The 16th Torton horizon (Matzen Sand) of the Matzen field in Austria is the largest oil reservoir in Austria. With about 87 MMcm of oil initially in place and 2.7 Bcm of free gas initially in place, it is one of the biggest fields onshore Europe.

Figure 1. Top structure map of the 16th Torton reservoir of the Matzen field. The reservoir consists of several compartments that are connected via a common aquifer.


In 2006 and 2007, an integrated study was performed to optimize production from this mature field, which started in 1949. The study aimed at identifying opportunities for additional wells and optimizing reservoir management after almost 60 years of production.
A comprehensive numerical model was constructed, history matched and used for optimization of the field production. Following is the geological setting of the field. Then the production history and reservoir drive are described. Afterwards,
Figure 2. Increase in oil production due to field optimization. A substantial further increase is expected after full implementation of the new reservoir management concept.
production optimization and results of the optimization are delineated.

Reservoir description

The Matzen field is located about 12 miles (20 km) northeast of Vienna in the Vienna Basin. It consists of many stacked sands. One of the reservoirs is the 16th Torton horizon. The reservoir is separated by faults into different compartments. The compartments are in communication via a common aquifer.

The average permeability was about 1.2 Darcy, average porosity 25% and average initial water saturation was 15%. Permeability determined in cores ranged from 18 mD to 10 Darcy. The average oil sand net thickness was 56 ft (17.1 m). The initial gas cap sands have an average net thickness of 28.5 ft (8.7 m). The oil gravity is 25°API and the viscosity is about 5 cP. The initial solution GOR was 45 m3/m3. The initial oil/ water contact was located at a depth of 4,888 ft (1,490 m) subsea and the initial gas/water contact at a depth of 4,773 ft (1,455 m) in the main area. The initial pressure was 160 bar at the depth of the oil/water contact. The reservoir temperature was 138°F (60°C).

Production history

The first well that encountered the 16th Torton horizon was drilled in March 1949. Peak oil production of about 7 Mcm/d was achieved in 1954. Since that point in time, oil production steadily declined.

In December 1967, a flank water injection scheme was implemented. Water flooding decreased the decline rate, which was about 8% per year prior to water flooding to about 4% per year after water flooding.

The wells were completed first deep in the reservoir to produce oil from the lower layers and from areas below local limestone layers. After the wells watered out, they were re-completed further up.

Cumulative oil production until 2007 has been 42 MMcm of oil and 3.75 Bcm gas. The current water cut is about 93%.

Reservoir drive mechanism

For the first almost 20 years, the reservoir was produced without water re-injection. The pressure declined; however, aquifer influx was significant. Due to the fact that the pressure declined, water injection was started in late 1967. Since then, the drive mechanism is characterized by edge water drive with coning and cusping.

In the western part of the reservoir, only small initial gas caps were present which expanded due to gas coming out of solution. The largest area of the reservoir in the eastern part contains a large gas cap, resulting in some gas/ oil gravity drainage. The flood performance is influenced by the poor mobility ratio (water viscosity 0.6 cP,
oil viscosity 5 cP).


Production optimization


To optimize production from the 16th Torton horizon, several scenarios were investigated. To facilitate the simulation, the horizon was split into several compartments by using streamline simulation. In order to capture uncertainties, assisted history matching and forecasting including uncertainties was used.

Even the most pessimistic case resulted in economically attractive infill drilling projects. Hence, three wells were drilled in late 2007 and early 2008. In addition to infill drilling, optimizing production by increasing production and water injection rates and limiting the gas/oil ratio was investigated. The results indicated that substantial incremental oil production can be achieved. In 2007, the new field management was implemented.

Results

As mentioned above, three infill wells were drilled in late 2007 and early 2008. The wells encountered a total of more than 196 ft (60 m) of sands with high oil saturations. The fourth well will be drilled in late 2008. These results show that even in a field with almost 60 years of production, significant additional sands with high oil saturations can be found. These wells will be brought onstream in the third quarter of 2008.
In late 2007 and early 2008, the first projects to optimize production from this reservoir were performed. Production was optimized, wells exceeding the suggested gas/oil ratio limit were shut-in, and water injection was improved.


Figure 2 shows the results of this field optimization, the highest oil production in more than 15 years has been achieved and the oil production trend is still increasing.

Increased liquid production leads to substantially more fluids that have to be transported to facilities, separated and injected. The surface facilities available have limited capacity. Also, the facilities were distributed over several places. Therefore, the decision was taken to completely renew the facilities to reduce OPEX and increase liquid production rates. Also, two additional injection wells are in the drilling sequence to optimize reservoir management. So far, quick wins were realized. It is expected that the full implementation will lead to substantial additional increase in oil production rate from this mature field.


Even after almost 60 years of production, significant optimization potential exists in the 16th Torton Horizon of the Matzen field. This potential was identified by an integrated study.
Using production forecasts including uncertainty, it could be shown that infill drilling opportunities with low risk exist. Three out of the four wells which were proposed have been drilled, all three were successful.


In addition, optimizing gas/oil ratio limits, water injection, and liquid production lead to significant increase in oil production. In combination with renewal of the facilities, further production increase is expected at reduced operating costs.