Movable Oil Research Articles

Study on effect of viscosity on thickness of boundary layer in tight reservoir

It has become a consensus that viscosity has an important impact on boundary layer of tight reservoirs. However, there are few quantitative studies on the effect of viscosity on boundary layer by core experiments. NMR analysis based on high-speed centrifugal gas-water and gas-oil displacement and low-temperature adsorption experiment were implemented in this study on typical tight reservoir parallel cores of Ordos and Bohai Bay basins. Total bound water/oil saturation, specific surface area and ratio of micro pore of the reservoir quantitatively were finally obtained, which were used for calculating irreducible water/oil film thickness of reservoir and analyzing influence of viscosity on movable oil and boundary layer. Research show that, movable oil saturation of core saturated high viscosity oil is 23.92% and 18.61% lower than that of core saturated low viscosity oil and water respectively, and effective seepage space is greatly reduced. The lower permeability reservoir has, the greater reduction movable space with high viscosity oil of reservoir owns. The average bound water film thickness of Ordos and Bohai Bay basin cores is 17.74 nm and 16.99 nm, respectively. The average bound oil film boundary of core in Ordos Basin is 20.72 nm. The average thickness of high viscous oil film of core in Bohai Bay basin is 38.10 nm, and the thickness of low viscosity oil film is 18.80 nm. The oil-water viscosity ratio in Ordos Basin is small, and oil-water film thickness is close, indicating that fluid viscosity has little influence on boundary layer thickness of target reservoir. The low viscosity oil-water viscosity ratio in Bohai Bay basin is small, and oil-water film thickness is close. The thickness of high viscosity oil film is more than twice that of low viscosity oil film and water film. When the oil viscosity is higher than 8.9 mPa s, thickness of boundary layer will be greatly affected, leading to a significant reduction of effective seepage throat, a significant increase of seepage resistance and development difficulty.

Microscopic oil occurrence in high-maturity lacustrine shales: Qingshankou Formation, Gulong Sag, Songliao Basin

Occurrence and mobility of shale oil are prerequisites for evaluating shale oil reserves and prioritizing exploration targets, particularly for heterogeneous lacustrine shales. The Qingshankou Formation in the Gulong Sag, Songliao Basin is a classic lacustrine pure shale reservoir that contains abundant shale oil resources. The predicted geological reserves of the shale are 1.268 × 109 t. In this study, field emission scanning electron microscope (FE-SEM), the modular automated processing system (MAPS), pyrolysis-gas chromatography (Py-GC), low-pressure nitrogen gas adsorption (LPNA), Soxhlet extraction, pyrolysis, and 2-D nuclear magnetic resonance (NMR) were integrated to describe the shale oil components, microscopic occurrence, mobility, and the effective pore size distribution. Meanwhile, the related controlling factors are discussed.The shale oil in the Qingshankou Fm exists dominantly in the matrix pores of the clay minerals, with small amounts distributed in the intergranular pores of terrigenous clastic grains, intercrystalline pores of pyrite, intragranular pores of ostracod shells, and micro-fractures. Shale oil is distributed in the pore spaces of variable sizes in different lithofacies. The clay mineral-laminated shales are characterized by the broadest range of pore size and largest volume of pore spaces with shale oil distribution, while the ostracod-laminated shales have limited pore spaces retaining oil. Furthermore, the proposed integrated analysis evaluates the shale oil molecules existing in two states: movable, and adsorbed oil, respectively. The result illustrates that movable oil takes up 30.6%–79.4% of the total residual oil. TOC, mineral composition, and pore structures of the shale joint together to control the states and mobility of the shale oil. TOC values are positively correlated with the quantities of shale oil regardless of the state of oil. The mineral components significantly impact the state of shale oil. Noticeable differences in the states of oil were observed following the changing types of minerals, possibly due to their difference in adsorption capacity and wettability. Clay minerals attract more adsorbed oil than movable oil. Felsic minerals generally decrease the occurrence of total and adsorbed oil. Carbonate plays a positive role in hydrocarbon retention of all the shale oil states. As for the pore structure, the average pore size exerts a critical impact on the total, movable, and adsorbed oil content. The total pore volume and specific surface area of shales play a principal role in controlling the total yields and amounts of adsorbed oil. This research improves the understanding of the occurrence characteristics and enrichment mechanisms of shale oil in terrestrial pure shales and provides a reference for locating favorable shale oil exploration areas.

Logging evaluation of pore structure and reservoir quality in shale oil reservoir: The Fengcheng Formation in Mahu Sag, Junggar Basin, China

The Permian Fengcheng Formation in the Mahu Sag of the Junggar Basin is characterized by frequent changes of mineral compositions and lamina structure. The alkali lacustrine shale reservoir shows strong heterogeneity and anisotropy, it is particularly important to clarify the relationship between pore structure and reservoir quality. The pore characteristics were investigated by using thin sections, Scanning Electron Microscope (SEM), and Nuclear Magnetic Resonance (NMR) analyses. The pore types are mainly composed of inorganic pores, organic pores, and microfractures. The storage space is dominated by inorganic pores and microfractures. The pore structure was divided into four types by NMR parameters including T2 spectral morphology, T2gm, total porosity, and movable fluid porosity. Combined with core NMR experiments and two-dimensional (2D) NMR logs, 21 ms was adopted as the T2cutoff value to represent the demarcation between movable and bound fluids. From Type I to Type IV, the energy clusters reflect the movable fluids including movable oil and movable water gradually decreasing in the upper right corner. The energy clusters reflect the bound fluids including clay-bound water and bitumen gradually increasing in the lower left corner in the T1-T2 map. The results show that the heterogeneity of mineral compositions and lamina structures are the key factors directly leading to the complexity and distribution of pore structure. Quartz with strong compaction resistance helps keep a large number of primary interparticle pores, and feldspar dissolution pores caused by organic acids are present. Dolomite intercrystalline pores and dissolution pores provide a large amount of storage space for the shale, while the cementation of calcite reduces pore spaces. The increase of felsic mineral content is conducive to improving the pore structure and oil-bearing potential of oil shale reservoir, while clay minerals and calcite are contrary. There are abundant primary interparticle pores and dissolution pores in the layered siliceous (felsic) shales, and they consist of the upper sweet spot in the Fengcheng Formation. The longitudinal time (T1) and transverse time (T2) spectra are bimodal with high total porosity and movable oil content, reflecting high reservoir quality and oil-bearing property. Laminated dolomite shales contain dolomite intercrystalline pores and dissolution pores, and they consist of the lower sweet spot in the Fengcheng Formation. The results above provide a new perspective on the evaluation of pore structure and reservoir quality of shales in the context of an alkaline lake.

A New Index to Evaluate the Seepage Capacity of Water-Wet Sandstone Reservoirs

The water-wet sandstone reservoirs in the Liushagang Formation of the Beibuwan Basin has tremendous exploration potential for oil reserves in the South China Sea. However, owing to the weak correlations between petrophysical parameters and oil productivity, the production performance and seepage capacity showed significant differences in various reservoirs. The production performance of the field was evaluated by characterizing the mobility of two-phase flow through the concept of classical global mobility. However, global mobility still does not consider differential displacement pressure (DDP) and movable oil saturation (MOS). Therefore, a new index based on the Li–Horne model was established to simultaneously evaluate the seepage capacity of water-wet sandstone reservoirs, accounting for DDP and MOS. The detailed work stemming from the model included selecting water-wet sandstones with different lithologies and comparing the displacement effects of different flooding systems, oil viscosities, injection water salinities, pressure conditions, and MOS in multiple sets of parallel core samples. Finally, the new index was validated. A strong correlation was found between the new index and oil productivity per-unit differential pressure through displacement analysis of rock/oil/water, rock/oil/gas, and rock/oil/polymer systems on several core samples. The developed index for evaluating seepage capacity is suitable for different sandstones, flooding systems, oil viscosities, injection water salinities, pressure conditions, and productivity test data, thus providing insight into the production performance and seepage capacity parameters of water-wet sandstone reservoirs.

Paleoenvironmental Conditions and Shale Oil Potential of the Carboniferous Ha’erjiawu Formation in the Santanghu Basin, NW China

The Carboniferous Ha’erjiawu Formation in the Santanghu Basin represents a significant potential target for shale oil exploration, yet its characteristics remain largely unknown. This study utilizes a combination of elemental and organic geochemical analyses to investigate the paleoenvironmental conditions and shale oil potential of the Carboniferous Ha’erjiawu Formation black shales within the Santanghu Basin. The results suggest that the Ha’erjiawu Formation black shales were deposited in water columns with low salinity and dysoxic conditions, as indicated by paleosalinity and redox proxies such as Rb/K, B/Ga, B content, V/Cr, V/(V + Ni), V/Al, and Mo/Al. Furthermore, the climatic proxies (Ga/Rb, Sr/Cu and K2O/Al2O3) indicate that the Santanghu Basin underwent a warm-humid/cold-dry oscillating climate during the deposition of the Ha’erjiawu Formation black shales, potentially influenced by synsedimentary volcanic activity or the Late Paleozoic glaciation. The organic geochemical analyses have revealed that the Ha’erjiawu Formation black shales are rich in type II kerogen, which is in the early mature to mature stage, indicating a significant potential for oil generation. However, there is considerable variation in the oil content of the analyzed samples, with only a few containing movable oil. Given the high abundance of brittle minerals within the Ha’erjiawu Formation black shales, it will be indispensable to meticulously evaluate and identify intervals exhibiting abundant movable oil for successful shale oil exploration and development within this geological unit.

Oil occurrence mechanism in nanoporous shales: A theoretical and experimental study

In tight shales, occurrence characteristics limit oil migration and recovery. This paper proposes an innovative approach based on experimental and theoretical models to investigate the oil occurrence mechanism in nanoporous shales. Thermogravimetry (TG) and nuclear magnetic resonance (NMR) tests were conducted to investigate the migrations and distributions of adsorbed, irreducible, and movable oils. Furthermore, the oil micro-occurrence characteristics within shales were quantitatively clarified using the theoretical equation for the adsorption ratio. Lacustrine shales with different lithofacies from Dongying Sag, Bohai Bay Basin, China, were evaluated as a case study. The results showed that adsorbed, irreducible, and movable oils occur in different pore sizes. The adsorbed oil is primarily saturated in micropores (<0.1 μm) and mesopores (0.1–1 μm) but hardly in macropores (>1 μm), characterized by an average density of around 1.4974 g/cm3 and a mean adsorption thickness of approximately 0.723 nm at a temperature of 60 °C. The irreducible oil predominantly occurs in mesopores, whereas the movable oil primarily exists in mesopores and macropores, and the weight ratio rapidly increases with increased pore size. Additionally, the NMR T1–T2 patterns of the adsorbed, irreducible, and movable oils were reported, and these patterns can directly reveal the states of oil micro-occurrence in shale pore-fracture systems. This study gives substantial insights into the oil occurrence mechanisms in nanoporous shales.

Experimental Study on EOR in Shale Oil Cores during Associated Gasflooding: A Case Study from Yanchang Formation, Ordos Basin

Summary A significant amount of associated gas has been produced from shale oil reservoirs in the Ordos Basin, northern China, in recent years, which has provided an opportunity for using low-cost, associated gas in enhanced oil recovery (EOR) projects. However, there are few other reports of EOR projects in shale oil reservoirs using associated gas, and a quantitative evaluation of the technique is needed. Therefore, we conducted associated gas and waterflooding experiments in shale oil samples at constant and gradually increasing injection pressure while monitoring the spatial distribution of movable and residual oil by means of nuclear magnetic resonance (NMR) technology. Before the injection experiments, we performed mercury intrusion tests and measured the NMR transverse relaxation time, T2, of fully saturated samples to characterize the pore-throat size distribution of rock samples. Furthermore, we established a novel and robust mathematical model based on a fractal description of the pore space and a capillary tube model to determine the lower limit of the pore radius of movable oil, rc, during gas- and waterflooding. We observed that the oil recovery factor at a low injection pressure (i.e., 0.6 MPa) during the associated gasflooding was lower than that during waterflooding under both constant pressure injection mode and gradually increasing pressure injection mode. However, the performance of associated gasflooding was greatly improved by increasing the injection pressure. High injection pressure indeed produced a higher oil recovery factor, thinner residual oil film thickness, and smaller rc during associated gasflooding than during waterflooding under both injection modes. These differences in behavior appear to be linked to dissimilarities in flooding mechanisms at high and low injection pressures. Our main conclusion is that associated gasflooding at high injection pressure (i.e., 6 MPa) has a better potential for enhancing the oil recovery factor than waterflooding in shale oil reservoirs.

Oil Mobility Evaluation of Fine-Grained Sedimentary Rocks with High Heterogeneity: A Case Study of the Lucaogou Formation in the Jimusar Sag, Junggar Basin, NW China

The oil mobility in unconventional tight/shale oil reservoirs is complex because of the high heterogeneity in the matrix pore structure and connectivity. Thus, it is difficult to evaluate hydrocarbon exploration potential precisely. In this study, multistep temperature pyrolysis (MTP) Rock-Eval and 1D (dimensional) as well as 2D nuclear magnetic resonance (NMR) techniques were employed to systematically characterize the oil mobility in lacustrine fine-grained sedimentary rocks from the Lucaogou Formation in the Jimusar Sag, Junggar Basin, NW China. The results show that the Lucaogou Formation fine-grained sedimentary rocks can be subdivided into six types of lithofacies. With the increase of organic matter richness, the content of adsorbed oil increases, whereas the content of movable oil increases first and tends to stabilize (when total organic carbon (TOC) > 4%). This is because when TOC is low, the fine-grained sedimentary rocks need to self-adsorb before oil production; when TOC increases further, the generated oil will break through the absorption limit and charge into the adjacent reservoirs; therefore, the movable oil ceases to increase. Permeability is found to have a greater impact on movable fluid saturation than porosity. Meanwhile, good throat radius and pore connectivity are conducive to oil flow as movable oil is more sensitive to throats rather than pores. Furthermore, a higher content of brittle minerals is not necessarily favorable for oil flow; alternatively, more clay minerals are easy to from cements causing pore blockage, which will essentially hinder oil mobility. Overall, the organic matter content, reservoir pore structure, and rock mineral composition are the main factors affecting tight/shale oil mobility. On the basis of the above research, a conceptual model of oil mobility in different lithofacies’ reservoirs is established. These results have a reference significance for evaluating oil recoverability in fine-grained sedimentary rocks.

Oil occurrence state and quantity in alkaline lacustrine shale using a high-frequency NMR technique

Complex fluid occurrence states and structures of shale reservoirs greatly affect shale oil productivity. For lacustrine shales with strong heterogeneity, it is important to identify oil movability, occurrence states and pore structures in different lithofacies in order to efficiently develop shale oil. This study combines conventional core analysis, X-ray diffraction (XRD), argon ion milled-scanning electron microscopy (AIM-SEM), multiple isothermal stages (MIS) pyrolysis and high-frequency nuclear magnetic resonance (HF-NMR) to create maps for samples in native, saturated, centrifuged, and dried states. A new T1-T2 map interpretation scheme is proposed, and fluid occurrence models for different shale lithofacies are established. Four oil species can be identified on the T1-T2 map. Free oil and adsorbed oil in macropores are located in the centers and edges of intergranular/intercrystalline pores, respectively. Oil in mesopores is located in intragranular/intracrystalline dissolution pores. Adsorbed oil exists in the pores of dispersed organic matter and in the marginal fractures of organic matter laminae. NMR and pyrolysis correlate well in the oil contents that they define. The occurrence state of shale oil in the Fengcheng Fm is closely related to minerals and organic matter. Siliceous minerals are beneficial to the occurrence of free oil that is usually a highly movable. The fluid-holding capacity of calcareous shale is limited, especially for adsorbed oil and restricted oil. Clay minerals (>10%) are not conducive to shale oil enrichment and flow, and mixed shale almost exclusively contains bound water. Organic matter is conducive to increasing oil content and to the movable oil saturation of siliceous shale and mixed shale.

Geochemistry of an unconventional, saline lacustrine petroleum system: Dongpu depression, Bohai Bay Basin, China

Inter-salt shales are both important organic-rich sediments and shale oil exploration targets. This paper examines the controls on the composition of retained fluids in an inter-salt lacustrine shale oil system based on geochemical analysis of 125 samples with vitrinite reflectances of approximately 0.9% Ro from a 50 m shale-rich sequence between two evaporites. Core samples were immediately stored at −50 °C to reduce the evaporative loss of hydrocarbons. The sequence is highly heterogeneous and includes siltstone, argillaceous mudstone, calcareous mudstone, dolomitic mudstone, and argillaceous dolomite. Source rock samples with higher TOC contents (>1.0 wt%) and higher genetic potentials (S1 + S2 > 2.0 mg HC/g rock) are typically calcareous mudstone, dolomitic mudstone, and argillaceous dolomite, and contain predominantly type II kerogen. Salinity controlled both bottom water deoxygenation and the development of carbonate minerals, and the increase in aquatic organisms (including prokaryotes and eukaryotes) leads to a positive relationship between OM richness and quality. High TOC (>2.0 wt%) samples contain oil-prone kerogens and have high absolute contents of liquid hydrocarbons (S1-1 > 0.2 mg HC/g rock, S1-2 > 1.0 mg HC/g rock), and high relative contents of liquid hydrocarbons [(S1-1 + S1-2)/(S1-1 + S1-2 + S2-1) > 0.45]. The amount of oil retained in source rock horizons is mainly controlled by the sorptive properties of the solid phase organic matter. Oils (S1) within siltstones are derived from adjacent source intervals; multi-stage temperature pyrolysis shows that they are lighter – and thus more readily produced - than the oils retained within the source intervals. Although the absolute amounts of oil in siltstones are lower than those in the source intervals, a smaller fraction is sorbed on solid phase organic matter, so that there are similar amounts of moveable oil in siltstones and source rocks. Interbedded siltstones, organic-rich calcareous mudstones, dolomitic mudstones, and argillaceous dolomites are all favourable intervals for inter-salt shale oil development.

Pore system classification of Jurassic Da’anzhai Member Lacustrine Shale: Insight from pore fluid distribution

Lacustrine shale oil has the potential to lead the development of China's oil and gas industry. By integrating scanning electron microscopy, low-temperature CO2 and N2 adsorption, high-pressure mercury intrusion, and nuclear magnetic resonance with centrifugation at different speeds, the pore system and pore fluid distribution of Da’anzhai Member lacustrine shale in the Sichuan Basin are studied. The results show that: (1) The reservoir space is mainly inorganic pores and micro-fractures. Nano-micron scale pores are commonly found and widely distributed in the Da’anzhai shale with multiple peaks of 28 nm, 200 nm, 900 nm, and 3.5 µm. The total pore volume ranges from 0.00849 to 0.02808 cm³/g, and the pores ranging from 100 nm to 1000 nm are the main contributors to total pore volume. (2) Pore fluid can be divided into movable oil, bound oil, and adsorption oil. The proportion of movable oil, bound oil, and adsorbed oil is 21.4%, 12.4%, and 66.2% in Da’anzhai shale, respectively. Movable oil mainly occurs in pores larger than 350 nm, bound oil is 30–350 nm, while adsorbed oil mainly exists in pores below 30 nm. (3) The higher the total organic carbon content and clay minerals content, the smaller the pore size, resulting in the low content of movable oil. The higher the content of brittle minerals such as quartz, the better the development of intergranular pores and microfractures, and the higher the content of movable oil. Through the grading evaluation of shale pore structure and pore fluid, it is conducive to guide the exploration and development of Da’anzhai shale oil, which has important theoretical and practical significance.

Nuclear magnetic resonance response characteristics and quantitative evaluation method of fluid saturation of lacustrine shale oil

The quantitative evaluation of fluid saturation is important for formation evaluation of shale oil. However, there is currently no effective method to identify the fluid occurrence state and quantitative evaluate the fluid saturation of lacustrine shale oil because of the complexity of diagenetic minerals and pore types. In this paper, a method is proposed for the quantitative evaluation of fluid saturation based on nuclear magnetic resonance (NMR), X-ray diffraction (XRD) and scanning electron microscopy (SEM) measurements for shale samples of Fengcheng Formation, Mahu sag in Junggar Basin, China. These studies revealed that the shale oil rocks mainly contain quartz, feldspar, dolomite, calcite and clay minerals, both develop organic and inorganic pores. The fluids mainly occur in the form of bitumen, clay bound water, bound water, bound oil and movable oil in this study area. Based on the findings from these experiments, a mixed rock index (MI) and mud index (SI) were proposed to divide the shale oil formations into three types, including sand shale, dolomitic shale and mudstone. A T1−T2 2D NMR fluid occurrence state characterization map was established to identify the different fluids by the MI, SI and NMR characteristics. Furthermore, a method was proposed to quantitatively calculate the coefficient distribution of bound and movable fluids for shale oil in different formations. Finally, the proposed method was successfully applied into the lacustrine shale oil in the Fengcheng Formation to identify fluid occurrence state and evaluate fluid saturation quantitatively.

Oil Mobility of Low-Mature Lacustrine Shale and Controlling Factors: A Case Study from the Upper Cretaceous Nenjiang Formation, Gulong Sag, in the Songliao Basin

Producing low-mature shale oil resource is becoming economically available as in situ organic matter or heavy oil conversion technologies are introduced to shale oil production. However, we still lack suitable evaluation parameters and criteria for characterizing oil content and mobility in low-mature shales, which are very important for low-mature shale oil economic production. With the aim to better understand the influence factors for low-mature shale oil content and mobility, 16 shale core samples were collected from low-mature Upper Cretaceous Nenjiang Formation (K2n), Gulong Sag, in the Songliao Basin, to investigate their mineral composition and organic geochemical and pore characteristics. The results show the following: (1) Four shale lithofacies were identified, such as mudstone, carbonate lamina shale, bioclastic shale, and mixed lamina shale. (2) Shale oil mobility [represented by the oil saturation index (OSI)] was mainly controlled by large-sized pore distribution. (3) Total organic carbon (TOC) content and lithofacies had great influence on the distribution of oil mobility in the shale. As for mudstone and bioclastic shale, TOC played the most important role in controlling shale oil mobility, whereas for carbonate lamina shale and mixed lamina shale, TOC and mineral variation both have impacts on oil mobility. (4) The average contents of TOC, S1, and OSI in K2n were higher than those in the deeper Qingshankou shale. The oil mobility controlling factors in K2n and K2qn were both TOC and preservation conditions. (5) A new index was proposed to weigh the content of shale oil, in situ OSI, and multiple isothermal pyrolysis parameter S2-2. The in situ OSI shows that K2n has high oil retention capacity, and the in situ oil mobility is 2–3 times the movable oil content.

The Occurrence Mechanism of Lacustrine Shale Oil in the Second Member of the Paleogene Kongdian Formation, Cangdong Sag, Bohai Bay Basin

The lacustrine shale in the second member of the Kongdian Formation (Ek2) is the most significant target of shale oil exploration in the Cangdong Sag, Bohai Bay Basin, China. To investigate the occurrence mechanisms and to reveal the influencing factors of shale oil mobility in Ek2, a series of analyses (X-ray diffraction (XRD), field emission scanning electron microscopy (FE-SEM), total organic carbon (TOC) analysis, Rock-Eval pyrolysis, low-temperature nitrogen physisorption (LNP), mercury intrusion porosimetry (MIP), and multiple isothermal stage (MIS) pyrolysis) were conducted on samples collected from well cores in the Cangdong Sag. The results show that the lithofacies can be categorized as laminated felsic shales, laminated and massive mixed shales, and laminated and massive carbonate shales. The shales were characterized by a high organic matter abundance and moderate thermal evolution with good to excellent hydrocarbon generation potential and contained a high abundance of Type I and II1 kerogens. Laminated felsic shales and laminated mixed shales, compared with other lithofacies, had clear advantages in the amount of free hydrocarbon that can be volatilized from the rock (S1), the oil saturation index (OSI) value, and the free oil and movable oil content. LNP, MIP, and MIS pyrolysis analyses show that the residual shale oil mainly occurred in pores with diameters smaller than 200 nm, and the pore diameter when residual oil occurred in some laminated shale samples could reach 50 μm. The lower limits of the pore diameter where free oil and movable oil occurred were 7 and 30 nm, respectively. The mobility of shale oil is controlled by the shale oil component, thermal maturity, TOC content, and pore volume. The results herein provide a basis for the evaluation of optimal shale oil intervals.

The Geoscience Frontier of Gulong Shale Oil: Revealing the Role of Continental Shale from Oil Generation to Production

The clay mineral content of Daqing Gulong shale is in the range of about 35%–45%, with particle sizes less than 0.0039 mm. The horizontal fluidity of oil in Gulong shale is poor, with near-zero vertical flowability. As a result, Gulong shale has been considered to lack commercial value. In recent years, however, interdisciplinary research in geoscience, percolation mechanics, thermodynamics, and surface mechanics has demonstrated that Gulong shale oil has a high degree of maturity and a high residual hydrocarbon content. The expulsion efficiency of Gulong shale in the high mature stage is 32%–48%. Favorable storage spaces in Gulong shale include connecting pores and lamellar fractures developed between and within organic matter and clay mineral complexes. The shale oil mainly occurs in micro- and nano-pores, bedding fractures, and lamellar fractures, with a high gas–oil ratio and medium–high movable oil saturation. Gulong shale has the characteristics of high hardness, a high elastic modulus, and high fracture toughness. This study achieves breakthroughs in the exploration and development of Gulong shale, including the theories of hydrocarbon generation and accumulation, the technologies of mobility and fracturing, and recoverability. It confirms the major transition of Gulong shale from oil generation to oil production, which has extremely significant scientific value and application potential for China’s petroleum industry.

Experimental Study of Oxygen-Rich in Situ Combustion for Heavy Oil Recovery

The in-situ combustion method is the commonly used method for heavy oil production with high recovery rate and low cost. However, the characteristics of the oil oxidation reaction during in-situ combustion are still not clearly understood so far. In this study, the thermal oxidation experiment was carried out for the in-situ combustion process based on the heavy oil from Du 66 block. The results show that: the fired oil zone can be divided into the combustion zone, the coking zone, the condensation zone, the movable oil zone, etc. When the combustion front is formed, the CO2 and CO contents rise to 10% and 20%, respectively. In the expansion phase of the combustion front, the oxygen utilization rate is 83.93%, and the H/C atomic ratio is 1.413, indicating that the high temperature oxidation reaction plays the leading role. Sustained gas injection with enough intensity can ensure that the combustion front moves forward continuously, and the combustion front can drive the crude oil forward in the form of snowballing due to the extremely high oil displacement efficiency. The pressure increases as the combustion front and the movable oil zone advance, but the movable oil zone begins to decrease as it advances to the production well. Through this study, it is concluded that effective combustion front and movement of combustion front are the foundation for the formation of movable oil zone. And the movable oil zone pressurization is an important mechanism for in-situ combustion. The findings of this study can help for better understanding of the in-situ combustion oxidation mechanism and can improve the production design for heavy oil reservoirs.

Multi-probe low-frequency induction log and high-frequency induction log if the reservoir contains the low resistivity annulus zone

A low resistivity annulus appearing near the well due to reservoir fluid displacement by mud filtrate is a reliable indicator of movable oil presence in the reservoir. In practical cases estimation of low resistivity annulus parameters is possible based on high-frequency induction logging data analysis. When interpreting practical data of other resistivity logging methods its influence on signals is usually not taken into account. The paper discusses the results of the 5IK and VIKIZ logs numerical simulation which substantiate the possibility of identifying low resistivity annulus according to multi-probe low-frequency induction logging in geoelectric conditions typical for the Cretaceous mixed-saturation reservoirs of the Imilorskoye oilfield.

Occurrence characteristics and influential factors of movable oil in nano-pores by molecular dynamics simulation

CO2-enhanced oil recovery (CO2-EOR) technology has shown great application potential in the development of tight reservoirs. Since the proportion of nano-pores in tight oil reservoirs exceeds 77%, it is necessary to further study the occurrence state of crude oil in nano-pores. In this paper, the molecular dynamics simulation was applied to study the adsorption and diffusion behaviors of multi-component crude oil in quartz (hydrophilic) nano-pores. Besides, the density discretization method was used to investigate the occurrence characteristics of crude oil, the proportion of movable fluid in nano-pores, and the effects of CO2 and polar molecules (C3H6O) on the adsorption characteristics of crude oil. The simulation results showed that the adsorption state of crude oil in the quartz nano-pores was in the form of 4 adsorption layers with a thickness of 0.45 nm each. In nano-pores, the oil molecules with longer molecular chains were more likely to aggregate and adsorb on the quartz surface. Among them, polar oil molecules have the strongest adsorption capacity on the quartz surface. Moreover, the crude oil potential energy and the self-diffusion coefficient gradually increased from the vicinity of the quartz wall and tended to be stable in the free layer. Meanwhile, the content of movable crude oil gradually augmented with the increasement of nanometer pore width and temperature. Furthermore, the pressure had little effect on the density distribution of crude oil in the pores. In contrast, the temperature had a more significant effect on the density distribution of the adsorption layer. At last, due to the more substantial adsorption capacity of CO2 on the rock surface, the crude oil adsorbed initially on the rock surface would be stripped off by CO2, converting from irreducible oil to moveable oil.

A new method for characterizing dynamic reservoir quality: Implications for quality maps in reservoir simulation and rock type classification

Determining reservoir quality is vital in order to efficiently produce hydrocarbon and/or inject fluids for secondary/tertiary recovery and carbon sequestration. In this study, we introduce a new approach and present dynamic reservoir quality index (DRQI). A high-quality reservoir would have high displacement (recovery) rate and displaceable (recoverable) saturation of oil. A modified true effective mobility (TEM) function is developed representing displacement rate of oil by an injected fluid (e.g., water or CO2). DRQI is defined as the area under modified TEM curve of oil and includes the well-known reservoir quality index (RQI) as its special case. A large dataset composed of 220 water displacing oil relative permeability experiments, conducted on limestone and dolomite rocks from three Iranian carbonate reservoirs, was used to investigate the potential relationships between DRQI and other reservoir characteristics (e.g., irreducible water saturation, bulk irreducible water, maximum movable oil saturation, and bulk maximum movable oil) as well as quality indicators of RQI, flow zone indicator (FZI), and Winland r35. Results showed that irreducible water saturation and maximum movable oil saturation as well as their bulk variants may not be appropriate for characterizing multiphase quality of reservoirs. Furthermore, the frequently-used single-phase rock quality indicators RQI, FZI, and Winland r35 were not found to be very accurate in characterization of dynamic reservoir quality. DRQI can be used in reservoir simulation studies as a criterion for defining quality maps, and in petrophysical tasks for rock typing and comparing between dynamic qualities (in terms of displacement rate and displaceable saturation of oil) of rock samples.

Geological characteristics and shale oil potential of alkaline lacustrine source rock in Fengcheng Formation of the Mahu Sag, Junggar Basin, Western China

Shale oil is the main field of unconventional hydrocarbon exploration and exploitation. Additionally, deep (>4500 m) petroleum exploration in sedimentary basins is a worldwide frontier topic. The Fengcheng Formation in the Junggar Basin is deeply buried and formed in the special sedimentary environment of alkaline lakes. Studying this set of source rocks will provide insights into the deep unconventional hydrocarbon exploration in other basins with similar geologic settings worldwide. Therefore, this research takes Fengcheng shale as the object to systematically analyze the geochemical characteristics, reservoir quality, and shale oil resources’ potential based on total organic carbon (TOC), Rock-Eval pyrolysis, vitrinite reflectance (Ro), X-ray diffraction (XRD), field emission-scanning electron microscopy (FE-SEM), and other experimental methods.The Fengcheng shale has moderate organic matter abundance (0.5%–2.0%) and high hydrocarbon generation potential (averaging 3.95 mg/g). The shale is mainly comprised of type II kerogen, which can easily generate oil. Meanwhile, the source rock has reached the mature to high-mature thermal evolution stage. The mineral composition reveals the shale of Fengcheng Formation mainly contains higher values of carbonate minerals and lower quantities of clay minerals. Shale has poor physical properties, with porosity ranging from 1.0 to 12.0% (3.37% on average) and permeability generally lower than 0.1mD. However, the Fengcheng shale has a significantly higher brittleness than the North American marine shales and has good conditions for hydraulic fracturing. The pores developed in the shale are mainly intergranular, micro-fractures, and intragranular pores, while organic pores are rare. Generally, the hydrocarbon of the shale mainly exists in inorganic pores. Fractures are well developed in shale, and many micro-fractures and macro-fractures can be seen in the core. These fractures are important for hydrocarbons migration and accumulation. The shale oil saturation index OSI and S1 show that despite the migration of some hydrocarbons from the source rocks of the Fengcheng Formation, a large amount of crude oil is still retained, and a considerable part of the shale oil is movable oil. It indicates that Fengcheng shale is rich in shale oil resources and is a favorable target for shale oil exploration and exploitation.