High Oil Saturation Research Articles

Evaluation of the applicability of in-situ combustion in a heavy oil carbonate field with high initial oil saturation

The present work describes a set of four in-situ combustion (ISC) tests for assessing the applicability of the technology for the heavy oil (19° API) carbonate field and determining the optimal initial oil saturation. The potential candidate for the ISC is a carbonate reservoir with a depth ranging from 1133 m to 1196 m, a porosity of 9–13%, and an average permeability of 280 mD. The performed screening study examined the quality and the quantity of available fuel, air requirements, and the ability of the combustion front to propagate through the porous media. Based on screening results, the ISC technology was chosen for a detailed laboratory study. A high-pressure ramped temperature oxidation (HPRTO) test and three medium-pressure combustion tube (MPCT) tests were performed to estimate the effect of initial oil saturation and to assess the suitability of the target field for the ISC method. This study was conducted at reservoir conditions to take into account the phase behavior at elevated pressures and temperatures. The effect of different oil saturation on combustion performance was investigated. Combustion parameters such as fuel and air requirements, recovery efficiency, front velocity, and composition of produced gases were obtained and analyzed. Based on the experimental results, it was proposed to reduce the oil saturation with hot water treatment and further switch to ISC. The study determined the initial oil saturation level of 0.38–0.70 within which the ISC can be implemented on target heavy-oil carbonate field. This research demonstrated potential technology application problems and defined a set of favorable conditions for ISC applicability. Additional features (such as oil plugging and calcite decomposition), which may occur in the process of on-field implementation, were observed at applied reservoir conditions. The equipment operation parameters for the target field were calculated and specified based on the obtained ISC parameters.

Geological Characteristics and Exploration Prospect of Black Shale in the Dongyuemiao Member of Lower Jurassic, the Eastern Sichuan Basin, China

China has yielded huge commercial production from the marine organic-rich shale but shows a slow exploration process in the lacustrine organic-rich shale. Multiple lacustrine shales in the Lower Jurassic of the eastern Sichuan Basin, rich in organic matters, are potential targets for shale hydrocarbon exploration and development. An investigation of the Dongyuemiao member, Lower Jurassic, was firstly conducted utilizing the macroscopic and microscopic analyses on outcrops and drilling cores to reveal the characteristics of sedimentary subfacies, mineral compositions, organic matter content and types, thermal maturity level, and reservoir quality. The dark shales in the Dongyuemiao member can be grouped into four general categories: shore, shallow, semi-deep, and deep lacustrine shales. The semi-deep and deep lacustrine shales generally have higher values in thickness (>20 m), average total organic carbon (TOC) content (>1.5 wt.%), and average porosity (>2%) relative to shore and shallow lacustrine shales. All four categories of shales primarily consist of type II kerogen and have thermal maturity levels exceeding the vitrinite reflectance value of 0.9–1.0% (or the Tmax of ∼440°C). Thermally powered pore generation generally promoted the pore system as indicated by the positive correlation between porosity and Tmax. Notably, the semi-deep lacustrine shale in the vicinity of the Qiyueshan Fault Zone shows abnormally high porosity and low oil saturation index (OSI) at Tmax>∼465°C potentially due to the promoted hydrocarbon expulsion through multiscale fractures. Except for the vicinity of the Qiyueshan Fault Zone, the semi-deep and deep lacustrine shales generally show the better exploration prospect relative to the shore and shallow lacustrine shales. Additionally, the high content of clay minerals (>40 wt%) reduced the brittleness of the semi-deep and deep lacustrine shales which may challenge the artificial hydraulic fracturing.

Coupled influence of wettability alteration and geometry on two-phase flow in porous media

The objective of this paper is to investigate the interplay between wettability alteration and domain geometry in influencing the pore-scale displacement and trapping mechanisms of two-phase flow in porous media. A new wettability alteration algorithm is introduced to quantify and track the spatial and temporal variability of the wettability state of every pore. Simulations in an initially oil-wet domain are conducted using the lattice Boltzmann model while utilizing the wettability alteration algorithm to capture the new wettability states. The simulations are then resumed under the new generated wettability states to investigate the coupled impacts of wettability alteration and domain topology on the resulting pore-scale displacement behavior. We observe varying degrees of improvements in the oil phase fractional flow as the wettability state is varied towards water-wet conditions influenced by the domain geometry, capillary number, and phase saturation. Significant heterogeneity, increased surface roughness, and the prevalence of narrower pore spaces in the rock sample in comparison to the spherepack increase the percentage of trapped oil ganglia. As a result, wettability alteration results in varying degrees of oil remobilization events, followed by coalescence with the main flow path, especially at higher capillary numbers. Moreover, oil phase fractional flow at higher oil saturation becomes influenced primarily by the increased phase connectivity, and improvements due to wettability alteration become less significant. Similar displacement mechanisms are observed in both domains, controlled primarily by the wettability distribution and the local pore geometry. However, the resulting flow pathways, which dictate the overall flow behavior, are controlled by the frequency of various displacement mechanisms and are a function of the domain geometry. The observations in this study highlight the complex interactions between wettability heterogeneity and pore geometry in influencing pore-scale two-phase flow. The wettability alteration algorithm introduced can be used to optimize pore-scale displacement processes by providing a framework to track the locations and the relative degree of wettability alteration, enable automatic wettability alteration, and detect trapped ganglia without the need for post-processing.

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.

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.

The effects of in-situ emulsion formation and superficial velocity on foam performance in high-permeability porous media

Foam has been considered as a mobility control agent for Enhanced Oil Recovery (EOR) applications in heterogeneous and fractured reservoirs. Foam enhances sweep efficiency by enabling the injected gas to flow from high-permeability to low-permeability regions. The foam injection velocity is an essential factor affecting foam mobility control and flow behavior. Furthermore, the presence of remaining oil adversely impacts foam generation leading to a failure in governing mobility control. In this study, foam performance in establishing mobility control effect and favorable apparent viscosity was experimentally investigated under a range of total superficial velocities in the presence and absence of crude oil during foam propagation in high permeability sand packs representing a propped fracture network. In the absence of oil, a pronounced effect of total superficial velocity on the mobility control performance was observed at the transition foam quality regime. Co-injection of oil and foam led to noticeable foam destabilization, as expected. However, a further increase in oil fractional flow resulted in larger overall flow resistance. We found that the formation of in-situ surfactant/oil emulsion contributed to the high apparent viscosity exhibited at the steady-state condition. These findings suggest that the steady-state flow resistance established during foam flooding at high oil saturations should be interpreted as the mobility control effect resulting from emulsion formation rather than the development of strong foam.

Genetic incorporation of oil-utilizing ability in Cupriavidus malaysiensis USMAA2-4 for sustainable polyhydroxyalkanoates production from palm olein and 1-pentanol

The sustainability in polyhydroxyalkanoates (PHA) production is drawing increasing attention as the effort to increase the economic feasibility for commercialization pursues. Oleic acid is widely preferred by bacteria but its employment for PHA production makes sustainability rather dubious. This study showed promising poly(3-hydroxybutyrate-co-3-hydroxyvalerate) [P(3HB-co-3HV)] content of 68 wt % by lipase genes-harbouring Cupriavidus malaysiensis USMAA2-4 transformant from palm olein and 1-pentanol. High oleic acid content and low oil saturation caused palm olein to outperform crude palm oil, crude palm kernel oil and soybean oil due to its preference for oleic acid shown by previous screening. The transformant showed 8-fold and 40-fold higher lipase activity compared to C. necator H16 and its wild-type respectively. The transformant was unaffected by Co2+ but the growth of C. necator H16 was inversely proportional to Co2+ concentration and the employment of 1-pentanol also ceased its growth and PHA accumulation. Although the inhibitory effect of Fe2+, Cu2+ and Zn2+ at high molarity on LipA decreased PHA content of C. malaysiensis USMAA2-4 transformant by 23–24 wt %, the lipase activity was restorable with high molarity of Ca2+, thus resulted in higher PHA content. The transformant enabled the employment of low-cost 1-pentanol as the precursor for cost-effective PHA production and its preference for palm olein contributed to higher sustainability.

Fluid Discrimination in Ultra-Deep Reservoirs Based on a Double Double-Porosity Theory

We develop a methodology, based on rock-physics templates, to effectively identify reservoir fluids in ultra-deep reservoirs, where the poroelasticity model is based on the double double-porosity theory. P-wave attenuation, the ratio of the first Lamé constant to mass density (λ/ρ) and Poisson ratio are used to build the templates at the ultrasonic and seismic frequency bands to quantitatively predict the total and crack (soft) porosities and oil saturation. Attenuation on these frequency bands is estimated with the spectral-ratio and frequency-shift methods. We apply the methodology to fault-controlled karst reservoirs in the Tarim Basin (China), which contain ultra-deep hydrocarbon resources with a diverse pore-crack system, low porosity/permeability and complex oil-water spatial distributions. The results are consistent with well-log data and actual oil recovery. Crack porosity can be used as an indicator to find regions with high oil saturation, since high values implies a good pore connectivity.

The technology of effective reservoir prediction in fault development zone

Reservoir prediction in the middle and late stages of development is not only to predict the sandstone, but also to define the specific location of Petroleum-bearing sandstone. The post-stack seismic data is superimposed on a multi-channel seismic data level, although the signal-to-noise ratio is improved to a certain extent, the average amplitude value is obtained in the superposition process, so that only the effective prediction of the sand body can be realized. However, the pre-stack seismic data can obtain the information of shear wave by the longitudinal wave. The characteristics of the shear wave that cannot propagate in the fluid can effectively predict the reservoir and fluid distribution. In order to further quantify the remaining oil potential in fault area, prestack seismic inversion technology and petrophysical analysis are used to determine the favorable oil-bearing area. On this basis, prestack geostatistical inversion is completed to further clarify sand body with high oil saturation. Combined with numerical simulation, it effectively predicts the residual oil distribution at the edge of fault and the precision of the remaining oil quantitative characterization results is high. The recognition rate of thick layer saturation is more than 90%, and the recognition rate of thin interlayer saturation is more than 70%, which can meet the demand of fine reservoir prediction.

Distribution Model of Fluid Components and Quantitative Calculation of Movable Oil in Inter-Salt Shale Using 2D NMR

Some inter-salt shale reservoirs have high oil saturations but the soluble salts in their complex lithology pose considerable challenges to their production. Low-field nuclear magnetic resonance (NMR) has been widely used in evaluating physical properties, fluid characteristics, and fluid saturation of conventional oil and gas reservoirs as well as common shale reservoirs. However, the fluid distribution analysis and fluid saturation calculations in inter-salt shale based on NMR results have not been investigated because of existing technical difficulties. Herein, to explore the fluid distribution patterns and movable oil saturation of the inter-salt shale, a specific experimental scheme was designed which is based on the joint adaptation of multi-state saturation, multi-temperature heating, and NMR measurements. This novel approach was applied to the inter-salt shale core samples from the Qianjiang Sag of the Jianghan Basin in China. The experiments were conducted using two sets of inter-salt shale samples, namely cylindrical and powder samples. Additionally, by comparing the one-dimensional (1D) and two-dimensional (2D) NMR results of these samples in oil-saturated and octamethylcyclotetrasiloxane-saturated states, the distributions of free movable oil and water were obtained. Meanwhile, the distributions of the free residual oil, adsorbed oil, and kerogen in the samples were obtained by comparing the 2D NMR T1-T2 maps of the original samples with the sample heated to five different temperatures of 80, 200, 350, 450, and 600 °C. This research puts forward a 2D NMR identification graph for fluid components in the inter-salt shale reservoirs. Our experimental scheme effectively solves the problems of fluid composition distribution and movable oil saturation calculation in the study area, which is of notable importance for subsequent exploration and production practices.

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.

Characteristics and controlling factors of tuff tight reservoir in Tiaohu formation of Malang sag, Santanghu basin, China

Santanghu basin in Northwest China is a petroliferous basin. In recent years, researchers have discovered tuff tight reservoirs in the Tiaohu formation of Malang sag. Thin section, scanning electron microscopy, electron probe, X-ray diffraction, and CT scanning analysis are applied to reveal the petrological characteristics, physical properties, and pore texture of tuff tight reservoirs. Major controlling factors of the formation of high-quality tuff tight reservoirs are also discussed. The results show that the tight reservoir is intermediate-acidic crystal-vitric tuff. The main component of tuff reservoir is felsic vitroclastic, followed by crystal fragment and a small amount of bioclast, and trace clay content. Mercury injection and CT scanning show that the tight oil reservoir is characteristic of medium-high porosity, ultra-low permeability, and high oil saturation, which is controlled by its pore texture. There are four types of micropores in tuff reservoir, among which the principal reservoir space is devitrified micropores and crystal fragment dissolution micropores. Micropores are distributed universally in the tight oil reservoir, and the throat is nano-scale throat. It is considered that the tuff in the study area is formed by the deposition of volcanic ash in stable water after long-distance drifting in the air. The formation of high-quality tuff tight oil reservoir derives from 3 key factors: (1) shallow-semi-deep lacustrine environment, which is less affected by terrigenous input; (2) intermediate-acidic volcanic ash which forms the tuff reservoir; (3) devitrification and dissolution during the diagenesis.

Study on long-term rheological characteristics of polymer gel and prediction of its creep fracture time

Conformance control by using the polymer gel is an important stimulation technique of heterogeneous oil reservoirs. After operation of the conformance control, the water channeling of heterogeneous oil reservoirs can be plugged, which can force the follow-up injected water to divert into the area with high oil saturation. Thus, under the action of water injection pressure, the polymer gel is deformed. Because this is a long-term process, the ability to resist the long-term deformation and resist damage of polymer gel is important for the long-term plugging effect. However, there are few reports on the effect of long-term rheological characteristics of the polymer gel on its plugging ability. Therefore, it is of great significance to study the rheological characteristics of the polymer gel under the long-term action of a stress, which can be used to accurately predict the effective period of plugging the water channeling. In this paper, taking the Hook body and the viscous pot as the basic elements, and considering the Maxwell model and the Kelvin model as the basic models, a combined viscoelastic mechanical model of the polymer gel is established, which can be used to simulate the creep deformation of polymer gel. At the rheological damage stage of the polymer gel, the strain is increased exponentially and the mechanical parameters is decayed exponentially with time. By introducing the damage variable, based on the stress - time equivalence principle of polymer materials, the time of creep fracture of the polymer gel can be accurately calculated. Since then, the polymer gel is started to break obviously and lost its ability for plugging. This study can provide an important guidance to optimizing the scheme of conformance control and predicting the validity period.

Microscope dynamic characterization of oil charging in tight sandstone using a physical simulation experiment

Physical processes of oil charging in tight sandstone were simulated and analyzed using oil displacement water in sandstone micro-visualization models. Microscope dynamic characterizations of oil charging were obtained, and factors controlling the oil charging process in tight sandstones were elucidated in combination with thin section analysis, scanning electron microscopy (SEM) and rate-controlled porosimetry (RCP). Results indicate that three types of residual water exist in tight sandstone reservoirs: water-in-oil droplets; corner residual water; and connect-pore residual water. The charging rate of oil varied in the direction of migration, and uniform oil-water interfaces were not recorded during oil charging. The dynamic process of oil charging was classified as: (i) fingerlike and (ii) netlike. During fingerlike oil charging processes, the frontal movement formed obvious dominant paths, and the residual water area was large. During netlike oil charging processes, oil migrated through multiple channels forming a network of paths, having high terminal oil saturation. Due to the narrow pore-throat, oil charging characteristics of tight sandstones are not sensitive to variations of pore-throat radii; charging characteristics depend on the effective storage space and connectivity of the pore-throat. Connectivity of the dissolution pore-throat was found to be good, and the effective storage space of dissolution combined pores was large. Our results, therefore, indicate that oil charging of tight sandstone is controlled by pore-throat structures formed by dissolution.

Characteristics and potential area optimization of Oil layer A reservoir in T Oilfield

Oil layer A of T oilfield has a low development degree. At present, there are 5 medium and highyield wells in the area, showing a good evaluation and development prospect. In order to understand the reserve potential of this area, the reservoir forming law and reservoir characteristics are further analyzed by analyzing the structure and reservoir development characteristics. The research shows that Oil layer A has two types of reservoirs: one is structural reservoir, which is distributed in the large structural trap near the Aogula-Halahai fault zone in the east of the oilfield. It is characterized by close oil source, short migration path and stable reservoir development. It is a "large and enriched" reservoir. The other type is lithologic reservoir, which is distributed at the sedimentary end of the western structure of the oilfield, and is characterized by distant oil source. After long-distance secondary migration, it is greatly influenced by the development degree and physical properties of the reservoir, but it is a "small but fat" reservoir with high oil saturation. On the basis of clarifying reservoir types, characteristics and evaluation ideas, this paper carries out reserve optimization classification, and selects three potential areas: block Y1 and block Y2 which are mainly controlled by structure and block Y3 which is controlled by lithology.

Temperature-responsive self-lubricating hydrogel from dynamic Diels-Alder crosslinking for reservoir in-depth profile control

Deep formation layer is of high temperature, heterogeneity and oil saturation. Therefore, the gel for its profile control should have large strength, good migration and temperature tolerance performance in formation. In this work, a temperature-responsive self-lubricating hydrogel PAFB, applied to in-depth profile control, was synthesized by combining FA-BGPP network—a dynamic covalent cross-linking network based on Diels-Alder reaction with PAHH network—a temperature-resistant and high-strength polymer network. Due to retro Diels-Alder reaction, FA-BGPP network can decompose into fragments at high temperature and exude to gel surface to form a lubricating layer, thus endowing PAFB with self-lubricating ability. Meanwhile, PAHH network with good temperature resistance acts as protective frame to make PAFB gel being of high strength at high temperature. From oil displacement experiments results at 120 °C, compared with PAHH, the plugging rate, differential pressure at subsequent water flooding stage, fractional flow in low permeability sandpack and oil recovery of PAFB-0.7 gel were increased by 41.6%, 57.3%, 60% and 44.6% respectively, up to 83.1%, 118 KPa, 80% and 75.6%, showing its good performance for in-depth profile control and enhanced oil recovery.

The effect of emulsion and foam on anti-water coning during nitrogen foam injection in bottom-water reservoirs

Bottom-water coning occurs in middle and late stages of bottom-water reservoir development, resulting in a rapid increase of water cut and a serious decline in oil production from wells. Water plugging with nitrogen foam is an effective method for improving development during the high water-cut period of a bottom-water reservoir. During nitrogen foam injection, large amount of foam stay around the well. Meanwhile, the crude oil and foaming agent which is a type of surfactant meet together and generate large amount of emulsion. The paper explores the formation and flow characteristics of emulsion in a micromodel and performs a series of one-dimensional flow tests to investigate oil−water sensitivity, as well as water-plugging and enhanced oil recovery (EOR) efficiency of foam and emulsion in a heterogeneous reservoir. A two-dimensional visual experiment was performed to study foam evolution in an oil layer and the anti-water coning process. The results indicate that blockage of pore throats by emulsion occurs because of superimposed blockage in narrow throats and accumulation plugging in large pores with multiple droplets. Foam is less stable and provides less resistance with higher oil saturation, which is in contrast to emulsion. Foam and emulsion injection can result in subsequent water flooding that diverts from the high-permeability zone to the low-permeability zone, decreases the water cut, and improves the oil recovery. The visual experiment showed that a high-flow resistance zone composed of foam and emulsion forms after part of foam defoaming, which is beneficial to expand swept volume and improves oil recovery of lateral water flooding. The paper can provide references for anti-water coning and EOR by nitrogen foam injection in a bottom-water reservoir.

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.

Reservoir formation conditions and key technologies for exploration and development in Qingcheng large oilfield

The Qingcheng oilfield, the largest shale oil field in China, was discovered in 2019 in source rock of Chang 7 Member of Mesozoic Yanchang Formation, Changqing Oilfield in Ordos Basin, with newly increased proven geological reserves of 358 million tons, predicted geological reserves of 693 million tons, and a total of 1.051 billion tons of shale oil resources. This achieves a historic breakthrough in exploration of shale oil in Chang 7 Member. In recent years, focusing on key issues, such as whether there develop sweet spots in source rock, whether commercial oil production capacity can be formed, and whether scale-effective development can be achieved, studies about geological conditions for shale oil accumulation have been continuously carried out, key supporting technologies have been developed, and a series of theoretical innovations and technological breakthroughs have been achieved in oil exploration in source rocks. The results indicate that shale oil accumulation in Chang 7 Member is controlled by following factors. Firstly, lacustrine black shale, dark mudstone and other high-quality source rocks lay a material foundation for shale oil formation. Secondly, sandy deposits intercalated within black shale and dark mudstones are exploration sweet spots, and sandbody combination types are controlled by morphology of bottom of the lacustrine basin. Thirdly, reservoir properties are good due to development of micro-nano pore throats. Finally, reservoirs with high oil saturation and high gas-oil ratio are formed due to high-intensity oil charging in source rock. Effective matching of multiple factors is a key for shale oil accumulation in Chang 7 Member in Ordos Basin. Through innovation of key supporting technologies, exploration and development technologies for shale oil are developed, and substantial breakthrough on exploration and development of shale oil is realized. The first application of logging-seismic combination technology in loess plateau improves significantly quality of 3D seismic data, which effectively guides prediction of sandy sweet spots. Three-quality well logging technology is used for further evaluation of geological and engineering sweet spots of shale oil. With volumetric fracturing technology based on precise segmentation of long horizontal wells, initial daily oil production of individual well is increased from previously 10 tons to more than 18 tons. The exploration breakthrough in source rocks in Chang 7 Member in Qingcheng oilfield provides an important resource base for the second accelerated development of Changqing Oilfield. It is predicated that oil production from shale in Chang 7 Member in Qingcheng oilfield will reach three million tons in 2022 and five million tons in 2025.

Laboratory Evaluation of Polymer Retention in a Heavy Oil Sand for a Polymer Flooding Application on Alaska's North Slope

SummaryFor a polymer flooding field trial in a heavy oil reservoir on Alaska's North Slope, polymer retention is a key parameter. Because of the economic impact of retention, this parameter was extensively studied using field core material and conditions. In this paper, multiple types of laboratory measurements were used to assess hydrolyzed polyacrylamides (HPAM) polymer retention, including a brine tracer, effluent viscosity, total effluent organic carbon, and effluent chemiluminescent nitrogen. Retention tests were conducted in different Milne Point Schrader Bluff sands, with extensive permeability, grain size distribution, X-ray-diffraction (XRD), and X-ray fluorescence (XRF) characterizations. Several important findings were noted. Polymer retention based on effluent viscosity measurements can be overestimated unless the correct (nonlinear) relation between polymer concentration and viscosity is used. Polymer degradation (either mechanical or oxidative) can also lead viscosity-based measurements to overestimate retention. Inaccessible pore volume (PV) (IAPV) can be overestimated if insufficient brine is flushed through the sand between polymer banks. Around 100 PVs of brine may be needed to displace mobile polymer to approach a true residual resistance factor and properly measure IAPV. Even for a sandpack with kwsor = 20 md, IAPV was zero for HPAM with a molecular weight (Mw) of 18 MM g/mol. Fine-grained particles (<20 µm) strongly impacted polymer retention values. Native NB#1 sand with a significant component of particles <20 µm exhibited 290 µg/g, while the same sand exhibited 28 µg/g after these small particles were removed. Polymer retention did not necessarily correlate with mineral composition. The NB#1, NB#3, and OA sands had similar elemental and clay compositions, but the NB#1 sand exhibited ∼10 times higher retention than the NB#3 sand. Polymer retention did not necessarily correlate with permeability. NB#1 sand exhibited much higher retention than OA sand, even though NB#1 sand was twice as permeable as OA sand. No evidence of chromatographic separation of HPAM molecular weights was found in our experiments. Although retention tended to be greater without a residual oil saturation (than at Sor), the effect was not strong. Aging a core (with high oil saturation) at 60°C reduced HPAM retention by a factor of two. Under similar conditions, polymer retention was greater for a higher Mw HPAM (18 MM g/mol) than for a lower Mw HPAM (10 to 12 MM g/mol). In many cases with high polymer retention values (e.g., 240 µg/g), polymer arrival at the end of the core was relatively quick, but achieving the injected concentration occurred gradually over many PVs. This effect was not caused by chromatographic separation of polymer molecular weights. Results from modeling of this behavior were consistent with concentration-dependent polymer retention. The form assumed for the retention function in a simulator can have an important impact on the timing and magnitude of the oil response from a polymer flood. Field-based observations can underestimate polymer retention, depending on when the tracer and polymer concentrations were measured and the assumptions made about reservoir heterogeneity.