Karoo Basins

Shale Gas

The southern main Karoo basin of South Africa is considered prospective for shale gas exploration.Currently the Permian Whitehill Formation is thought to be most favourable target formation for shale gas exploration and production, owing to the high total organic content (TOC) averaging 5%, favourable maturities (Ro = 1- 4 %), thickness (30m average), depth (>1500m) and regional continuity of this formation. Furthermore, given the relatively high TOC and it proximity to the Whitehill Formation, the underlying and overlying Prince Albert and Collingham Formations are also of commercial interest.

The first Technical Cooperation Permits (TCPs), in respective of shale gas assessment, were awarded between 2009-2010 to Falcon Oil and Gas, Shell B.V. International and Sasol-Chesapeake-Statoil consortium. In 2010, the first Exploration Right (ER) applications were received from Shell B.V. International, Falcon Oil and Gas and Bundu Oil and Gas (Pty) Ltd. Subsequent to the initial ER applications, National Government declared a moratorium, from 2011 over the mid and southern regions of the Karoo Basin. As yet no exploration activities, except for a few academic studies, for shale had commenced.

ER applications received prior to the 2011 moratorium were exempt from moratorium conditions and is currently being reviewed and administered by the Petroleum Agency SA to be recommended for approval or refusal by the department of Mineral Resources. Currently the work programmes do not include hydraulic fracturing for the first three years and the moratorium still remains on new applications.

The Main Karoo basin is considered an active petroleum system based on oil and gas shows documented within well reports and published literature. In 1968, exploration well CR1/68 in the southern main Karoo Basin yielded a gas flow rate of 1.83 mmscf/day for 23 hours from the fractured Fort Brown shale. The Fort Brown was thought to be self-sourcing (i.e. a gas shale), but may also have been charged by the underlying Whitehill Formation.

The shale gas resource within the Main Karoo basin remains highly speculative, due to the lack of geochemical and geophysical data, however technically recoverable gas-in-place scenarios suggests volumes range between 30 Tcf to 485 Tcf (Petroleum Agency SA, 2012, 2013, 2014, 2015, 2016, 2017; EIA, 2011, 2013) . The internal estimate devised at the Petroleum Agency SA as of 2018, is 205Tcf, this estimate includes the Prince Albert, Whitehill and Collingham Formations.

A major exploration risk factor is the existence of dolerite intrusions, which occur in much of the Karoo Basin. The dolerites could have possibly compartmentalized the shales, metamorphosed the shales and perhaps overcooked the shales overmature). Although exploration activities in the Karoo Basin is yet to kick off, the basin is still considered highly prospective for shale gas resource, but such a resource potential will remain inconclusive until exploratory drilling and hydraulically fractured test wells produce commercial quantities of gas. Shale gas exploration will also depend upon the gas market prices and if the resource is of economic feasibility. Shale gas exploration could possibly create many jobs in the outlying areas of the rural Karoo, however significant capital will need to be invested to develop the infrastructure which is lacking in these areas.

Coal-bed Methane (CBM)

Coal bed methane (CBM) is a source of natural gas that is generated and stored in coal beds. Coal therefore acts as both the source and reservoir rock, with the methane being produced by microbial (biogenic) or thermal (thermogenic) processes. Coal has a large surface area and can hold enormous quantities of methane. Since coal seams have large internal surfaces, they can store on the order of six to seven times more gas than the equivalent volume of rock in a conventional sandstone gas reservoir. CBM exists in the coal in three basic states: as free gas; as gas dissolved in the water in coal; and as gas “adsorbed” on the solid surface of the coal.

In South Africa, the presence of methane gas in coal is well known from its occurrence in underground coal mining, where it presents a serious safety risk. Historically, the methane was vented to the atmosphere, but is now becoming an increasingly important source of natural gas globally. The coal deposits in South Africa are found within the Karoo basin and fault bounded rift basins further north. These basins are host to large volumes of coal and where the coal concentrated with methane gas, this holds potential for significant future sources of energy

The Deep Biogenic Gas (DBG)

The Deep Biogenic Gas (DBG) refers to the occurrences of hydrocarbons in the deep mines within the Witwatersrand Basin in South Africa. DBG is an unconventional gas produced at great depth directly by microorganisms during respiratory and fermentative processes (microbial gas). Substantial quantities of hydrocarbon gases have been observed within the Witwatersrand Basin during both coal and gold exploration activities. The gas is composed predominantly of methane, and other hydrocarbons including helium. Gas shows were discovered in the Free State and Evander goldfields several decades ago, and are the most promising target areas for DBG exploration at present.

The methane encountered in underground gold mining of the Archean Witwatersrand Basin in the Free State and Evander goldfields was regarded only as a mine explosion hazard and flared in large quantities. As such, local gas shows at surface have also been known to burn for years without showing any evidence of depletion. Gas encountered is not generally contained in traps but rather is being continually generated at depth and migrating to surface along natural fracture systems, faults and dykes. Published data indicates that much of the produced gas is of microbial origin, generated by primitive bacteria that inhabit deep water-bearing fissures. It is thought that additional gas may be generated within the carbonaceous shale and coal-bearing Karoo strata at shallower depth. However the source and migration pathway of the gas are unusual and present significant challenges to fully define the ultimate potential of the resources as no known analogues exist for this type of gas production.

Most recently, Molopo Exploration and Production (Pty) Ltd in South Africa has been granted the Production Right in the Free State goldfields, with first proven onshore gas reserves for the region. This former mining hazard may therefore become a potential renewable future energy source for South Africa.

Conventional oil and gas

South Africa’s offshore basins can be divided into three distinct tectonostratigraphic zones. The western offshore comprises a broad passive margin basin related to the opening of the South Atlantic in the Early Cretaceous. This is known as the Orange Basin which is the largest offshore basin.

The eastern offshore is a narrow passive margin that was formed as a result of the breakup of Africa, Madagascar and Antarctica in the Jurassic.

Very limited deposition has occurred here and only the Durban and Zululand Basins contain an appreciable sedimentary section. The southern offshore region, known as the Outeniqua Basin, shows a history of strong strike slip movement during the Late Jurassic – Early Cretaceous breakup and separation of Gondwana. The Outeniqua Basin consists of a series of en echelon sub-basins (the Bredasdorp, Pletmos, Gamtoos and Algoa basins) each of which comprises a complex of rift half-graben overlain by variable thicknesses of drift sediments. The deepwater extensions of these basins (excluding the Algoa Basin) merge into the Southern Outeniqua Basin.

Upper Palaeozoic

Subduction on the southwest margin of Gondwana in the Late Carboniferous – Early Permian led to the transformation of an old passive margin into a foreland basin (the Great Karoo Basin). Further convergence in the Permo-Triassic led to the development of the Cape Fold Belt which extends from Australia through Antarctica and South Africa to South America.

Mesozoic and Tertiary

Following erosion and peneplanation there was a phase of widespread volcanism in the Early to Middle Jurassic in southern Africa, the Falklands and Antarctica. This provides the first evidence of the impending breakup of Gondwana.

At this time the Falkland Islands lay off the south or southeast coast of South Africa . Breakup started on the eastern margin of Africa with Madagascar and Antarctica beginning to move away in the Middle Jurassic. This initiated the formation of the Durban and Zululand basins.

During the Early to Mid-Cretaceous a complex series of microplates including the Falkland Plateau gradually moved west southwestwards past the southern coast of Africa creating important dextral shearing of the South African margin. This created the Outeniqua sub-basins as a series of oblique rift half-grabens which may be regarded as failed rifts, oldest in the east and youngest in the west.

The rift phase on the south coast ended in the Lower Valanginian , but was followed by at least three phases of inversion related to continued dextral shearing. This ended in the mid-Albian with the final separation of the Falkland Plateau from Africa. This transitional rift-drift phase was followed by development of a true passive margin. The Lower Valanginian drift-onset unconformity on the south coast is contemporaneous with the earliest oceanic crust in the South Atlantic.

The Orange Basin was initiated as a series of isolated and linked north-south trending grabens during the Lower Cretaceous. The drift-onset unconformity here is dated as Hauterivian, somewhat younger than in the Outeniqua Basin. A rift-drift transitional phase in the Orange Basin occurred until the Early Aptian. Later Cretaceous and Tertiary sedimentation took place in a marine passive margin setting.

All these basins are generally clastic in nature and have been explored over the last few decades for both oil and gas. Gas production has been ongoing since the middle 90’s from shallow marine sandstones on the flanks of the Bredasdorp Basin, while oil has been produced from mid-Cretaceous aged basin floor fan deposits in the central basin. Interest in exploration has recently increased dramatically and large areas of the South African offshore, including very deep water acreage, are currently being explored.

Ultra Deep Offshore and Gas Hydrates

Frontier Offshore encompasses those areas which have seen minimal exploration up to and beyond the 200NM EEZ. Little or no geoscience data (e.g. wells, seismic), a lack of geological knowledge and understanding, are some of the key stumbling blocks in these regions. In the Orange Basin for example, ultra-deep waters in excess of 3000m adds to the challenges in investigating these areas by traditional methods alone. However, recent advances in geophysical acquisition and remote sensing techniques have made these offshore areas more accessible to exploration.

The Agency embarked on a frontier pilot project in 2010 within the Orange Basin. Existing data such as wells, seismic, etc. available on the Continental margin on the West Coast of South Africa were used to extend geoscience interpretation into frontier regions. The Orange Basin Basin Analysis (OBBA) project aims to address and aid current knowledge and understanding of the Basin, in particular the deeper parts. Ultimately the project hopes to unlock new conventional and unconventional resources.

One of these unconventional resources, gas hydrates occurs in permafrost regions of the arctic and in deep-water along continental margins worldwide. Gas hydrates are solid ice-like structures in which mostly methane are trapped within water-cage like molecules. It is important because it contains vast volumes of methane which indicates its potential as a future energy resource. Secondly extracting gas hydrates may affect sediment strength, which can initiate landslides along a continental slope and rise. Lastly the release of gas hydrates to the atmosphere can influence global climate. Gas hydrates can be studied in two ways: wells and on seismic reflection lines as Bottom Simulating Reflectors (BSRs). A BSR is formed on seismic reflection lines because of a contrast in velocity generated by the hydrate-cemented zone. The stability of natural gas hydrates is primarily affected by temperature and pressure, and secondary by pore fluid salinity, the nature of gas enclosed and the grain size of the host material.

BSRs have been recognized on multichannel seismic imagery along the South African continental margin, especially along the upper continental slope in the regions of the Orange River delta. Though no discoveries have yet been made, gas hydrate has been discovered north of the Walvis Ridge offshore Namibia. Gas hydrates along the South African margin are stable at water depths >420m and bottom-water temperatures of ~7°C.

Estimation methods to delineate and quantify the amount of gas hydrates are: acoustic impedance inversion of seismic data, Vp/Vs, Rock Physics, AVO and seismic attribute analyses. Until recently, only two methods for extracting methane from hydrates offshore were employed. One was the release of pressure of the hydrate by drilling a hole into it, the second by pumping in steam or hot water, releasing the methane from the hydrate. A third method recently introduced is CO2 injection.

The Agency initiated a gas hydrate project in 2011 along the west coast of South Africa in order to document the existence and regional distribution of gas hydrates.