Oil Recovery Factor Research Articles

Performance evaluation and mechanism study of a functionalized silica nanofluid for enhanced oil recovery in carbonate reservoirs

In this investigation, a functionalized SiO2 nanofluid was developed by integrating sodium oleate to mercapto-terminated nano-SiO2 via the thiol-ene “click” reaction. The developed nanofluid in the presence of higher concentrations (> 40,000 ppm) of NaCl at 70 °C was confirmed to be more stable than the original SiO2 nanofluid based on the outcomes obtained from precipitate observation, particle dimension, and zeta potential measurements. Successful integration of sodium oleate on the target nanoparticles was corroborated by a series of characterization approaches. Furthermore, the viscosity, contact angle, and interfacial tension (IFT) determinations were conducted to investigate nanofluids' potential for enhanced oil recovery (EOR). The results indicated that the viscosity of the functionalized SiO2 nanofluid (labeled FF-4) accounted for 3.48 cp after adding 40,000 ppm NaCl, while that of the original SiO2 nanofluid (labeled OF-4) was 1.15 cp. From the contact angle values, the carbonate rock surface was transformed from oil-wet (135°) to water-wet (72° and 38°) after being treated with the OF-4 and FF-4. The wettability alteration was attributed to the formation of the wedge film in the contact line area between the rock and fluids (oil sample and nanofluid). The functionalized nano-SiO2 helped to reduce IFT because of the simultaneous presence of the alkane chain (oleophilic) and carboxylate group (oleophobic) on the particle surface, making the functionalized nano-SiO2 have an amphiphilic structure. However, the original nano-SiO2 hardly changed IFT. Micro-model experiments showed that the OF-4 had a prominent oil displacement effect by changing wettability to a water-wet state and reducing the viscous fingering phenomenon. Core flooding tests demonstrated that the oil recovery factor of the FF-4 was almost 2.5 times that of the OF-4. Viscosity improvement was considered as a new oil recovery mechanism after wettability alteration and IFT reduction. This paper revealed the important properties of the functionalized nano-SiO2 and provided a novel efficient nanofluid for EOR in carbonate reservoirs.

Design and synthesis of a new ionic liquid surfactant for petroleum industry

This study is intended to synthesize and assess a new pyridinium-based Ionic Liquid (IL) surfactant, 1-octadecyl-pyridinium bromide, in terms of crude oil–water Interfacial Tension (IFT) reduction and wettability alteration. The synthesized IL surfactant is firstly characterized through proton Nuclear Magnetic Resonance (1H NMR). Then, the pendant-drop and sessile drop techniques are employed to study crude oil–water IFT and the wettability of carbonate rocks. Based on the IFT results, the synthesized IL has a Critical Micelle Concentration (CMC) of 200 ppm, at which crude oil–water IFT reduces by 95.9 %, from an initial value of 23.7 mN/m to 0.97 mN/m. Increasing the salinity up to 100,000 ppm could not make the synthesized IL less effective than that of free from salinity, as the magnitude of IFT is obtained to be 0.938 mN/m at CMC. Based on the wettability investigation phase, the synthesized IL changes the wettability of carbonate slices from oil-wet to intermediate-wet (140.47°–90.97°). It is also observed that the synthesized IL can tolerate harsh salinity conditions as no appreciable change in the contact angle is noticed after increasing the salinity even up to 150,000 ppm (84.54° at CMC). It should be noted that an optimal salinity of 50,000 ppm is found based on the results of IFT and contact angle measurements. The introduced surfactant is expected to exhibit a significant positive impact on the oil recovery factor while implementing chemical flooding.

Chemical-assisted MMP reduction on methane-oil systems: Implications for natural gas injection to enhanced oil recovery

Miscible natural gas injection is widely considered as a practical and efficient enhanced oil recovery technique. However, the main challenge in this process is the high minimum miscibility pressure (MMP) between natural gas and crude oil, which limits its application and recovery factor, especially in high-temperature reservoirs. Therefore, we present a novel investigation to quantify the effect of chemical-assisted MMP reduction on the oil recovery factor. Firstly, we measured the interfacial tension (IFT) of the methane-oil system in the presence of chemical or CO2 to calculate the MMP reduction at a constant temperature (373K) using the vanishing interfacial tension (VIT) method. Afterwards, we performed three coreflooding experiments to quantify the effect of MMP reduction on the oil recovery factor under different injection scenarios.The interfacial tension measurements show that adding a small fraction (1.5 wt%) of the tested surfactant (SOLOTERRA ME-6) achieved 9% of MMP reduction, while adding 20 wt% of CO2 to the methane yields 13% of MMP reduction. Then, the coreflooding results highlight the significance of achieving miscibility during gas injection, as the ultimate recovery factor increased from 65.5% under immiscible conditions to 77.2% using chemical-assisted methane, and to 79% using gas mixture after achieving near miscible condition. The results demonstrate the promising potential of the MMP reduction to significantly increase the oil recovery factor during gas injection. Furthermore, these results will likely expand the application envelop of the miscible gas injection, in addition to the environmental benefits of utilizing the produced gas by re-injection/recycling instead of flaring which contributes to reducing the greenhouse gas emissions.

Impact of salinity on fluid/fluid and rock/fluid interactions in enhanced oil recovery by hybrid low salinity water and surfactant flooding from fractured porous media

Wettability alteration of the porous medium from oil-wet (OW) to neutral-wet or even water-wet (WW) is proposed as one of the main mechanisms behind the enhanced oil recovery (EOR) by the Low Salinity Water Flooding (LSWF). However, our recent studies for a specific crude-oil/brine/rock of the oil reservoir in the Middle East, shows that LSW (diluted sea water) is not that much effective, neither to change the wettability of the surface nor to significantly increase the oil recovery factor. This obstacle becomes more challenging when we deal with fractured formations, where the imbibition of injected fluid from fracture into matrix and its propagation within the matrix, is the main macroscopic mechanism of the EOR. Chemical EOR, in which the chemical additive is added to the injecting brine, is one of the hybrid techniques which can boost oil recovery in such cases. In this study, CTAB as a cationic surfactant was added to brine solutions with different ionic strengths (i.e., sea water (SW), 10 times diluted sea water (10dSW) and 2 times concentrated sea water (2cSW)). Contact angle, zeta potential of both fluid/fluid and fluid/rock surfaces, and IFT tests were conducted to shed insight on interactions in crude oil/brine and rock/brine interfaces and the role of ionic strength. Finally, dynamic micromodel tests were performed in oil-wet fractured porous media to observe the impact of the added surfactant along with different ionic strength on displacement mechanisms and oil recovery.Experimental results show that neither electrical double layer expansion nor multiple ion exchange mechanisms cannot justify the observed detachment of oil droplets from the oil-wet substrates in the presence of the CTAB. Surfactant are absorbed on the oil/brine interface by the embedment of their hydrophobic tails in oil. Both surfactant molecules and the non-polar oil components (that are attracted to hydrophobic tail of surfactant molecules), are attracted to the solution via the hydrophilic parts of the surfactants. The effectiveness of this mechanism is dependent on both the concentration of the surfactant and concentration of the ions in brine.In the case that the aforementioned mechanism is adequately dominant and effective, the small droplets of oil will be detached from continuous oil bulk, resulting in oil to be broken to smaller droplets which enhances the detachment of the oil bulk from oil-wet substrates. This fluid/fluid interaction mechanism also promotes the imbibition of the aqueous phase into the matrix and also its propagation within the matrix.

Insights into in-situ upgrading of bitumen in the hybrid of steam and combustion process: From experimental analysis aspects

In situ combustion (ISC) has been evaluated as a follow up process in the steam injection process for heavy oil and bitumen recovery. Except for providing energy or heat to reduce bitumen viscosity, in situ upgrading of bitumen is another advantage of ISC process. In situ upgrading of bitumen through co-injection of steam and oxygen is evaluated in this work. Three different types of laboratory experiments, including one static thermal cracking experiment, one ramped temperature oxidation (RTO) experiment, and one combustion tube test, were performed to examine the produced oil properties and the potential of bitumen in situ upgrading. A comprehensive analysis of produced oil properties and gas composition was performed. Bitumen was significantly upgraded in the thermal cracking experiment at a temperature of 430 °C, in which Saturates fraction increased to 56%, while Resin and Asphaltene fractions reduced to 6.7% and 6.8%, respectively. The thermal cracking of Resin and Asphaltene contribute to the production of the light oil and gases, leading to the upgrading of the bitumen. Dynamic properties of produced oil were measured in the RTO and combustion tube test in terms of produced oil viscosity, density, boiling point temperature distribution, and produced oil compositions, etc. In the RTO test, the extent of bitumen upgrading is greater with the increase of temperature, further proving that the high temperature generated by the combustion front is able to effectively crack the bitumen. Furthermore, the lack of light hydrocarbon in the produced oil indicates light hydrocarbon participates in the high temperature oxidation reactions. Different from thermal cracking experiment and RTO test results, combustion tube test results indicated that the bitumen was slightly upgraded in late stage of the combustion tube test and most produced bitumen are similar with original bitumen. By examining the temperature distribution along the combustion tube, it is found that upgraded bitumen cannot be effectively displaced to the producer. This implies the limitation of in situ upgrading in the conventional in situ combustion process. Proper well configuration was recommended for the future field application of the hybrid steam and combustion process to achieve the high oil recovery factor and partial in situ upgrading of bitumen.

Phase Behavior in Nanopores and Its Indication for Cyclic Gas Injection in a Volatile Oil Reservoir from Duvernay Shale

Abstract Duvernay shale spans over 6 million acres with a total resource of 440 billion barrels’ oil equivalent in the Western Canada Sedimentary Basin (WCSB). The oil recovery factors typically decrease with the decreasing of gas-oil ratio (GOR) in oil window of Duvernay shale. The volatile oil recovery factors are typically 5–10%. Enhanced oil recovery technologies should be applied to improve the economics of the reservoirs. In this paper, the volatile oil from the Duvernay shale was taken as an example for phase behavior study. We analyzed the nanopore confinement on phase behavior and physical properties of Duvernay shale oil. The shift of critical properties was quantified within nanopores. With the confinement of nanopores, the viscosity, density, and bubble point pressure of the oil decrease with the shrinking of the pore size. Minimum miscibility pressure (MMP) was calculated for different injected gases. The MMP from high to low is N2>CH4>lean gas>rich gas>CO2. In the case of injecting the same gas component, the MMP decreases as the pore size decreases. The wellhead rich gas is suggested to be the main gas source for gas injection in Duvernay shale. The formation pressure should be rapidly increased to the MMP and maintained close to it, which would help to improve the effect of gas injection and enhance shale oil recovery. This paper can provide critical insights for the research of shale oil gas injection for enhanced oil recovery.

A comprehensive investigation of SAGD steam chamber in dual horizontal well pairs: Expansion angel and connection characteristics

The expansion behaviors of the steam chamber play a significant role in the stability of steam-assisted gravity drainage (SAGD). For Long Lake extra-heavy oil reservoir, the 3D SAGD physical model based on similarity criteria is established in this work to investigate the expansion angel and connection characteristics of the steam chamber at varying well-pairs spacing and vertical distance. The results show that expansion angles of the well spacing of 50 m, 75 m, and 100 m are 16.5° and 17.6°, 22.5° and 23.0°, 25.4° and 24.8°, and the sweep efficiency is 96.7%, 90.8%, 78.6%, respectively. The smaller the well spacing between the dual well-pairs, the smaller the final expansion angle of the steam chamber, and the greater development effects. The vertical distances of 3 m have the maximum expansion angles (24.0° and 16.7°), and the highest sweep efficiency (81.6%). The smaller vertical distance of the dual well pair is accompanied by the larger expansion angle, which is beneficial to the development and propagation of steam chambers. The vertical expansion of the steam chamber is concentrated in the early stage of development, and the lateral expansion speed increases after the steam chamber contacts the top of the reservoir. The lateral expansion velocity and width of the steam chamber are the largest (0.36 cm/min and 0.4 cm/min, 20 cm) at the well-pairs spacing of 100 m. The heavy oil recovery factors at varying well-pairs spacing are in turn, 39.4% (50 m), 37.1% (75 m), and 33.7% (100 m). Compared to 6 m and 9 m, the vertical distances of 3 m have the highest ultimate oil recovery, 35.4%. Considering the economy and exploitation effect, the dual well-pairs with 50–75 m spacing and no vertical distance is recommended to promote the successful application of the SAGD technique in heavy oil reservoirs with 20–30 m thickness.

Effect of pore structure and injection pressure on waterflooding in tight oil sandstone cores using NMR technique and pore network simulation

As an economical and reusable method of enhancing oil recovery, waterflooding is widely used in the development of tight oil reservoirs, although it has often been found unsuccessful owing to the adverse properties of tight rocks. Accurate knowledge of the pore-scale distribution of oil in tight rocks during waterflooding is needed for devising strategies to maximize oil recovery. Here, we used a two-fold approach to identify the amount and spatial distribution of the residual oil as a function of injection pressure. We i) characterized the pore structure of two cores from a tight sandstone reservoir in the Ordos basin, China, and ii) conducted waterflooding experiments with different injection pressures using nuclear magnetic resonance measurements. We found that even small differences in the tight sandstones pore structures caused measurable variations of the amounts oil produced from different classes of pores. For example, in experiments using identical water injection pressures but samples with different permeabilities, a permeability increase by a factor of 3 corresponded to a 10% reduction in oil recovery. We also found that the increase in residual oil saturation caused by increasing the injection pressure was unfavorably dependent on the pore structure heterogeneity. This observation was supported by pore network simulations, which were additionally carried out. We therefore conclude that it is necessary to evaluate the pore structure heterogeneity of the reservoir rocks when attempting to enhance the oil recovery factor of a tight reservoir by means of the common strategy of raising the waterflood injection pressure.

Strategies of SAGD Start-Up by Downhole Electrical Heating

The SAGD start-up process normally circulates steam in both the injector and producer, which consumes a large amount of steam, requires the high cost of high-temperature-produced liquid treatment, and unavoidably results in preferential communication in heterogeneous reservoirs. In order to achieve uniform preheat and full steam chamber development in SAGD wellpairs, downhole electrical heating to start up SAGD was proposed and investigated in this study using physical and numerical simulation approaches. Two 3-D scaled physical experiments were designed and implemented to investigate the feasibility and heating characteristics of such a method. Numerical simulation was conducted using an SAGD sector model with typical field properties to design the preheating process, optimize key operational parameters, and formulate the soak strategy to determine the SAGD conversion timing. The experimental results indicate that electrical heating outperforms steam circulation in achieving the uniform thermal communication in heterogeneous reservoirs, which is challenged in the conventional steam circulation process. The preheating process and operational parameters of electrical heating were formulated and optimized, which include wellbore pre-flush, wellbore saturation by heat conduction fluid, electrical heating, and replacement of heat conduction fluid periodically. Surveillance of temperature difference along the horizontal section while powering off electrical heating intermittently is optimized to be the SAGD conversion timing determination strategy. Based on the combination results of scaled physical simulation and pilot wellpair numerical simulation, full heat communication and steam chamber development are achieved along the horizontal length by electrical preheating, and the oil recovery factor of the pilot wellpair is enhanced by 14.8%, indicating encouraging potentials in heavy oil and bitumen development.

Synergistic Efficiency of Zinc Oxide/Montmorillonite Nanocomposites and a New Derived Saponin in Liquid/Liquid/Solid Interface-Included Systems: Application in Nanotechnology-Assisted Enhanced Oil Recovery.

Oil production faces challenges such as limited oil production from carbonate reservoirs, high oil production costs, and environmental issues. Chemical flooding as an enhanced oil recovery (EOR) method (CEOR) can increase oil production by the use of chemical additives such as surfactants into the reservoirs. Surfactants can increase oil recovery by interfacial tension (IFT) reduction and alteration of the rock wettability from oil-wet to water-wet. The synthesis of chemicals such as synthetic surfactants is usually costly and harmful to the environment. To solve these problems, many researchers have oriented on the use of natural surfactants instead of synthetic ones within the CEOR process. A new approach to increase the efficiency of CEOR is the synergizing of the chemical additives with nanoparticles as a hybrid fluid, which is known as the nanotechnology-assisted EOR method. In this research, a natural surfactant derived from Cyclamen persicum (CP) plant was extracted, and its performance was optimized with the zinc oxide/montmorillonite (ZnO/MMT) nanocomposite in a synergistic usage. At the optimum concentration of the surfactant, the measurements of the IFT and the contact angle show 57.78 and 61.58% optimizations, respectively. Also, in the presence of NaCl, the performance of CP is improved. IFT and contact angle measurements were also conducted for ZnO/MMT nanofluids and CP-ZnO/MMT as hybrid nanofluids. Results indicate that ZnO/MMT nanocomposites can alter the wettability of the carbonate rock to the water-wet state. Also, the CP-ZnO/MMT hybrid nanofluid shows a good potential in both IFT reduction and altering wettability from oil-wet to water-wet. Finally, to investigate the effects of solutions on increasing oil recovery factor (RF), the optimum concentrations of the surfactant, nanocomposite, and hybrid solutions were selected for dynamic core flooding experiments, and improvements showed oil RF increases of 8.2, 6, and 13%, respectively.

Experimental study on the effect of pressure decline rate on foamy oil flow characteristics in a heavy oil–CO2‐C3H8 system

AbstractCO2‐based cyclic solvent injection (CSI) processes have gained great interest and have been piloted to enhance heavy oil recovery sustainably. Although the performance of pure CO2 injection is encouraging, it is still not commercially feasible. In order to improve the performance of the CSI process, CO2 (72%) and C3H8 (28%) were chosen to be mixed with a heavy oil sample, and then four pressure depletion tests were conducted to investigate the effects of decline rates on the enhanced oil recovery performance and foamy oil flow behaviour. The production behaviour can be divided into three phases: volume expansion production phase (7% contribution), foamy oil flow production phase (73% contribution), and solution‐gas drive phase (20% contribution). The experimental results showed that depletion rates positively correlated with oil recovery factors in the last two phases. Additionally, the foamy oil flow phase was further divided into two zones: Zone‐1 (bubble nucleation and growth dominant zone) and Zone‐2 (bubble coalescence and disengagement dominant zone). The results showed that higher pressure depletion rates lead to larger pressure differences which in turn resulted in an increasing bubble nucleation rate in Zone‐1. While coalesced bubbles in Zone‐2 lead to a stronger discontinuous gas flow and the relative permeability of the oil phase decreased sharply. Compared with relatively lower heavy oil recovery factors (19.4%) in pure heavy oil–CO2 system, the heavy oil–CO2‐C3H8 system took advantage of a higher oil recovery factor (23.44%). Furthermore, the relatively lower average gas recovery factor and cumulative gas–oil ratio (cGOR) indicated that CO2 can be sequested in heavy oil reservoirs more efficiently.

Evaluation of Gas-Based EOR Methods in Gas-Invaded Zones of Fractured Carbonate Reservoir

More than half of all recoverable oil reserves are found in carbonate rocks. Most of these fields are highly fractured and develop different zonations during primary and secondary recovery stages; therefore, they require a different developmental approach than conventional reservoirs. Experimental results for water-alternating gas injection [WAG] and foam-assisted water-alternating gas [FAWAG] injection under secondary and tertiary recovery conditions were used to investigate these enhanced oil recovery [EOR] methods in gas-invaded reservoirs. The relative permeability curves of the cores and the fitting foam parameters were derived from these experiments through history matching. These findings were then used in a quarter five-spot, cross-sectional, and a sector model of a carbonate reservoir where a double five-spot setup was implemented. The fracture and matrix properties’ impact on the recovery was illustrated through the cross-sectional model. The gas mobility reduction effect of the FAWAG was more noticeable than that of WAG. The apparent viscosity of the gas was increased due to the foam presence, which caused a diversion of the gas from the fractures into the matrix blocks. This greatly enhanced the sweep efficiency and led to higher oil recovery. The gas front was much sharper, and gravity overrides by the gas were much less of a concern. The properties of the fracture network also had a significant effect on the recovery. Oil recovery was found to be most sensitive to fracture permeability. At the same time, sweep efficiency increased substantially, improving the recovery rate in the early injection stages, and differed slightly at the ultimate recovery. However, a lower fracture permeability facilitated gas entry into the matrix blocks. The results of the reservoir sector model were similar to the core and pilot. However, the WAG injection recovered more of the uppermost layers, whereas significant portions of the lowest layer were not effectively recovered. In contrast, FAWAG was more effective in the lowest layer of the reservoir. The FAWAG was a beneficial aid in the recovery of gas-invaded fractured reservoirs, increasing the oil recovery factor with respect to WAG.

Effects of chemical osmosis on swelling clays and the elastic properties of the Pierre shale with its implications for oil recovery

The main objective in this study is to experimentally investigate how two types of shales different in swelling characteristic and organic carbon content behave in terms of the mechanical and infiltration properties when being subjected to changing osmosis with varying brine salinity under in-situ stress conditions. This research also aims to determine the swelling tendency of thePierre shale and replicate the effect of selection of brine salinity on oil recovery in liquid-rich shales. A series of coupled measurements from the triaxial experiments at reservoir conditions was conducted on Pierre shale core samples to determine rock properties and behavior under fluid pore pressure intrusion. The main use of the measured properties is to demonstrate the impact of fluid transport induced by low salinity water injection accompanied by osmosis, clay swelling, and rock elasticity change on oil recovery from rock matrix. The Young's modulus, bulk modulus, and Poisson's ratio of the Pierre shale were determined from measurements on the two types of Pierre shale samples obtained from an outcrop having high 65 wt% of smectite content and well core having lean clay content and 3.5 wt% TOC (total organic carbon). The first two experiments were performed on the outcrop samples comprising of similar characteristics of 65 wt% smectite with negligible TOC while the last experiment was performed on the well core sample containing negligible smectite content with 3.5 wt% TOC. The membrane efficiencies of the shale samples were experimentally determined to range from 5% to 28% depending on clay content and stress. The outcrop shale showed 1% of swelling that is significantly higher than 0.07% of swelling developed in the well core shale lean in clay content. One of the most important findings of this research is that the membrane coefficient representing the stress sensitivity of membrane efficiency of organic-rich well core shale was found to be 11.5%/kpsi which is significantly higher than that of the swelling shale ranging from 2.2 to 3.5%/kpsi. This is interesting because the approximately 5.5 times stiffer matrix of organic-rich shale shows the significantly higher stress sensitivity in terms of the membrane efficiency. The Young's modulus of swelling shale declined with water saturation as well as the water transfer driven by osmotic pressure with low salinity brine. In contrast, the well core shale showed significant increase in the dynamic Young's modulus. The experimental data were used to evaluate the mass exchange between the fractures and rock matrix using a coupled fluid flow and geomechanics model accounting for shale swelling and osmosis transport to evaluate how fluid and rock interaction affect the oil recovery from the rock matrix of the Pierre shale during low salinity water injection (LSWI). A 25% increase in oil recovery factor was determined after considering the effects of changing membrane efficiency due to clay swelling resulting from LSWI. The modeling results therefore suggest that the variation of membrane efficiency due to swelling can be an important factor affecting the oil recovery from matrix block during LSWI enhanced oil recovery.

Using Digital Models to Identify Hydrodynamic Interference Between Producing and Injection Wells to Improve Field Development Management Efficiency

Effective development of oil fields is impossible without reliable information on the degree of well interference. The interference between production and injection wells is evaluated using indicators that are commonly known as the interference coefficients or connectivity coefficients. There are a number of statistical, analytical, and predictive methods for hydrodynamic connectivity (interference) assessment. This paper focuses on a new approach designed to overcome the challenges related to the rational development of reserves and well interference assessment with building an improved hybrid material balance model. The purpose of the research was to evaluate various scenarios for well interference assessment, as well as to identify hydrodynamic communication between injection wells and specific producing wells for prompt decision-making to optimize the development system. The paper discusses the results of studies conducted on one field of Western Siberia, having a complex geological structure and high heterogeneity. Well interference coefficients were obtained as the result of the studies, which helped us to understand how the average proportion of water injected from a particular injection well effectively impacts the producing wells in question located in the immediate vicinity. The digital hybrid model was used to identify the injection wells that are hydrodynamically connected with producing wells, estimate the degree of their impact on the production performance of the latter, as well as monitor the dynamics of such influence for each well. Based on the analysis performed, some recommendations were made for improving the oil recovery factor in the oil fields and reducing development costs.

Oil recovery factor express evaluation during carbonate reservoirs development in natural regimes

The article provides a geological and field analysis of the productivity factor and specific balance reserves per well influence on the current and final oil recovery factor during the development of the deposit in natural conditions. The analysis was carried out for various groups of deposits in carbonate reservoirs confined to the lower and middle Carboniferous systems of the Volga-Ural oil and gas province. Empirical dependencies allowing the deposits development monitoring, evaluating the effectiveness of using secondary and tertiary enhanced oil recovery techniques, making sound management decisions to improve the development process not only for the objects of analysis but also for analogue objects have been obtained. Keywords: oil recovery; well grid density; specific balance reserves; oil flow rate; production; oil recovery factor; productivity factor.

Evaluation and use of the productivity coefficient for development management problems solving

It is shown that in the conditions of low-productive carbonate deposits with hard-to-recover reserves, confined to the Middle Carboniferous deposits of the Birskaya saddle and the Perm-Bashkir arch of the Volga-Ural oil and gas province, the productivity factor determined during the well flow rate stabilization period after development largely determines the final technological development indicators. We propose geological and statistical models allowing determining the productivity values to the greatest extent reflecting the real reservoir properties at the point of opening it with a well. The obtained results make it possible to evaluate the effectiveness of measures aimed at improving the efficiency of managerial decisions to achieve the maximum return on the oil companies’ assets. Keywords: productivity factor; geological and statistical models; empirical base models, oil recovery factor; geological and physical parameters; technological development indicators.

Improving the lower cretaceous deposits development efficiency in Western Siberia employing enhanced oil recovery

For the eleven groups of oil deposits in terrigenous reservoirs of Western Siberia, confined to the Lower Cretaceous deposits, the most effective techniques for enhanced oil recovery were selected based on a criteria analysis, followed by the numerical modeling application in terms of the final oil recovery factor. The need for a differentiated approach when using enhanced oil recovery techniques is specified. An algorithm for replicating the results obtained in the fields that did not participate in the study based on the analogy method is presented. Keywords: enhanced oil recovery techniques; oil recovery factor; hard-to-recover reserves; analogy method; differentiation and grouping of oil deposits.

Regulation of development of the main deposit of the рashi horizon bavlinskoye field by limiting water injection

At the beginning of the 1950s, edge waterflooding, the first of many types of waterflooding, was applied to terrigenous deposits of the Pashi horizon of the Bavlinskoye field. Based on the results of geological and technological modeling, it was obtained that the development of low-permeability sections of the reservoir, intermediate zones in the area of the injection and contraction production rows lags behind and, undoubtedly, leads to a rapid water cut of the produced product and a decrease in the oil recovery factor, therefore the authors in this work conducted numerical experiments to regulate the front advancement of the injected water to the deposits of the Pashi object by limiting the volume of water injected into the reservoir using geological and technological 3D modeling. Analysis of the results of the conducted numerical experiments to regulate the development of the reservoir of the Pashi object by limiting the volume of water injection showed that in this way it is possible to improve the technological indicators of development (increase oil production and reduce water production) and select the most acceptable amount of injected water, which will be technologically and economically viable. Keywords: in-line and in-line waterflooding; oil-bearing contour; injection restriction; daily production; industrial experiment; injection wells ring; well injectivity; monolithic sandstones; filtration flow direction.

Research and justification of innovative techniques employment for hydrocarbons production in difficult conditions

For the difficult conditions of development of various groups of facilities in the carbonate reservoirs of the eastern part of the Volga-Ural oil and gas province, models have been created that allow the search and justification of the use of innovative techniques of hydrocarbon production. Algorithms for forecasting the final oil recovery factor under conditions of heterogeneous information and various kinds of uncertainties are proposed. The use of the algorithm of the method of group arguments accounting for the construction of geological and statistical models is substantiated. The physical interpretation of the obtained models of the oil recovery process is given. The need for a differentiated approach in solving various problems of managing the development of various groups of objects in carbonate reservoirs is shown. Keywords: oil recovery factor; stepwise regression analysis; group accounting of arguments method.

Increasing the efficiency management of carbonate oil deposits development in the Kashiro-Podolsk deposits of the Birsk saddle

The article describes a new integrated approach to the analysis and design of carbonate reservoirs of the Kashira-Podolsk deposits development of an oil field confined to the Birskaya saddle. This approach made it possible to obtain results allowing making sound management decisions, as well as optimizing design decisions in the conditions of active involvement of the facility in the development and increasing the oil recovery factor from 0.247 to 0.288 units reserves by the AB1 category. In the future, it is planned to replicate the successful experiences in other fields with a similar geological structure in the north of Bashkortostan. Keywords: oil fields development; carbonates; Kashir-Podolsk deposits; reserves depletion; acid fracturing; horizontal well.