Introduction
With the progress in global oil and gas exploration, onshore deep to ultra-deep strata have become one of the important exploration fields. Formations at 4 000 m to 6 000 m or 4 500 m to 6 000 m are commonly called deep layers, and those at 6 000 m to 9 000 m are called ultra-deep layers [1⇓-3]. Searching reservoirs with relatively higher porosity and permeability in a low-porosity and low-permeability setting is a hot spot and challenge for hydrocarbon exploration of deep to ultra-deep formations[4-5]. Previous studies claimed that deep and ultra-deep clastic reservoirs have been through historically geothermal temperature and effective stress higher than those on medium to shallow reservoirs. In such cases, most of primary inter-granular pores cannot be preserved, which leads to low porosity and low permeability and the predominance of dissolved pores and fractures as reservoir space [6⇓⇓⇓-10]. As hydrocarbon exploration constantly advances toward deeper formations in recent years, high-quality clastic reservoirs with predominant primary pores have been discovered successively [11-12].
Braided river delta front sand bodies are developed in the first and second members of the Paleogene Oligocene Linhe Formation (called Lin-I and Lin-II, respectively) in the Linhe Depression in the Hetao Basin. Since 2020, high-production oil flows have been obtained from deep and ultra-deep reservoirs of Lin-II to Lin-I. The highest open-flow oil production is 523 m3/d from deep reservoirs, and that from ultra-deep reservoirs is up to 1 285.77 m3/d during well test. At deep sandstone reservoirs below 4 500 m, the maximum porosity is 29.2%, and the maximum permeability is 2 550×10-3 μm2. At ultra-deep sandstone reservoirs below 6 000 m, the porosity and permeability may reach 18.2% and 42.9×10-3 μm2, respectively. Moreover, thin-section petrographic analysis reveals the predominance of primary inter-granular pores in both types of reservoirs. The deep and ultra-deep reservoirs of the Paleogene Linhe Formation in the Linhe Depression present the physical properties (porosity and permeability) much superior to those of the Paleogene in the Bohai Bay Basin of East China, which is also a Cenozoic graben basin. The genesis and control factors of the high-quality reservoirs have become an important scientific focus. More studies have been carried out on the sedimentary facies, hydrocarbon sources and hydrocarbon accumulation history of the Linhe Formation, but less on the genesis of the deep high-porosity reservoir, the causes of the differentiation of the reservoir physical properties and the control factors of high-quality reservoirs [13⇓-15]. This work investigates the basic reservoir characteristics, the causes for high primary porosity and different physical properties of deep reservoirs and the control factors on high-quality reservoirs based on cores, drilling and well logging data, and rock and mineral tests and analysis. The findings are expected to provide technical supports for selecting future exploration targets and evaluation and prediction of deep and ultra-deep clastic reservoirs.
1. Geological setting
Located in the northwestern margin of the Ordos Basin, the Hetao Basin is like an arc distributed among the Bayanwula Mountain-Langshan Mountain structural belt, the Helan Mountains structural belt, the Yinshan Moun-tains fold zone and the Yimeng Uplift, and covers an area of about 4×104 km2 [13⇓-15] (Fig. 1a ). The Linhe Depression located in the southwestern Hetao Basin is a major hydrocarbon-bearing area. It is divided into the southern Jilantai Sag, the middle Dengkou low bulge and the northern Bayannur Sag (Fig. 1b ). Regionally, the depression dips northwestward and on a cross-sectional view, there are slopes and sags from southeast to northwest [13]. From the bottom to the top, formations in the Linhe Depression are the Lower Cretaceous Lisangou and Guyang formations, Eocene Wulate Formation, Oligocene Linhe Formation, Miocene Wuyuan Formation, Pliocene Wu-lantuke Formation and Quaternary Hetao Group [13⇓-15]. The Linhe Formation is specifically divided into three members, and the Lin-I and II Members are primary oil-bearing layers (Fig. 1c ). In addition, the Lin-II Member can be sub-divided into the upper and lower sub-members. The deposition of the lower sub-member of the Lin-II Member and the Lin-I Member was associated with a high source supply in the sedimentary background of a saline lake basin, resulting in a large-scale distal braided river delta system characterized by sandstone fully filled and interbeds of sandstone and mudstone in the depression [13]. The upper sub-member of the Lin-II Member was deposited when the lake basin was in the peak with a low source supply, so extensive high-quality source rocks were developed in the saline lake basin. Furthermore, the overlying Neogene Wuyuan Formation is ultra-thick mudstone that acts as a regional caprock. To sum up, the Linhe Formation is associated with excellent conditions for a source-reservoir-cap rock assemblage.
Fig. 1. Location of the Linhe Depression in the Hetao Basin (a), tectonic units (b) and composite stratigraphic column of the Paleogene Lin-II to Lin-I members (c) (modified from Reference [13]). |
2. Basic reservoir characteristics
2.1. Petrologic characteristics
The Oligocene Linhe Formation reservoir in the Linhe Depression is mainly quartz-rich sandstone, including feldspar-quartz sandstone, lithic quartz sandstone, lithic feldspar sandstone and feldspar lithic sandstone. The reservoir has high compositional maturity and abundant quartz. The average and maximum contents of quartz are 72% and 88%, respectively, and those of feldspar are 16% and 28%, respectively. The average content of lithics is 12%, and the lithics are predominantly quartzite and granitic gneiss with abundant quartz. The average total content of quartz, feldspar and rigid lithics amounts to 90%. The total interstitial materials of the reservoir account for, in most cases, less than 5%, and the content may be higher in some local locations. The interstitial materials are mostly mud matrix, calcite, dolomite and anhydrite, which account for more than 95% of the total.
The sandstone grains are fine, well sorted (the sorting coefficient of 1.3-1.7) and medium round. The reservoir is grain-supported. Medium-fine sandstone and fine sandstone are dominant, followed by inequigranular sandstone and siltstone. The medium-fine and fine sandstones have a low content of mud matrix, a low content of cements (possibly high in local zones) and the best physical properties. The inequigranular sandstone generally has abundant mud matrix and relatively inferior physical properties. The siltstone generally has abundant cements and inferior physical properties. In summary, the Linhe Formation sandstone reservoir is characterized by “three highs and one low”, namely a high content of rigid grains, high compositional maturity, high textural maturity and a low content of interstitial materials.
2.2. Reservoir space and physical properties
Casting thin section and scanning electron microscope (SEM) analyses show that the reservoir space is dominated by primary inter-granular pores that account for more than 95%, despite the Lin-II to Lin-I members are almost below 4 000 m (Fig. 2a-2g ). A high linear correlation is found between the porosity and permeability of the reservoir (Fig. 3a ). It is indicated that primary pores are flow channels in the reservoir.
Fig. 2. Reservoir space and diagenetic characteristics of sandstone reservoirs of the Paleogene Linhe Formation in the Linhe Depression. (a) Medium-fine sandstone with well-developed primary inter-granular pores, weak compaction, point-line contact among grains; 5 676.81 m; Well XH111; casting thin section; (b) fine sandstone with well-developed primary inter-granular pores, weak compaction, point-line contact among grains; 4 986.53 m; Well XH12-2; casting thin section; (c) fine sandstone with well-developed primary inter-granular pores, weak compaction, point-line contact among grains; 6 037.00 m; Well HT1; casting thin section; (d) medium-fine sandstone with well-developed primary inter-granular pores, weak compaction, point-line contact among grains; 6 195.00 m; Well HT1; casting thin section; (e) fine sandstone with well-developed primary inter-granular pores; 4 239.50 m; Well XH1; SEM; (f) medium sandstone with calcite on grain edges; 4 416.95 m; Well XH1-2; casting thin section; (g) fine sandstone with pores partially filled with calcite clusters; 4 302.31 m; Well XH1-2; casting thin section; (h) fine sandstone with inter-granular fillings of micritic dolomite; 5 680.50 m; Well XH111; casting thin section. |
Fig. 3. Physical properties of sandstone reservoir cores of the Linhe Formation (N is the number of samples). |
Statistics of porosity and permeability measurements of 1 023 cores from 16 wells reveal that the porosity of the Linhe Formation reservoir is mostly 10%-25%, with an average of 17.3% and the maximum of 29.2%; and the permeability is mostly (10-1 000)×10-3 μm2, with an average of 194.7×10-3 μm2 and the maximum of 2 550×10-3 μm2 (Fig. 3b , 3c ). According to the industrial standard (i.e., Evaluating Methods of Oil and Gas Reservoirs) [16], the reservoir is classified into a medium-high-porosity and medium-high-permeability reservoir. The deep reservoir with the maximum porosity and permeability (29.2% and 2 550×10-3 μm2, respectively) is identified as a high-porosity high-permeability reservoir. The ultra-deep reservoir with the maximum porosity and permeability (18.3% and 42.9×10-3 μm2, respectively) (Fig. 3d , 3e ) is rated as a medium-porosity medium-permeability reservoir. In addition, low-ultra-low-porosity and low-ultra- low-permeability reservoir is found in the Linhe Formation, which is mostly sandstone with abundant cements or mud matrix. In general, from south to north, the Linhe Formation contains large-scale high-quality reservoirs with medium-high porosity and medium-high permeability and primary pores in the Linhe Depression.
2.3. Diagenesis
The deepest core of the Linhe Formation was taken at about 6 200 m. The diagenesis of the Linhe Formation in the study area is characterized by deep burial, low compaction and cementation, and locally high compaction and cementation. Casting thin sections and SEM images demonstrate that lost primary pores are mainly attributed to compaction and cementation. Dissolution is weak, and compresso-solution, re-crystallization or metasomatism is almost zero.
2.3.1. Compaction
The whole process of the burial evolution of the Linhe Formation reservoir was associated with compaction, and it is the largest diagenetic contributor to the loss of pri-mary pores. The compaction of the Linhe Formation sandstone is gradual with increasing burial depth. In the process, grains were re-arranged into tight and stable packs. The inequigranular sandstone with a high mud matrix content is featured by compacted deformation of mud matrix. The cored depth of the Linhe Formation is 4 000-6 200 m. The overall compaction of the reservoir is low (Fig. 3d , 3e ). Point-line contact among grains is dominant. Some grains are “floating”. Almost no concave-convex contact was observed (Fig. 2a-2g ). Reservoir slices taken at about 6100 m show a plenty of primary pores (Fig. 2c , 2d ) which contribute to the measured porosity of 18.2%. Reservoir slices taken at 4 000-6 200 m indicate the compaction-induced relative loss of primary pores is mostly 8%-20%, and 14% on average. In the severe area, the relative loss of primary pores caused by compaction is 30% to 55%, and averaged about 40%, revealing compaction is generally low (Fig. 4 ). Compaction is different on different lithology. On the inequigranular sandstone with a high mud matrix content and less sortable, the compaction effect is high, so that mud matrix and finer grains were squeezed into the space among coarser grains, reducing the porosity. On the medium-fine and fine sandstone with a low mud matrix content and better sortable, the compaction effect is weak, and grains are in point-line contact, so inter-granular pores were largely preserved. In the cemented sandstone, grains are in point contact or “floating”, the compaction effect is low, suggesting that early cements effectively suppressed later compaction. The measured pressure coefficient is 0.93-1.10 in the Linhe Formation in the slope zone, indicating a normal pressure system, and that in the sag zone is 1.54-1.56, indicating an overpressure system. Hydrocarbon generation is the main cause for the overpressure in the Linhe Formation mudstone in the Naoxi subsag belt, and the reservoir is over-pressurized via overpressure transfer [13]. In Well XH1, the homogenization temperature of the brine inclusion in the Linhe Formation reservoir at 5 078.40 m is mainly 130 °C to 140 °C, and the brine inclusions are of the same stage of oil inclusions. This together with the burial-thermal history suggests that hydrocarbon accumulation in the Linhe Formation started at 3 Ma and has been lasting to now. Therefore, the overpressure inside the Linhe Formation reservoir should be later than 3 Ma and weakly affected reservoir compaction. Comprehensive analysis demonstrates that the Linhe Formation reservoir has a high content of rigid grains and it is better sortable and round, and the compositional and textural maturity is high, so the reservoir is strong to resist compaction. According to the measured temperature and homogenization temperature of brine inclusions, the geothermal gradient is mainly (2.0-2.6) °C/100 m, with an average of 2.3 °C/100 m. The low geothermal gradient reduced the compaction-induced porosity rate. As suggested by the burial history, the Linhe Formation was shallower than 2 500 m for a long time before 5.3 Ma, and grew to the current depth in a rapid process and a rather short period. The prolonged early shallow-burial and late rapid deep-burial caused the reservoir to experience low temperature and low effective stress for a long time, and high temperature and high effective stress for a short time, consequently low compaction-induced porosity reduction.
Fig. 4. Porosity loss caused by compaction and cementation in the Linhe Formation reservoir (based on 201 samples). |
2.3.2. Cementation
During the Cenozoic, the Linhe Depression was a saline lake basin where cementation effect, another important diagenetic contributor to the loss of primary porosity of the Linhe Formation reservoir, was strong. Based on thin sections and 201 core samples from 13 wells, the cements in the Linhe Formation reservoir are mainly calcite (Fig. 2g ), dolomite (Fig. 2h ) and anhydrite, locally siliceous materials and authigenic clay minerals were found. Calcite, typically in a form of micritic or grouped crystals, fills in the inter-granular pores. Dolomite occupies inter-granular pores in forms of micritic, silty, or euhedral crystals. As for anhydrite, it generally fills in the inter-granular pores in a form of grouped crystals, point contact or floating, which suggests cementation took place with penecontemporaneous-early diagenesis. The volumetric fraction of cement is 0-28% and averaged 7%. The cementation-induced relative loss of primary porosity is mostly 0-40% and averaged 19% (Fig. 4 ). The overall cement content of the reservoir is low, but locally high. Cements were found in all sandstones with different grain sizes. Of them, inequigranular sandstone and siltstone have a higher content of cements. The tops, bottoms and edges of the sand bodies in thick and laterally stable underwater distributary channels and mouth bars are highly cemented, while the middle parts are weakly or hardly cemented. The cement content is high for thin beach bars, sheet sands and underwater distributary channels.
To sum up, different sandstones have different diagenetic features. The inequigranular sandstone with abundant mud matrix and experiencing intensive compaction and weak cementation, and the sandstone with abundant cement and experiencing weak compaction and intensive cementation have inferior physical properties. On the contrary, the sandstone with less interstitial materials and experiencing weak compaction and cementation presents superior physical properties and developed into high-quality deep-ultra-deep reservoir.
3. Genesis of deep and ultra-deep reservoirs with high porosity anomaly
Comprehensive consideration of reservoir material fabrics, diagenetic kinetics and diagenetic evolution demonstrates that it is the coupled effects of the material fabric basis with preexisting high compaction resistance, the weak thermal-compaction diagenetic kinetics featured by low geothermal gradient and prolonged shallow and late rapid deep burial, and the diagenetic environment of weak compaction and weak cementation caused by paleo-water salinization and salinity differentiation in the saline lake basin that created the high-quality deep and ultra-deep reservoirs with medium to high porosity in the Linhe Formation.
3.1. Strong compaction resistance of pre-existing material fabrics
The detrital composition and texture are the pre-existing material fabric basis for the diagenetic evolution of reservoir rocks, and they are the primary factor affecting the level of early mechanical compaction [17⇓⇓⇓-21]. Early mechanical compaction is mainly manifested as re-packing and plastic deformation of detrital grains. The Linhe Formation sandstone in the Linhe Depression is made of quartzite and metamorphic rocks of granitic gneiss with abundant rigid grains after long-distance transport and elutriation. It has high compositional and textural maturities and provides an important material fabric basis for the development of high-quality reservoir rock. The Linhe Formation sandstone has a high content of quartz which makes the reservoir have high resistance to compaction and low plastic deformation during compaction. Meanwhile, the sandstone grains are very sortable and round, so more inter-granular pores would be preserved when they were re-arranged into tight and stable packs. With similar burial depth and lithology, the compaction-induced porosity reduction is negatively related to the total volumetric fraction of rigid grains in the Linhe Formation reservoir. In other words, higher volumetric fraction of rigid grains leads to lower porosity reduction induced by compaction. On the contrary, the compaction-induced porosity reduction is positively related to the sorting coefficient. At similar burial depths, the well-sorted reservoir with a lower sorting coefficient is associated with lower compaction-induced porosity reduction. To sum up, a higher content of rigid detrital grains and good sorting facilitate high resistance to mechanical compaction and are favorable for the preservation of primary pores.
3.2. Weak thermal-compaction effect of telo-diagenetic kinetics
The diagenetic evolution of pores is affected jointly by geothermal field, burial model, fluid effect, and stress field witnessed by sandstone during the burial process. These factors comprehensively constitute the kinetic field of reservoir telo-diagenesis [17,19]. For the Oligocene Linhe Formation in the Linhe Depression, both dissolution and deep-burial cementation are weak, and the fluid effect on the diagenetic evolution of the reservoir pores is small. From the Linhe period to the Quaternary, the Linhe Depression was generally subjected to an extensional and subsiding setting, so the effect of the tectonic stress field on the reservoir was rather weak. Since the Quaternary, the basin has started strike-slip extension associated with a dominant compresso-shear tectonic stress. At that time, the reservoir had been deep, even ultra-deep, and its particles were tightly packed. The tectonic stress field had no considerable impact on reservoir compaction. The tectonic stress field and the overpressure caused by late hydrocarbon generation barely affected late compaction of the primary pores (below 2 000 m). The geothermal field and the burial model jointly created the late thermal-compaction diagenetic kinetics of the Linhe Formation reservoir, which is one of the control factors affecting the diagenetic evolution of the pores (in particular, the deep burial after the reservoir grains were compacted into tight and stable packs). In the area where the reservoir was less affected by tectonic stress and overpressure, the control factors on the preservation of the pores are temperature, geological age and burial model, such as the sandstone with certain compositional and textural maturities and buried at a certain depth. The joint effects of the above three factors can be characterized by a time-temperature index (It-t) whose mathematical definition is given in references [17⇓⇓-20]. This index is mainly controlled by geothermal parameter and thus, referred to as the thermal maturity of sandstone, representing the compaction intensity of sandstone [17⇓⇓-20]. The low geothermal gradient in the Linhe Depression and the burial model featured by prolonged shallow burial and late rapid deep burial of the Linhe Formation created the late thermal-compaction diagenetic kinetics. It is in favor of weak compaction, consequently a low It-t, low thermal maturity and low compaction-induced porosity reduction of the deep and ultra-deep reservoirs.
3.2.1. Low geothermal gradient suppresses compaction-induced porosity reduction
Geothermal field is a key factor controlling the diagenetic evolution of reservoir rocks. As the geothermal gradient increases, the water-rock interaction in sandstone is accelerated, and so is the mechanical compaction-the compaction rate in the area with a high geothermal-gradient is considerably higher than that in the area with a low geothermal gradient [18-19]. The current geothermal gradient of the Linhe Depression is (2.0-2.6) °C/100 m and averaged 2.3 °C/100 m (relatively low). The measured core porosity versus burial depth shows that the average vertical porosity reduction rate of the reservoir is (2%-3%)/1 000 m. It is low compaction-induced porosity reduction (Fig. 3d ). Based on the restored burial-thermal history (Fig. 5 ), the It-t of the Linhe Formation reservoir at variable burial depths can be calculated. The It-t is about 8 (Fig. 6 ) at 6 000 m. Moreover, the It-t presents a logarithmic correlation with the compaction-induced porosity reduction. Specifically, for the reservoirs with similar grain sizes, interstitial material contents and sorting coefficients, the increase in It-t is associated with the growth of the compaction-induced porosity reduction (Fig. 7 ). We simulated the correlation between It-t and depth in a setting with the similar burial model and lithology to the Linhe Formation reservoir, and found that at 3.0 °C/100 m and 3.5 °C/100 m, the It-t values are about 200 and 1 500, respectively, at 6 000 m. They are much higher than those of the Linhe Formation sandstone at the same burial depth. It-t versus depth and It-t versus compaction-induced porosity reduction illustrate that at the same depth, the reservoir in the area with a high geothermal gradient presents a It-t value higher than that in the area with a low geothermal gradient, and this higher It-t value is associated with higher compaction-induced porosity reduction. In the case of the low geothermal gradient of the Linhe Depression, deep and ultra-deep reservoirs generally have low It-t values, low thermal maturity and small compaction-induced porosity reduction.
Fig. 5. Burial evolution of the Linhe Formation in Well HT 1. E3l2—Oligocene Lin-II; E3l1—Oligocene Lin-I; N1w— Miocene Wuyuan Formation; N2w—Pliocene Wulantuke Formation; Q—Quaternary |
Fig. 6. Relationship between time-temperature index and depth of Linhe Formation sandstone. |
Fig. 7. Relationship between time-temperature index (It-t) and compaction-induced porosity reduction of Linhe Formation sandstone. |
3.2.2. Long-term shallow burial and short-term deep burial is helpful to preservation of reservoir pores
Burial model decides the diagenetic duration, burial depth and effective duration and intensity of a diagenetic environment on sandstone [17-18]. In the area with a rather uniform geothermal field, the burial model is the control factor on the diagenesis and pore evolution of the reservoir. If the strata are free from uplift and denudation, the burial models can be classified into prolonged early shallow burial-late rapid deep burial (called long-term shallow burial), gradual burial and early deep burial. With similar geothermal fields, the sandstones of the same age and lithology present different It-t values as they are buried to the same depth via different burial models. The sandstone after long-term shallow burial experiences long-term effects of low temperature and low effective stress, and short-term effects of high temperature and high effective stress. Therefore, it has the lowest It-t value. The It-t value of the gradually buried sandstone is higher, and that of the early deeply buried sandstone is the highest. The above conclusion suggests that the sandstone after long-term shallow burial has lower thermal maturity and weaker compaction, which help to preserve primary pores (Fig. 6 ). From south to north, the burial model of the Oligocene Linhe Formation in the Linhe Depression is long-term and shallow. The reservoirs were shallow than 2 500 m for a long time before 5 Ma, indicating a long effect duration of low temperature and low effective stress. Later, the burial depth rapidly exceeded 4 000 m in a short period, which represents a short effect duration of high temperature and high effective stress. The burial model resulted in the current low It-t value and small compaction-induced porosity reduction. The It-t value of the Linhe Formation reservoir at 4 000 to 7 500 m is 0.2 to 40.0 and corresponds to a predicted compaction-induced porosity reduction of 12% to 22%, indicating weak compaction.
3.3. Diagenetic environment with weak fluid compaction and weak cementation
3.3.1. Weak fluid compaction
Fluid compaction affects the compaction process by affecting the stability of framework grains [18]. A saline or alkaline lake basin usually experiences relatively intensive early cementation which is favorable for improving the resistance to framework compaction and suppressing fluid compaction [18]. The Linhe Formation was deposited in a saline lake basin where the early saline diagenetic fluids triggered localized early (and shallow) cementation, which is reflected at a micro scale, by continuous grains on the surface of the reservoir framework, or locally carbonate cements among the grains (Fig. 2f ). The eodiagenetic carbonate cements free from intensive diagenetic modification are relatively euhedral, and rhombus dolomite crystals observable among the grains. They can improve the compaction resistance to the framework. At a macro scale, strong cementation at the top, bottom and edge of the sandstone left a tight cement crust about 0.5 m thick (Fig. 8 ), which effectively mitigated the compaction inside the sandstone.
Fig. 8. Comprehensive column of reservoir cores of the Linhe Formation in Well XH111. |
3.3.2. Low cementation-induced porosity reduction in the area with low paleo-salinity
The Linhe Formation in the Linhe Depression was deposited in semi-saline to saline waters, and the paleo-salinity is different both laterally and vertically (Figs. 9 and 10 ). Across the depression, the paleo-salinity in the slope zone is lower than that in the sag zone. In the area with low paleo-salinity, the cementation intensity of the reservoir is generally low, but high locally. Generally, the cement content is low, despite locally high. Vertically, the paleo-salinity of the lower section of the Lin-II Member and the Lin-I Member with a higher sand-to-formation ratio is lower than that of the upper section of the Lin-II Member. Fine reservoir characterization shows that cementation is strong at the top and bottom of a thick sand body, while a thin sand body is, in most cases, relatively uniformly cemented (Fig. 8 ). Cementation differentiation at different positions in a thick sand body is related to the distance to the sand-mud interface. From the sand-mud interfaces at the top and bottom of a sand body to the middle of the sand body, the cementation intensity considerably drops. The cement content inside the sand body is therefore highly correlated to the distance to the sand-mud interface. A shorter distance means a high cement content (Fig. 11a ), and the total volumetric fraction of cement drops to below 3% and reaches a plateau, as the distance exceeds 2.5 m. Statistics shows the cement content in the middle of a sand body declines with the sand body thickness. The thicker the sand body, the cement content in the middle of the sand body is lower. In comparison, the cement content is higher in a whole thin sand body (Fig. 11b ). There are more thick sand bodies in the Linhe Formation. The sand bodies over 3 m thick each account for about 35%, 1-3 m for 50% and below 1 m less than 15%. So the Linhe Formation reservoirs experienced weak cementation and low cementation-induced porosity reduction.
Fig. 11. Cement content in different parts of a sand body, and sand body thickness vs. the cement content in the middle of a sand body in the Linhe Formation. |
4. Control factors and development of high-quality reservoir rocks
The Oligocene Linhe Formation in the Linhe Depression was developed into high-quality deep and ultra-deep reservoirs with medium to high porosity. However, the reservoirs at the same burial depth present different physical properties (superior and inferior) which are controlled by grain size, sorting and interstitial material content according to thin sections and properties analysis. Fine grains, poor sorting and more interstitial materials mean poor reservoir physical properties. Thin section observation demonstrates two types of interstitial materials, namely mud matrix and cement. The size and sorting of reservoir framework grains and mud matrix are mainly controlled by sedimentary hydrodynamics. The type and content of cement is mainly decided by the paleo-salinity of the saline lake basin and sand body thickness.
4.1. Control factors on high-quality reservoirs
4.1.1. Sedimentary hydrodynamics
Hydrodynamic conditions during deposition control the size, sorting and mud matrix content of clastic sediments and thus, affect later diagenesis and reservoir physical properties. In the Linhe Formation, the physical properties of the siltstone are the worst, those of the inequigranular sandstone are worse, and they become good from the fine sandstone to the medium-fine sandstone. As per core observation and thin section analysis, the siltstone with the worst physical properties is generally developed in thin sheet sands, at the bottom of mouth bars and top of underwater distributary channels under weak hydrodynamic conditions. These sediments have high mud matrix content and inferior original physical properties, and are prone to late cementation. The cement content is generally over 15% and the porosity is typically below 8.5%. The inequigranular sandstone is typically developed at the bottom and flank of underwater distributary channels, the flank of mouth bars and inter-distributary bays under weak hydrodynamics. The sediments are less sortable and contain abundant mud matrix generally 10%-30%. This results in low original porosity and detrital grains being prone to slide and re-arrange during burial compaction, which facilitates the intrusion of mud matrix and finer grains into the space among coarser grains and lost inter-granular pores. The compaction process is accelerated, and the deterioration of reservoir physical properties is exaggerated-the current porosity is generally 1%-15%. The better sortable fine sandstone and medium-fine sandstone generally occur in the main bodies of underwater distributary channels and mouth bars under relatively intensive hydrodynamics. In general, the content of interstitial materials is below 10%, and the porosity exceeds 15%, representing the best physical properties (Fig. 12 ).
Fig. 12. Comprehensive column of Lin-I cores taken in Well XH1. |
4.1.2. Paleo-salinity
Paleo-salinity controls the type and content of contemporaneous-eodiagenetic cements, and finally reservoir physical properties. The Linhe Formation mudstone interbedded with sandstone was deposited in saline waters with abundant ions like Ca2+, Fe2+, Mg2+, CO32−, SO42−. The higher the paleo-salinity, the more abundant the ions are. During the normal compaction on the mudstone in the contemporaneous-eodiagenetic phase, the pore pressure rose, and the solubilities of minerals such as carbonates and sulphates became large, too, consequently, plentiful ions entered formation water. As compaction proceeded, formation water flew into adjacent sandstone through the sand-mud interface and diffusion driven by pore pressure and concentration differences caused by compaction, and cements precipitated as zones at the top and bottom of the sandstone, which hindered the intrusion of high-concentration formation water from the mudstone into the sandstone during the meso-telo- diagenetic phase and therefore, resulting in low cementation in the middle of the thick sandstone. In a saline lake basin, the higher the paleo- salinity and the thicker the mudstone, the higher the salinity of the fluid enters the sandstone and the stronger the diffusion effect, consequently strong cementation and thick cementation zones on the sandstone. Vertically, from the bottom of the Lin-I Member and the top of the Lin-II Member toward the upper sub-member of the Lin-II Member, the lithological association is found with the thickening of dark mudstone (for both the cumulative and single-layer thicknesses) and increasing content of gypsum in mudstone. From the slope zone to the sag zone across the depression, the proportion and single-layer thickness of dark mudstone both grow, accompanied by the gradual growth of the gypsum content of mudstone. In addition, the gypsum layer in the upper sub-member of the Lin-II Member gradually thickens and even forms thick halite in the basin center. From the lower sub-member of the Lin-II Member to the Lin-I Member, the Sr/Ba ratio of the mudstone is characterized by the trend of first increasing and then decreasing, which indicates the overall “low-high-low” variation of the cement content of the sandstone reservoir and the “high-low-high” trend of the reservoir physical properties (Fig. 10 ). Laterally from the slope zone to the sag zone, the depression can be divided into low-salinity, medium-salinity, high-salinity and higher-salinity zones (Fig. 9 ), as per the lithology and authigenic mineral precipitates. In the low-salinity zone, the sandstone is featured by high cementation intensity, and the cements are mostly calcite and dolomite. In the medium-salinity zone, the cementation intensity of the sandstone slightly drops, and the cements are mostly calcite and dolomite, with some anhydrite. In the zone with high salinity, the sandstone is featured by medium cementation intensity, and the cements are predominated by anhydrite, calcite and dolomite. Finally, in the higher-salinity zone, the sandstone cementation intensity is high, and the cements are mainly anhydrite, halite and mirabilite. With increasing paleo-salinity, the total cement content in the sandstone gradually climbs up, and the cementation zones at the top and bottom of the sandstone thickens. Correspondingly, the reservoir physical properties become worse, and the predominant cements change from carbonates to anhydrite, halite and mirabilite.
Fig. 9. Paleowater salinity zones and sandstone cements in the Linhe Formation, Linhe Depression. |
Fig. 10. Comprehensive column of Lin-II and Lin-I members observed in Well XH1-2. |
4.1.3. Sand body thickness
The sand body thickness also affects the cement content of the reservoir and thus decides the reservoir physical properties. The top and bottom of the thick sand body are highly cemented, and the thin sand body is prone to overall cementation. With similar burial depths, lithologies and paleo-water salinities, the sand body thickness of the Linhe Formation is well correlated to the porosity of the middle part of the sand body (i.e., the middle porosity of the sand body). For a sand body less than 1 m thick, the middle porosity is generally below 8.5%. A sand body of 1-3 m thick has middle porosity of 8.5%-18.0%. A sand body of 3-5 m thick has middle porosity of 18% to 20%. A sand body over 5 m thick has middle porosity over 20%. To sum up, with increasing thickness, the middle porosity gradually grows until to a plateau (Fig. 13 ).
Fig. 13. Relationship between sand body thickness and middle porosity for Linhe Formation reservoirs. |
4.2. Development of high-quality reservoirs
Based on the analysis of control factors, burial evolution and paleo-water salinity, the diagenetic evolution of high-quality reservoirs of the Linhe Formation can be divided into three stages (Fig. 14 ).
Fig. 14. Reservoir formation and evolution of the Linhe Formation in the Linhe Depression, Hetao Basin. |
(1) Early rapid compaction-induced porosity reduction (23-30 Ma): The first stage was associated with the deposition of the Lin-I to Lin-II members. The water in the lake basin was salinized, and the basin was in a weak extensional fault depression with weak tectonic compression. Sediments were rapidly buried at 1 500 m to 2 000 m, and detrital grains were gradually compacted from loose to tight and point-contact. The inequigranular sandstone with abundant mud matrix experienced large compaction-induced porosity reduction due to its low compaction resistance, and the porosity at the end of this stage was below 15%. High-salinity fluid in the mudstone interbedded with sandstone flew into adjacent sandstone via diffusion and created cement-abundant sandstone zones at the top and bottom of the sandstone. At the end of this stage, the cement-abundant sandstone had porosity below 10%. The fine and medium-fine sandstones of the Linhe Formation had a fewer interstitial materials and higher compaction resistance. In addition, the locally-concentrated cements, though less in quantity, improved the compaction resistance. Therefore, inter-granular pores were largely preserved, and the porosity at the end of this stage was up to about 30%.
(2) Long-term shallow burial and weak compaction (5.3-23.0 Ma). The middle stage started a long-term shallow burial of the Lin-I to Lin-II members. At that time, the sedimentary basin was an extensional rifted basin with weak tectonic compression. The sediments were slowly buried at 2 500-3 000 m, and compaction became strong. Compaction on the sandstone with rich mud matrix was further intensified, resulting in compaction-induced porosity reduction, and the reservoir became more compacted and tighter so that the porosity dropped to below 10%. The cement-abundant sandstone was more densified by cementation of high-salinity diagenetic fluid, and the porosity fell to below 5%. At low formation temperature and low effective stress in the process of long-term shallow burial, the sandstone with a fewer interstitial materials and high compaction resistance suffered low porosity reduction. Moreover, the tight cement zones at the top and bottom of the sandstone prevented the intrusion of saline diagenetic fluid into the sand body, and suppressed the cementation effect. Therefore, the inter-granular pores were preserved and the porosity at the end of the middle stage was up to about 26%.
(3) Rapid deep burial and weak compaction (since 5.3 Ma to present). The basin gradually changed from intensively extensional Pliocene fault depression to Quaternary strike-slip extension, and the homogenization temperature of the brine inclusions at the same stage as the oil inclusions shows that hydrocarbon accumulation has started since 3 Ma. The Lin-II and Lin-I members were buried at 5 000-6 000 m rapidly in a short period of 3.0-5.3 Ma. Both the mud matrix-rich sandstone and the cement-rich sandstone became tight. Meanwhile, mechanical compaction on the sandstone with a fewer interstitial materials and rich rigid grains stopped. In the process of rapid deep burial, the reservoir was affected by high formation temperature and high effective stress only a short time, and the compaction-induced porosity reduction was low. In addition, the tight cemented zones at the top and bottom of the thick sand body can prevent saline fluid in the mudstone from entering the sandstone, and late cementation was weak, so that the porosity of the reservoir at the end of the last stage was up to about 22%. Hydrocarbon accumulation in the reservoirs with high porosity and high permeability has started since 3 Ma when they were quickly buried below 6 000 m. And late extensional strip-slip tectonic movement had only a minor influence on the reservoirs.
4.3. Distribution of high-quality reservoirs
High-quality Linhe Formation reservoirs are located at the main bodies of underwater distributary channels and mouth bars. They are thick and have high compositional and textural maturities. During the Linhe period, the hydrodynamics was weak laterally from the slope zone to the sag zone and vertically from the bottom of the Lin-I and the top of the Lin-II toward the middle of the two members. Correspondingly, the sand body became thin, the paleo-salinity became high, the cement content rose, the thickness limit for sand bodies prone to cementation climbed up, and the thickness percent of high-quality reservoirs declined. The deposition of the lower sub- member of the Lin-II Member and the Lin-I Member in the slope zone was associated with strong source supply. The two members are featured by high sand/formation ratio, thick single layers, low paleo salinity, and low cementation intensity. It is predicated that they are associated with large-scale development of high-quality reservoirs. In the sag zone, the sand/formation ratio is relatively low, the sand layer is thin (compared with that in the slope zone), and the paleo salinity is high, so cementation is a key factor affecting reservoir effectiveness. The sandstone reservoirs in the main body of the lower sub-member of the Lin-II Member and the Lin-I Member are expected to be high-quality hydrocarbon reservoirs with well-developed primary pores because they are thick and stable, and have abundant rigid grains that are sortable and round. In addition, cementation is weak in the middle, and they are close to the hydrocarbon generation center (Fig. 15 ).
Fig. 15. Vertical distribution of sandstone reservoirs in the Lin-II and Lin-I members (section location shown in |
5. Conclusions
The Linhe Formation reservoirs have rich quartz. Quartz, felspar and rigid lithics account for 90% in total. The reservoirs are featured by “three highs and one low”, namely a high content of rigid grains, high compositional maturity, high textural maturity and a low content of interstitial materials. Deep and ultra-deep reservoirs with primary pores, medium-high porosity and medium-high permeability are high-quality reservoirs.
The diagenesis of the Linhe Formation reservoirs is characterized by deep burial, globally weak compaction and cementation and locally strong compaction and cementation. Rich rigid grains and high compositional and textural maturities ensured the reservoirs a high resistance to compaction. Low geothermal gradient and long-term shallow burial and late rapid deep burial created weak compaction diagenetic kinetics, and imposed weak compaction on the reservoirs. Specifically, the low geothermal gradient reduced the compaction rate with depth, and the short-term high formation temperature and high effective stress in the process of long-term shallow burial and late rapid deep burial reduced compaction-induced porosity reduction. The saline water in the saline lake basin suppressed fluid compaction, and the lateral and vertical differentiation of paleo-salinity led to low cementation and low cementation-induced porosity reduction in the low-salinity zone. Ultimately, deep and ultra-deep reservoirs with primary pores were developed into good reservoirs with abnormally high porosity.
The fine and medium-fine sandstones in underwater distributary channels and mouth bars are better sortable and have fewer interstitial materials. They are expected to be high-quality reservoirs after deep burial and weak compaction. The cement content of the reservoir is controlled jointly by paleo-water salinity and sand body thickness. The content and types of cements are dependent on the vertical and planar differentiation of paleo-salinity, and cementation is low in the low-salinity zone. At the top and bottom of a thick sand body, cementation is high and the reservoir physical properties are poor, while cementation is weak and the physical properties become good in the middle of the thick sand body. Thin sand bodies are evenly cemented and tight. In the slope zone, the Lin-I Member and the lower sub-member of the Lin-II Member are featured by high sand/formation ratios, thick layers and low paleo-salinity. Correspondingly, the cementation-induced porosity reduction is low, and the reservoir physical properties are good. The Lin-I Member and the lower sub-member of the Lin-II Member are found with large-scale development of high-quality deep reservoirs. In the sag zone, the middle of the thick and stable sand bodies is less cemented and expected to have favorable ultra-deep reservoirs.
Nomenclature
GR—natural gamma, API;
It-t—time-temperature index, dimensionless;
Rlld—deep lateral resistivity, Ω·m;
SP—spontaneous potential, mV.