Results of modeling polymer flooding using the example of the AB1-2 object model of the K oil field

This paper compares the effiency of heavy oil recovery factor by water and polymer flooding under different level of temperature (26°, 50° and 75°C). The performances of both methods were assessed by analyzing the fractional flow curves and the oil recovery factor (%OOIP) for the same temperature. Rheological measurements were carried out to characterize and to select the fluids. Buckley-Leverett model was applied to evalute the effectiveness of the recovery method after the injected fluid breakthrough. Due to the high oil viscosity, the displacement for water flooding is unfavarable. However, the polymer addition improves the viscosity ratio injected/displaced fluids, making the displacement front more sharp. The fractional flow curves showed that the polymer flooding reduces the amount of the remaining oil more than water flooding and the oil recovery are greatly influenced by the test temperature. As the temperature increases, the oil recovery increases, for both methods. At the same temperature, the final oil recovery is equal for water and polymer flooding, showing that the used polymer has not affected the residual oil saturation. However, the polymer flooding was able to anticipate the oil production and the anticipation was more pronounced for higher temperatures. The mobility ratio reduction with temperature rising turned the displacement more piston-like, highlighting the anticipation of the produced oil by polymer flooding.

There are 54 blocks entered into subsequent water flooding period after polymer flooding in Daqing oilfield, The comprehensive water cut is as high as 97.2% and the average oil recovery factor is 57% for the reservoir after polymer flooding, There are 44% geological reserves still remained underground and these reserves are of good quality for further exploitation. But the reservoir has gone through deepen development by tertiary oil recovery and entered into the period of the fourth enhanced oil recovery, so how to further enhance oil recovery is a world's toughest problem. Therefore a new oil displacing system with high efficiency should be developed suitable for the reservoir after polymer flooding in order to greatly enhance oil recovery for ultra-high water cut reservoir after polymer flooding. In this paper, lots of lab experiments have been carried out consisting of oil displacement performance evaluation and formula optimizing. A new ASP formula using associated polymer has been developed, the incremental oil recovery of this system is 10.35% in the lab experiments of natural cores after polymer flooding. In contrast to linear polymer ASP system, associated polymer ASP system can reduce polymer dosage by 48% and increase oil recovery by 3.3% at the same time. The reservoir engineering and oil displacement scenarios have been worked out and the field test has been carried out in the N3D block with 16 injection wells and 25 production wells after polymer flooding in Daqing oilfield. The numerical simulation predicts the incremental oil recovery can reach up to 8.76% after polymer flooding. The test has entered into field and obtained good technological and economic development effect. The blank water flooding began in Sep 2012 and the trial injection of ASP flooding began in Oct 2013 and the main ASP slug began in Jun 2014. Till Oct 2019, the accumulative injection pore volume was 0.9104 PV with the injection pressure increased by 4.7 MPa, water absorption thickness ratio increased by 27.1%, the biggest water cut decline of single well was 6.4% and the staged incremental oil recovery was 7.89%. At present, the accumulative oil production increment is 0.647 million barrels and the economic benefit is 32.35 million dollars. The numerical simulation prediction shows that the final accumulative oil production increment is 0.657 million barrels and the final economic benefit is 32.87 million dollars. This new technology and field test can enhance oil recovery greatly for ultra-high water cut reservoir after polymer flooding and obtain good technological and economic development effect, so it has a broad application prospect and can be applied extensively in ultra-high water cut blocks after polymer flooding in Daqing oilfield.

In water flooding, residual oil is displaced by injecting water into the reservoir formation. Oil displaced from injection wells is physically swept to adjacent production wells by water. Compared to conventional oil fields, offshore heavy oil fields have low oil recovery using water flooding. If we had a better knowledge of the flow characteristics of the water and oil phases, it would be very useful to improve the oil recovery of the heavy oil reservoir. In developing oil fields, it is important to study the patterns of changes in the f low characteristics of the oil and water phases. This will guide the development of numerical simulation models. This study considered the geological characteristics, fluid properties, and construction technology of an offshore oil field with heavy oil. The relative permeabilities of water and oil were investigated using steady-state and unsteady-state methods. With the unsteady state method, the effect of core permeability, water washout, and oil viscosity on the relative permeability curve and oil displacement efficiency of water flooding has been investigated. Artificial cores were utilized in the experiments. The artificial cores were developed to simulate the structure of unconsolidated sandstone in an offshore oil f ield. Computed tomography and mercury pressure testing are used to demonstrate the change in the internal structure of the core. Water washout forms the “cleaning” and “erosion” function, which affects core pore structure, increases the radius of the core pore throat, and increases the core permeability. It has the same effect on relative permeability curves and oil displacement efficiency as it does on increased permeability. The total oil recovery decreases with increasing oil viscosity since the ability to control water mobility weakens during the flooding process. Moreover, the coverage volume of the displacing water phase decreases, and the two-phase flow range narrows. Water sweeps expand as core permeability increases, resulting in a wider twophase flow as the relative permeability of the water phase increases. In turn, this enhances oil efficiency displacement and total oil recovery.

Polymer flooding for improving sweep efficiency has been studied extensively in laboratory and tested in fields for conventional oils. From the literature, polymer flooding is not recommended for oils with viscosity higher than 200 mPa.s. Severe viscous fingering during waterflooding of heavy oil leaves a large amount of oil untouched in the reservoir. Polymer flooding could be a potential method for enhanced heavy oil recovery by improving the sweep efficiency. However, how a polymer flooding should be planned for a heavy oil reservoir to make it economically feasible has not been studied. This paper investigated the potential of polymer flooding for heavy oil reservoir using a heavy oil of 1,450 mPa.s. Tertiary polymer flooding tests were performed in both homogeneous and heterogeneous (channelled) sandpacks. Results in homogeneous sandpacks showed that there existed a viscosity range for the injected polymer solution, in which the oil recovery had an evident increase with the increase of polymer solution viscosity. When the viscosity of polymer solution was outside of this range, the increase in polymer solution viscosity resulted in only a small incremental oil recovery. It was also found that the earlier the polymer flooding was applied, the lower the polymer solution viscosity was required to have an obvious increase in tertiary oil recovery. Results in channelled sandpack tests showed that the existence of heterogeneity in porous media greatly lowered the tertiary oil recovery by polymer flooding. These laboratory results will be helpful for the planning of polymer flooding for heavy oil reservoirs. Introduction Thermal method is the most effective technique for heavy oil recovery. However, many reservoirs' conditions restrict the application of thermal techniques, such as thin pay thickness or deep reservoir. Waterflooding of heavy oil reservoir can only achieve a very low oil recovery because of severe viscous fingering. Polymer flooding is a well-recognized technique of mobility control for conventional oils, which could be a potential method for enhanced heavy oil recovery by improving the sweep efficiency. Many laboratory studies and field testes of polymer flooding were reported for conventional oils. Jewett and Schurz1, Chang2 and Needham and Doe3 presented extensive literature reviews on polymer flooding. However, very few literatures4 were concerned with heavy oils. Generally, polymer flooding is applicable for the reservoir with high mobile oil saturation and moderate heterogeneity. It has not been recommended for the case with oil viscosity greater than 200 mPa.s2, 5, 6. Severe viscous fingering during waterflooding of heavy oil leaves large amount of oil in the reservoir untouched. Both technical and economic factors restrict the application of polymer flooding to heavy oil reservoirs with oil viscosity of thousands centipoises. It is not feasible to make the viscosity of the polymer solution to be comparable with that of the heavy oil in the reservoir. For instance, partially hydrolyzed polyacrylamide may not provide high viscosity in high-salinity water even a relatively high concentration is used, especially in the presence of divalent cations (such as calcium) 7.

The five large oil fields found in the Russian Republic of Tatarstan have been producing from the Devonian sandstone reservoirs for more than fifty years. Currently all of them have entered the maturity stage. In all five fields waterflooding methods have been applied since the very start of production. And though the principal development approaches and strategy do not differ, development rate, volumes of fluid produced, actual and design oil recovery factor (ORF) do differ. The largest of the five fields, Romashkinskoye, has been developed in independent areas divided by injection wells’ rows. There are 21 such areas. Comparative analysis of these areas’ performance is of specific interest. To make a generalized estimate of production performance of the five fields, we have ranked them by a number of geologic parameters. The same ranking has been performed for all areas of the Romashkinskoye oilfield. For the purpose of analysis these areas have been further divided into seven groups by a common integral geologic parameter. The investigation method involves a correlation analysis of the fluid production and oil recovery profiles at different stages of development of both fields and areas; as well as evaluation of the present-day status of development, in that number with account for the tendency towards operating assets’ change. It has been demonstrated that the oil recovery factor and its behavior at different development stages depend to a large extent on reservoir geology. Besides, there is a close correlation between fluid and oil production rates. In mature fields very important factors are status of assets and producing wells’ density. Fields and areas have been identified which call for immediate rejuvenation operations.

Background A lot of works are devoted to the issues of injection and production wells location in a zonal inhomogeneous permeable reservoir. Researchers are trying to understand how the location of wells in reservoir zones with different permeability affects oil recovery efficiency. This issue is particularly acute for development systems with maintaining reservoir pressure. It has been established that the location of injection wells in low-permeable zones, and production in the high-permeable zones of the reservoir contributes to increasing the coverage of the impact. Moreover, even in the conditions of a partially developed reservoir, the transformation of the existing development system according to the above principle has significant potencies for increasing the oil recovery factor (ORF). Another actual problem is the study of the effect of extensive high-permeable inclusions (faults, reservoir tightness zones) on the effectiveness of regular development systems. It is concluded that the development systems with different location of production and injection wells with regard to fault lines are unequal. This assumption requires not only qualitative, but also quantitative evaluation. Aims and Objectives: Consider the dependence of oil recovery on the location and orientation of the rows of production and injection wells with regard to fault lines. Results 1. It was established that the location of the rows of wells parallel to the fault line (variants 1, 2, 5, 6) allows to achieve a higher ORF compared to placing the rows of wells perpendicular to the fault line (variant 3). 2. Location a row of injection wells in the raised part of the reservoir is less effective than their location in the lower part. The most effective is the location of a row of production wells in the zone of decompression of the reservoir, and the rows of injection wells - outside the zone of decompression. This variant of well row location has the maximal withdrawal rate and the highest ORF value.

In Poland there are approximately 60 oil fields located in different geological structures. Most of these fields have been producing for several years to several dozen years, and now require redefining of the development plan by utilizing an improved oil recovery (IOR) or enhanced oil recovery (EOR) method to achieve a higher oil recovery factor. Here we present the redevelopment plan for the Polish Main Dolomite oil field, that aimed to optimize and maximize the oil recovery factor. Considering all available geological and reservoir data, both a static and dynamic model were built and calibrated for three separate reservoirs connected to the same production facility. Then the comprehensive study was performed where different development scenarios was considered and tested using reservoir numerical simulation. The proposed redevelopment scenarios included excessive gas reinjection to the main reservoir, additional high-nitrogen (N2) gas injection from a nearby gas reservoir (87% of N2), carbon dioxide (CO2) injection, water injection, polymer injection, water-alternating-gas (WAG), well stimulation, and a combination of these methods. Development plans assumes also drilling new injection and production wells and converting existing producers to gas or water injectors. The key component in development scenarios was to arrest the pressure decline from the main field and decrease the gas/oil ratio (GOR). An additional challenge was to implement in the simulation model all key assumptions behind various development scenarios, while also taking into account specific facility constraints and simultaneously handling separate reservoirs that are connected to the same facility, and hence affecting each other. From numerous scenarios, the scenario that requires the least number of new wells was selected and further optimized. It considers the drilling of only one new producer, one new water injector, and conversion of some currently producing wells to gas and water injectors. The location of the proposed well and the amount of injection fluids was optimized to achieve the highest oil recovery factor and to postpone gas and water breakthrough as much as possible. The optimized case that assumes low investments is expected to improve incremental oil production by 90% over No Further Actions Scenario. However, the study suggests the potential of more than tripling incremental oil production under a scenario with considerably higher expenditures. The improved case assumes drilling one more producer, four new water injectors, and injection of three times more water. The presented field optimization example highlights that in many existing Polish oil fields there is still a potential to reach higher oil recovery without considerable expenditures. However, to obtain more significant oil recovery improvement, higher capital expenditure is necessary. To facilitate the selection of the best development scenario, a detailed economic and risk analysis needs to be conducted.

The average global recovery factor of a typical oil and gas field is approximately 40% at after secondary recovery processes such as gas lifting and water flooding. The low recovery factor is often a result of by passing a considerable amount of oil in the reservoir due to unknown reservoir heterogeneity and incomplete understanding of the geology. Enhanced oil recovery (EOR) methods will play a key role in increasing recovery factors from existing reservoirs. Heterogeneous reservoir sands often show permeability contrast between layers and therefore lead to early water breakthrough when water flooding. In such situations, polymer flooding can potentially be a suitable EOR technique that helps to lower water cut and increase recovery. The addition of polymers to the injected water lowers the mobility ratio, thereby reducing viscous fingering and delaying water breakthrough. This study investigates how a polymer flood design can be optimized while considering geological uncertainty in the reservoir models as well as modelling decisions. We applied an adjoint based technique to match data from a prolonged waterflood in the Watt Field, a synthetic but realistic clastic reservoir that is based on real data and captures a wide range of geological heterogeneities and uncertainties through a range of different model scenarios and model realizations. We apply Latin hypercube experimental designs with the Particle Swarm Optimization algorithm in CMOST. This was used to build a proxy model employing polynomial regression for the optimization of the engineering parameters to maximize NPV. The optimization were performed for both history-matched models (constrained optimization) and the original, non-history-matched models (unconstrained optimization). The aim of this work is to analyse how geological uncertainties inherent to a heterogeneous clastic reservoir as well as modelling decisions impact the design and performance a polymer flood. We further investigate how the different optimization methods impact the predicted reservoir performance and optimal design of the polymer flood. Our findings show that both, geological and engineering uncertainties, impact polymer flooding and that designing the right well controls is essential for successful polymer flooding. Shale cut-offs are identified as a key petrophysical uncertainty when optimizing a polymer flood in a heterogeneous clastic reservoir. Furthermore, forecasts using constrained optimization yielded a much narrower range of incremental oil recovery and NPV during polymer flooding and may underestimate both, risk and opportunities for polymer flooding because the history matching of the water flood emphasizes different geological features compared to the way geology interacts with a more viscous polymer solution.

Purpose. Increasing oil recovery from deposits and reducing the water content of producing wells by providing conditions for uniform displacement of oil from the reservoir under the influence of high reservoir pressure. Methodology. The purpose of the work is achieved by conducting theoretical and experimental studies of the process of creating high elastic energy in the formation by pumping water with injection well pumps to overcome the resistance of oil and water filtration through the pores of the rock and oil rise at the mouth of producing wells. The absence of pumps from producing wells and the acceptance of equal amounts of injection and production wells over the reservoir area significantly increases the reservoir pressure above the pressure of oil saturation with gas. Due to the significant elasticity of the rock and fluids under high reservoir pressure, the oil coverage with water increases and there is no premature breakthrough of water into producing wells. The possibility of creating high elastic energy in an oil reservoir by pumping water into injection wells has been experimentally studied. Findings. It has been established that high reservoir energy in the field of elastic deformation of rock and fluids can be created mainly by pumps from injection wells, due to which oil is uniformly displaced from the reservoir along the entire front without breaking through the injected water into producing wells along the path of least resistance. The adoption of equal amounts of producing and injection wells and their sequential arrangement in rows contributes to the development of high potential energy in the reservoir and increase the pick-up rate of injection and production wells. As a result, the skeleton of the rock forming the pores expands, and the water injected into the reservoir and the displaced oil accumulate and increase reservoir energy. Originality. The effectiveness of the proposed method for maintaining high reservoir pressure is achieved as a result of creating high energy of rock and fluids in the area of their elastic deflation and increasing the coverage coefficients of oil displaced by water over the area and profile of the productive formation without the use of additional capacities and pumping units from producing wells. Practical value. The developed new technique for maintaining high elastic reservoir pressure not lower than the pressure of oil saturation with gas by pumping water into the reservoir can be carried out in oil fields using standard technological equipment and increase oil recovery to 60–70 % at its existing values of 40–45 % and reduce the water content of produced oil to 0–10 % at its existing values of 20–80 % and above.

Simulation Study on Polymer Flooding for Enhanced Oil Recovery: A Case Study

Application of polymer flooding in the revitalization of a mature heavy oil field

The paper presents the results of a pilot project implementing WAG injection at the oilfield with carbonate reservoir, characterized by low efficiency of traditional waterflooding. The objective of the pilot project was to evaluate the efficiency of this enhanced oil recovery method for conditions of the specific oil field. For the initial introduction of WAG, an area of the reservoir with minimal potential risks has been identified. During the test injections of water and gas, production parameters were monitored, including the oil production rates of the reacting wells and the water and gas injection rates of injection wells, the change in the density and composition of the produced fluids. With first positive results, the pilot area of the reservoir was expanded. In accordance with the responses of the producing wells to the injection of displacing agents, the injection rates were adjusted, and the production intensified, with the aim of maximizing the effect of WAG. The results obtained in practice were reproduced in the simulation model sector in order to obtain a project curve characterizing an increase in oil recovery due to water-alternating gas injection. Practical results obtained during pilot testing of the technology show that the injection of gas and water alternately can reduce the water cut of the reacting wells and increase overall oil production, providing more efficient displacement compared to traditional waterflooding. The use of WAG after the waterflooding provides an increase in oil recovery and a decrease in residual oil saturation. The water cut of the produced liquid decreased from 98% to 80%, an increase in oil production rate of 100 tons/day was obtained. The increase in the oil recovery factor is estimated at approximately 7.5% at gas injection of 1.5 hydrocarbon pore volumes. Based on the received results, the displacement characteristic was constructed. Methods for monitoring the effectiveness of WAG have been determined, and studies are planned to be carried out when designing a full-scale WAG project at the field. This project is the first pilot project in Russia implementing WAG injection in a field with a carbonate reservoir. During the pilot project, the technical feasibility of implementing this EOR method was confirmed, as well as its efficiency in terms of increasing the oil recovery factor for the conditions of the carbonate reservoir of Eastern Siberia, characterized by high water cut and low values of oil displacement coefficients during waterflooding.

Application of biomanufacturing in polymer flooding

The results of indicator research of oil reservoirs, conducted in 2011 and 2013 on the same areas of injection wells oil field in Republic of Kazakhstan. Studies were conducted on layers Ю-I - Ю-X, in which productive sediments are Callovian Stage, Bathonian Stage, Bajocian Stage of Jurassic. As a result of research the values calculated the total weight of the recovered from the mouths of the producing wells of the indicator (%), calculate the volume (m3) and performance channels of LFR (m 3 / day) in the inter-well space, the actual speed of the labeled water (m / day), permeability of LFR channels (μm 2 ) and hydraulic conductivity (μm 2 *cm/cPs). The aim of the research of 2011 was study the hydrodynamic characteristics of the layers, identify of fluid flow in areas of low filtration resistance in the inter-well space. The aim of the research of 2013 were performance evaluation conducted in 2012, geological and technical measures (GTM), aimed at increasing oil recovery in the areas of indicator research 2011. The task was to create a system of evaluating the effectiveness of GTM in the field of low filtration resistance. Have been proposed evaluation criteria sweep efficiency of developed oil formations. All areas on the results of studies carried out during the period 90 - 120 days, i.e. in the areas of low filtration resistance, divided into three groups: uniform water flood, water flood ambiguous, non-uniform water flood. The article presents the parameters used for classification. Classification allows you to recommend priority areas for inclusion in the plan of GTM to increase oil production. Conducting of indicator research before and after the GTM allows to estimate the changing nature of water flood on the area and to draw conclusions on the effectiveness of these measures. Transition area injection well from the group of non-uniform displacement to uniform water flood talk about the positive result of conducted GTM.

Taking PI1-2 oil-bearing formations of northeast block in Lamadian oilfield as an example, laboratory experiments of high-concentration polymer flooding in artificial five-spot flat-panel core model are conducted, the effect of polymer molecular weight, concentration, slug size on oil displacement effect are evaluated and the influence on injection pressure of those parameters are analyzed. At the same time, injection parameters, such as polymer molecular weight, concentration and slug size etc, are optimized combined with actual injection ability of high-concentration polymer flooding from the pilot site. The results show: high-concentration polymer flooding after polymer flooding can further improve recovery, in addition, episode recovery degree can be improved with the increase of concentration and high-concentration slug; the theory of similarity on injection-production differential pressure between laboratory flat model experiment and actual reservoir is put forward, and parameters information of injection pressure in real reservoir are obtained through upscaling the flat model; the optimized polymer injection parameters for the pilot site in Lamadian oilfield are molecular weight of 25 million, concentration of 3,500mg/L, slug size of 0.5 PV, and the recovery can be improved 8.47%OOIP through using those optimal parameters. Introduction Polymer flooding, as the leading post-waterflood production technology in major oil reservoirs of Daqing oil field(1-4), has been put into the large-scale field application since 1996. At present, sixteen polymer-flooded blocks with geological reserves of 2.75×108 t OOIP are in the follow-up water flooding stage. The technology to further improve the recovery after polymer flooding is the true sense of the secondary development of oilfield technology (5-6), it is one of the key technology to realize the secondary development of Daqing oil field. In 2002 Daqing oil field company Technology Symposium, Academician Wang Demin proposed that the increased oil recovery by high-concentration polymer flooding is higher than that of conventional polymer flooding, and adopting high-concentration polymer in different stages of conventional polymer flooding can also yield good effects. Xia Huifen et al.(7-9) conducted the laboratory study on the microscopic displacement mechanisms of polymer solution, and concluded that increased recovery in microscopic displacement mechanism of polymer solution is due to the viscoelastic effect of polymer solution. Lu Xiangguo et al.(10) carried out the research on the optimization of polymer molecular weight, and proposed that if the formation and surface conditions allow, we should choose the higher molecular weight as the oil displacement agent; Wu Wenxiang et al. (11) did the research on the effect of high-concentration polymer injection timing and slug combinations on oil displacement effect, the results showed that the earlier the conventional polymer flooding converts to high-concentration polymer, the higher the oil recovery will achieve. Conventional polymer flooding in PI1-2 oil-bearing formations in Lamadian oilfield was switched to inject high-concentration polymer as a test in the course of the middle stage of conventional polymer flooding, the results of this field test show that 6% OOIP incremental oil recovery over the conventional polymer flooding was obtained. Now we plan to carry out a field test that injects high-concentration polymer after conventional polymer flooding in 106 meters well spacing in PI1-2 oil-bearing formations of northeast block in Lamadian oilfield.