Hard-to-Recover Reserves Formation Analysis for West Siberian Fields

By A.A.Tomilov, I.P. Popov, April 8, 2013

The block-type basement structure determines development of fractured and porous reservoirs in the productive section and integrity of the hydrodynamic system of multiplay fields. Neglect of the tectonic and hydrodynamic factors results in separate depletion of two reservoir types, the formation of difficult-to-recover reserves and growth of unproductive expenses.

At present, the majority of hydrocarbon fields of West Siberia are mature development fields that are characterized by a high water cut resulting in formation of difficult-to-recover reserves. It is our opinion that this is caused by insufficient consideration of the model of pool reservoir properties.

According to modern concepts, the time of hydrocarbon pool formation in the Jurassic and Neocomian deposits of the mid-Ob region covers the late-Cretaceous and Neogene-Quaternary epochs; it was conditioned by the block-type structure of the basement. Faults, confining the blocks, are fractured zones along which vertical migration of hydrocarbons takes place [1].

Activation of fissure-fault tectonics and vertical migration of hydrocarbons with out cropping give rise to gas, bacteria, hydrochemicals and other anomalies, which are registered by aerial and space surveys. This confirms the integrity of the hydrodynamic system of multi-horizon fields [1,2]. Dependence of the reservoir oil saturation factors and well productivity factors on the distance to the tectonic faults leads to the conclusion that pool formation is determined by the secondary reservoir storage, that is by fractures and capillary channels comparable with pores and having the tectonic origin. Hydrocarbon presence in fractures and pores causes the development of fractured (F), porous fractured (PF), fractured-porous (FP) and porous (P) reservoirs in productive intervals. Using the dependence of field-geological parameters on skin-effect, and dependence of skin-effect on pressure drawdown, authors of the study [2] describe the technique for differentiation by the field data and development performance. A range of indicator diagrams (Fig. 1а) confirms presence of four reservoir types. In injection wells (Fig. 1б), injectivity is increasing with time, which is caused by fracture widening.

During overbalanced drilling at 5-8 MPa (over 20 percent), drilling mud loss and fracture plugging are observed. During formation testing, most of the indicator diagrams (ID) had a concave production rate axis (Fig. 2а), which indicated reduction of permeability in the near-wellbore reservoir zone (fractures). At the beginning of development, the reservoir could be depleted as a porous one (P), fractured-porous (FP), or porous-fractured (PF). In the course of pilot production, fracture cleanup took place (either spontaneous or resulting from treatment with surfactants or acid solutions), production rates increased and indicator diagrams obtained a usual convex form, indicating that the well is connected to the fracture (F) storage. As ΣQo=f(Qo), where ΣQo – cumulative production; Qo – recovery rate, the mechanism of fracture cleaning and pool drainage is definitely reflected (Fig. 2б) on curve characteristics ΣQo, irrespective of the stratigraphy, lithology and reserves value [2,3].

According to the study [3] and Fig. 2в, the end of product withdrawal from the fractures (point А) is determined by the stabilization of the curve ΣQo at the low level. As the section characterizing