Large petroleum deposits in tight reservoirs
Substantial quantities of oil and gas can be found in tight reservoir zones which are challenging to produce. That applies in part to rocks buried deeper than 4 000 metres in the Central and Viking Grabens in the North Sea and on the Halten Terrace in the Norwegian Sea. A commitment to new and improved technology will be important for boosting the productivity of these challenging reservoirs and thereby making profitable recovery possible.
High pressure, high temperature (HPHT) and cementation as a result of increasing depth help to complicate recovery from tight reservoirs. In some cases, sandstone may have well-preserved porosity and permeability despite great depth. This could reflect the presence of chlorite and kaolinite, which prevent quartz cementation. Smørbukk and 6406/2-1 Lavrans are examples of fields and discoveries in the Norwegian Sea where chlorite has contributed to good reservoir quality.
The alternation between zones with quartz cementation and chlorite presents a challenge in tight reservoirs. As a rule, reliable mapping of the extent of good sand in the reservoir will be difficult. A good understanding of the depositional environment is important for predicting both high- and low-permeability zones in the best possible way.
Condensate blocking is one challenge which may be faced in low-permeability gas and condensate fields. When reservoir pressure falls below the dew point, condensate will precipitate and Liquid can accumulate around the well. That lowers the relative permeability of the gas and reduces flow properties in the reservoir, which can lead to poorer well productivity. Certain reservoir zones with low permeability in the HPHT Kristin field present challenges precisely for this reason.
Click on the maps to see the various zones.
A number of fields and discoveries which consists completely or partly of tight sandstone reservoirs are located along the western side of the Halten Terrace in the Norwegian Sea. They lie primarily in HPHT areas, as shown in map 1. Large parts of their reservoir rocks are assumed to have tight zones as a result of quartz cementation. Largely of Jurassic age, these rocks lie deeper than 4 000 metres in the Åre, Tilje, Tofte, Ile and Garn formations.
Examples of discoveries and fields with tight sandstone reservoirs are 6406/9-1 Linnorm, 6506-1 Victoria and Kristin. These three deposits are estimated to have resources in place of 300-450 million scm oe, of which as much as 250 million scm oe are thought to lie in tight reservoir zones. Up to 30 per cent of the Ile, Tofte and Tilje formations in 6406/2-1 Lavrans have permeabilities of 0.01-0.1 mD. The Garn formation is regarded as tight in 6406/2-1 Lavrans. In the Smørbukk deposit, large resources are estimated to occupy tight reservoir zones in the upper and middle parts of the Tilje formation.
Map 1. HPHT map of the Norwegian Sea. Fields and discoveries located in the Jurassic high-pressure regime are estimated to contain big remaining resources in tight reservoir zones
Southern North Sea sector
Large resources are located in tight chalk reservoirs in the Central Graben at the southern part of Norway’s North Sea sector (map 2). Recovery from discoveries and fields in these areas faces some of the same challenges encountered in the Norwegian Sea. The chalk deposits have very low permeability, and production from them is often dependent on fracturing the rock. Tor, Albuskjell, Edda and Valhall are examples of fields with large remaining resources in tight chalk reservoirs. The original resources in place in these four fields are estimated to total around 800 million scm oe.
Reservoirs in the Tor, Albuskjell and Edda fields, which have ceased production, comprise the Tor and Ekofisk formations. These alternate between tight and moderately porous layers. Resources originally in place in these fields are estimated at about 300 million scm oe. When they ceased production, their recovery factor was 20-30 per cent. The tight reservoir zones lie primarily in the Ekofisk formation. According to NPD estimates, most of the oil now produced from Tor and Albuskjell came from the Tor formation. This is the easiest formation to produce from. The NPD assumes that large resources remain in the Ekofisk formation.
Valhall is producing from the Tor and Hod formations. The Tor formation is more permeable and produces better than the Hod formation. Resources originally in place in the field are estimated to be just over 500 million scm oe, with a recovery factor of about 35 per cent (resource categories 0-2).
Map 2. The southern part of Norway’s North Sea sector, showing discoveries and fields with large remaining resources in tight chalk reservoirs.
Northern North Sea sector
Tight reservoirs are also found in the Shetland group, which lies above the main reservoir in the Gullfaks and Oseberg fields (map 3). A revised plan for development and operation (PDO) of Gullfaks secured government approval in 2015. This includes producing the resources proven in the Shetland group.
The latter is estimated to contain resources in place of 100-800 million scm oe on Gullfaks and Oseberg. Producing from these rocks has proved challenging, and the recovery factor is very low.
Producible hydrocarbons have been proven in the basement rock on the Edvard Grieg field in the Utsira High area. Such rock is generally hard and tight, but in this area is more porous and fractured as a result of diagenesis and tectonic movements. Hydrocarbons have subsequently migrated into the basement rock.
Map 3. Extent of the upper part of the Shetland group in the northern part of Norway’s North Sea sector. The interpretation has been modified from the FMB software belonging to TGS.
Technology progress can ensure value creation
An earlier NPD study of a gas discovery with a tight reservoir in the Norwegian Sea found that efficient production would require drainage points created by hydraulic fracturing throughout the reservoir. This method involves generating fractures in a reservoir by injecting water and Chemicals.
READ ALSO: Well technology in tight reservoirs
The Åsgard field has tight zones in the parts of the Tilje formation in Smørbukk, while parts of the Garn formation in Smørbukk Sør are regarded as tight. Hydraulic fracturing has previously been used to boost productivity on Smørbukk.
Åsgard is also the only field on the Norwegian continental shelf (NCS) where the Fishbone technology developed in Norway has been utilised. This was done in a tight reservoir on Smørbukk Sør. The latter was discovered in 1985, but was earlier considered non-commercial because of low-permeability zones. During testing of the technology, about 150 “fishbones” with a diameter of 12 millimetres were drilled 10-12 metres out from the borehole with the aid of rotating turbines.
FOR MORE INFORMATION, SEE statoil.com Smørbukk Sør Extension
The ease with which a liquid or a gas flows through porous media. Measured in Darcys.
1 Darcy = 1 000 milliDarcys (mD).
A reservoir with low permeability, often defined by the following values:
- lower than 0.01 mD for a gas-filled reservoir
- lower than one mD for an oil-filled reservoir
By comparison, unconsolidated sand has a permeability of more than 5 000 mD. Concrete can have a permeability between 0.1 and one mD. Unconventional tight shale-gas reservoirs may have a permeability below one mD.
Conventional and unconventional petroleum resources
Unconventional petroleum resources is a collective term for oil and gas deposits which cannot be recovered commercially with conventional production wells and technology. This is usually because flow to the wells would be very low.
Chlorite is converted from iron minerals washed out in brackish water and then buried, and grows on quartz grains. It can hinder quartz cementation and thereby preserve permeability.
This can arise at depths below 4 000 metres, and reduces reservoir properties by filling pore spaces with quartz. That in turn means poorer flow properties for oil and gas.
When reservoir pressure falls below the dew point, condensate precipitates out and liquid may accumulate around the well. This in turn reduces the relative permeability of the gas, worsens flow properties in the reservoir, and may result in poorer well productivity.
A high pressure, high temperature reservoir, often defined as a pore pressure gradient of 0.8 psi/ft and a downhole temperature greater than 149°C.
Pore spaces as a percentage of the total volume of a rock.
The relationship between the quantity of petroleum which can be recovered from a deposit and the amount originally in Place.