation about the chemical and physical mechanisms involved in low salinity water injection. Core flooding experiments on reservoir porous media were carried out, giving promising results in terms of matrix additional oil recovery with low salinity waterflood. Furthermore, a simulation work to predict the benefits in the field was executed. Core experiments were reproduced using a wettability change model to obtain low salinity water parameters, the salt-dependent relative permeability curves. The process was scaled up to a fine sector model, calibrated on historical production data, representing the area of interest for low salinity water pilot. Simulations of low salinity water injection were run in different forecast scenarios and additional recovery was compared with sea water injection. In order to evaluate the global effect of low salinity water injection as EOR process, all the aspects were taken into consideration, decrease in residual oil saturation, permeability reduction, expected sweep efficiency on effective reservoir matrix volume. The experimental and simulation results were used for an economical feasibility study for a desalination plant in the field to reduce the salinity of current injected sea water.

Numerous early reports on experimental works relating to the role of wettability in various aspects of oil recovery have been published. Early examples of laboratory waterfloods show oil recovery increasing with increasing water-wetness. This result is consistent with the intuitive notion that strong wetting preference of the rock for water and associated strong capillary-imbibition forces gives the most efficient oil displacement. This report examines the effect of wettability on waterflooding and gasflooding processes respectively. Waterflood oil recoveries were examined for the dual cases of uniform and non-uniform wetting conditions. Based on the results of the literature review on effect of wettability and oil recovery, coreflooding experiments were designed to examine the effect of changing water chemistry (salinity) on residual oil saturation. Numerous corefloods were conducted on reservoir rock material from representative formations on the Alaska North Slope (ANS). The corefloods consisted of injecting water (reservoir water and ultra low-salinity ANS lake water) of different salinities in secondary as well as tertiary mode. Additionally, complete reservoir condition corefloods were also conducted using live oil. In all the tests, wettability indices, residual oil saturation, and oil recovery were measured. All results consistently lead to one conclusion; that is, a decrease in injection water salinity causes a reduction in residual oil saturation and a slight increase in water-wetness, both of which are comparable with literature observations. These observations have an intuitive appeal in that water easily imbibes into the core and displaces oil. Therefore, low-salinity waterfloods have the potential for improved oil recovery in the secondary recovery process, and ultra low-salinity ANS lake water is an attractive source of injection water or a source for diluting the high-salinity reservoir water. As part of the within-scope expansion of this project, cyclic water injection tests using high as well as low salinity were also conducted on several representative ANS core samples. These results indicate that less pore volume of water is required to recover the same amount of oil as compared with continuous water injection. Additionally, in cyclic water injection, oil is produced even during the idle time of water injection. It is understood that the injected brine front spreads/smears through the pores and displaces oil out uniformly rather than viscous fingering. The overall benefits of this project include increased oil production from existing Alaskan reservoirs. This conclusion is based on the performed experiments and results obtained on low-salinity water injection (including ANS lake water), vis-a-vis slightly altering the wetting conditions. Similarly, encouraging cyclic water-injection test results indicate that this method can help achieve residual oil saturation earlier than continuous water injection. If proved in field, this would be of great use, as more oil can be recovered through cyclic water injection for the same amount of water injected.

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).

Different oil displacement experiments conducted on sandstone and carbonate samples show that low salinity water (LSW) injection can reduce the residual oil saturation (ROS). Recently, surfactant flooding (SF) in combination with low salinity water (known as low salinity surfactant (LSS) flooding) is proposed as a potentially promising hybrid enhanced oil recovery (EOR) process. A lower ROS is reported for a LSS process compared to that seen in SF or with LSW at the same capillary number. The capillary desaturation curve (CDC) is a well-known tool to study the effect of viscous and capillary forces on ROS for different EOR techniques. In this study, ROS data of various LSW, SF, and LSS flooding experiments at different capillary numbers are collected to develop a CDC to analyze the performance of the hybrid LSS method. This can help to analyze the effect of the hybrid method on an extra improvement in sweep efficiency and reduction in residual oil. A lower ROS is observed for LSS compared to LSW and SF in the same capillary number range. Our study shows different behaviors of the hybrid method at different ranges of capillary numbers. Three regions are identified based on the capillary number values. The difference in ROS is not significant in the first region (capillary number in the range of 10−7–10−5), which is not applicable in the presence of surfactant due to the low interfacial tension value. A significant reduction in ROS is observed in the second region (capillary number in the range of 10−5–10−2) for LSS compared to SF. This region is the most practical range for SF and LSS flooding. Hence, the application of LSS provides a noticeable benefit compared to normal EOR techniques. In the third region (capillary numbers greater than 10−2), where the surfactant flooding is a better performer, the difference in ROS is negligible.

In this study, the synergetic effect of ultrasonic waves and low-salinity water (LSW) on the oil flow in porous media was investigated. In this regard, a series of experiments including oil viscosity measurement, microscopic imaging, interfacial tension (IFT) measurement, and thermal gravimetric (TG) carried out on the crude oil before and after the ultrasonic treatment using a probe-type generator (20 kHz and 100 W). According to the results, ultrasonic waves increased the oil flow rate in porous media by decreasing the oil viscosity and increasing the temperature. Irradiated oil viscosity was reduced by 45% at the optimum time. Ultrasonic wave irradiation caused a 31% reduction in IFT between crude oil and water due to the cracking of large components. Also, the IFT between the LSW and irradiated oil was 51% less than the high-salinity water. The simultaneous use of ultrasonic waves and LSW decreases IFT between the oil and water due to the change in the electric charge and as a result, increases the creation of water-in-oil emulsions. The simultaneous use of ultrasonic waves and LSW is important from environmental and economic points of view including decreasing oil contamination in porous media and increasing oil recovery from rock.

Effect of divalent cations in formation water on wettability alteration during low salinity water flooding in sandstone reservoirs: Oil recovery analyses, surface reactivity tests, contact angle, and spontaneous imbibition experiments

Handil Field is a giant mature oil and gas field situated in Mahakam Delta, East Kalimantan Indonesia. Peripheral Low Salinity Water injection was performed since 1978 with extraordinary results. This paper describes the success story of this secondary recovery by low salinity water injection application in the peripheral of Handil field main zone, which successfully increased the oil recovery and brought down the remaining oil saturation beyond the theoretical value of residual oil saturation. Water producer wells were drilled to produce low salinity water from shallow reservoirs 400 - 1000 m depth then it was injected to main zone reservoirs where the main accumulation of oil is situated. This low salinity water reacted positively with the rock properties and in-situ fluids which is described as wettability alteration in the reservoir. It is related to initial reservoir condition, connate water saturation, rock physics and connate water salinity. This peripheral scheme then observed having the sweeping effect on top of pressure maintenance due to long period of injection. The field production performance was indicating the important reduction of residual oil saturation in some reservoirs with continuous low salinity water injection. From static Oil in Place calculation, some reservoirs have high current oil recovery up to 80%. This was proved by in situ residual oil saturation measurement which was performed in 2007 and 2011. It was indicating the low residual saturation as low as 8% - 15%. This excellent result was embraced by a progressive development plan, where water flooding with pattern and chemical injection will be performed later on. The continuation of this peripheral injection is in an on-going development with patterns injection which is called water flooding development. An important oil recovery can be achieved with a simple scheme of low salinity injection, performed in a close network injection, where the water treatment is simple yet significant oil gain was recovered. This innovation technique brings more revenue with less investment compared to chemical EOR injection.

Laboratory tests and field applications show that low-salinity water flooding could lead to significant reduction of residual oil saturation. There has been a growing interest with increasing number of low-salinity water flooding studies. However, there are few quantitative studies on the effect of using sea-water injections on oil recovery. As oil production continues, a drop-in reservoir pressure will occur due to the loss of reservoir fluids, and this drop-in pressure will lead to a decrease in oil production. The reservoir pressure is maintained by the water injection process. Where sea-water is injected into the aquifer area below the oil area to support the tank pressure. This study presents a laboratory investigation of the effect of salinity injection water on oil recovery, permeability, and relative permeability in the water flooding process. This study was conducted using several samples of sandstone saturated with oil by placing them in the reservoir conditions by placing them in a vacuum oven to ensure complete saturation of the samples with oil and then extracting the oil from them using liquid permeability where the samples are injected. With the formation water until reaching the recovery plateau and obtaining an average reading, the flow, permeability and pressure difference are measured, as well as the relative permeability and recovery factor, then the samples are injected again with sea water and the new results are recorded through seawater injection. The results of this study showed an increase in oil recovery with decrease in residual oil saturation and increase in the recovery factor.

Many laboratory coreflood studies have shown increased oil recovery is achieved by waterflooding using low salinity water, compared with injection of seawater or high salinity produced water. The reasons for this improved oil recovery are thought to be due to effective wettability changes and / or controlled removal of clay constituents. This paper describes a log-inject-log field test, designed to identify whether this phenomenon could be observed within the near well region of a reservoir. The log-inject-log test was meticulously designed and executed, to ensure that flow rates were maintained at low rates, and that cross flow was minimised, to ensure that the results were representative of bulk reservoir waterflood displacement. A producing well was selected for the test to ensure that all saturation changes occurred under stringently controlled test conditions and that the results would not be affected by previous high rate water injection. 10–15 ‘pore volumes’ of high salinity brine, were injected into the ‘volume of interest’, to obtain a baseline residual oil saturation. This was followed by sequences of more dilute brine followed by high salinity brine for calibration purposes. Multiple log passes were conducted during injection of each brine. At least three further passes were run to ensure that a stable saturation value had been established after injection of each brine. Extensive water sampling was conducted to confirm brine salinities and increase confidence in the quantitative saturation results. The results were in line with previous laboratory tests from other fields, and showed 25–50% reduction in residual oil saturation when waterflooding with low salinity brine.

Many laboratory coreflood studies have shown increased oil recovery is achieved by waterflooding using low salinity water, compared with injection of seawater or high salinity produced water. The reasons for this improved oil recovery are thought to be due to effective wettability changes and / or controlled removal of clay constituents. This paper describes a log-inject-log field test, designed to identify whether this phenomenon could be observed within the near well region of a reservoir. The log-inject-log test was meticulously designed and executed, to ensure that flow rates were maintained at low rates, and that cross flow was minimised, to ensure that the results were representative of bulk reservoir waterflood displacement. A producing well was selected for the test to ensure that all saturation changes occurred under stringently controlled test conditions and that the results would not be affected by previous high rate water injection. 10 - 15 ‘pore volumes’ of high salinity brine, were injected into the ‘volume of interest’, to obtain a baseline residual oil saturation. This was followed by sequences of more dilute brine followed by high salinity brine for calibration purposes. Multiple log passes were conducted during injection of each brine. At least three further passes were run to ensure that a stable saturation value had been established after injection of each brine. Extensive water sampling was conducted to confirm brine salinities and increase confidence in the quantitative saturation results. The results were in line with previous laboratory tests from other fields, and showed 25 - 50% reduction in residual oil saturation when waterflooding with low salinity brine.

This paper presents a systematic assessment of the potential of low salinity water flooding for the Dong-He-Tang reservoir in the Tarim Oilfield, China. This reservoir has a high reservoir temperature of 140 °C, high formation water salinity of 142,431 ppm total dissolved solids and an in-situ oil viscosity of 2.2 cp. Our laboratory evaluation included contact angle tests, and spontaneous imbibition and core-flooding experiments using representative core samples from the reservoir. Contact angle tests were conducted at various temperatures (60, 100 and 140 °C) and pressures (20, 30, 40 and 50 MPa). Core-flooding experiments were conducted under the reservoir temperature of 140 °C. Formation brine and low salinity water (100 times diluted formation brine) were used in the experiments. Contact angle and spontaneous imbibition experiments showed that low salinity water shifted the reservoir wettability towards more water-wet. In addition, spontaneous imbibition experiments showed that low salinity water recovered significantly more oil than high salinity water. Furthermore, corefloods were conducted using low salinity water under tertiary and secondary modes. Experimental results were history matched to derive relative permeability curves and capillary pressure curves while considering the non-uniqueness of such history-matching. Results showed that compared to high salinity water flooding, low salinity water shifted relative permeability curves towards lower residual oil saturation, showing a higher oil relative permeability and lower water relative permeability at the same water saturation. The parameters derived from laboratory experiments were used as input for reservoir simulation models to investigate the potential of low salinity water flooding in the reservoir using two layered box models. Findings showed that low salinity water accelerated oil production by increasing the oil relative permeability, thus resulting in a higher recovery factor with only a fraction of pore volume of low salinity water injection. Implications of these findings, such as slug size, salinity of injected brine, non-uniqueness of derived relative permeability curves on incremental oil recovery were assessed. This paper is novel in the following aspects. First, the potential of low salinity water at a high reservoir temperature of 140 °C was systematically investigated. Second, laboratory experiments showed that low salinity water changed the reservoir wettability towards more water-wet, which is consistent with the observed shift in the relative permeability curves derived from core-scale numerical simulation. Third, the potential of the low salinity water in such high temperature environments was assessed using reservoir simulation based on the input from laboratory experiments.

Qualitative assessment of improved oil recovery and wettability alteration by low salinity water injection for heterogeneous carbonates

Smart water (or low salinity water) flooding has been an emerging technology in the petroleum industry since last two decades. Low capital cost and operating expenses of this flooding make it attractive for the petroleum industry. This paper examines the economic feasibility of the injection of smart water and compares with other conventional water flooding techniques. Optimization has also been done with different dilution schemes through particle swarm optimization. This study analyzes the effect of smart water and sequential dilution of injected sea water through reservoir modeling. A three-dimensional black oil reservoir model is developed by using ECLIPSE 100. In addition, this study presents the economic feasibility of the injection of smart water and compares with other conventional water flooding techniques. The study is divided into four cases: i) oil is produced without water flooding, ii) formation water is injected in the reservoir, iii) sea water is injected in the reservoir, and iv) water injection is taken place by sequential dilution of high salinity water. In each case, economic evaluation is completed by calculating the costs and revenues generated by water injection, and oil prod uction. The results show that sea water injection did not give additional oil recovery compared to formation water injection for our case. However, additional results show that sequential dilution flood recovers more oil than sea water and formation water injection. Moreover, five main parameters are optimized such as number of cycles of different salinities, duration of various cycles, salinity values for different cycles, injection rate and production rate. Optimization results show even better results than sequential dilution. The optimization also shows that the additional oil recovery is achieved when the dilution sequence is altered. This outcome illustrates that increased oil recovery is not only dependent on step wise reduction of sea water salinity but also with the variation of dilution pattern. This paper presents a novel technique for the reservoir engineers to study smart water flooding with different perspective. Sequential dilution has been an acceptable technique for increasing oil recovery. However, change of the dilution pattern could be a good alternative and thus provides a cost-effective technique as compared to sequential dilution.