The application of basin modeling of oil and gas systems based on the capillary-gravity concept

ANNOTATION

Oil and gas reservoirs exhibiting low reservoir properties often have significant deviations in structure of hydrocarbon reservoirs they contain, based on anticlinal theory of oil and gas accumulation. First, these deviations are related to sharp fluctuations found in water-oil and water-gas interfaces and failure to subordinate the shape of deposits to structural factor. When dealing with such objects, geologists often have to assign unreasonable structural deflections, various impermeable seals of tectonic or sedimentary origin whose presence is not always confirmed by seismic and drilling data. The reason for such difficulties is that anticlinal theory does not consider capillary forces counteracting hydrocarbon migration to be key to reservoir formation. Any oil and gas reservoir is a multiphase pore system with countless contacts, both between different fluids and in host pore space. As per molecular physics laws, the major role in oil and gas water distribution in such systems is controlled primarily by capillary properties of the environment such as capillary pressure at water-oil interface, interfacial tension magnitude, pore channel radius and wetting behavior of solid phase. Due to capillary forces, sharp fluctuations at water-oil interfaces and significant shifts of oil and gas reservoirs relative to vaults of anticlinal structures are observed

KEYWORDS:

• Oil
• gas
• reservoir
• capillary pressure
• interfacial tension
• capillary barriers

Introduction

When dealing with oil and gas geology problems, geologists often encounter phenomena that contradict the generally accepted understanding of the conditions under which oil and gas deposits are formed. Very often these contradictions are associated with deviations in the structure of hydrocarbon reservoirs from the principles of anticlinal theory of oil and gas accumulation. This theory has been effectively applied for many years to the design of oil and gas exploration for geological targets of simple structure characterised by high reservoir properties. The anticlinal-gravity concept of oil and gas accumulation dates back to the mid-19th century, when the American oilman known as Colonel Drake suggested a link between oil deposits and anticlinal uplifts. Later on, on the basis of this method, any objects confined to elevated reservoir areas in structural plan began to be considered promising. The essence of the anticlinal concept is that the formation of hydrocarbon deposits is due to their buoyancy forces. According to modern petroleum geology textbooks for two centuries, the first and most important component necessary for oil accumulation and reservoir formation is structural uplift (Ali, 2017). Based on the approaches used by the anticlinal concept of oil and gas accumulation, more than 50,000 oil and gas fields have been discovered in the world so far. Most of the major fields that form the basis of the global oil industry were discovered in the mid-20th century (Tsoskounoglou et al., 2008). To this day, the anticline concept is the basis for exploration plans, oil and gas reservoir modelling, reserves estimation and development design. However, the number of large reservoirs discovered in recent decades has been declining rapidly. It is clear that new methods for prospecting and exploring for hydrocarbons are needed to maintain world production levels.

In addition, using the conventional approach when dealing with complex geological targets characterised by low reservoir properties, geologists often have to assign oil and gas reservoirs to various impermeable screens, of tectonic or sedimentary origin, the presence of which is not always confirmed by seismic and drilling data.

The reason for these difficulties lies in the fact that anticlinal theory does not consider as key, forces resisting the migration of hydrocarbons both during formation of the deposit and during its development. The main forces resisting oil migration are various capillary effects. Any oil and gas reservoir, irrespective of the conditions of its formation, facies component and tectonic processes occurring both during its formation and operation, is a multiphase pore system with an infinite number of contacts both between different fluids and in the surrounding pore space. According to the laws of molecular physics, the main role in oil and gas water distribution in the pore multiphase system is controlled mainly by capillary properties of the medium, such as capillary pressure value at the water-oil contact, interfacial tension value, pore channel radius and nature of solid phase wetting, i.e., hydrophilicity or hydrophobicity of reservoir rock. The combination of these conditions and characteristics results in a certain unique oil and gas trap. As the famous American geologist (A. I. Levorsen, 1948): each oil field is unique in that it has its own development and its formation can be considered the end result of the interaction of many variables. And to such causes, first of all, the differently directed action of capillary and gravitational forces, especially in reservoirs with low filtration properties, must be attributed. As a result of capillary forces, sharp fluctuations in the position of water-oil contacts and significant shifts of oil and gas reservoirs relative to the vaults of anticlinal structures are observed. Prediction of oil and gas contours from the position of capillary-gravity concept of oil and gas accumulation allows to explain the reasons of complex distribution of oil and gas water in natural hydrocarbon traps and to outline ways of searching for new oil and gas deposits, not subject to structural factor.

Materials and methods

As an example of predicting the oil and gas accumulation contour from the perspective of the capillary-gravity theory of oil and gas accumulation, this article examines the structure of the reservoir of formation BT17 in the R field.

The P field is located in the north of the West Siberian oil and gas province within the Yamal-Nenets Autonomous District. The stratigraphic section of the P field is represented by sandy-clay deposits of Mesozoic-Cenozoic sedimentary cover, underlain by pre-Jurassic basement rocks. The oil and gas bearing formation BT17 considered in this article is confined to the Lower Kheta Formation, composed of sandstone and siltstone layers. The age of the formation is Berriasian-Early Valanginian.

The structure of the Bt17 reservoir in question shows a mismatch in the distribution of water, oil and gas to the modern structural plan of the reservoir. Tests carried out in the north-eastern part of the structure yielded oil flows in the same absolute elevation interval as gas flows in wells located in the south-western part of the structure. According to geologists, who consider oil and gas reservoirs with such a structure solely from the anticlinal concept of oil and gas accumulation, this discrepancy in the distribution of fluids saturating the reservoir is due to the presence of various screens, of tectonic or sedimentological origin, which, however, are often not confirmed by either drilling or seismic data. Figure 1 shows a schematic of the reservoir structure in terms of the anticline-gravity concept of oil and gas accumulation. The shape of the deposit corresponds to the structural structure of the reservoir roof, but the oil-saturated part of the deposit near well 706 is separated from the gas-saturated part located at the same hypsometric level by a zone of claying, which has the shape of some “ancient channel” whose presence has not been confirmed by drilling data. This “laced” form of occurrence of geological bodies according to the concepts of classical palaeogeography is characteristic of sand bodies separating impermeable rocks rather than of clay impermeable rocks.

Figure 1. Schematic of the structure of the BT17 reservoir from the perspective of anticlinal-gravity theory of oil and gas accumulation.

If we consider the formation patterns of this deposit from the perspective of the capillary-gravity concept of oil and gas accumulation, the inconsistency in the shape of the deposit with the modern structural plan can be explained by the action of capillary forces in the pore environment of the reservoir.

The most significant values determining the influence of capillary forces on the distribution of hydrocarbons and produced water in the pore space of the reservoir rock are such surface-molecular properties of the reservoir as the nature of its wettability and the value of capillary pressure. The influence of reservoir rock wettability on oil recovery and its connection with capillary pressure has been reviewed by many authors (Anderson, 1987; Morrow 1990; Masalmeh 2003). However, these studies practically do not consider the issues concerning study of capillary forces and their influence on reservoir formation processes.

Meanwhile, during both oil recovery and the formation of an oil or gas reservoir, capillary pressure is the main force resisting migration and filtration of hydrocarbons. The nature of pore medium wettability determines the direction of capillary forces, while interfacial tension and curvature of interfacial surface determine the value of capillary pressure.

It is known that when oil or gas comes into contact with a water-saturated porous medium, an interfacial tension creates a pressure difference at the water-oil (gas) interface, which represents capillary pressure.

The concept of surface tension in immiscible liquids first appeared more than two centuries ago (Chen et al., 2006) and is described by the famous Young-Laplace equation (Young, 1805; Laplace, 1805). This equation states that the magnitude of capillary pressure Pc when two immiscible phases (in our case, water and oil/gas) are introduced into a porous medium is proportional to the product of interfacial surface curvature 1/r and surface tension γ.

(1) $\mathrm{Pc}\approx \pm \mathit{\gamma }\cdot \left(1/\mathrm{r}\right)$(1)

By convention (Anderson, 1987), the capillary pressure (Pc) in an oil-water system is defined as the difference between the pressures in the oil (Po) and water phase P(w):

(2) $\mathrm{Pc}=\mathrm{Po}-\mathrm{Pw}$(2)

Based on this definition, the radius of curvature of the interfacial surface pointing towards the oil phase is positive and pointing towards water is negative. Accordingly, depending on the curvature of the interface, the capillary pressure can be positive or negative. When the interface is flat, the capillary pressure is zero. In the case of hydrophilic rock, where the solid phase is predominantly wetted by water, Pc will be positive, i.e., the pressure inside the oil exceeds the pressure inside the water by the value of Pc, and the contact surface is concave towards the water phase. If the reservoir is hydrophobic, Pc will be negative, i.e., the pressure inside the oil is less than that inside the water by the value of Pc, and the contact surface is concave towards the hydrocarbon phase.

In both cases, the oil or gas element seeks a position and shape in which its surface and capillary energy, which is the ratio of capillary pressure to fluid density, reach a minimum. Since the density of the fluid is constant in each case, in order to achieve a minimum capillary energy, the oil or gas element must be shaped in such a way that the capillary pressure also has a minimum value. Accordingly, in the case of a hydrophilic reservoir, oil or gas will tend to occupy relatively large pores, while water will fill the shallowest pores. The opposite pattern in the distribution of liquids and gases would be observed in a hydrophobic reservoir.

Types of capillary barriers

According to the capillarity theory of oil and gas accumulation proposed by Bolshakov (1995), there are three classes of unconventional capillary-screened deposits (hydrophilic, hydrophobic and mixed, hydrophilic-hydrophobic) that may be present in almost every oil and gas bearing area and are controlled by so-called capillary barriers of the first and second kind. The hydrocarbon resources of such reservoirs vary from insignificant to gigantic.

Two groups have been identified among the hydrophilic class deposits, one of which includes deposits shielded by capillary barriers of the first kind and the other by the second kind. Barriers of the first and second kind are genetically and functionally distinct. The first of them is caused by filtration-lithologic variation of the reservoir laterally and acts as an accumulating factor, preventing secondary migration of hydrocarbons. Its origin is due to capillary pressure surges at the junctions of different porous facies. The second kind of barrier arises at the water-hydrocarbon contact of deposits of any type when the oil and gas reservoir cools. It does not play an accumulating role, but it prevents oil and gas overflow during deformations and trap opening during tectonic rearrangements. Deposits shielded by capillary barriers of the first kind may be present in any oil and gas bearing area, whereas capillary-screened hydrocarbon accumulations controlled by second kind barriers are predominantly found in oil and gas bearing areas overlain by cryolithozone. However, their presence should not be ruled out even outside the permafrost area, for example, in areas characterized by low modern reservoir temperatures.

The genetic difference between the hydrophilic and hydrophobic classes predetermines a different set of prospecting, exploration and development techniques for each.

This article examines the formation of a hydrophilic reservoir controlled by a second-generation capillary barrier. The origin of such reservoir-stabilising screens is usually confined to areas where oil-saturated reservoirs have undergone significant reductions in reservoir temperatures since the formation of oil and gas reservoirs.

According to known studies the surface tension is significantly dependent on the temperature of the medium (Michaels & Hauser, 1951; Ye et al. 2008; Hough et al. 1951).

According to Gimatudinov Sh and Shirkovsky (1982) the interfacial tension in the “gas-water” system practically doubles when the temperature drops from 120°C to 70°C, which leads to a corresponding increase in capillary pressure in the pore medium. This phenomenon causes a capillary barrier to arise at the contact between water and hydrocarbons in the pore environment of the oil and gas reservoir. Once the reservoir temperature decreases, the deposit “freezes” at the site of its initial accumulation due to increased capillary pressures. In the absence of tectonic movement and relative homogeneity of reservoir filtration properties, the standard position of the water-oil contact coincides with a capillary barrier of the second kind. The stabilizing effect of a capillary barrier of the second kind can be demonstrated only after complete or partial removal of the structural factors that led to the accumulation of the reservoir before reservoir temperatures decrease.

Influence of reservoir temperatures on hydrocarbon reservoir stabilisation

The reservoir temperatures of natural oil and gas reservoirs and the patterns of their change depend mainly on heat flux density. Over the course of geological history, heat flux density has changed significantly over time under the influence of various factors. The reservoir temperatures in different oil and gas provinces have been significantly affected by changes in solar radiation intensity and related climate changes. Cooling of sedimentary rocks reached the greatest extent, particularly in the northern oil and gas provinces, particularly in the north of Western Siberia. This change in sediment temperature regime was facilitated by a decrease in heat flux density simultaneously with climatic cooling. A decrease in reservoir temperatures at the same time as neotectonic deformation in the Pleistocene has been reported by many authors. Reduced reservoir temperatures in some northern provinces of China reached 60°C (Duan & Wu, 2020). In northern Canada, declines in reservoir temperatures during this period exceeded 90°C (Magara, 1976). In areas of permafrost spreading, cooling of oil and gas reservoirs during the neotectonic stage of geological development reached its maximum.

Most authors attribute formation of permafrost to the Late Cenozoic cooling (TODD et al., 2007). The Late Cenozoic ice age in the northern hemisphere began at the beginning of the Pleistocene about 2.7 million years ago. Up to 10 episodes of significant ice sheet activity and Northern Hemisphere ice sheet formation were observed in northeastern Eurasia over a period of 2.5–0 Ma (Cavanagh et al., 2006). The cooling effect of the cryolithic zone affected the temperature regime of oil and gas reservoirs throughout this period. The average decline in reservoir temperatures throughout the sedimentary cover in the West Siberian oil and gas province, according to Nesterov et al. (1982) amounted to 30°C. In the southern part of the basin, in the roof of the Cenomanian sediments, sedimentary temperatures decreased by 25–30°C. In the circumpolar areas of northern West Siberia, sedimentary cover sediments cooled by 30–50°C. As a result of the Late Cenozoic glacial period, the rocks of the sedimentary basin of the West Siberian oil and gas province cooled down to a depth of 4 km.

Lower reservoir temperatures caused a significant increase in interfacial tension at the water-hydrocarbon contact and a corresponding increase in capillary pressure at gas-water and water-oil contacts. Thus, the reservoirs were stabilized in areas of initial hydrocarbon accumulation. Due to increased capillary pressure, further structural alterations in the neotectonic stage of geological development could no longer lead to reformation of oil and gas deposits. As a result, the combined effect of active neotectonic processes and low reservoir temperatures in the Late Cenozoic led to the emergence of oil and gas accumulations in northern oil and gas bearing provinces that are not subject to the structural factor, making it impossible to search for and explore them from the position of conventional conventional solutions.

Neotectonic deformation and its relation to capillary barriers of the second kind

Many authors attest that the northern areas experienced substantial post-glacial deformation (Dehls et al., 2000). Deformation in northern Canada was greater than one hundred metres (Dyke et al., 1991; Adams & Clague, 1993). Even greater spread of neotectonic movements during this period had been observed in northern territories of Western Siberia (Varlamov, 1985). Neotectonic deformations here reached several hundred meters. Slightly less run-up in tectonic movements was observed in the Shirotny Priob’ye region – on the order of tens of meters. As a result, some of the local uplifts were dissolved and other uplifts were formed.

The high velocity and broad scope of neotectonic transformations have led to a radical structural reorganization of many oil and gas reservoirs. For example, A. Levorsen (1958) reports that the Capro oil reservoir in Arkansas (USA) tilted over a period of 10–12 years.

Active neotectonic processes in the area of cryolithozone development, where oil and gas reservoirs have experienced the greatest cooling, suggest that a wide variety of oil and gas reservoirs shielded by capillary barriers of the second kind are widely distributed within these areas.

However, only two varieties are known to be reliable amongst the proposed multitude – post-anticlinal oil and gas reservoirs. One type is confined to structures with inherited development (near-anticlinal) and the other to completely disintegrated anticlines that are not reflected in the present structure.

It should be noted that during the formation of paleoswales in rocks characterized by supercapillary pore sizes, such as those of Cenomanian age, due to low capillary pressures, fluids could move in accordance with new structural forms of newly formed traps. Therefore, the stabilizing role of capillary barriers of the second kind is most pronounced for more submerged shallow porous reservoirs of Neocomian and Jurassic ages characterized by low permeability. Partial or complete divergence in reservoir shape from the modern structural plan of oil and gas-bearing reservoirs located in northern areas is quite common. Accordingly, exploration and supplementary exploration of such reservoirs should not be approached solely from the traditional view of oil and gas reservoir formation.

Results and discussion

Determinant for the second kind of barriers is cooling of oil-and-gas reservoirs, which causes increase of capillary pressures at water-hydrocarbon contacts due to increase of interfacial tension with decrease of reservoir temperature. The oil and gas reservoir must cool to such an extent that the increase in interfacial tension and, consequently, capillary pressure at the water-hydrocarbon contact is sufficient to prevent movement of hydrocarbons through the water-saturated formation by gravitational forces during its tectonic deformations, up to complete disintegration of natural traps contained in it.

Such capillary-screened oil and gas reservoirs may be present in any oil and gas-bearing province whose subsoil experienced significant cooling during the neotectonic stage of geological development or is characterised by low current reservoir temperatures.

However, they are most widespread in oil and gas bearing areas overlain by permafrost strata because the cryolithozone, along with the weakening in time of heat flow, uplift, etc., can be considered as an additional significant factor in cooling sedimentary cover rocks to a considerable depth. Of greatest practical interest are post-stratigraphic hydrocarbon accumulations, which is due to the comparative ease of their prediction. The main elements of local forecasting and refinement of the contours of such deposits can be based on paleostructural and paleogeographical studies with the compilation of appropriate models of their structure. The connection between the present-day structure of hydrocarbon deposits at fields in the West Siberian oil and gas province and neotectonic processes was suggested earlier (Rybak, 1987), but the influence of capillary pressures on the stabilization of the deposit at its initial accumulation site was not considered at that time.

Principles for predicting the contour of deposits shielded by capillary barriers of the second kind

In most cases, the current structure of oil and gas reservoirs is the main criterion for determining the spatial position of water-oil and gas-water contacts. This approach often leads to significant errors in determining the position of oil and gas-bearing contours and, consequently, to errors in determining the deposit area and oil and gas saturated volume.

According to Bolshakov (1995), the following principles should be followed when defining oil-bearing contours of capillary-screened deposits:

In the regional prediction stage, thermometric studies of oil and gas reservoirs are the main ones, as well as assessing the extent of their neotectonic alteration. The purpose of thermometric studies is to assess the extent to which reservoir temperatures have decreased since hydrocarbon accumulation began in its traps. If cooling of the oil and gas reservoir was sufficient to create stabilizing capillary barriers, the intensity of subsequent neotectonic movements is studied. The intensity of tectonic movements is assessed to determine whether anticlinal paleovolcanic reservoirs can be fully or partially disintegrated.

Next, structural and palaeostructural plots are carried out. Paleostructural maps should be plotted at the time of maximum cooling of the oil and gas reservoir in question. If it is impossible to obtain a well traceable horizon in the Upper Cenozoic interval, a horizon chronologically closest to the time of the lowest reservoir temperatures can be taken as a reference for isopachite map construction. For the West Siberian section, this could be the basement of the Turonian Stage. Obviously, this may lead to certain errors in identifying and delineating deposits. However, the errors mostly introduce quantitative rather than qualitative distortions in the true structure of productive horizons under the generally inherited tectonic development of the region. Using the resulting paleostructural maps, anticlinal traps are identified according to the anticlinal concept of oil and gas accumulation, and with the available data on the oil and gas content of the reservoir based on well test results, the position of the inferred horizontal water-oil contacts is determined, which are then projected onto the present-day structure.

When predicting the oil-bearing contours of productive formations in West Siberia, it should be kept in mind that maximum reservoir temperatures up to 120°C in the sedimentary cover were observed in the early Oligocene (Kurchikov & Stavitsky, 1987). Accordingly, conditions for hydrocarbon migration were optimal in the early Oligocene because interfacial tensions were almost completely compensated. The mobility of fluids due to this fact contributed to the most complete subordination of reservoir contours to the form of anticlinal traps. The onset of formation of the permafrost strata is attributed to the cooling of the early Pleistocene. At that time, hydrocarbon reservoirs were stabilized by second-order capillary barriers due to increased interfacial tension, and further tectonic deformation could no longer result in fluid overflows due to increased capillary pressures at water-hydrocarbon contacts.

As an example of predicting the contour of oil and gas accumulation from the position of capillary-gravity theory of oil and gas accumulation, this article examines the structure of the reservoir of formation BT17 of the R field. The structure of the reservoir of formation BT17, made on the basis of the traditional view of the processes of formation of hydrocarbon deposits is shown in Figure 1.

In order to carry out paleostructural analysis to clarify the reservoir contour from the perspective of capillary-gravity theory of oil and gas accumulation, the Turonian basement, which satisfactorily correlates with the seismic reflection horizon D, was used as the horizon closest to the time of maximum cooling of the sedimentary cover due to the absence of reliable benchmark horizons of the upper part of the section. According to the paleostructural plan, oil and gas accumulations are confined to local anticlinal uplifts separated by a structural sag. There is also a local structure in the southwestern part of the area in question, within which a post-aniclinal hydrocarbon deposit may be present. Thus, prior to declining reservoir temperatures and subsequent neotectonic transformations, oil and gas accumulations were fully consistent with the principles of anticlinal theory of oil and gas accumulation and gas-water contacts had a near-horizontal position (Figure 2).

Figure 2. Schematic of the hydrocarbon reservoir structure of the BT17 formation at Early Turonian time.

Thus, substantiating the position of oil-water and gas-water contacts on the modern structural plan of the reservoir in question does not require the construction of any unconfirmed zones of claying or faulting. When projecting the contours of oil and gas bearing capacity, identified on the basis of paleostructural analysis, onto the modern structure of the reservoir (Figure 3), a rather sharp discrepancy between the shape of the deposit and the modern structure of the reservoir is detected. Nevertheless, this position of contact boundaries is fully explained from the perspective of the capillary-gravity concept of oil and gas accumulation.

Figure 3. Schematic of hydrocarbon reservoir structure from the capillary-gravity theory of oil and gas accumulation.

Conclusions

The use of capillary reservoir characterization data allows for more accurate prediction of the position of oil-water contacts that do not correspond to the current reservoir structure. This eliminates the need to assign non-existent screens such as impermeable faults or unconfirmed zones of reservoir claying to oil and gas reservoirs.

Based on the Young-Laplace equation, capillary screens arising at the water-hydrocarbon interface that control reservoir shape can genetically be of two types. The first occurs at junctions of different porous facies, i.e., increase in capillary pressure in this case occurs due to variation in pore channel radius of curvature.

The second type of capillary screen, discussed in this article, owes its origin to a decrease in reservoir temperatures, which led to an increase in interfacial tension and consequently a capillary pressure surge and subsequent neotectonic deformations. The distribution of this type of capillary-screened reservoir, which is inconsistent with modern reservoir structure, is determined by the presence of a cryolithic zone or limited to the spread of relatively low reservoir temperatures.

The most feasible searches are for post-anticlinal oil and gas reservoirs screened by second-order capillary barriers located in areas of disintegrated anticlines.

Acknowledgments

This article was prepared as part of the Digital Core technology project at the West Siberian Interregional World-class Science and Education Centre

Disclosure statement

No potential conflict of interest was reported by the author(s).