TyumenNIIgiprogaz: Exploration Planning Principles for the Omorin License Block

Gorlov Ivan Vladimirovich: Head of Field Geology, Geophysics & Estimation of Reserves department, TyumenNIIgiprogaz
Kachinskas Igor Victorovich: Junior Research Fellow, TyumenNIIgiprogaz
Sankova Natalya Vladimirovna: Junior Research Fellow, TyumenNIIgiprogaz

The Omorin license block (LB) is located in the Baykit oil-and-gas area in the Leno-Tungus petroleum province (fig. 1). Two petroleum deposits are found in this area, Omorin and Kamov, with production reservoirs confined to the terrigenous depositions of  the Vendian period, in particular, the B-VII reservoir of the Katanga suite and the reservoirs B-VIII and B-IX of the Oskobin suite that formed during the Tyrian and early Danilov periods.

The Vendian terrigenous formations are upcapped with 28 wells in the area. Cased hole formation testing was only conducted in 18 wells. In the remaining wells there was no production which was confirmed with geophysical well logging (GWL) data and the results of open hole testing. One of the peculiarities of this exploration project is that out of 56 wells tested using the cased-hole method, only five (9%) had shown commercial petroleum influx rates. Namely the Om-2 well for the  reservoir B-VII at the Omorin deposit had shown a gas influx rate with absolute open flow rate of 624,000 m3/day and 545,000 m3/day for the B-VIII reservoir. The flow rates for the Om-12 well in the B-VIII-1 reservoir were 1,096,000 m3/day with an 11 mm annulus. The B-IХ reservoir flowed at 369,000 m3/day with a 5 mm annulus. At the Kamov deposit, a single well (Km-1) for the B-VIII-1 reservoir, showed an oil influx rate of 153.6 m3/day with 14 mm flow choke. The remaining 51 wells either had no influx (48 %), or had non-commercial influx rates (25 %), or produced water with non commercial traces of oil (18 %).

The small share of highly productive zones in the listed reservoirs is due to complexity of the reservoir structures and lack of reliable methods that would help forecast the reservoirs with enhanced porosity and permeability features (PPF). This study will review terrigenous reservoir formation sedimentations and secondary transformation features which should be taken into account during the exploration activities at Omorin LB.

Based on existing ideas about paleography [Shemin, 2007] and the facies environment in the Tyrian period [Borovikova, 2010; Melnikov, Isayev, 2004; Melnikov, Konstantinova, 2006; Moiseyev, Konstantinova, Romanov, 2011; Starikov, 1989], the formation of arenated Vendian reservoirs took place in littoral shallow-water conditions. Thus, one of the works [Borovikova, 2010] notes that the existence of a shoreline stretched all the way across the entire Baykit petroleum area during the Tyrian period (fig.1) which determined the distribution of deltaic, beach and bar type sand packages as well as channel bodies, dejection cones, sand washouts and other sand packages found in littoral areas in the Oskobin and Katanga suites within the Omorin block. Moreover, L.N. Konstantinova, S.A. Moiseyev and M.I. Romanov consider that “…channel and deltaic environments were predominant for the western part of the Baykit anteclise”. [Moiseyev, Konstantinova, Romanov, 2011, p.15].

Based on the interpretation of seismic cross sections for the effective reflection factors produced by the REAPAK software, in the south-west part of the Kama arch, channel sands (the deepest cut-in area) are found west of the Vdr-6 well [Melnikov, Isayev, 2004].

Channel deposits, in our opinion, do not only make their geological record as partially entrenched barriers of the Vendian depositions into Riphean formations, but also directly in the Vendian terrigenous rock stratum. Indeed, based on the R. Passega diagram point distribution (fig.2), it may be concluded that most samples from the Vendian terrigenous reservoirs correspond to mudflows and graded suspended matter areas. According to the diagram, the RQP field corresponds to sedimentation from graded suspended matter formed in the lower parts of the rapid streams at their very bottom. It is notable that most samples from Km-1 pertain to this area. Part of the samples from Om-17 fall within the PO field, which was formed with sedimentation of mixed origin, partially transferred with rolling movement and partially by sedimentation from the suspended matter. This could also be stream sedimentation, but with the lower dynamics compared to the RQP field.

The differences in sedimentation dynamics for the Vendian terrigenous reservoirs are not only observed in wells, but also within the reservoirs. This fact is not only confirmed with the genetic diagram data but also with the fact that the sorting factor values vary significantly (both horizontally and vertically) within the same reservoir, from well to poorly sorted (table 1). Thus, for the Plt-1 well, the maximum sorting factor for the B-VIII-1 reservoir is 1.78, which is half of the value for Km-1, which is 3.57. Such high sorting factor values are also found for B-VIII and the B-IX reservoirs (well Km-2).

Waste streams have formed channel-shaped sedimentary bodies, or waste stream beds. These depositions are diagnosed based on GWL data, shapes of microlaterolog (MLL) and laterolog (LL) survey curves and curves of natural and induced radiation gamma-ray logging (GRL), neutron gamma logging (NGL) and acoustic logging (DT).

Let’s review this on an example of the B-VII reservoir in the Om-2 well (fig. 3). The large section of the B-VII reservoir is predominantly formed with terrigenous rock that is less coarse the further up the section you travel.  It changes from gritstone and coarse sandstone to fine sandstone and siltstone. It lies in intervals at a depth between 2428.3m and 2434.8m and can be divided into two intervals: the lower one from 2432.5m to 2434.8m, and the upper one ranging from 2428.3m to 2432.5m.

The lower interval is represented by cavernous fine sandstone with inter-layers of siltstone and fine-grained to coarse-grained sandstone and gritstone, the latter reaching 2.5m in thickness. In the middle of this interval, there is an interlayer of dark-brown argillites. Towards the top of the interval, the grain size increases (GRL and MLL curves decrease towards the top while increasing on DT curve). A distinctive feature of the lower interval based on logging data is that it has minimal indicated values (in comparison with depositions below and above the interval) for the MLL curve and maximum values for the DT curve.

The upper interval is represented with even interlayering of dolomitized, fine-grained sandstone and siltstone. The logging characteristics distinguishing it from the lower interval with higher MLL and NGL values. The different GRL and NGL logging curves prove the dolomitization of the rock. In particular, GRL curves for dolomitized sandstone intervals shows a tendency of decreasing values compared to the intervals above and below, whereas the NGL curve has the opposite tendency of increasing values.

Within this section of the reservoir, most rock is reddish-brown in colour, which signifies the exisitance of oxidized sedimentation regimen and is due to the shallow waters in the basin and the strong dynamics of the aqueous mediums.

Based on the fact that channel deposits in the B-VII reservoir section for the Om-2 well are only confirmed by bottom hole core logging data, the migration of the waste stream beds can be concluded. Proof of such migrations, across the reservoir, is based on the fact that the interlayers of coarse-grained sandstone are only found in two wells, Om-2 and Om-9, at the Omorin field. The other wells in this reservoir are represented by either dolomitized consertal sandstone (Chgb-1, Om-17, Om-11 and Om-12), or by even interlayering of dolomitized fine-grained sandstone and dolomites (Om-5, Om-8, Om-1).

In the same manner, it may be shown that depositions of the waste stream beds are there in other reservoirs; in particular, for the B-VIII-1 reservoir intervals they are uncapped in wells Om-17 and Km-1 and are absent in all other wells.

Experience of forecasting the productive depositions at the Omorin deposit using Pangea’s interpretation software, analogous to [Yaitskiy, 2006] had shown that the development of channel facies in the Vendian formations may be estimated based on 2D seismic data and the conversion of seismic field attributes in the DT and GRL logging curves. Presently this approach is undergoing validation in the geology and geophysical monitoring department of TyumenNIIgiprogaz.

Considering the low thickness of the Vendian terrigenous reservoirs, the objective of prospecting for channel facies will present a difficult challenge, however this is a very important issue, because it is the very channel facies that are related to three of the four mentioned testing programs with commercial influxes of hydrocarbons, i.e. units uncapped by Om-2 and Km-1 wells.

The other principal is related to the fact that the terrigenous reservoirs feature two secondary porosity types, intergranular and fractured.

As demonstrated by extensive petrographic studies, the Vendian section (Katagan, Oskobin, Vanavar suites) and the Ryphean sections have complex epigenetic transformation features [Surkov, Korobeynikov, Krylov, 1996]. In zones of increased permeability, carbonaceous and terrigenous formations are hydrothermally altered to various degrees. The dolomites are silicified, sometimes significantly so; they are also often anhydritized. Siltstones are also quite silicified. In a number of instances, they show veinlets of hydrothermal dolomites. The sandstones are mostly silicified, somewhat more rarely there are areas of silicification and adularization. Adular development is confined to immersed caverns.

This analysis demonstrates that the porosity of sandstone-siltstone Vendian rock variations at Omorin license block is little related to the granulometric characteristics of the reservoirs. Indeed, as seen in table 2, the porosity of siltstone (Pf of 8 to 10%) is very different from porosity of medium-grained (Pf of 12 to 20%) and fine-grained sandstone (Pf of 14 to 18%). Whereas porosity of fine-grained silt sandstone and fine-grained silty sandstone varies within the entire range of values from 8 to 20%. In other words, increased secondary porosity could not form within initially low-porosity siltstones and is developed with higher probability within sandstone with larger grain size.

Because larger grained rock forms in channel formations, reservoirs with higher porosity are confined to the latter. This also explains higher flow rates which were observed during the testing in the Om-2 well with the uncapped B-VII and B-VIII channel facies, as was noted earlier.

Fractured voids in the rocks are confirmed by both the field core logging and the laboratory testing data. E.g., field core logs for Om-12 well in the interval between 2642.9 and 2648.0, show reservoir B-VIII-1 characterized by quartzo-feldspetic sandstone, dense, average strength, with alternating massive and bedded structures, there is also a short sub vertical open fracture in the base of the interval. The next layer was characterized by gray and dark-gray dolomitic sandy siltstone, the lower core was cracked in two along the surface of the sub vertical open fracture and was partially broken.

Further down the section for the B-IX reservoir, field core logs noted closed-type fractures. The middle part of the interval between 2652.1m and 2653.8m, represented by fine laminated inter layering of argillite and fine-grained gray sandstone with thin-bedded horizontal, cross-bedded and crenulated textures, there is a sub vertical closed-type 0.5m long fracture, with the core fragmented along it. These tight fractures are also found in more finely-grained stones. E.g., in the interval between 2664.0m and 2665.5m, where the B-IX reservoir is characterized by fine-grained argillous siltstone, light-gray with a tint of green,  thinly laminated and weakly anhydritized; in the lower part of the layer, there is a vertical closed-type fracture with core fragmentation along it. It should be noted that the porosity of samples taken for laboratory testing did not exceed 7%, with predominating values of 2-4%. As per assessment based on GWL data, the porosity in reservoir layers varies from 5 to 8%. Regardless of such low porosity, the interval 2656–2662m produced gas with flow rates of 36.9 thousand m3 with 5 mm annulus. Thus, it is safe to say that the gas influx here is related to the fracturing of the reservoir formations.

Fracturing has a great influence on the filtration properties of terrigenous Vendian reservoirs.  This is also evident in the lab research on determination of dynamic permeability coefficient (DPC) for the gas. DPC is the permeability of gas in presence of irreducible water.

Fig. 4 is a point diagram showing the correlation of the dynamic permeability coefficient and the open porosity for terrigenous rock of Vendian age; the diagram was made based on the results of the analysis performed in “Ecogeos” Ltd. laboratory in Moscow. Of the samples who’s porosity exceeded 11%, there is a classic linear correlation between the porosity factor and permeability logarithm with predominating scatter points not exceeding half an order of magnitude. A completely different situation is found in the lower porosity values, especially for the interval between 1 and 4%. Here, the spread of values in relation to the linear dependence exceeds two orders of magnitude. Another area for attention is that the full-sized samples with visible fractures, although featuring low porosity (1 to 4%), also featured an increased dynamic permeability. It is very apparent that such permeability is determined by their fracturing. This is also confirmed by the fact that regardless of very low porosity, its dynamic permeability is only slightly below absolute permeability determined in dry samples, whereas for most samples where the porosity was between 2 and 4 % it decreases drastically by more than one order of magnitude.

Wide distribution of fracturing in the reservoirs under review, in our opinion, is the reason for such a large (almost 50% as mentioned earlier) number of “dry” wells detected by cased hole logging, since an absence of influx may be a consequence of considerable contamination of the formation zone with drillings mud and cement slurries, running right through the fractures.

The role of colmatage in the sampling of fractured reservoirs is well observed in the B-VIII-1 reservoir testing in the production string of Km-3. Based on core studies and the drill stem formation testing (DSFT) results, as well as the interpretation of the complex GWL data, the interval between 2390.0 and 2398.7m features two reservoir interbeds totaling 3m in thickness and represented with gray and dark-gray siltstone with interlayers of anhydrites and black argillites. During an open hole formation test using KII2M-146 equipment, pressure drawdown of 9.55 MPa resulted in gas inflow rate of 17.5 thousand m3/day from the interval between 2376 and 2399 m (which is thicker than B-VIII-1 reservoir). After the completion of the well, reservoir testing in the production string was conducted on the interval between 2377 and 2397 m (which was nearly consistent with the interval for open hole formation testing). With that, at the average dynamic level of 1021.5 m, there was a gas influx of 3.3 thousand m3/day with film of liquid hydrocarbons, i.e. the reservoir is underdeveloped.

In our opinion, further well stimulation using hydrofracturing (HF) operations should be done here. Efficiency of HF in fractured reservoirs is proved by data published in the report [Denk, 1998]. Namely, it proves that “… for prospecting areas with wide development of fractured and porous fractured reservoirs, determination of actual commercial significance of such petroleum formations (irrespectively of their lithological composition, facial attributes, deposition depth etc) is impossible without a targeted aperture of fluid-conveying fractures and their fixation in an open state”. [Denk, 1998, p.232].

Therefore, a successful field exploration at the Omorin license block should be based on two main principles:
1.    The location of prospecting wells should be determined based on allocation of channel facies development zones.
2.    When testing fractured and fractured-porous reservoirs, hydrofracturing technologies should be implemented for prospect evaluation and prospecting holes if they uncap producing reservoirs outside of the channel facies.

Literature
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