Reduce Water Cut Research Articles

Forecasting the efficiency of waterflooding, thermal and chemical enhanced oil recovery methods in Bobrikovian reservoirs

The development of reserves contained viscous and highly viscous oil poses one of the major challenges in modern reservoir engineering. The poor performance of conventional waterflooding prompts the application of enhanced oil recovery (EOR) methods, of which thermal and chemical EOR are considered the most efficient. Reservoir simulation is a powerful tool for evaluating EOR performance. Serial runs of a history-matched model of a Bobrikovian reservoir are used to evaluate the incremental oil production due to each EOR technique and formulate the efficiency limits of the process performance criteria. In contrast to previous studies that evaluated EOR applications using reservoir simulation modeling, an entirely new quality model is derived through automatic history matching performed by solving an inverse problem. Another novel feature is the automated selection of the optimum field development scenario given a user-defined objective function. Evaluating the performance of hot water injection in a Bobrikovian reservoir suggests that this technology yields positive effects when the injected water temperature ranges from 50 °C to 90 °C. The surfactant–polymer flooding method is also investigated. The largest incremental oil production with a constant surfactant concentration of 0.5% is observed for a polyacrylamide concentration of 0.25%, which can be attributed to a water cut reduction due to plugging the well-drained and flushed reservoir zones. The greatest incremental oil production is achieved when injecting 1.5% surfactant and 0.25% polyacrylamide. The highest efficiency per ton of injected chemicals is obtained when injecting 0.5% polyacrylamide and 0.10% surfactant. Keywords: High-viscosity oil; EOR; thermal methods; surfactant-polymer flooding; reservoir simulation; history matching; injection simulation scenario.

Combining Thermal Effect and Mobility Control Mechanism to Reduce Water Cut in a Sandstone Reservoir in Kazakhstan.

The application of polymer flooding is currently under investigation to control water cut and recover residual oil from a giant sandstone reservoir in Kazakhstan, where the water cut in most producers exceeds 90%, leaving substantial untouched oil in the porous media. The primary objective of this research is to explore the feasibility of a novel approach that combines the mechanisms of mobility control by polymer injection and the thermal effects, such as oil viscosity reduction, by utilizing hot water to prepare the polymer solution. This innovative hybrid method's impact on parameters like oil recovery, resistance factor, and mobility was measured and analyzed. The research involved an oil displacement study conducted by injecting a hot polymer at a temperature of 85 °C, which is higher than the reservoir temperature. Incremental recovery achieved through hot polymer injection was then compared to the recovery by conventional polymer flooding and the conventional surfactant-polymer-enhanced oil recovery techniques. The governing mechanisms behind recovery, including reductions in oil viscosity, alterations in polymer rheology, and effective mobility control, were systematically studied to comprehend the influence of this proposed approach on sweep efficiency. Given the substantial volume of residual oil within the studied reservoir, the primary objective is to improve the sweep efficiency as much as possible. Conventional polymer flooding demonstrated a moderate incremental oil recovery rate of approximately 48%. However, with the implementation of the new hybrid method, the recovery rate increased to more than 52%, reflecting a 4% improvement. Despite the polymer's lower viscosity during hot polymer flooding, which was observed by the lower pressure drop in contrast to the conventional polymer flooding scenario, the recovery factor was higher. This discrepancy indicates that while polymer viscosity decreases, the activation of other oil displacement mechanisms contributes to higher oil production. Applying hybrid enhanced oil recovery mechanisms presents an opportunity to reduce project costs. For instance, achieving comparable results with lower chemical concentrations is of practical significance. The potential impact of this work on enhancing the profitability of chemically enhanced oil recovery within the sandstone reservoir under study is critical.

EOR of heavy oil polymer on Alaska's North Slope: History matching challenges and solutions in a significant long-term water cut reduction

In 2016, a pilot program in Alaska's Milne Point Field tested polymer flooding for heavy oil recovery. Using four wells in the Schrader Bluff reservoir, it aimed to assess its effectiveness in capturing heavy oil resources. Generally, polymer flooding can boost oil production by 10-15%, typically occurring 6-9 months after injection. However, in this case, it took over 24 months for a polymer breakthrough. The method proved highly effective, consistently reducing water content by over 40% and maintaining a low level below 20% for 18 months. Applying standard simulation methods, like history matching, became challenging due to this prolonged low water cut. The usual history-matching processes focus on relative permeability, permeability corrections, and skin effect modifications. Nevertheless, these alternatives proved ineffective. In response to the extended low water cut in Alaska's North Slope, a unique approach was suggested. This approach entails highlighting the low-end point (Krw) across multiple relative permeability curves and adjusting these values according to the water cut history. Additionally, the method takes into account permeability adjustments, Equation of State on analyzes of oil viscosity, J-function incorporation, and considers the potential for viscous fingering during the process. The pilot program displayed remarkable polymer flooding effectiveness, but its unique performance on the North Slope required a modified history-matching approach to simulate its success accurately.

Experimental investigation and numerical simulation of relative permeability modifiers during water shut-off

Relative permeability modifier (RPMs) is a water-shutoff technique that is implemented mostly in high water-producing wells when conventional mechanical isolation methods are not suitable. To optimize RPM injection treatment, numerical simulation is the most effective tool. In this study, laboratory experiments were conducted to investigate the rheology and characteristics properties of newly formulated polymer grafted bentonite (GB). Baseline GB dispersion rheological model was developed using the concept of the effective volume fraction of particles, which depends on hydrodynamic forces. The model considers the effects of the three most significant factors, namely concentration, shear rate, and temperature. GB was then tested in a coreflood to ensure effectiveness and applicability in real reservoir conditions. Coreflood results were matched using a numerical simulator and the rheology model was incorporated to reduce uncertainty and determine critical GB-related simulation parameters. Subsequently, a pilot-scale simulation, which uses the history-matched coreflood parameters, was built to predict and optimize 5-spot pattern performance. A sensitivity analysis was performed for the effect of GB volume injected, layer thickness, and permeability contrast. The results show that the viscosity equation resulting from the modeling allows appropriate correlation of the experimental data of shear stress versus shear rate with change in concentration and temperature. The simulation results reveal that the injection of GB has improved pilot-scale performance in both water-cut reduction and oil recovery. Sensitivity results indicate that the effective period of GB treatment is longer when treated in low water cut than in high water cut. However, more GB injection results in better water control.

Design of Artificial Neural Network for predicting the reduction in permeability of porous media as a result of polymer gel injection

Cross-linked polymer gel is widely used in the oil and gas industry to block high permeability conduits and reduce water cut. The complex nature of this fluid, especially regarding flow in porous media, makes its numerical simulation very time-consuming. This study presents an approach to designing an Artificial Neural Network (ANN) model that could predict the permeability reduction caused by injecting polymer gel into a 2D rock sample. Our methodology consists of two main parts: numerical simulation and ANN model building. Considering the advantages of the Lattice Boltzmann Method (LBM) this approach is used to model the injection of polymer gel in porous media. Using this model, more than 20,000 simulations were performed which resulted in highly unbalanced dataset, so an innovative approach for balancing regression dataset is also proposed in detail in this paper. The final constructed ANN model could predict the permeability reduction in a fraction of a second with less than 2.5% Mean Absolute Error (MAE). The result indicates the importance of balancing datasets to obtain a reliable prediction from ANN. Also, it should be mentioned that gelation parameters had the most significant impact on the value of permeability reduction, with mean absolute SHapley Additive exPlanations (SHAP) values of 20 and 12.5 for TDfactor and Threshold, respectively.

Polymer Screening for Efficient Water Cut Reduction in a Sandstone Oilfield in Kazakhstan.

Polymer flooding is one of the most widely used and effective enhanced oil recovery techniques. It can improve the macroscopic sweep efficiency of a reservoir by controlling the fractional flow of water. The applicability of polymer flooding for one of the sandstone fields in Kazakhstan was evaluated in this study and polymer screening was carried out to choose the most appropriate polymer among four hydrolyzed polyacrylamide polymer samples. Polymer samples were prepared in Caspian seawater (CSW) and assessed based on rheology, thermal stability, sensitivity to non-ionic materials and oxygen, and static adsorption. All the tests were performed at a reservoir temperature of 63 °C. Based on the results of the screening study, tolerance of a polymer towards high-temperature reservoir conditions, resistance to bacterial activity and dissolved oxygen present in make-up brine, chemical degradation, and reduced adsorption on rock surface were considered the most important screening parameters. As a result of this screening study, one out of four polymers was selected for the target field as it showed a negligible effect of bacterial activity on thermal stability. The results of static adsorption also showed 13-14% lower adsorption of the selected polymer compared to other polymers tested in the study. The results of this study demonstrate important screening criteria to be followed during polymer selection for an oilfield as the polymer should be selected based on not only polymer characteristics but also the polymer interactions with the ionic and non-ionic components of the make-up brine.

Application of gel systems for water shut-off on Uzbekistan oil fields

The article presents a water shut-off method with simultaneous acid treatment effective in both terrigenous and carbonate reservoirs. Field and experimental studies were carried out in the fields Kruk and Shurchi. As a result of the measures taken, a significant increase in oil production and reduction of production water cut was observed. Keywords: gel systems; gel formation; water shut-off; oil well; well flow rate.

Experimental Investigation on the Performance of Polymer-Coated Clay/Polyacrylamide Hydrogel for Water Shutoff Treatment

SummaryPolymer gel system has been identified as having the potential for blocking and diverting water flow. However, the current polymer reported an inability to maintain its mechanical strength, limited penetration depth, and instability in reservoir conditions of high temperature and high pressure. A distinctive bentonite nanomer clay (PGV)/acrylamide (AM)-co-2-acrylamido-2-methyl-1-propanesulfonic acid (AMPS) preformed particle gel with poly(ethylene glycol-b-tetramethylene oxide) (PEGTMO) coating to control the swelling kinetics is formulated. The in-house formulated gel’s ability to block and divert water flow in a porous medium is studied. The formation recipe of the gel was achieved by numerous swelling tests as induced by brine solution under reservoir conditions. Through the swelling tests, the long-term thermal stability of the gel solution was demonstrated. The incorporation of PGV clay particles improves the swelling and mechanical properties of the gel. Premature swelling can be avoided with PEGTMO coating as it slows the swelling rate over a 10-minute period, which gives the advantage of controlling the swelling before reaching the intended site of action during coreflood experiments. The rheological behavior of the hydrogel features rubber-like mechanical behavior with a viscosity value of 1.17 cp, which displayed water-like characteristics. Further, significant permeability reduction of large fractures is demonstrated by the coreflooding experiment with a calculated result of 96.2%. This formulated gel could offer the solution as a blocking agent in void space channels containing reservoirs that leads to a reduction of water cut due to thief zones.

A Systematical Review of the Largest Polymer Flood Project in the World: From Laboratory to Pilots and Field Application

Summary This paper presents a systematical review of the largest polymer flood project in the world, applied to multilayered, heterogeneous sandstone reservoirs in the giant Daqing Oilfield in China. First, reservoir and fluid characteristics are highlighted to understand the heterogeneity of the reservoir. Next, the project history is summarized, including laboratory studies, pilot tests, commercial tests, and fieldwide applications. Third, typical polymer flood performance and reservoir management measures are presented. Finally, key understandings and lessons learned from more than 50 years of experience are summarized. The La-Sa-Xing Field in the Daqing Field Complex contains three types of reservoir sands: Type I sand with high permeability, Type II sand with medium permeability, and Type III sand with low permeability. Polymer flood was studied in the laboratory in the mid 1960s, followed by small-scale pilots beginning in 1972 and industrial-scale pilots starting in 1993, all of which successfully reduced water cut and enhanced oil recovery. Fieldwide application commenced in 1996, targeting the Type I sand. With Type II sand being brought onstream in 2003, the project achieved a peak production of 253,000 BOPD in 2013. Polymer flood reduced water cut by 24.8%. Reservoir management measures, such as zonal injection, profile modification, hydraulic fracturing in low-permeability sand, and injection optimization, proved to be effective. Based on the water-cut performance, production can be divided into four stages: (1) water-cut decline, (2) low water cut, (3) rebound, and (4) water chase. Fit-for-purpose improved-oil-recovery measures were implemented for each stage to improve production performance. Key understandings and lessons learned include the following: (1) Polymer flood improves both sweeping and displacing efficiencies; (2) high interlayer permeability contrast leads to low incremental recovery; (3) variable well spacing should be adopted for different reservoir types; (4) adoption of large molecular weight (MW) and large slug size greatly enhances recovery; and (5) salt-resistant polymer is beneficial for produced water reinjection in Type II sand; (6) zonal injection increased swept reservoir zones by 9.8% and swept pay thickness by 10.3%; (7) profile modifications helped improve vertical conformance in injection wells and led to enhanced sweeping efficiency and extended low water-cut stage; and (8) optimization-recommended well spacing for Type I, Type II, and Type III sands is 10–15.5, 5.6–7.6, and 2.5–3.6 acres, respectively. In comparison with generally 6–8% incremental recovery by polymer flood in the industry, this project achieved an impressive incremental recovery of 12%, enhancing the oil recovery factor from 40% by primary recovery and waterflood to 52% stock tank oil initially in place (STOIIP). The progressive approach from laboratory experiments through pilots and finally to field application is a best practice for applying polymer flood fieldwide for a giant field such as the La-Sa-Xing Field.

Preparation and migration study of multi-walled carbon nanotube hybrid polymer gel particles: EOR implication

Multi-walled carbon nanotube hybrid polymer gel particles (MWCNTs-HPGP) were synthesized using the free radical polymerization approach to reduce water cut at first. The microstructure, particle size distribution, swelling characteristics, strength, and rheology of MWCNTs-HPGP were then studied. Subsequently, the migration and plugging properties of MWCNTs-HPGP were assessed at the core scale. The morphology of MWCNTs-HPGP was irregular with interpenetration networks, and MWCNTs-HPGP could expand by 48.2–94 times in brine with varying salinities (0 ∼ 20 × 104 mg/L NaCl), according to experimental results. After 60 d of age, MWCNTs-HPGP retained 95.2% of strength. Furthermore, the MWCNTs-HPGP dispersion solution’s shearing thinning feature and good viscoelasticity supplied it with favorable injectivity and deep migrating capacity. In addition, when the matching coefficient (β, the ratio of MWCNTs-HPGP median particle size to the average pore diameter) was 1.06 and the flooding rate was 0.5 mL/min, MWCNTs-HPGP could efficiently plug large pores with a plugging efficiency ranging from 82.7% to 98.5%. All the experimental results demonstrated that MWCNTs-HPGP could be a potential candidate for deep profile control and displacement in high temperature and high salinity reservoirs.

Preparation and profile control evaluation of core‐shell structure and surface‐hydrophobic modified polyacrylamide microsphere

AbstractPolyacrylamide (PAM) microsphere has been widely used in the field of profile control to reduce water cut in heterogeneous reservoirs. However, its mechanical strength and plugging ability are still needed to be improved. In this paper, a core‐shell structure and surface‐hydrophobic polyacrylamide M‐P(AM‐PEP) microsphere was prepared by using acrylamide (AM), block polyether macro monomer (PEP) and modified SiO2 with double bond on the surface as monomers through dispersion polymerization. After the optimization of synthesis conditions, the results of SEM and TEM confirmed that M‐P(AM‐PEP) microsphere had the nano‐scale spherical shape and the inorganic core/polymer shell structure, while the contact angle test results showed that M‐P(AM‐PEP) microsphere had the surface‐hydrophobicity. Swelling experiments presented that the size of M‐P(AM‐PEP) microsphere can be increased by 6 times and had obvious self‐gathering behavior. The inorganic core and self‐gathering behavior are helpful for improving mechanical strength and plugging ability of PAM microsphere, respectively. Profile control and oil recovery improvement experiment showed that injecting 0.1 PV M‐P(AM‐PEP) microsphere can decrease the water cut and increase the oil recovery of 17.95%. This new microsphere could be an efficient technology for the profile control in the heterogeneous reservoir.

Improved oil recovery techniques and their role in energy efficiency and reducing CO2 footprint of oil production

Production of mature oil fields emits significant amount of CO2 related to circulation and handling of large volumes of gas and water. This can be reduced either by (1) using a low-carbon energy source and/or (2) reducing the volumes of the non-hydrocarbon produced/injected fluids. This paper describes how improved oil recovery techniques can be designed to reduce CO2 intensity (kgCO2/bbl oil) of oil production by efficient use of the injectants. It is shown that CO2 emissions associated with injection of chemicals is strongly influenced by water cut at the start of the project, extent of the water cut reduction, and chemical utilization factor defined as the volume of produced oil per mass or volume of the injectant. As an example, for the oil field considered in this study, 3–8% reduction in water cut can result in 50–80% reduction in its CO2 intensity. In addition to the incremental oil production with lower CO2 intensity, the earlier implementation of enhanced oil recovery methods can extend the lifetime of the mature fields if carbon emission cut-offs are applied. In case of CO2 enhanced oil recovery (EOR), the large storage potential for CO2 can significantly reduce the overall CO2 emissions of oil, albeit at a large energetic cost. For CO2 EOR using CO2 captured from gas power plants, improving the utilization factor from 2 bbl/tCO2 to 4 bbl/tCO2 can reduce the CO2 intensity of the produced oil from 120 kgCO2/bbl to 80 kgCO2/bbl (33% reduction).

Исследование геомеханических свойств пород-коллекторов для уточнения дизайна гидроразрыва пласта

Introduction. The oil and gas resources of Russia have been growing mainly with hard-to-recover reserves of old producing regions and deposits located in hard-to-reach regions with undeveloped infrastructure for the last quarter of a century. The difficult conditions for the development of such fields and the extraction of residual reserves of the “old” fields create problems in hydrocarbons production, the complex geological structure causes great difficulty.Since the geological structure peculiarities of the fields often increase the risks of rapid well production flooding, the urgent task is to reduce such risks during hydraulic fracturing, to maintain the cost at a profitable level, and to ensure environmentally friendly conditions. The article considers the possibility of reducing the risk of water inflow along a hydraulic fracture and increasing the correctness of the fracture development prediction in a water-prone direction, which should ensure sufficient technological efficiency of work. Purpose of research is the need to develop innovative techniques and updated approaches to hard-to-recover oil reserves development, new techniques to improve the quality and success of work while maintaining their profitability. Research methodology. A comprehensive analysis of the hydraulic fracturing actual results, the results of laboratory studies and subsequent field tests. Research results and discussion. Based on the conducted studies, a technique has been proposed that allows determining the hydraulic fracturing design which makes it possible to reduce the risks of arbitrary, uncontrolled fracture propagation. The conducted field tests confirmed the significance and reliability of the proposed methodology. Findings. The article presents the results of studies of the hydraulic fracturing process. An updated technique for predicting hydraulic fractures is proposed, considering the reservoir rocks geo-mechanics. Field tests were carried out, which showed the effectiveness of calculations using the new technique – fluid inflows with reduced water cut and increased oil production from the target reservoir were obtained, i.e. penetration of cracks into the aquifer is not allowed. It has been established that during hydraulic fracturing it is necessary to fix the fracture with no more than 5 tons of prop pant. It was determined that the pad volume should be reduced to 50% of the injected prop pant weight. It was found out that it is preferable to use a linear gel to reduce the height of the hydraulic fracture, as well as to assess the need to correct the model based on the test operations results. The results of the research can be used on deposits similar in geological and commercial characteristics to those studied.

Evaluation and scientific justification of polymer flooding application in the Uzen oilfield

The Uzen field is at the late stage of development, with an average field water cut of over 90% due to a long-term non-shale waterflooding. At the same time, the current oil saturation of the reservoir is estimated as more than 50%, which may provide a promising future for the field. According to world practice, the application of chemical enhanced oil recovery (CEOR) methods can provide high oil recovery, and extend the cost-effective life of the field. Therefore, the application of chemical enhanced oil recovery is particularly relevant considering the current status of the Uzen field. The main method of CEOR is polymer flooding (PF), which has proven its high efficiency over 60 years of application in the industry. The objective of this study is to evaluate and justify the application of the polymer flooding technology to the conditions of the Uzen field. According to this objective, first of all, the world experience of polymer flooding was studied, including the latest large-scale projects in the fields of China, the USA, Canada, India, Oman and other countries. Criteria for the effective application of polymer flooding were developed and screening of the geological and physical characteristics (GPC) of all objects of the field was carried out. In addition, facies maps and the current state of development were analyzed to select a potential pilot test site. A review of the surface facilities, an analysis of the water supply sources and the characteristics of different polymers were carried out to develop a project for the pilot test of the technology. Preliminary hydrodynamic calculations show reduced water cut, increased oil production and an increase of 7% in oil recovery. Feasibility studies prove the profitability of the polymer flooding at oil prices above $55/bbl. This study is the basis for further implementation, adaptation and optimization of polymer flooding

Theoretical Research in Laboratory and Field Trial of Micro-Nano-Oil Displacement System Conformance Control Technology

Abstract In recent years, a series of field tests of a new micro-nano-oil displacement system (MNS) conformance control technology have been carried out in different oilfields, which can increase oil production and reduce water cut obviously. However, compared with its field application, the research on its performance evaluation and oil displacement mechanism is still in the initial stage. And it is urgent to carry out relevant research work. Therefore, this paper made a profound study on its physicochemical properties, reservoir adaptability, transport and deep fluid diversion ability, and oil displacement mechanism. Results show that MNS with a series of particle sizes in different sizes (from nanometer to micrometer) can be obtained. And it has good expansion ability. Through reservoir adaptability evaluation, the matching relationship between the size distributions of MNS particles and pore throat is given, which has important guiding significance for MNS particle size selection for target reservoir before field trial. Furthermore, MNS has strong transport ability. When migrating in the porous media, it shows the motion feature of “trapping, deformation, migration, retrapping, redeformation, and remigration,” which can obtain better oil incremental effect than traditional polymer flooding. Under the condition of the same agent type, composition, and slug size, the oil recovery rate can be further enhanced by 6.96%. In addition, MNS conformance control technology has obtained good technical and economic effect in the 8 oilfields, with the lowest input-output ratio of 1.67 and the highest of 14.37. The reason why MNS have the above-mentioned good performances depends on its advanced mechanism: the unique particle phase separation phenomenon. When transporting in porous media, MNS particles gather in the larger pore to form bridge blocking, and its carrier fluid displaces oil in the small pore. Working in cooperation, MNS can realize deep fluid diversion and expand macroscopic and microscopic swept volume.

Application of Gel for Water Shutoff: A Case Study of Kelebija Oil Field

Summary This paper focuses on the results of water shutoff operations using polymer gel in the Kelebija oil field. The methodology of candidate wells’ selection and the manner of performing the operation will also be included. The Kelebija oil field is characterized by a complex reservoir system with heterogeneous layers of different permeability and dual porosity with a strong waterdrive aquifer, which led to the early breakthrough of water. For the last 25 years, the average water cut was above 90%. Implementation of water shutoff operations began in 2019 and was performed on seven wells with an 85.7% success rate. It proved to be very effective with a water-cut reduction from 23% to as much as 72%. The average water cut for the entire Kelebija oil field has dropped by 12% and oil production increased by 210%.

Research and effect analysis on improving injection mode of weak alkali ASP flooding in poor oil layer block

In view of the large proportion of thin and poor layers in the weak-alkali ternary flooding block, the statistical analysis method is used to optimize the division of well groups with injection capacity, establish a strategy chart for different types of groups to maintain injection and tap potential, and optimize the well groups of different sand body connectivity types. The fracturing method strengthens the whole process of fracturing in the well area with poor injection capacity. The effective thickness water absorption ratio is over 80%, the maximum water cut reduction in the stage is 9.65%, the low water cut stable period is 16 months, and the recovery factor is increased by 8.77 percentage points. development effect.

Associative polymers for disproportionate permeability reduction – Formation wettability effects

Core-based laboratory experiments were performed on water- and chemically-treated-oil-wet Berea sandstone long-core samples to investigate the disproportionate permeability reduction (DPR) potential of a low-molecular weight associative polymer. The impact of single- and two-phase DPR treatments were considered at 60 °C. In the experiments conducted, real-time electrical resistivity measurements were obtained during the coreflood tests to serve as (a) a valuable tool for fluids saturation monitoring and (b) improved core fluids saturation evaluation in flooded porous media. Results from DPR treatments in water-wet cores showed high initial oil residual resistance factors, RRFo (≈20), followed by relatively long clean-up times; stabilized RRFo was achieved at relatively high PVs of oil injection (≈25). For the range of the post-treatment pressure gradients applied in the laboratory experiment, no DPR effects were observed for the water-wet core samples. However, the different shear-dependent behavior for the oil and water phases in the treated zone suggests that a positive DPR effect is possible at extrapolated low post-treatment applied pressure gradients; this could also be translated as higher clean-up times. For the two-phase DPR treatments in water-wet cores, RRFo can be significantly reduced to approximately 8, while RRFw stabilized at the relatively high value of 40. However, the required significantly long clean-up period during oil flow through the treated zone may question the efficiency of the achieved DPR effect. For the two-phase DPR treatment in oil-wet cores, stabilized RRFo were achieved at considerably lower injected oil PVs, i.e., shorter post-treatment clean-up periods were required. In addition, distinguishably smaller RRFo values were achieved for the oil-wet cores compared to the water-wet ones with a substantial separation from the achieved RRFw values (i.e., faster attainment of low values ranging between 6 and 4 for 15 to 40 injected PVs clean-up duration). These results indicate greater potential for effective positive DPR treatment for oil-wet medium treated through two-phase injection methods. Multi-rate tests conducted during polymer injection showed that the mobility reduction (resistance factor, RF) during DPR treatments, for both single- and two-phase methods, are shear dependent. In addition, post-treatment water and oil injection (production) showed different behavior regarding permeability reduction (RRF). In both core wettability cases, water flow experienced a noticeable power-law dependency to the applied differential pressure. On the other hand, the oil flow behavior in the two wettability cases was different; slightly shear-thinning for the water-wet cases and weakly shear-thickening for the oil-wet cores. In both cases the shear dependency of oil flow was much less pronounced than that of the water flow. Finally, the production water cut can be decreased to a noticeable amount using associative polymer DPR treatments. However, one must note that the water cut reduction (economic gain) is associated with a reduced total (oil) production rate (time loss); therefore, implementation of an associative polymer DPR treatment should be considered carefully.

Modeling to support physicochemical enhancement techniques

The article discusses ways to increase the oil recovery factor in already developed fields, special attention is paid to the methods of enhanced oil recovery. The comparative structure of oil production in Russia in the medium term is given. The experience of oil and gas companies in the application of enhanced oil recovery in the fields is analyzed and the dynamics of the growth in the use of various enhanced oil recovery in Russia is estimated. With an increase in the number of operations in the fields, the requirements for the selection of candidates inevitably increase, therefore, the work focuses on hydrodynamic modeling of physical and chemical modeling, highlights the features and disadvantages of existing simulators. The main dependences for adequate modeling during polymer flooding are given. The calculation with different concentration of polymer solution is presented, which significantly affects the water cut and further reduction of operating costs for the preparation of the produced fluid. The possibility of creating a specialized hydrodynamic simulator for low-volume chemical enhanced oil recovery is considered, since mainly simulators are applicable for chemical waterflooding and the impact is on the formation as a whole.

Synergistic Modes and Enhanced Oil Recovery Mechanism of CO2 Synergistic Huff and Puff

With the gradual declining of oil increment performance of CO2 huff-and-puff wells, the overall oil exchange rate shows a downward tendency. In this regard, CO2 synergistic huff-and-puff technologies have been proposed to maintain the excellent effect and extend the technical life of such wells. However, there is no specific research on the mechanism and synergistic mode of CO2 huff and puff in horizontal wells. This study aims to establish the synergistic mode and determine the adaptability and acting mechanism of CO2 synergistic huff and puff. Three synergistic huff-and-puff modes are proposed based on the peculiarity of the fault-block reservoir’s small oil-bearing area and broken geological structure. We establish three typical CO2 synergistic huff-and-puff models and analyze the influence of different geological and development factors on the huff-and-puff performance with numerical simulation. Each factor’s sensitivity is clarified, and the enhanced oil recovery (EOR) mechanism of CO2 synergistic huff and puff is proposed. The sensitivity evaluation results show that the reservoir rhythm, inter-well passage, well spacing, high-position well liquid production rate, and middle-well liquid production rate are extremely sensitive factors; the stratum dip and injection volume allocation scheme are sensitive factors; and the relationship with structural isobaths is insensitive. The EOR mechanism of synergistic huff and puff includes gravity differentiation, supplementary formation energy, CO2 forming foam flooding, and coupling effect of production rate and oil reservoirs. The implementation conditions of the two-well cooperative stimulation mode are the simplest. The two-well model is suitable for thick oil layers with a positive rhythm and large formation dip. The single-well mode requires no channeling between the wells, and the multi-well mode requires multi-well rows and can control the intermediate well’s fluid production rate. Field application at C2X1 block shows a good performance with a total oil increment of 1280 t and an average water-cut reduction of 57.7%.