High Residual Oil Saturation Research Articles

Experimental and Numerical Simulation Study on CO2-Assisted Steamflooding in Ultraheavy Oil Reservoirs

Summary Certain ultraheavy oil reservoirs with depths approaching 1000 m feature wide well spacing. After cyclic steam stimulation (CSS), cold oil zones with high residual oil saturation exist between wells. This leads to a high oil saturation at the steam front during the subsequent steamflooding process, which in turn results in a high injection pressure. The simultaneous injection of CO2 and steam into the formation can optimize formation pressure and enhance steam utilization efficiency. A majority of laboratory-based experimental studies have reported favorable outcomes with CO2-assisted steamflooding. However, some field tests of CO2-assisted steamflooding have encountered severe steam channeling problems, resulting in oil recovery and an oil/steam ratio below the expected level. Consequently, this study uses an ultraheavy oil reservoir as a case study and integrates physical simulation with numerical simulation to investigate the impact of CO2-assisted steamflooding on enhanced oil recovery in ultraheavy oil reservoirs. The findings suggest that the beneficial effect of CO2 in reducing oil viscosity and injection pressure plays a significant role in models with smaller thickness, thereby improving oil production rate and recovery factor. However, as the thickness of the model increases, the adverse effect of CO2 exacerbating steam channeling becomes increasingly evident, leading to a decline in the oil recovery factor and a longer duration to reach the maximum recovery factor. Therefore, in field applications, it is essential to consider adjusting the CO2 injection method or using thermosetting plugging agents to achieve superior results.

CALCULATION OF AN ALTERNATIVE DEVELOPMENT SYSTEM FOR THE MAIN DEPOSIT OF THE DANILOVSKOYE OIL AND GAS CONDENSATE FIELD

The article provides a calculation of an alternative development system for deposit 3 (Main deposit ) of the Danilovskoye oil and gas condensate field. At the time of the analysis, this deposit is in the pilot development stage, with six development variants proposed in the trial operation project, which assume a principled arrangement of wells along an areal homogeneous grid. At the same time, due to the need to maintain the energy of the formation (that is, certain values of thermodynamic conditions), three provide for a transition to pressure maintenance, with the resulting four-point scheme of effect on the deposit (intensity 1:2; one well for injection, two for production). In the alternative model under consideration, the development method also involves a subsequent transition to pressure maintenance, but with a more active, five-point waterflooding system (intensity 1:1, equal ratio of production and injection wells), if necessary, as will be shown in the work, easily convertible to a nine-point one. The latter is an objective advantage, since the formation has low permeability and high vertical and lateral heterogeneity, and during waterflooding, zones not affected by the impact may appear, and, consequently, zones with high residual oil saturation. When calculating the characteristics of the proposed alternative method, modeling using the Peaceman method is used. Peaceman’s method is based on determining the well-reservoir connectivity of each individually opened cell, used to calculate flow rates (taking into account different values of average water cut for wells). The method is classical and, although it includes a large number of limiting assumptions, it is applicable everywhere and can provide sufficient justification for the effectiveness of the chosen development variant. General recommendations for the development of the entire field are also given (taking into account the low viscosity and lightness of oil and the properties of reservoir rocks). Such as the use of acid fracturing technology, the use of surfactants, hydrochloric acid treatments (HAT) and a complexing phosphorus-containing reagent — AFC.

Numerical analysis of water-alternating-CO2 flooding for CO2-EOR and storage projects in residual oil zones

Residual oil zones (ROZs) have high residual oil saturation, which can be produced using CO2 miscible flooding. At the same time, these zones are good candidates for CO2 sequestration. To evaluate the coupled CO2-EOR and storage performance in ROZs for Water-Alternating-CO2 (WAG) flooding, a multi-compositional CO2 miscible model with molecular diffusion was developed. The effects of formation parameters (porosity, permeability, temperature), operation parameters (bottom hole pressure, WAG ratio, pore volume of injected water), and diffusion coefficient on the coupled CO2-EOR and storage were investigated. Five points from the CO2 sequestration curve and the oil recovery factor curve were selected to help better analyze coupled CO2-EOR and storage. The results demonstrate that enhanced performance is observed when formation permeability is higher and a larger volume of water is injected. On the other hand, the performance diminishes with increasing porosity, molecular diffusion of gas, and the WAG ratio. When the temperature is around 100 °C, coupled CO2-EOR and storage performance is the worst. To achieve optimal miscible flooding, it is recommended to maintain the bottom hole pressure (BHP) of the injection well above 1.2 minimum miscibility pressure (MMP), while ensuring that the BHP of the production well remains sufficiently high. Furthermore, the tapered WAG flooding strategy proves to be profitable for enhanced oil recovery, as compared to a WAG ratio of 0.5:1, although it may not be as effective for CO2 sequestration.

Screening of Chemicals to Enhance Oil Recovery in a Mature Sandstone Oilfield in Kazakhstan: Overcoming Challenges of High Residual Oil

Chemical flooding, such as alkaline-surfactant (AS) or nanoparticles-surfactant (NS) flooding, is an enhanced oil recovery (EOR) technique that has been increasingly utilized to enhance the oil production rate and recovery factor while reducing chemical adsorption. The AS/NS flooding process involves the injection of a mixture of surfactant and alkali/nanoparticles solutions into an oil reservoir to reduce the interfacial tension between the oil and water phases by surfactant and lower surfactant adsorption by alkali or nanoparticles (NPs) to improve the residual oil recovery. In this study, the AS/NS flooding is evaluated for a Kazakhstani oilfield by systematically screening the chemical constituents involved. Field A in Kazakhstan, one of the oldest fields in the country, has been waterflooded for decades and has not produced even 50% of the original oil in place (OOIP). Currently, the water cut of the field is more than 90%, with a high residual oil saturation. Therefore, besides polymer flooding to control mobility, chemical EOR is proposed as a tertiary recovery method to mobilize residual oil. This study aimed to screen chemicals, including surfactant, alkali, and NPs, to design an effective AS/NS flooding program for the target field. The study focused on conducting laboratory experiments to identify the most effective surfactant and further optimize its performance by screening suitable alkaline and NPs based on their compatibility, stability, and adsorption behavior under reservoir conditions. The performance of the screened chemicals in the porous media was analyzed by a set of coreflood experiments. The findings of the study indicated that alkali agents, particularly sodium carbonate, positively affected surfactant performance by reducing its adsorption by 9–21%. The most effective surfactant combination was found, which gave Winsor type III microemulsion and the lowest interfacial tension (IFT) of 0.2 mN/m. The coreflood tests were conducted with the screened surfactant, alkali, and NPs. Both AS and NS tests demonstrated high residual oil recovery and microemulsion production. However, NS flooding performed better as the incremental oil recovery by NS flooding was 5% higher than standalone surfactant flooding and 9% higher than AS flooding. The results of this screening study helped in designing an efficient chemical formulation to improve the remaining oil recovery from Field A. The findings of this study can be used to design EOR projects for oil fields similar to Field A.

NUMERICAL INVESTIGATION ON THE IMPACT OF INITIAL WATER SATURATION DISTRIBUTION ON HOT WATER FLOODING PERFORMANCE UNDER NON-ISOTHERMAL CONDITIONS

The heterogeneity in the spatial distribution of initial water saturation influences the performance of hot water flooding. The prospect of a reduction in oil recovery arises from the development of viscous instability. In the present study, a numerical simulation model has been developed by coupling heat transport, and multiphase flow in porous media integrated with the non-isothermal flow, and the numerical model has been verified with the existing analytical solution by Buckley and Leverett. The formation of a wavy temperature profile at the condensation front was found with a decreased depth of temperature penetration. The average rise of temperature is drastically affected by the spatial distribution of initial water saturation. The formation of viscous fingering was highly dominating in the reservoir, with initial water saturation randomly distributed and causing the front to move in an irregular pattern from the initial stage of the flooding. The heterogeneous reservoir with initial water distribution showed the earlier formation of viscous fingering than the homogeneous reservoir. The heterogeneity in the spatial distribution of initial water saturation had caused viscous instability, lower viscosity reduction, lower displacement sweeps efficiency, and higher residual oil saturation. The present study is limited to spatial distribution in initial water saturation to a certain degree of heterogeneity. The heterogeneity in the spatial distribution of initial water saturation highly impacted the production performance of hot water flooding. The present study provides an idea for the implementation and future development of hot water flooding in a randomly initial water saturation distributed environment.

Increased oil recovery through the use of combined technology

There is a growing number of fields in the world that are at the last stage of development. These fields are characterized by high residual oil saturation and water saturation. In addition, newly discovered fields are characterized by the content of high-viscosity oil. The development of such reservoirs is associated with great difficulties. This paper considers a combined technology that allows to intensify oil production from oil reservoirs. The studies were carried out on a homogeneous reservoir model in the following sequence. First, we carry out the displacement of oil by injecting electrochemically modified water (catholyte). Then we pump in a gas-liquid emulsion slug, which we push through with water or catholyte. The combined action of the emulsion and catholyte leads to an increase in the pressure drop and a change in the filtration rate. As a result, this leads to an increase in the oil recovery factor.

Effects of miscible degree and pore scale on seepage characteristics of unconventional reservoirs fluids due to supercritical CO2 injection

Supercritical CO2 (ScCO2) injection is a potential way to enhance oil recovery (EOR). The displacement effect varies significantly with the difference of miscible degree and pore scale. However, studies in this field are rarely reported. In this paper, relative permeability curves of three miscible types are firstly measured. Interestingly, the ultimate oil recovery of near-miscible flooding is found to be comparative with that of miscible flooding due to the obvious decrease of gas relative permeability under higher residual oil saturation. On this basis, four main zones in the vicinity of oil-ScCO2 contact are divided in view of the multiple contact miscibility mechanism. A new threshold pressure gradient (TPG) considering both pressure sensitivity and oil properties, is proposed as the indicator of the seepage capacity for the reservoir fluids. The seepage resistance of different cores is greatly reduced due to the ScCO2 injection, especially for the permeabilities less than 5 × 10−3 μm2. The modified TPGs decreased exponentially with the increase of mobility indicating that the seepage capacity of reservoir fluids can be enhanced significantly by strong and sufficient interactions of ScCO2 and oil. Thus, CO2 soaking-alternating-gas (CO2-SAG) flooding is proposed and evaluated to verify the importance of contact time and mass transfer.

Numerical Simulation Study of Tracking the Displacement Fronts and Enhancing Oil Recovery Based on Ferrofluid Flooding

Water flooding is crucial means to improve oil recovery after primary production. However, the utilization ratio of injected water is often seriously affected by heterogeneities in the reservoir. Identification of the location of the displacement fronts and the associated reservoir heterogeneity is important for the management and improvement of water flooding. In recent years, ferrofluids have generated much interest from the oil industry owning to its unique properties. First, saturation of ferrofluids alters the magnetic permeability of the porous medium, which means that the presence of ferrofluids should produce magnetic anomalies in an externally imposed magnetic field or the local geomagnetic field. Second, with a strong external magnetic field, ferrofluids can be guided into regions that were bypassed and with high residual oil saturation. In view of these properties, a potential dual-application of ferrofluid as both a tracer to locate the displacement front and a displacing fluid to improve recovery in a heterogeneous reservoir is examined in this paper. Throughout the injection process, the magnetic field generated by electromagnets and altered by the distribution of ferrofluids was calculated dynamically by applying a finite element method, and a finite volume method was used to solve the multiphase flow. Numerical simulation results indicate that the displacement fronts in reservoirs can indeed be detected, through which the major features of reservoir heterogeneity can be inferred. After the locations of the displacement fronts and reservoir heterogeneities are identified, strong magnetic fields were applied to direct ferrofluids into poorly swept regions and the efficiency of the flooding was significantly improved.

Pore Network Modeling of Oil–Water Flow in Jimsar Shale Oil Reservoir

The oil–water two-phase flow mechanism is the critical issue for producing shale oil reservoirs after huge-volume hydraulic fracturing treatment. Due to the extremely low permeability of the shale matrix, the two-phase experimental measurement is impossible for shale samples. In this work, a pore network model is proposed to simulate steady-state oil–water flow with mixed wettability under consideration. The model is first applied in Berea sandstone, and the calculated relative permeabilities are validated with experimental studies for different wettability scenarios. Then, the three-dimensional FIB-SEM imaging of the Jimsar shale sample is used to extract a representative shale pore network with 13,419 pores and 31,393 throats. The mean values of pores and throats are 29.75 and 19.13 nm, and the calculated absolute permeability is 0.005 mD. With our proposed model, the calculated relative permeability curves show a high residual oil saturation for all the wettability conditions. Specifically, the oil-wet and mixed-wet conditions yield lower residual oil compared with the water-wet condition. For 50–50 mixed-wet conditions, the water phase relative permeability is much higher for smaller pores being oil-wet than the larger pores being oil-wet.

Oil production performance and reservoir damage distribution of miscible CO2 soaking-alternating-gas (CO2-SAG) flooding in low permeability heterogeneous sandstone reservoirs

Miscible CO 2 -SAG flooding is an enhanced form of CO 2 flooding, which mitigates the inadequate CO 2 -crude oil interaction by adding a CO 2 soaking period just after CO 2 breakthrough (BT). The addition of the soaking process results in improvements in the recovery of residual oil during the secondary CO 2 flooding process, which may vary across the reservoir, and lead to differential changes in the distribution of permeability decline and wettability variation due to asphaltene precipitation. In this work, CO 2 -SAG and simple miscible CO 2 flooding experiments were carried out at reservoir conditions (90 °C, 23 MPa) on low permeability long composite cores with progressively decreasing permeability in the direction of injection. The results show that the overall oil recovery factor (RF) was 72.8% after CO 2 -SAG flooding, 11% higher than simple miscible CO 2 flooding (61.8%). The oil RFs of individual core plugs decreased progressively along the core (i.e., with decreases in initial permeabilities). The inadequate interaction occurs more for those cores with low permeability and high residual oil saturation close to the outlet. Consequently, recovery is improved more in lower permeability cores, particularly in medium sized pores of these cores. By contrast, the permeability decline of core plugs after CO 2 -SAG flooding was 8–20%, 1.0–4.5% higher than that after simple miscible CO 2 flooding. The permeability decline of the cores close to the injection end showed a slight increase, and continued to decrease along the injection direction after CO 2 flooding. However, the overall decline in core permeability at the injection end was greater than that at the outlet. The soaking process led to a more homogeneous distribution of permeability decline and a greater increase in permeability decline. The distribution of wettability variation was consistent with the distribution of residual oil saturation after CO 2 flooding. The wettability variation was larger and the cores in middle had the biggest values after SAG flooding. • Oil recovery is improved more for lower permeability cores at the outlet, particularly in medium sized pores after SAG flooding. • The soaking process leads to a greater increase in permeability decline due to asphaltene precipitation. • The distribution of wettability variation is consistent with the distribution of residual oil saturation after CO 2 flooding.

Study of surface complexation modeling on a novel hybrid enhanced oil recovery (EOR) method; smart-water assisted foam-flooding

This contribution focuses on surface complexes in the calcite-brine-surfactant system. This is relevant for the recovery of oil when using a new hybrid enhanced oil recovery (EOR) method, which combines smart-water (i.e., ionically modified brine) and foam-flooding (SWAF) of light oil with dissolved carbon dioxide (CO2) at high pressure in carbonate (i.e., calcite) reservoirs. Using this new hybrid EOR-method (i.e., the SWAF-process) is not only economically attractive (i.e., it reduces opex costs) but also enhances the effectiveness of the production process, and thus reduces the environmental impact. Ionically modified brine (i.e., low-salinity) has a dual improvement effect. It not only leads to more stable foam lamellae, but also helps to change the carbonate rock wettability, leading for some conditions to more favorable relative permeability behavior. The mechanism for the modified permeability behavior in the presence of ionically modified brine is only partly understood. Therefore, we study this process initially in a zero dimensional (thermodynamics) setting, which can be used for the one dimensional (1D) displacement process with an oleic phase that contains carbon dioxide (CO2) and an aqueous phase that contains both carbon dioxide (CO2) and all the ionic substances. Using DLVO theory and surface complexation modeling to better understand the mechanism(s) of ionically modified brine as wettability modifier and foam stabilizer. We perform simulations using both (NaCl) and (MgCl2) to show the effect of a divalent ion at the high-salinity (8500 mmol/kg-w) and low-salinity (0.4 mmol/kg-w) for both ambient-conditions at (25°C) and at the reservoir-conditions (80°C). We confine our analysis to a description that uses the Dzombak-Morel model of surface complexes, which is based on the Debye-Hückel theory (i.e., valid up to ionic strength of 0.3 (mol/kilogram of water)). We also investigate the effect of carbon dioxide (CO2) on the stability of low-salinity foam-laminae. We model the foam-laminae, which contain as surface complex a (cationic) surfactant in an aqueous phase. We use the PHREEQC-software to calculate the surface charge and the surface potential. The presence of a carbon dioxide (CO2) phase leads to dissolution of four valent C(IV) compounds in the aqueous film. PHREEQC also calculates the equilibrium concentrations and surface potential and allows the study of the effect of salinity and the carbon dioxide (CO2) gas pressure. For the soap-film (foam-film) in a carbon dioxide (CO2) atmosphere we do use Pitzer activity coefficients (i.e., valid up to 6 (mol/kilogram of water)). As our aim is to show the methodology and the versatility of this approach, we leave more realistic choices of these parameters for future work.sFor the conditions considered we can qualitatively state that, in the presence of (NaCl i.e., at pH > 10) and (MgCl2 i.e., pH > 10.3), the low-salinity case shows a more stable water-film behavior at (25°C) and at (80°C) than the high-salinity case for both (25°C) and (80°C). Moreover, high carbon dioxide (CO2) pressures have a destabilizing effect on the film, as they reduce the surface potential. A reduced surface potential leads to a decreasing electrostatic double layer repulsion and thus destabilizes the foam-film, whereas low-salinity leads to less screening of the surface potential and thus improves the stability of the foam-film. The low-salinity flow is characterized by a high residual oil saturation and low end-point permeability for the two phase oil-water flow. This leads to a more favorable mobility ratio and thus a more favorable displacement process. For the calcite surface an enhanced stability helps to stabilize the water film on the calcite surface if the oil-water surface charge has the same sign as the surface charge on the calcite surface. Our calculations show the pH range where the sign of these charges is the same or opposite at low-salinity and high-salinity conditions. Admittedly these calculations only show trends, but can be used to delineate optimal conditions for the application of “Smart Water Assisted Foam (SWAF) Flooding”. It is expected that the SWAF-process under the optimum conditions will make the proposed new hybrid Enhanced Oil Recovery (EOR) process environmentally and economically attractive.

Mechanistic Modeling of Nanoparticles-Assisted Surfactant Flood

High interfacial tension (IFT) between oil and water brings about high capillarity leading to high residual oil saturation. Surfactants are employed to reduce IFT or modify wettability and mobilize the trapped oil. This paper aims to investigate the interaction of sodium dodecyl sulfate as a surfactant and two types of silica nanoparticles in different particle sizes for the purpose of enhancing oil recovery. Accordingly, the effect of employed nanoparticles on the critical micelle concentration (CMC) of the surfactant was investigated by the use of electrical conductivity measurements. Phase behavior studies were also carried out to examine the solubilizing ability of the surfactant and nanoparticles assembly. Based on the analysis of solubilization curves, an ultra-low IFT chemical formulation for the target reservoir crude oil was identified and the stability of the optimum solutions was examined through visual observation, optical absorption, and zeta potential measurements. The oil recovery experiments were performed in a quarter five-spot transparent pore network model saturated with crude oil to observe the displacement behavior of the injectant and its influence on oil recovery. Phase behavior tests indicated that the silica nanoparticles smaller in size are more effective in terms of IFT reduction since they can achieve ultra-low IFT level, and the conductivity measurements showed they relatively reduce the CMC of the surfactant. The results of stability tests demonstrated the optimum solutions are stable for more than 1 week. The micromodel experiments displayed that oil recovery increased by 4% during nanoparticles-assisted surfactant flood in comparison with surfactant flood.

Micro-pore structure and oil displacement mechanism analysis for deep zone and low permeability reservoir in Mobei oilfield

The Mobei reservoir is a low-permeability-sandstone reservoir, due to differences in pore geometry, it can be divided into two independent reservoirs: A1 reservoir and A2 reservoir. For better understanding the water flooding development effects of Mobei reservoir, the mercury intrusion porosimetry, water flooding CT scanning and micro-CT scanning experiments are used in this study. The result shows that the reservoir has the strong heterogeneity which is weaken gradually from A1 reservoir to A2 reservoir. Reservoir pore radius is mainly distributed in the 100–200 microns, the throat radius is mainly distributed in the 1–3 micron. The water flooding core experiment in each reservoir shows a short water-free oil production period and rapid water cut after breakthrough. The A2 reservoir core flooding process is similar to piston displacement, the A1 reservoir core flooding process refers to the phenomenon (The fingering phenomenon in the process of core flooding in the A1 reservoir is obvious). The calculated water drive efficiency of the A2 reservoir is 61.2%, which is higher than 49.1% of the A1 reservoir. According to the CT scanning process, the Mobei oilfield has low micro displacement efficiency and the A1 reservoir has a smaller spread (sweep area) and higher residual oil saturation.

Self-Colmatation in terrigenic oil reservoirs of Eastern Siberia

The main objective of this work is to study formation damage phenomenon associated with in-situ migration of fines in rock samples from terrigenic reservoirs of Eastern Siberia experimentally. Results of oil flooding for the wide range of flow rates and permeabilities show that oil does not lead to fine mobilization and its consequent retention with permeability reduction. The permeability decrease is observed only when water is flowing in the porous space. Water itself is shown to be a strong driver of self-colmatation, which is likely because of its intensive physicochemical reaction with pore surface. Performing multiple core flooding tests and analyzing the data, we define the range of rock properties and flow conditions corresponding to development of the situ formation damage (self-colmatation). We classify self-colmatation over 5 types characterized with different behaviors of permeability decrease. We comprehensively study the dependencies of permeability reduction specifics on rock properties and flooding conditions. The dependencies account for multiple parameters correlated with permeability reduction: absolute permeability, residual oil saturation, three characteristic pore diameters, four characteristic grain diameters and four major minerals within the rock structure. We discovered that the increase of formation damages are associated with high absolute permeability and low residual oil saturations. It was shown that characteristic size of migrating fines is 0.01–0.005 mm and the diameter of pores where these fines can be strained is 12 μm. We derive a single numerical criterion to estimate the influence of 13 parameters on colmatation process. The absolute permeability and the fraction of pore throats with diameters higher than 30 μm are shown to be the strongest influencers on colmatation.

A novel method to model and characterize in-situ bio-surfactant production in microbial enhanced oil recovery

Capillary force is an important factor that limits the efficiency of water flooding by trapping the oil in porous media. High capillarity is caused by high interfacial tension (IFT) between oil and water that leads to a high residual oil saturation. Surfactants are widely used to reduce IFT and significantly mobilize the entrapped oil. However, the surfactants that are injected into a reservoir to lower the IFT several orders of magnitude may not be cost effective. Microbial enhanced oil recovery (MEOR) process may potentially address a cost effective alternative to surfactant flooding. In the MEOR process, nutrients and natural bacteria are injected into a reservoir and both indigenous and injected microorganisms are able to react and then generate biosurfactants based on in-situ reactions.Modeling of microbial enhanced oil recovery requires coupling kinetics transport with local equilibrium transport in the presence of the surfactant phase behavior model (i.e. Hand’s rule). In general, reservoir simulators do not model relative chemical reactions that consider the effect of essential environmental parameters such as temperature, salinity, and pH.The main objective of this work is to present first order Monod kinetic equations as a function of temperature, salinity, and pH, which control the biodegradation reactions and microbial growth rate. Furthermore, the impact of biosurfactant adsorption, maximum growth rate, and nutrient concentration are systematically investigated. Also, the effects of environmental factors are implemented in a four-phase chemical flooding reservoir simulator (UTCHEM). Subsequently, the simulator is used to history match a coreflood experimental data to model the contribution of cited parameters on oil recovery.Results show that in-situ biosurfactant generation rates can be thoroughly modeled based on environmental factors IFT can be reduced in a similar manner as surfactants. Simulation results show 10–15% incremental oil recovery using in-situ biosurfactant compared to waterflooding. Moreover, based on the simulation results, nutrient concentration, salinity and temperature are found to be the most significant parameters influencing oil recovery, whereas pH has insignificant effect.The understanding of in-situ biosurfactant generation in a MEOR process, implementing a new environmental model into the simulator, and investigating of various parameters influencing the efficiency of the MEOR process are the key findings of this work.

Experimental study and pilot test of urea- and urea-and-foam-assisted steam flooding in heavy oil reservoirs

Abstract During steam flooding in heavy oil reservoirs, steam override and channeling often cause high residual oil saturation. To quantify and alleviate these phenomena, a 3-D experimental model for urea- and urea-and-foam-assisted steam flooding was designed and developed. Three comparative experiments were conducted to facilitate the identification of different effects of flooding, including conventional steam flooding (CSF). The system was switched to urea-assisted steam flooding (UASF) and to urea-and-foam-assisted steam flooding (UFASF). A comparison of specific parameters, including instantaneous oil-steam ratio (OSR), instantaneous watercut, difference in pressure between the inlet and outlet, and oil recovery, showed UFASF to be more effective than CSF or UASF with respect to flooding. As indicated by the change in temperature, the UFASF was able to control the steam override and channeling and fully extend the steam chamber effectively. This not only increased the sweep efficiency but also improved the conformance factor of the steam flooding. The experimental results of the UFASF were successfully used to guide a pilot test of the Jin-1 Block at Liaohe Oilfield, China. Results indicated that the UFASF may be a feasible means of improving the oil recovery of the steam flooding in heavy oil reservoirs.

Petrophysical analysis of early cretaceous Saar carbonates from Sharyoof oilfield in the Masila Basin, eastern Yemen, and their impact on reservoir properties and quality

The Saar Formation, the late Early Cretaceous in age, is a secondary reservoir rock containing low amounts of proven oil in the Sharyoof oilfield, Masila Basin. The lithofacies of the Saar Formation at Sharyoof oilfield is mainly composed of dolomite and dolomitic limestone with limestone intercalations, reflecting a marine setting. Petrophysical properties and some petrographic characteristics were used to evaluate the reservoir characteristics and quality of the Saar carbonates. Generally, the Saar carbonates have poor to good reservoir quality. The porosity ranges from 6 to 21 %, and permeability varies from 0.01 to 500 md. The pore types are secondary pores in form vugs and fractures as identified under microscope. The good reservoir quality of the Saar carbonates is characterized by a relatively high secondary porosity and permeability. Therefore, the dolomite and dolomitic limestone intervals of the Saar Formation have good reservoir quality and reveal promising reservoir characteristics, which should be taken into consideration during future development of the Sharyoof oilfield. The Saar carbonates have hydrocarbon saturation exceeding 70 %, with low oil movability, indicating high residual oil saturation and the production is mainly water with limited oil.

IMPROVING EFFICIENCY OF HYDRAULIC FRACTURING UNDER HIGH WATERCUT RESERVOIR CONDITIONS OF БВ-8 FORMATION, POVKHOVSKOE FIELD

Its first large-scale hydraulic fracturing operation was performed at Povkhovskoe field with up to 200 tons of proppant agent injected. The technology has been developed to improve the efficiency of fracking, tapping hard-to-recover and bypassed oil reserves in water-flooded zones of the reservoir. The introduction of large-scale fracking lead to the significant increase in the recovery factor on the pilot area due to extra contact with the reservoir, i.e. higher sweep efficiency. Based on the analysis of the oil reserves recovery and their vertical distribution it has been noted that the application of a large-scale frac job is guided by the presence of zones with uneven residual oil distribution, layers with high residual oil saturation, abundance of blind or dead-end zones, lenses and hemi-lenses at a certain distance from the wellbore which have not been developed yet. As possible candidates wells with over 95% watercut (9 wells) have been studied and analyzed from the idling well stock: piezometric, suspended, not producing in the previous years due to their unprofitability. This approach addresses one of the top challenges of an oil company – how to lessen the number of idling wells. Large volumes of the proppant agent injected create rather long hydraulic fractures up to 120-200 m which extend far into the formation thus draining the interwell reservoir space which is poorly developed. The reach or the step-out of the second boreholes at Povkhovskoe field is in the range of 150-350 m. Field trials of large-scale fracking at БВ8 development target of Povkhovskoe field resulted in high average efficiency with increased oil rate and specific technological efficiency of 10.8 tons per day. The economic calculations showed that hydrofrac with 200 tons of proppant injected is cost-effective at the minimum incremental oil achieved of 9.8 tons per day. Large-scale fracking operations may be considered as an alternative to expensive and high-cost sidetracks.

Evaluation of Hydrocarbon Saturation Using Carbon Oxygen (CO) Ratio and Sigma Tool


 The main aim of this study is to evaluate the remaining oil in previously produced zones, locate the water productive zone and look for any bypassed oil behind casing in not previously perforated intervals. Initial water saturation was calculated from digitized open hole logs using a cut-off value of 10% for irreducible water saturation. The integrated analysis of the thermal capture cross section, Sigma and Carbon/oxygen ratio was conducted and summarized under well shut-in and flowing conditions. The logging pass zone run through sandstone Zubair formation at north Rumaila oil field. The zones where both the Sigma and the C/O analysis show high remaining oil saturation similar to the open hole oil saturation, could be good oil zones that do not appear to be water flooded. The zones where the Sigma analysis shows high residual oil saturation, which is close to open hole oil saturation and the C/O analysis, show medium residual oil saturation; this could indicate that these zones were fresh water flooded to a certain extent and they still keep some residual oil. If the C/O analysis shows low residual oil saturation, it indicates that these zones were probably fresh water flooded thoroughly. If both Sigma analysis and the C/O analysis show medium residual oil saturation, most probably these zones were saline water flooded to a certain extent and they still keep some residual oil.

Structure of residual oil as a function of wettability using pore-network modelling

In the water flooding of mixed-wet porous media, oil may drain down to relatively low residual oil saturations (Sor). Various studies have indicated that such low saturations can only be reached when oil layers in pore corners are included in the pore-scale modelling. These processes within a macroscopic porous medium can be modelled at the pore-scale by incorporating the fundamental physics of capillary dominated displacement within idealised pore network models. Recently, the authors have developed thermodynamic criteria for oil layer existence in pores with non-uniform wettability which takes as input geometrically and topologically representative networks, to calculate realistic Sor values for mixed-wet and oil-wet sandstones [16, 21]. This previous work is developed in this paper to include (i) the visualisation of the 3D structure of this residual oil, and (ii) a statistical analysis of this “residual/remaining” oil. Both the visualisation and the statistical analysis are done under a wide range of wettability conditions, which is reported for the first time in this paper.The structure of residual oil for strongly water wet systems is well known (where residual=remaining oil) and our model agrees with this but this structure changes radically for mixed wet systems (where residual≠remaining) and this has not yet been visualised experimentally. We find that for more water-wet systems high final residual oil saturations are reached at relatively small amounts of water injected and this oil is present in the pores as bulk oil. On the other hand, for more oil-wet systems we find a slow decrease of the amount of remaining oil with increasing amounts of injected water. During the process, the remaining connectivity of the oil phase is increasingly provided by oil layers only, hence the slow drainage. The final residual oil saturation, only reached in the theoretical limit of an infinite amount of injected water, is almost entirely contained in large number of (relatively low volume) oil layers, which are present in pores of most radius sizes.