Strategy and Acreage Acquisition
SOMA’s strategy in offshore Somalia was to acquire acreage within which a diverse portfolio of drillable assets could be generated, guided by the results of two major studies on the available regional data.
Esri, USGS,OpenStreetMap contributors, TomTom, Garmin, FAO, NOAA, USGS, RPS, FGS
Two PSA blocks were selected, 129/130 in the northern Mid Somalia High (MSH) area, and 192 in the Central Mogadishu Deep Basin
Holding acreage in the two areas exposes SOMA to a portfolio of opportunities and diverse risk profile with access to the carbonate play in the somewhat shallower water and target depths of the MSH and the deeper water, deeper targets of the clastic play of the Mogadishu Deep.
Long-term Commitment to Excellence
Two Key Factors positioned SOMA Oil and Gas in Somalia it to be the license-holder for the key PSAs 129 & 130 and PSA 192 to be the preferred partner in this emerging deepwater exploration province:
Knowledge
SOMA leverages its proprietary data and cutting-edge interpretations to maintain a competitive edge in the region. .
Key datasets include:
- Seabird (2014) aquisiton of major regional 2D dataset
- RPS (2015 – 2017) interpretation of regional 2D dataset
- U3 Explore (2022 – 2023) revamping of 2D, 3D Planning, Environmental Impact Study, Oil Seep Study in MSH, New plate tectonic model
All contracted funded by SOMA and its predecessor.
Our comprehensive knowledge base ensures we are best positioned to secure exploration rights in two of the basin's most promising PSAs
Persistence and Consistency
SOMA's unwavering dedication to the basin is demonstrated through continuous and strategic initiatives, ensuring sustained growth and industry leadership.
- Pioneering seismic acquisition: Leading efforts to gather essential data
- Major studies: Conducted in 2015-2017 and 2022-2023
- Quality acreage control: Consistently acquiring the best land in the basin
Our persistent and consistent approach has cemented SOMA's position as a knowledgeable and influential player in the region, driving long-term success and value.
This unrivaled dataset empowers SOMA to make informed decisions and maintain leadership in the industry.
Pioneers like SOMA, equipped with the right knowledge and a willingness to accept the risks inherent in unexplored exploration territory, become preferred partners for later entrants. By controlling an acreage position, they can leverage a diverse portfolio of opportunities to maximize value creation and minimize risk. The diversity of physical conditions (water depth, depth-to-target) and geology (reservoir type, fluid phase, trap type) across PSA 129 & 130 and PSA 192 exemplify these favorable conditions.
"Strategy is key"
In the dynamic landscape of emerging exploration provinces, strategic focus is key. For SOMA, careful analysis determined that the Jubba Deep basin presented higher technical risks and less commercial potential in the short to medium term. By deprioritizing this area, SOMA can concentrate investment capital and efforts on PSAs with greater value and potential, ensuring a more efficient allocation of resources and maximizing the prospects for successful exploration.
The Mid Somalia High Basin
The carbonates in PSA 129/130 in the MSH are the highest priority and lowest risk exploration targets, with large tilted fault-block structures easily mapped on the seismic data where reservoirs occur adjacent to oil-generating source rocks.
In the Mid Somalia High on PSA 129 & 130, carbonate reservoirs were deposited adjacent to the source rocks in the deeper part of the basin
The Mogadishu Deep Basin
In the Mogadishu Deep in PSA 192 potential reservoirs (yellow) occur in the Lower and Upper Cretaceous and the Palaeocene with migration of hydrocarbons from the deeper Jurassic
PSA 192 in the Mogadishu Deep provides access to sandstone reservoirs with a potential variety of trap types at three stratigraphic levels, but at somewhat higher risk than the MSH because the targets are less well defined on the seismic data and were deposited further from the source rocks
Offshore Somalia is a Frontier Basin
The history of exploration in a basin can be graphically illustrated by constructing a “Deepwater Creaming Curve”, which charts the volumes discovered in a basin against a measure of the exploration effort, usually time elapsed or number of wells drilled. In immature or frontier basins the very largest opportunities are usually drilled first because they are literally the easiest ones to map even on sparse data, and because only very large discoveries can overcome the financial hurdles of developing a discovery in an area without infrastructure. For this reason, typical creaming curves kick off from the time axis very steeply, and flatten over time as smaller opportunities become viable targets.
The above illustrates this phenomenon in a number of basins that have been successfully drilled in the past decade.
In common with Offshore Somalia, these are typical deepwater Frontier Basins where technical and commercial success depends on establishing as comprehensive an understanding as possible of the evolution of the basin and its petroleum systems before wells are drilled.
Size Matters in Frontier Basins
SOMA's PSA129 &130 encompasses approximately 6,000 km2, and 192 with 5,000km2. This area is equivalent to the size of one quadrant in the UK North Sea, a rift basin like Offshore Somalia featuring Jurassic source rocks and reservoir rocks from the Jurassic to the Palaeocene. In Quadrant 211 of the North Sea's Brent Province, over ten billion barrels of oil in place have been discovered since blocks were first licensed in the 1970s. The PSAs are in water depths of between 2,500m and 3,500m, so are considered "ultra-deep" exploration areas
Only two wells have been drilled Offshore Somalia in over forty years. Since the second of those in 2008, the data that has been collected and studies that have been undertaken have generated a sufficient level of understanding that the basin is ripe for the curve to “kick off”. This is the best time to enter the basin, which makes SOMA’s position very valuable.
In frontier basins the area of blocks is often significantly larger than in more mature basins where data density and the availability of infrastructure allows governments and companies to target smaller opportunities. This makes it more likely that early entrants, holding acreage with 100% interest, will control large drillable opportunities 100%.
Predicted Volumes in the PSAs
In the RPS Study conducted from 2015 to 2017, two major prospects were identified in PSA 129/130:
9.8B
N-B STOOIP
Total Stock Tank Oil Initially In Place for N-B prospect
3B
N-B Recoverable
Total Recoverable Oil for N-B prospect
6.3B
N-G STOOIP
Total Stock Tank Oil Initially In Place for N-G prospect
1.6B
N-G Recoverable
Total Recoverable Oil for N-G prospect
N-G is entirely within the PSA, while N-B is 80% on the PSA and 20% on adjacent PSA 131. The U3 study also recognized these structures as geologically similar, characterizing NB as a Lead Area.
RPS Volume Estimate
Unrisked STOOIP is approximately 16.1 billion barrels on PSA 129/130.
For PSA 192, the RPS study identified two prospects in the Middle and Upper Cretaceous:
5.1B
C-Q STOOIP
Total Stock Tank Oil Initially In Place for C-Q prospect
1.5B
C-Q Recoverable
Total Recoverable Oil for C-Q prospect
287M
C-X STOOIP
Total Stock Tank Oil Initially In Place for C-X prospect
86M
C-X Recoverable
Total Recoverable Oil for C-X prospect
RPS Volume Estimate 192
Unrisked STOOIP is approximately 5.38 billion barrels on PSA 192.
U3 Study
The U3 study recognized these structures as a single closure on the depth-converted seismic but did not assign prospect status due to the sparse data grid. It also noted potential for further stratigraphic trap prospectivity in Block 192 in both the Upper Cretaceous and Palaeocene intervals, pending 3D seismic acquisition.
A Success - Case
By analogy with GALP's success in Namibia in a scenario where PSA 129 & 130 and PSA 192 both prove to be successful more than 30 billion USD of value will potentially be created.
Somalia will write history in East Africa and propel itself forward.
Unrisked STOOIP is the total estimated oil in a reservoir without considering risks. Risked STOOIP adjusts this estimate by incorporating the probability of geological success, providing a more realistic figure for potential oil recovery.
So what about Madagascar
A bit of History
All sedimentary basins, hydrocarbon-bearing or not, form as a result of the downward collapse of part of the earth’s crust, which is usually related to the relative motion of the tectonic plates that make up that crust. The Somali offshore basins formed when a very large continent located at the time just south of the equator began to break up, a process which began in the early Jurassic when a fracture in the crust called a rift opened up to form a basin. The two sides of the basin were the part of the African continent that would become Somalia to the west, and what is now the north-west coasts of Madagascar and India to the east.
In a good news vs. bad news story, source rocks of Jurassic and Cretaceous age have been sampled Offshore and Onshore in Madagascar (good news for the presence of source rock in Somalia), but while where there are also abundant oil seeps and an onshore tar-sand belt in Madagascar, there have been no commercially significant oil discoveries. Is that bad news for Somalia?
The 2022/23 U3Explore study explained why Somalia and Madagascar are different. The predominant crustal deformation involved in the formation of the rift basin is downward tilting in an extensional tectonic regime. The complex forces in play in the rift as the plates of the Sechelles and India moved away, however, resulted in the application of compressive forces on the Somalian margin which resulted in uplift in some regions, a process known as Inversion.
The result of this uplift on the Somali margin was the formation of a large arch and trough in the Mogadishu Deep, and also uplift in the MSH. This uplift focused migration of fluids onto the highs/traps. This phase of inversion did not affect the margin in Madagascar, where the passive margin retained a consistent slope out of the basin, no large traps formed, and much of the generated hydrocarbon migrated out into surface seepage and formed the tar belt.