Sandstone Oil Research Articles

Oil distribution and dynamic characteristics of tight oil sandstone cores during spontaneous imbibition-plus-waterflooding and waterflooding-only using nuclear magnetic resonance

To understand the effect of the spontaneous imbibition (SI) and waterflooding on oil recovery in the tight sandstone reservoirs, we selected three pairs of tight sandstone samples from the Ordos Basin in China to conduct the SI-plus-waterflooding and waterflooding-only experiments, and monitor the oil distribution and flow characteristics by using the low-field nuclear magnetic resonance (NMR) technology. One interesting observation was that oil extracted in the SI process mainly comes from macropores and micropores, which doesn’t agree with the previous results wherein oil was produced from micropores, and oil was produced from the mesopores during the waterflooding after the SI process. The oil recovery factor of tight sandstone samples in the process of the SI-plus-waterflooding was more than 50%, and even more than 85%, which was greater than that in the waterflooding-only process. Moreover, we found that our tight sandstone samples behaved lower residual oil saturation, and wider oil-water two-phase co-flow region during the SI-plus-waterflooding process than that did during the waterflooding-only process. These differences in behavior appear to be linked to the fluid dynamic characteristics and capillary pressure acting on the flow fluid during the two processes. In summary, the SI-plus-waterflooding overcame the limitations related to waterflooding-only and further improved oil recovery factor in the tight sandstones.

Lessons Learned from a Prematurely Ended High-Pressure Air Injection Test in a Light Oil Naturally Fractured Reservoir

Summary Sixty billion barrels of oil still reside in the matrix of mature onshore and offshore Mexican reservoirs located in the southeast basins after primary and secondary recovery. Capillary and viscous forces are responsible for this amount of oil retained within the pore structure of the matrix (immobile oil). Gravitational forces are not enough to counterattack these forces due to the high fracturing intensity. On the other hand, laboratory testing demonstrates that oil residing in the matrix could be mobilized by the exothermic reaction that takes place with air injection. Air injection in homogeneous heavy and light oil sandstones and nonfractured limestones, at small or large scales during short and long periods of time, is feasible for producing resources technically and economically nonrecoverable by other means. However, to the best of our knowledge, the published literature does not report any application of an air injection project in naturally fractured reservoirs. During 2015, an air injection pilot test was performed in a light oil naturally fractured reservoir in Mexico, referred to as “A” field. The implementation of the pilot test was preceded by its corresponding laboratory study, which consisted of five accelerating rate calorimeter (ARC) tests and two combustion tube (CT) experiments. The analysis of the aforementioned experimental work led us to corroborate that air and oil react at reservoir conditions. Based on the above finding, the pilot test was conducted by injecting air at a rate of 10 MMscf/D with a wellhead pressure of 4,500 psia for 1.5 years, which was followed by a 1.5-year production period giving a total of 3 years for the pilot test. The results indicate that combustion was successfully applied in the reservoir. However, no oil was produced. This paper discusses the results of a prematurely ended air injection pilot test in “A” field and the main lessons learned from it, which could help in the design and its subsequent implementation in other naturally fractured reservoirs.

Geological characteristics and resource potential of shale oil in major basins of China

China shale oil can be classified as interlayer shale oil (in sandstone, carbonate, and diamictite) and genuine shale oil. Considering the characteristics and strong heterogeneity of continental shales, it is recommended to evaluate the interlayer shale oil resources using the elemental volume method based on pore volume, and the genuine shale oil resources using the elemental weight method based on oil content. Four key parameters for genuine shale oil resource evaluation (i.e., S 1, TOC, R o, and shale thickness) and three key parameters for interlayer shale oil resource evaluation (i.e., interlayer thickness, porosity, and oil saturation) are determined, and the lower limits of parameters are defined accordingly. The evaluation results show that the geological resources of genuine shale oil in Qing-1 member of Songliao Basin are 52.23 × 108 t; the geological resources of shale oil in Chang-73 sub-member of Ordos Basin are 66.80 × 108 t, including 27.73 × 108 t interlayer shale oil and 39.07 × 108 t genuine shale oil; the geological resources of shale oil in Lucaogou Formation of Junggar Basin are 15.62 × 108 t, including 11.99 × 108 t interlayer shale oil and 3.63 × 108 t genuine shale oil. This study provides a reference for exploration decision of shale oil in China.

Implication of interfacial tension reduction and wettability alteration by surfactant on enhanced oil recovery in tight oil reservoirs

Tight oil reservoir is usually characterized by poor physical properties with oil recovery less than 10%. The objective of the study is to investigate the effect of 4 different types of surfactants to change rock surface tension and interfacial tension as well as its impact on enhanced oil recovery (EOR) in tight oil reservoirs. Results shows that the fluoride FC-1 and GS surfactant has more potential for wettability alteration and interfacial tension reduction respectively. The interfacial tension decreased from 6.072 mN/m to 2.04 mN/m, 0.03 mN/m, 0.1 mN/m, and 0.04 mN/m under the action of FC-1, GS surfactant, FC-2, and FC-3, respectively. FC-1 made the wettability changed from original hydrophilic or oil-hydrophilic to hydrophobic and oil-phobic. While the effect of wettability modification by other three was not so obvious and the contact angle was no more than 45 degrees. So, the GS and FC-1 was selected for displacement tests to investigate the effect in augmenting injection and enhancing oil recovery. The average reduction rate of injection pressure by fluoride and Gemini surfactant was 32.4% and 14.2%, respectively. Under the action of fluoride and GS surfactant, the water-phase permeability increased by 36.8% and 29.9%, respectively. The improvement of recovery mainly occurred in primary water flooding, while the amount of oil displaced by surfactant solution and secondary water flooding was little or even no, with the recovery efficiency improved by 0–8.4%. The effect of fluoride was more obvious, revealing that changing rock wettability is more favorable than reducing the interfacial tension for oil recovery in tight sandstone oil reservoirs.

Salt precipitation in carbonates during supercritical CO2 injection: A pore-scale experimental investigation of the effects of wettability and heterogeneity

Salt precipitation in near-wellbore regions of subsurface reservoirs is a significant phenomenon that may occur during carbon dioxide (CO2) injection for carbon sequestration and enhanced oil recovery. It induces pore plugging, which causes reductions in porosity and permeability and hence well injectivity. Previous research in this area focused predominantly on salt precipitation in fully brine-saturated media, such as those found in deep saline aquifers. However, studies on salt precipitation in hydrocarbon reservoirs where brine and oil coexist are rare, particularly at the pore scale. In this study, we elucidate the occurrence and dynamics of salt precipitation at the pore-scale during supercritical CO2 injection into depleted carbonate and sandstone oil reservoirs at elevated temperature and pressure conditions. Specifically, we examine the influence of wettability and morphological heterogeneity on salt precipitation evolution and dynamics. Investigations on the influence of wettability reveal that the time required for the initiation of precipitation is shorter for an intermediate-wet carbonate compared to that for a weakly oil-wet carbonate. Relatively higher amounts of salt deposits are formed in the more hydrophilic (intermediate-wet) carbonate, leading to an intensification of porosity reduction in this rock. In addition, the presence of oil within the pore space does not hinder the precipitation process but suppresses the reverse flow of solutes toward the evaporation front, thereby creating localized precipitation at the front. The level of heterogeneity affects the precipitation initiation and its duration as well as the amount of precipitates formed, with lower salt saturations encountered in the less heterogeneous sandstone compared to the more heterogeneous carbonate. Heterogeneity also influences the salt cluster size distribution within pore elements such that, for the same wettability state, medium-sized clusters dominate in sandstone, while large clusters are the main contributors to the total salt volume in the more heterogeneous carbonate. This study forms a fundamental basis for the prediction of salt precipitation during three-phase flow processes induced by supercritical CO2 injection into porous media containing high-salinity brine and oil.

Oil generated overpressure of shale and its effect on tight sandstone oil enrichment: A case study of Yanchang Formation in the Ordos Basin, China

Oil generated overpressure (OGOP) is a key factor in tight sandstone oil enrichment. However, the relationship between the OGOP and oil enrichment remains unclear. On the basis of a physical simulation experiment and an oil injection experiment, an improved OGOP model based on the organic matter enrichment zone (OMEZ) was established, the attenuation of OGOP in shale was discussed, and the oil charging distance under different reservoir conditions was evaluated. The results showed that the OGOP starts from the OMEZ in the shale, is controlled by the OMEZ size, and decays during the expansion of the hydrocarbon expulsion microfractures. The attenuated OGOP acts as the initial migration force to push crude oil into tight sandstone reservoirs. The OGOP magnitude, OMEZ size and reservoir properties together determine the enrichment scale of tight sandstone oil. Driven by OGOP, the oil charging distance for the tight reservoir in the Yanchang Formation is only 66.7 m but 383.5 m for the conventional reservoir. These findings open a window to study the impact of shale internal structure on OGOP. The OGOP mathematical model and calculation method of various parameters in the process of oil accumulation proposed in this study are helpful for further understanding the mechanism of hydrocarbon generation, discharge, and enrichment.

Effectiveness of Oil Filling in Tight Sandstone Reservoirs of Yancheng Formation in Ordos Basin

The Ordos basin is one of the important oil-bearing basins in China, with abundant tight sandstone oil resources, wide distribution, and large thickness. It is the most realistic field of unconventional oil and gas exploration in China, and it is also an important oil and gas replacement resource at present. Oil accumulation in tight reservoirs is obviously different from conventional oil and gas accumulation, and the key lies in studying the effectiveness of oil filling in tight reservoirs. In order to solve this problem, this paper takes the tight sandstone reservoir of Member 7 of the Yancheng Formation in Ordos Basin as the research object, introduces the geological characteristics of this area after sorting out the previous research results, carries out the physical simulation experiment of oil filling, studies the relationship between the filling pressure and the lower limit of the filling throat, analyzes the effective accumulation space of the tight sandstone reservoir, defines the oil filling mechanism of the tight sandstone reservoir, and discusses the effectiveness and reservoir-forming effect of oil filling in different types of reservoirs. The results show that the rock types of tight sandstone reservoirs in the 7th member of the Yancheng Formation are mainly lithic feldspathic sandstone and feldspathic lithic sandstone, and the reservoirs have experienced strong compaction and carbonate cementation. The late iron-bearing carbonate cementation has further strengthened the degree of reservoir densification, and the reservoirs have been densified at the time of large-scale oil and gas filling. Through the simulation experiment of oil filling with natural cores with different physical properties, the relationship model between filling pressure and effective accumulation space of different types of tight sandstone reservoirs in Member 7 of the Yancheng Formation is established. With the change in filling pressure, the change trend and range of effective accumulation space of different types of tight sandstone reservoirs are obviously different. According to the relationship model between the filling pressure and the lower limit of the effective filling pore throat, the oil filling effectiveness of different types of tight sandstone reservoirs in the 7th member of the Yancheng Formation is determined. Class I and class II1 reservoirs are effective reservoirs for oil filling of tight sandstone reservoirs, which constitute the main oil-bearing section of tight sandstone reservoirs in member 7 of the Yancheng formation, while class II2 reservoirs are poor tight reservoirs, and class III reservoirs are basically oil-free, which are noneffective reservoirs for oil filling of tight sandstone reservoirs. The results provide theoretical data support for the next step of oil exploration and exploitation in tight sandstone reservoirs.

Comprehensive evaluation and reservoir classification in the Quan 3 Member of the Cretaceous Quantou Formation in the Fuxin Uplift, Songliao Basin

Continental tight oil sandstone reservoirs are developed in the Cretaceous Quentou Formation in the Songliao Basin, China. At present, there is still a lack of research on the reservoir microstructures, reservoir physical properties, and the division scheme of reservoir types in the Quan 3 Member of the Quanzhou Formation. Therefore, in this paper, taking the Quan 3 Member in the Fuxin Uplift Belt of the Songliao Basin as an example, the microscopic pore structure characteristics of tight oil sandstones have been systematically studied, and the classification standard of tight sandstones has been formulated. Furthermore, the sweet spots of the main production layers are predicted. The results show that the I sandstone group in the Quan 3 Member in the study area belongs to shallow water delta facies. Feldspar lithic fine sandstones are developed in the target layer, and calcareous sandstone is locally developed. Moreover, the mian pore types of the target layer include dissolved intergranular and intragranular pores, followed by primary intergranular pores, while micro-fractures are occasionally seen. According to the mercury intrusion test results, the pore-throat structures of the reservoir in the Quan 3 Member are divided into four types: 1) small-pore medium-throat type (point bar and delta distributary channel), 2) small-pore micro-throat type (point bar), 3) small-pore micro-throat type (natural levee), 4) micro-pore micro-throat type (river floodplain and inter-tributary bay). The lower limits of the physical properties of the effective reservoirs in the Quan 3 Member has been determined: the porosity is 10% and the permeability is 0.1 mD. Finally, combined with the study of the mercury intrusion curves, the physical properties and the sedimentary facies, the classification standard of the Quan 3 Member reservoirs was formulated. For the I sandstone group, the sweet spots of the Type I reservoirs are mainly developed in the Fuyu Oilfield in the southeast areas. The sandstones in this area suffered less compaction, and primary and secondary pores suffered from late dissolution are mainly developed.

Production prediction and main controlling factors in a highly heterogeneous sandstone reservoir: Analysis on the basis of machine learning

AbstractOwing to a lengthy oil‐bearing interval, strong anisotropism, and significant difference in the fluid properties of the sandstone oil reservoir in P Oilfield, it is quite challenging to accurately the productivity of the oil well at the initial stage. In this study, a deep neural network model is established, based on a gradient boosting algorithm, XGBoost, to forecast the initial productivity of oil wells, followed by an evaluation of the main controlling factors of productivity. One hundred oil wells in the study area were divided into training and verification groups. With a specific productivity index of an oil well with a stable period of approximately 6 months at the initial production stage as the target data, and geological, engineering, and oil reservoir parameters as input data, hyper‐parameters for adjustment and optimization were selected, and a deep‐learning‐based unconsolidated sandstone productivity forecast model was established to forecast the initial productivity of oil wells in the target area. The mean square root error of the forecast result was <0.15, which is highly consistent with actual productivity. Finally, by adopting the XGBoost algorithm, the weight ranking of the controlling factors of productivity was clarified as follows: microscopic pore structure parameter > crude oil viscosity > median grain size > lithology index > well completion method > flow zone indicator. Machine learning has the advantages of effective forecasting of oil well productivity and the main controlling factors using multiple dimensions and big data.

Study on the development options of tight sandstone oil reservoirs and their influencing factors

The research area of tight sandstone oil reservoirs was selected, a numerical model of the oil reservoir was developed, and a study of the development options and influencing factors was carried out to analyze the influence of different development methods, physical and engineering parameters on the development dynamics. Study shows that the two main factors limiting the efficient development of tight sandstone reservoirs are reservoir properties and formation energy. Fractured horizontal well injection huff and puff development can effectively improve reservoir physical properties and timely replenish formation energy, which is suitable for the development of such oil reservoirs. In dense sandstone reservoirs, its impact on production capacity is also relatively small when the permeability ratio is small. Due to both gravity and reservoir physical properties, the permeability ratio increases, the cumulative oil production of positive rhythm reservoirs decreases and that of reverse rhythm reservoirs increases, and the location of high-quality reservoirs in the upper part of producing wells is conducive to increasing the final recovery rate. A lower oil to water viscosity ratio can significantly increase the swept volume and improve development effect. Hydrophilic reservoirs can reduce the injection pressure and increase the spread range, effectively improving the problem of inability to inject, and improving reservoir hydrophilicity through surface activators can increase reservoir recovery. The water injection rate determines the recovery rate of formation energy. Generally, the faster the rate, the higher the cumulative oil production. Therefore, the rate of water injection should be increased as much as possible, taking into account construction conditions and economic evaluation. Additionally, the effect of water injection on the development effect is different at different stages, so the appropriate timing of water injection is very important to the water injection huff and puff development effect, and the use of early water injection in this research area is not conducive. Soaking can promote pressure and fluid redistribution and improve water injection huff and puff development effect, but soaking for a long time can lead to reservoir contamination and reduce crude oil production, so the preferred time for a soaking is about 20 days.

Controlling factors and predictions of well-connected pore-throat volumes in tight oil sandstones

Oil production from tight oil sandstone reservoirs has achieved success with the aid of hydraulic fracturing and horizontal well drilling technologies. However, approximately 90% of the oil in these reservoirs remains in place, and reservoir evaluation methods are essential for effective enhanced oil recovery. Well-connected pore throats constitute the connections between fractures and micropores in tight oil reservoirs and lead to high oil recovery levels when using enhanced oil recovery (EOR) methods. In this study, geological factors, such as reservoir quality, lithofacies, and oil charging extent, have been investigated, and their relationships with the well-connected pore-throat volume (Sapex) is discussed. Multiple linear regression and support vector machine (SVM) methods were used for Sapex predictions. The results show that the Sapex values increase as the porosity/permeability increase and then show a decrease. For the flow zone indicator (FZI), Sapex first decreases as the FZI increases and then a slight increase. High Sapex values can be present in nearly all lithofacies, except within some small-scale bedding structures. Increased oil saturations may increase the Sapex, but some rocks with no oil shows still have high Sapex values. High Sapex values are mainly present in two cases: (1) Rocks located close to source rocks with high acidic dissolution levels resulting in secondary porosity and authigenic clay contents. (2) Rocks located far from source rocks that have no oil shows and high contents of chlorite cement, which mainly indicate alkaline diagenetic environments. Predictions of Sapex using multiple linear regression and SVM methods indicate that SVM regression is a good method because of the two high Sapex rock types. The production data from wells with different Sapex values show that the Sapex has a large effect on fluid flow properties.

Effect of CO2 flooding in an oil reservoir with strong bottom-water drive in the Tahe Oilfield, Tarim Basin, Northwest China

The dissolution and diffusion of CO2 in oil and water and its displacement mechanism were investigated by laboratory experiment and numerical simulation for Block 9 in the Tahe oilfield, a sandstone oil reservoir with strong bottom-water drive in Tarim Basin, Northwest China. Such parameters were analyzed as solubility ratio of CO2 in oil, gas and water, interfacial tension, in-situ oil viscosity distribution, remaining oil saturation distribution, and oil compositions. The results show that CO2 flooding could control water coning and increase oil production. In the early stage of the injection process, CO2 expanded vertically due to gravity differentiation, and extended laterally under the action of strong bottom water in the intermediate and late stages. The CO2 got enriched and extended at the oil-water interface, forming a high interfacial tension zone, which inhibited the coning of bottom water to some extent. A miscible region with low interfacial tension formed at the gas injection front, which reduced the in-situ oil viscosity by about 50%. The numerical simulation results show that enhanced oil recovery (EOR) is estimated at 5.72% and the oil exchange ratio of CO2 is 0.17 t/t.

Oil origin and migration direction in Wushi sag, Beibuwan Basin, South China Sea

The Wushi sag is one of the most important petroleum-bearing units located in the Beibuwan Basin, South China Sea. Insufficient understanding of oil origin and migration direction, and lack of characterizing oil differential accumulation distribution patterns in Wushi sag greatly restrict further hydrocarbon exploration. In this study, oil-source rock genetic relationships and migration directions were analyzed in detail by combining geochemical analysis of 45 source rock samples, 23 crude oil samples, 12 oil sandstone samples, and basin modeling results. The geochemical data show there is distinguishable heterogeneity in Liushagang Formation (Fm) source rock in Wushi sag, which is divided into two types. The first type (including the Member (Mbr) 23 and Mbr 3 of Liushagang Fm source rocks) was deposited in a weak reducing to suboxic and fresh to brackish water environment with a predominance of aquatic algal plankton input. The second type (including the Mbr 1 and Mbr 21 of Liushagang Fm source rocks) was deposited in a suboxic and fresh to brackish water environment with mixed inputs of aquatic algal plankton and terrestrial higher plants. Three groups of crude oils (A, B, and C) are identified using their physical properties and biomarker data. The group A oil is characterized by a higher abundance of oleanane, lower abundance of C30 4-methylsterane, higher values of Pr/Ph, and lighter δ13C values, and is mainly derived from the Mbr 21 of Liushagang Fm source rock. Group B and group C oils are characterized by a lower abundance of oleanane and higher abundance of C30 4-methylsterane, but present some differences in Pr/Ph and δ13C values. Both groups of oils are sourced from the Mbr 23 of Liushagang Fm source rock, and their differences in geochemical characteristics indicate the lateral heterogeneity of source rock. Oil migration directions are determined by combining maturity parameters, pyrrolic nitrogen compounds, and also basin modeling results. The preferential oil migration directions in Wushi sag are from the central to the northeast and south of the sag. The accumulation distribution of different groups of oils is mainly controlled by the vertical and lateral heterogeneity of Mbr 2 of Liushagang Fm source rock.

Micro-Scale Pore-Throat Heterogeneity of Tight Oil Sandstone Reservoirs and Its Influence on Fluid Occurrence State

Quantitatively characterizing the micro-scale heterogeneity of pore throats in tight sandstone reservoirs is the key to accurately describing the influence of pore structures on fluid occurrence characteristics. In this study, taking the Chang 6 Member of the Yanchang Formation in the Huaqing area of the Ordos Basin as an example, the pore-throat heterogeneity of tight sandstone reservoirs and its influence on the fluid occurrence state have been systematically studied using cast thin section, scanning electron microscope, X-ray diffraction, constant velocity mercury intrusion, and nuclear magnetic resonance tests. The main types of pores developed in the target layer were intergranular pores, followed by feldspar dissolution pores. The radius distribution of the intergranular pores is between 5.0 and 210 μm, with an average value of 50.27 μm. In addition, the pore combination types with the best petrophysical properties are the intergranular pore type, the intergranular-dissolution pore type, and the dissolution-intergranular pore type; the average permeability and porosity are 0.62 mD, 0.40 mD, 0.44 mD, and 12.0, 12.3, 12.3%, respectively. The target sandstones contain four typical T2 relaxation time types. The large-pore-fine-throat combination reservoir has the best petrophysical properties. The larger the pore-throat uniformity value, the more uniform the pore-throat radius, and the greater the reservoir permeability. Therefore, the uniformity of throat development controls the seepage capacity of the tight reservoirs. The movable fluid saturation of different pore types has obvious differences. The movable fluid saturations at the 0.1 and 0.5 μm pore diameters of the macro-pore-fine-throat and macro-pore-micro-throat reservoirs both show an obvious inflection point, and the movable water saturation is higher with a larger throat radius.

Disparities in tight sandstone reservoirs in different source-reservoir assemblages and their effect on tight oil accumulation: Triassic Chang 7 member in the Qingcheng area, Ordos Basin

Determining source-reservoir spatial assemblages and their tight reservoir disparities is essential for revealing the differential accumulation mechanism of continental tight sandstone oil, but systematic classification and case studies are rarely reported. In this article, based on lithological combination characteristics, the source-reservoir spatial assemblages of the Triassic Chang 7 Member in the Qingcheng area of the Ordos Basin are systematically divided into three categories, namely, reservoir-sandwiching source (RSS), source-reservoir interbed (SRI) and source-sandwiching reservoir (SSR). Moreover, the tight sandstone reservoirs in different assemblages were characterized by a combination of macro observations from cores and geophysical logs and microscopic analysis from cast thin sections, FE-SEM, HPMI and XRD data. The results demonstrate that the tight sandstone reservoirs within different source-reservoir assemblages have similar lithological properties, but vary greatly in reservoir quality and natural fracture networks. In general, the RSS sandstones have the broadest pore-throat size distribution and the best physical properties due to the prevalence of residual intergranular pores, and the reservoir quality is slightly better than that of the SRI sandstones and significantly better than that of the SSR sandstones. Additionally, natural fracture types and fracture intensities vary greatly in different source-reservoir assemblages. The RSS assemblage contains mainly high-dip angle fractures with relatively low fracture intensities, the SSR assemblage is dominated by low-dip angle bedding-parallel fractures with relatively high intensities, and the SRI assemblage is characterized by a combination of these two assemblages. Under the control of overpressure derived from hydrocarbon generation, tight reservoirs with different source-reservoir assemblages present different lower limits of petrophysical properties for tight oil charging, and the effective reservoir proportion leads to a decreasing enrichment degree in the RSS, SRI and SSR assemblages successively. Furthermore, the natural fractures in different source-reservoir assemblages enhance the storage capacity while contributing to disparities in the vertical migration of tight oil. The natural fracture network of the vertically stacked RSS assemblage allows tight oil to migrate upward for a relatively long distance, while the SSR assemblage can effectively prevent the upward migration of the tight oil, thus forming differential tight oil accumulation and distribution characteristics in the different source-reservoir assemblages.

Analysis of forces during tight oil charging and implications for the oiliness of the tight reservoir: A case study of the third member of the Palaeogene Shahejie Formation, Qibei slope, Qikou sag

In contrast to those of conventional oil accumulation, the forces of tight oil accumulation are complicated and varied during tight oil charging. In this study, the tight oil sandstones of the third member of the Palaeogene Shahejie Formation (Es3) in the Qibei slope belt in the Qikou sag were taken as an example, the orders between oil charging and reservoir densification, and the forces during tight oil accumulation were investigated using basin modelling, fluid inclusion analysis, logging prediction, and thin slice identification. The concept of the net force during tight oil accumulation was established, and the relationship between the oiliness of the tight reservoir and the net force during the oil charging was qualitatively characterised using physical experiments and digital simulations. The results of this study indicate that two periods of oil charging occurred during 28–23 Ma and 12 Ma to present in the Qibei slope belt. Three stages were identified in the oil charging physical experiments and digital simulations, i.e., the breakthrough, rapid, and fully saturated stages, which had net forces of 5 MPa, 19 MPa, and 38 MPa in the Qibei slope belt, respectively. The net force and oil saturation during the late oil charging period can be used to predict the tight reservoir's oiliness. When the value was in the oil breakthrough stage, dry layers were identified; when the value was in the oil rapid charging stage, fractured oil layers were identified; and when the value was in the fully oil saturated stage, flowing oil layers could be identified. The results of this study provide insights into the driving mechanism of tight oil accumulation and the distribution of oil in tight reservoirs.

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.

Insight into bacterial community profiles of oil shale and sandstone in ordos basin by culture-dependent and culture-independent methods

To promote the exploitation of unconventional oil resources by indigenous microorganisms, the bacterial community profiles of oil shale and sandstone in Ordos Basin were investigated using Illumina Miseq sequencing combined with the culture-based method, which was performed and reported in this literature for the first time. A total of 601 operational taxonomic units (OTUs) were obtained from collected samples, the predominant phylum present in all samples was Proteobacteria (76.96%-93.07%). Discriminatory bacterial community profiles existed in those samples by culture-dependent and culture-independent methods, with variations not only in diversity indices but also in the abundance of bacteria at different genus levels. The dominant genera in cultured sandstone sample (SCB), uncultured sandstone sample (SUB), cultured shale sample (YCB), uncultured shale sample (YUB) were Enhydrobacter (71.62%), Acidovorax (42.44%), Pseudomonas (40.13%), Variovorax (70.02%), respectively. Both sample sources and culturing methods were the principal factors affecting the variation, while the communities’ structures were favored primarily by culture-dependent or culture-independent approaches. The high abundance of hydrocarbon degradation-related genes was exhibited in YCB, which reveals a great potential for utilization of the culture-dependent method in shale oil exploitation. This study provided guidance for the exploitation of shale oil and sandstone oil by artificial utilization of indigenous bacteria.

Dynamic Calculation of Water Sweep Efficiency and Relative Permeability Curve on Water Drive Reservoir

The water sweep efficiency is an important parameter in oilfield development. The present method needs to fit the core relative permeability curve, which has the problem of low accuracy and poor practicability. Based on three kinds of calculation formulas of water saturation, the calculation method of limit water sweep efficiency is put forward, and the dynamic method of two parameters in the index relationship between oil-water relative permeability ratio and water saturation is established. On this basis, the dynamic calculation method of sweep efficiency, oil displacement efficiency and oil-water relative permeability curve is formed, which overcomes the dependence on core permeability curve. The XJ oilfield calculation shows that for the south china sea marine sandstone oil field with abundant side water, the oil production is mainly from the water flooding region expansion in the initial oilfield developed period and then change to enhance oil displacement efficiency as the water sweep efficiency is to be stable, so the development policy of this oilfield should be to perfect production patterns nets in the initial oilfield developed period, then be to installe larger pumps and increase liquid production in the middle-later developed period. The proposed method is featured with accessible date, convenient calculation, showing a broad application prospect in dynamic analysis and development effect evaluation of oilfield.

Lower limits and controlling factors of the petrophysical properties of coal-measure sandstone oil reservoirs: A case study of the Jurassic Yan’an Formation in the Huanjiang area, Ordos Basin, China

Coal-measure sandstone oil reservoirs of the Jurassic Yan’an Formation in the Ordos Basin, China, have strong heterogeneity. Reservoir quality is the core factor that determines the large-scale accumulation of hydrocarbons. Taking the Yan’an Formation in the Huanjiang area, Ordos Basin, as an example, we have calculated the lower limits of petrophysical properties based on empirical statistics, porosity and permeability intersections, mercury injections and irreducible water analysis, oil tests, oil-bearing property analysis, and distribution functions. In addition, we have investigated the main controlling factors of effective reservoirs in the Yan’an Formation. The results demonstrate that the lower limits of petrophysical properties of the effective reservoir in the Yan’an Formation display a gradually decreasing trend as the depth increases. Furthermore, we have obtained the functions of the lower limits of the petrophysical properties and the depth. Sedimentation and diagenesis have a significant control effect on the quality of reservoirs in the Yan’an Formation. High-quality reservoirs have mainly developed in the sedimentary microfacies of point sand bar and distributary channel sand bodies. The strong compaction and cementation in the diagenesis process are the internal reasons for the poor petrophysical properties of the Yan’an Formation reservoirs. Overall, the effect of compaction on the petrophysical properties of the reservoir is stronger than that of cementation, whereas the secondary dissolution pores significantly improve the petrophysical properties of the reservoir.