Tulenovo field holds key to new drilling in Bulgaria

Steven Bottomley,Graham Pritchard
Balkan Explorers (Bulgaria) Ltd.
London

Tulenovo oil field is located on the Bulgarian Black Sea coast, 60 km northeast of the port of Varna and 25 km south of the Romanian border (Fig. 1 [217,604 bytes]). The accumulation, second largest in Bulgaria, has several unusual technical features:

• Shallow depth (±350 m)
• Cavernous porosity, giving excellent reservoir quality, oil recovery, and production flow rates
• An effective chalk seal
• Controversial and unproven source rock
• A secondary gas cap
• Extensive well coverage yielding detailed reservoir data.

MMS Petroleum plc, through its wholly-owned subsidiary Balkan Explorers (Bulgaria) Ltd., holds a 50% operating interest in Block 91-1, directly offsetting the northern culmination of Tulenovo field. The company recorded 850 km of high resolution marine seismic data in 1995 over the eastern extension of the Tulenovo structural trend.

Interpretation of these data resulted in development of a new, dual objective, prospect (Tangra) 15 km northeast of and on strike with Tulenovo. The prospect has estimated unrisked P50 reserves of 46 million bbl of oil in a Tulenovo analogue trap, and 23 million bbl in a secondary Eocene target. MMS plans to drill this prospect with a Romanian jack-up rig in 1998 and is seeking co-investors.

Tulenovo oil field

Tulenovo was discovered in 1951 by an onshore exploration well drilled on a prospect defined by gravity and seismic data.

Oil was encountered in dolomitized, fractured, and karstified late Jurassic to early Cretaceous (Valanginian) limestones at around 330 m RKB, and a number of early appraisal wells blew out upon penetrating this reservoir. Contemporary records indicate an estimated initial flow rate of 7 MMcfd of gas and about 4,000 b/d of oil before well R-16 was capped.

Development of this accumulation began in the mid-1950s, and over 400 production wells have been drilled (in accordance with standard Eastern European operating practices of that era), including slant wells and the construction of a pier to access reserves that extended beneath the sea.

Tulenovo field is the largest oil producer in Bulgaria at 260 b/d, albeit with a water cut above 98%, with 21 million bbl of oil having been produced since 1954. Reported flow rates of up to 2,000 b/d/well were achieved from crestal wells during early stages of field life using open hole, naturally flowing completions. Despite the high drilling density of about 10 acres/well, some wells have recovered in excess of 500,000 bbl (Fig. 2 [336,931 bytes]).

A small nonassociated gas accumulation occurs in overlying Oligocene sandstone stringers.

Tulenovo reservoir

Reservoir potential is developed at the erosional surface of a platform carbonate of late Jurassic to early Cretaceous age. This unit has the local lithostratigraphic name of Valanginian, although it ranges in age from Oxfordian to Barremian.

The best reservoir quality is encountered in the north of the field, associated with pervasive dolomitization and excellent development of secondary cavernous porosity and permeability. Core porosities are reported to range between 5 and 23% (average 13.5%), although bulk porosities are expected to be higher due to heterogeneous cavern development.

Caverns of 1-2 m in height are common, with voids of up to 13 m having been encountered during development drilling. Permeabilities of several Darcies are achieved in secondary porosity, while the caverns constitute unimpeded subterranean storage.

In contrast, the southern part of the field is only partially dolomitized. Limestone interbeds in this area have core-derived matrix porosity of 7-10% and permeabilities in the order of 5-10 md.

These systematic variations in poro-perm across Tulenovo field can also be demonstrated on a regional basis. Well data show that the late Jurassic to early Cretaceous carbonate reservoir sequence, which subcrops the late Cretaceous chalk/ marl seal, becomes progressively older from south to north (Fig. 3). This resulted from southwesterly tilting of the carbonate platform in the mid-Cretaceous, resulting in the northern area being sub-aerially exposed and eroded.

The bioclastic fabric of the Valanginian and older sediments thus exposed were also more susceptible to the development of secondary porosity than the Valanginian and younger sediments of the southern platform. Thus, the intensive weathering and karst development over the northern platform (in the vicinity of North Tulenovo and MMS's prospect) contrasts with the shallow marine carbonate facies encountered on the southern fringe of the uplift, which has little or no porosity development.

Reservoir seal

Vertical and lateral seals are provided by a drape of Upper Cretaceous pelagic chalk and marl that is well documented throughout the field.

The chalk is about 60 m thick, which is greater than the maximum throw recorded on intrafield faults (<45 m). the effectiveness of the top seal is further demonstrated by the occurrence of an associated gas cap.

The western bounding fault to North Tulenovo has a throw in excess of 150 m, showing that Paleogene sediments, on the downthrown side, also provide a viable lateral seal to the Tulenovo accumulation.

Oil, gas characteristics

Tulenovo contains a 30 m column of undersaturated 19° gravity oil with a 20 m secondary gas cap.

The oil has a pour point of -21° C., a viscosity of 55 cp at reservoir temperature of 37° C., and contains 0.3% sulfur. Assay of the oil shows a refining yield of 20% middle distillate and 80% low sulfur fuel oil.

Although the oil is biodegraded, biomarker analysis clearly shows a high content of n-oleanane, indicating a source of Tertiary age. The location of the source rock is controversial but must be located at least 50 km east or south of the field, as the Tertiary sediments in the immediate vicinity of the field are thin and immature.

The field's gas cap is reported to contain 94% meth- ane and 5% nitrogen. The gas is not in equilibrium with the underlying oil and is interpreted to represent a secondary feature resulting from more recent thermal or biogenic gas generation. Carbon isotope analysis of the gas is not available to resolve this matter. The most likely source of the gas is the foredeep to the Balkan mountains (the Kamchia depression), located south of the field (Fig. 1).

Structure, migration

Log correlations across Tulenovo field suggest that the late Cretaceous to Eocene section overlying the field is relatively constant in thickness. This suggests that paleo-relief, although assumed to be present at the Late Cretaceous unconformity (to develop karst), may not have been substantial.

There are, however, wide variations in thickness of the Oligocene section. Seismic evidence shows that this is due, primarily, to a phase of faulting in the late Oligocene, possibly exacerbated by erosion during a global eustatic low-stand that occurred at this time.

Although a paleotopographic trap may have been present over Tulenovo in the late Cretaceous, it is deduced that the present trap geometry is largely a function of late Oligocene tectonics. The trap has been modestly modified since the Miocene, probably with a dextral strike-slip component, with some faulting extending to the surface. Hydrocarbon migration appears to have been in two stages:

1. Oil migration into the trap in the Late Oligocene and Miocene; and
2. A post-Miocene gas charge.

Reservoir behavior

Characteristically, producing wells in Tulenovo are drilled to below the field oil-water contact (OWC) and have a vertical barefoot completion.

The overall production performance of the field (Fig. 4 [30,276 bytes]) has shown dry oil production for the first 7 to 8 years, followed by a very rapid increase in water cut. During the dry oil production phase, about 60% of the total reserves were recovered. This is interpreted to reflect initial depletion of the cavernous and fracture porosity, followed by recovery from the matrix by natural production and imbibition during aquifer encroachment.

Some reservoir stimulation has been conducted on a selective basis. These techniques include dynamite fracturing (unsuccessful) and acid squeeze, the latter being particularly effective in the tighter reservoirs on the southern limb of the field.

The oil accumulation is underlain by a regional aquifer that is also the principle potable water supply for northern Bulgaria, which is recharged from outcrops of the early Cretaceous west of the field. This provides a potentiometric head of about 16 m ASL at Tulenovo. Consequently, most wells flow naturally, and the field has unconstrained bottom water drive and pressure support. There has been no measurable depletion of reservoir pressure since production started in 1954, albeit even after extraction of almost 400 million bbl of oil and water.

Oil recovery

In a heterogeneous, dual porosity reservoir such as Tulenovo, determination of average reservoir characteristics is not possible with any degree of accuracy. Indeed, determination of stock-tank original oil in place is not realistically possible either through deterministic, stochastic, or material balance methods.

The high drilling density of Tulenovo permits accurate determination of gross rock volume (GRV) for the oil bearing intervals and has resulted in virtually complete drainage of oil from this field. This provides an excellent analog for prediction of potential recovery from offsetting prospects in the same reservoir.

The oil recovery per unit gross rock volume of the North Tulenovo accumulation was obtained by planimetering a Top Reservoir Structure map prepared by the field operator, Pleven Oil and Gas. The cumulative oil recovery of all wells within each fault block in the field was used to calculate the recovery of oil as a function of GBRV for (i) each fault block, and (ii) for the entire field.

The results of this study showed that on average the field yielded oil at 2.2% of GRV and, for the most prolific areas, over 3% of GRV (230 st-tk bbl/acre-ft). In comparative terms, this is equivalent to a "good" conventional sandstone reservoir of 20% porosity, 70% oil saturation, 75% net to gross, 1.05 reservoir bbl/st-tk bbl formation volume factor, and 30% recovery factor.

Tangra prospect

The Tangra prospect was mapped using high resolution seismic data, recorded by MMS in 1995, tied to nearby well data and information from Tulenovo field. The prospect, in 45 m of water, has a Valanginian primary objective and an Eocene secondary objective.

Seismic mapping confirmed the NE-SW trend of structures along strike with Tulenovo field (Fig. 3 [30,276 bytes]). The North Shabla-1 & 2 wells, drilled in 1993 with very poor seismic control, are demonstrated to be downdip from closures with modest reserve potential. However, these wells did encounter the Valanginian reservoir facies, both wells losing total circulation upon penetrating below the late Cretaceous seal.

The prospect, at the primary Valanginian reservoir level is approximately 4.5 x 6.5 km in size, with a maximum mapped relief of 100 m (Fig. 5 [109,421 bytes]). The structure is interpreted to have had the same structural history as Tulenovo field, having its main development in the late Oligocene, with minor structural modification in the post-Miocene. Tulenovo is therefore an excellent structural analogue for the Tangra prospect.

The Valanginian (late Jurassic-early Cretaceous) reservoir carbonates are expected to be well developed at this location, being part of a regional carbonate platform facies, with excellent reservoir properties (see discussion on Tulenovo above). A collapse structure has been interpreted over the crest of the prospect (Fig. 6 [210,815 bytes]) which is consistent with karst development.

Top and lateral seals are provided by a drape of late Cretaceous chalk-limestone, which has been proven over Tulenovo field. Fault throws and chalk seal thickness are comparable in both structures.

The presence of Tulenovo demonstrates that oil generation, migration, and entrapment have occurred within Block 91-1. The Tangra prospect shares the same structural trend, reservoir, seal, and structural history as Tulenovo field and should be equally favored for oil accumulation.

The secondary objective of the Tangra prospect comprises early Eocene bioclastic nummulitic limestones in a roughly circular bioherm, mapped on seismic data. The potential reservoir facies was encountered in an offset well (Severna-1), where it was porous and permeable although water bearing, having been encountered off-structure.

Stochastic reserve estimates for the prospect have been made using the recovery factor actually achieved in Tulenovo field for the primary Valanginian reservoir (see above) and appropriate parameters for the Eocene secondary target. This has resulted in unrisked P50 estimates 46 million bbl and 23 million bbl for the primary and secondary targets, respectively. Combined upside unrisked reserve estimates exceed 120 million bbl.

Using established industry practice for geologic risk assessment, MMS has risked success at the primary objective of the Tangra prospect as 1 in 3, reflecting inherent analogies to Tulenovo field.

E&D plans

MMS is negotiating with the Romanian contractor Petromar to drill the Tangra prospect in mid-1998, with an option for a back-to-back appraisal well. Petromar has a proven record in drilling for western operators within the Black Sea area, where it has been technically proficient, safe, and cost effective.

A site survey for the exploration well and three potential appraisal locations, with a 50 km high resolution seismic survey, will be recorded in the first quarter of 1998.

Based on reservoir and fluid data from Tulenovo field, MMS has provisional plans to develop any discovery with horizontal wells to increase flow rates and ameliorate the potential for water coning during production. A floating production system based on extended well test technology has also been investigated and prepared to accelerate the development and maximize project economic returns (Fig. 7 [100,355 bytes]).

Independent oil marketing scenarios, based on Tulenovo oil assays, have provided options for maximizing sales revenue in hard currency to the joint venture.

More information is available on the company's web site www.netkonect.co.uk/ mms-petroleum/bulgaria

Acknowledgments

The authors thank the Bulgarian Ministry of Environment and Waters, Pleven Oil and Gas, and MMS Petroleum Services Ltd. for permission to submit this article. Discussion on the reservoir engineering of Tulenovo field benefited greatly from technical input by Bob Harrison of Enterprise Oil plc.

The Authors