The Case
Request NDA
A Deeper Dive:
Discover a technical deep dive into the methodology of Soma and its data. Uncover the innovative approaches and detailed processes that drive Soma's data-driven insights.
Database and Technical Studies

The geology and petroleum system of the Offshore Basins were characterized in two studies, both of which were underpinned by the 2014 Seabird 2D seismic dataset , supplemented by a public-access satellite gravity and ship-borne magnetic datasets, published literature and commissioned studies , most notably the new 2022 plate tectonic model, and the 2023 Satellite Seep study.
Map of the 2014 Seabird 2D survey, shot with an average line spacing of 20 x 10km
Map of the 2014 Seabird 2D survey, shot with an average line spacing of 20 x 10km

Methodology & Credits

RPS Energy From 2015 to 2017 RPS Energy concentrated on establishing a geologic context for the evolution of the Somali coastal basin. It incorporated a review of all available well data and literature information to establish a stratigraphic framework for the basin, which was integrated with an open-source plate tectonic model and gravity and magnetic data to provide a context for interpreting the regional 2D time-domain seismic grid. Using the well and seismic data from in and around the basin, RPS constructed a comprehensive sequence-stratigraphic overview of the evolution of the fill in all three basins The resultant seismic-stratigraphic picture of the basin and structural surface maps were used to generate a prospect inventory, with the ranged volumetrics of each prospect quantified using literature analogues for reservoir and source rock properties and 1D well models for hydrocarbon phase potential. In higher risk areas, they designated some structures as leads when they did not have sufficient information to define risks and volumes, for example the “Mid Jurassic high relief reef” facies in the MSH. U3 Explore From 2022 to 2023 The U3 Explore study built on the seismic-stratigraphic and sub-basin framework developed by RPS and previous workers, and concentrated on refining and revamping the understanding of the geologic context for their development. The seismic data were converted into the depth domain, providing a more reliable context for understanding geologic geometries in the basin, and an updated plate tectonic model established an improved context for source rock deposition in the basin, both of which were important inputs to a 3D petroleum systems model. The study refined the play fairway models for the basin, providing additional context for the definition of prospectivity, for example recognizing the potential for a Palaeocene stratigraphic trap play in the Mogadishu Deep. The diagram depicts the shift from exploring multiple possibilities (divergent thinking) to focusing on specific prospects (convergent thinking). The study reaffirmed that both 129/130 and 192 are highly prospective blocks, no specific mapped prospects were defined as it was determined that the sparse 2D database and very limited well control did not support the definition of traps beyond the recognition of leads Clément Blaizot Oil Seep Study The Oil Seep study, conducted by consultant Clément Blaizot (France), utilized high-coverage Satellite Synthetic Aperture Radar (SAR) data to detect offshore oil seeps in a 73,500 km² area encompassing the Mid Somalia High. World map with green-highlighted coastal and offshore regions across various continents, representing areas where 30,000,000 km² were studied using 30,000 SAR images, resulting in 30,000 interpreted oil seeps. The methodology involved analyzing a minimum of 50 and a maximum of 93 SAR dates per point to highlight potential natural hydrocarbon leakages, minimize the impact of "lookalikes" (such as atmospheric, oceanic, and biological artefacts), and flag pollution and human activities. The study results included a PDF report detailing the detection methodology and significant seep anomalies, as well as a GIS shapefile documenting interpreted potential seeps with attributes like the date of the SAR image and a confidence index. Greencurve EIS Green Curve Somalia has been contracted to supply parts for an Environmental Impact Study (EIS) on offshore oilfields. This study assesses the environmental and community impacts of oil operations. Methodology includes literature review, field surveys, and community consultations. Marine ecosystem analysis involves biodiversity surveys and water quality testing, while socio-economic impacts are evaluated through economic analysis and health impact studies. Predictive models and scenario analysis help assess risks, leading to recommendations for eco-friendly practices and community development programs. Findings are compiled into a report for stakeholder review and finalization. Marine ecosystem analysis involves biodiversity surveys and water quality testing, while socio-economic impacts are evaluated through economic analysis and health impact studies. Predictive models and scenario analysis help assess risks, leading to recommendations for eco-friendly practices and community development programs. Findings are compiled into a report for stakeholder review and finalization. Data and outputs from the studies are available in the post-NDA data-room.

Regional Stratigraphy

Both the RPS and U3 Explore Study, follow a similar stratigraphic interpretation, with 8 to 10 regional stratigraphic surfaces confirmed by well ties to Meregh-1 (Jurassic carbonates) and Pomboo-1 (Cretaceous clastics). These surfaces define geological intervals when significant structural and stratigraphic events occurred, for example periods of deposition of source and reservoir rocks, structural events that define trap styles and petroleum migration pathways, and the differential evolution of the major sub-basins.
Critical Evidence for a Working Petroleum Product
One of the long-standing technical questions deterring industry entry into offshore Somalia has been that of the presence and effectiveness of a source rock, as none have been penetrated in the basin. There are, however, three lines of indirect evidence for an effective source rock, two of which were described in the RPS study, and the third and most conclusive produced by a study commissioned as part of the U3 study.
1
Documentation
The first indicator is the documentation of hydrocarbons in exploration wells drilled onshore in the coastal plain between the late 1950s and 1980s. Most shows were gas, with some liquid shows in wells in the northern area of Mudug Province . The geology of the coastal plain makes it highly unlikely that any of these shows were generated locally, and both studies concluded that they must have been generated in the rift and migrated laterally out of the basin.v
2
Reflectivity
Second, The most conclusive line of evidence is provided by a radar reflectivity surface seep study in the Mid Somalia High which shows very strong evidence of repeatable liquid hydrocarbon seepage from the seabed to the surface. This phenomenon correlates very highly with the presence of liquid hydrocarbons in the subsurface in many global basins.
3
Association
Third, within the basin, local disruption of seismic signal quality, sometimes associated with stratigraphically-conformant bright zones in the near-subsurface is indicative of gas migration up through the section. Association with gas chimneys makes it unlikely that the shallow gas is of biogenic origin.

In PSA 129 specifically, an area of repeatable anomalies of moderate interpretive confidence and outside any main shipping lanes was documented
Petroleum System Analysis:

All about that Source Rock

Back to Madagascar The source-rock model developed in the 2022/23 study proposed the deposition of organic-rich facies in the basin during the early period of extension when the basin was closed to the south and restricted to the north • During the initial rift phase (commencing ca. 175-165Ma) • During the orthogonal separation phases (sag, 165-161 Ma and drift, 161-145Ma) Seismic Geometry The characteristic seismic geometry of these intervals has been documented in many rift basins around the world, and was used to map the thickness of source rock around the basin. Thickness Map A regional thickness map - The major source intervals were mapped around the data where seismic resolution permitted. This map is for the “drift” source interval, which is the shallowest, and therefore the best-resolved. These maps were an important input to the Petroleum System model, as the thickness ranges input to the model were proportional to the overall thickness of the interval. This is therefore an important constraint on the volume of hydrocarbons generated.

Volume of Hydrocarbon Generated
In order to characterize the uncertainty in the overall volume and gas/liquid phase of hydrocarbons generated in the basin 2022/23 study utilized a probabilistic 3D basin-modeling package (Trinity 3D©) to calculate ranges for the total volume of liquids and gas that could have been generated in the basin for the three prognosed source intervals, (175-165Ma, 165-161Ma and 161-145 Ma). Models were also used to test for the efficiency of migration into mapped highs to test for the possibility that they may be only partially filled.
Output from Trinity 3D© - Demonstrating the correlation between 2D Seismic and 3D Model. The surface illustrated is a potential Hydro Carbon Migration Pathway
Ranges in the model input parameters that control the phase and volume of generated hydrocarbons were derived from:
Parameters
Published data from Jurassic analogue source rocks in the Afro-Arabian plate (e.g. Hanifa Formation, Arabian Peninsula; Uarandab Formation, Ethiopia and Somalia; Mabdi Formation, Yemen; Bathonian/Bajocian and Upper Kimmeridgian, Madagascar) were used for Hydrogen Index, Total Organic Carbon, and reaction kinetics which control phase (liquid or gas) and efficiency of generation.
Volume
Ranges of relevant data measured within the basin (burial depth, geothermal gradient, source thickness, fetch area), which influence phase through time (gassier as burial proceeds) and volume.

Present-Day Maturity

The model output maps of present-day maturity and volumetric statistics for the three main source intervals, for example for the 145Ma interval, the Mogadishu Basin likely to be delivering a mix of oil and gas charge, the Jubba Deep is more gas-prone, and the Mid-Somalia high partly in the oil window.

Petroleum System Analysis: Reservoir in PSA 129 & 130
PSA 129/130 has potential primary reservoirs in the Carbonate Fairway that has been characterized on the Mid-Somalia High (MSH), with potential reservoir fairways on the crests (“Shoulders”) of the rift blocks and in the basins between the rift blocks. There are secondary reservoirs in the Triassic pre-rift sediments that form the local “basement”
The characteristic seismic geometries in the rift, sag and drift intervals facilitated mapping the source interval around the basin
The stratigraphic/seismic correlation is constrained by the nearshore Meregh-1 well (Esso, 1982) . It penetrated 2900m of Middle and Late Jurassic micritic carbonates (interpreted as deep-water) on the upthrown side of the major basin-bounding fault system.
The Meregh-1 and El Cabobe wells provide facies descriptions of the reservoirs that occur on the Mid Somalia High
The stratigraphy is also described in the onshore well El-Cabobe-1 (Circled red, Arco, 1980) which penetrated 2560m of Middle and Late Jurassic carbonates with interpreted shallow-water “calcarenites, oolite and corals” on the upthrown side of the major basin-bounding fault system.

The carbonates were deposited throughout period of the evolution of the margin as the “supercontinent” Pangea broke up:
• In continental rifts forming early lacustrine basins (175 to 160 Million years) comparable to the modern African Rift System,
• On the passive margin of a restricted seaway (160 to 145 Million years), when deposition occurred both on a stable platform and in the developing rift basin,
• On the Passive margin subject to periodic inversion to a spreading ocean basin as first Madagascar and then India (145 to 130 Million years) separated
The Jurassic stratigraphy of the margin is unusual because carbonates were deposited simultaneously in three clear domains, a stable, subsiding shelf margin; a margin affected by inversion-associated uplift, and a coeval active rift.
The three domains remain clear on the Mid Somali High today, clearly expressed in the differing burial/inversion patterns of deposition across the area

The structural domains are separated and controlled by long-lived structural zones originating in the basement, probably related to transfer zones within the Jurassic rift, and possibly inherited from a precursor Triassic rift
The “Rift Shoulder” Fairway is analogous to the proven reservoirs in algal carbonates on tilted fault block-crest carbonate reservoirs of the Santos and Kwanza basins in Brazil and Namibia respectively, and to oolite reservoirs of the Smackover Formation on the US Gulf coast. A non-producing example from a similar tectonic regime are oolite sands developed on the salt-diapiric highs of the Lusitanian Basin.
Intra-basinal carbonates identified on the sparse 2D data as either buildups in the 2015/17 study (Tertiary examples in the Philippines) or erosive remnants in the 2022/23 study (Cretaceous analogues in Mexico), either of which may have sediments of reservoir quality.
The pre-rift Triassic clastics in the rift shoulders, comparable to the main reservoirs in many rift basins, for example the North Sea Brent province.
Analogue data from published work have been used to generate ranges of porosity and permeability for input to economic models for the fairway.
Petroleum System Analysis: Reservoir in PSA 192
In Block 192, the seismic data does not have the wavelength or frequency to image with any certainty reservoir sands within the clastic interval between the Lower Cretaceous and Palaeocene, so the presence of reservoirs in the block is interpreted from models predicated on understanding the depositional history of the basin, with some support from well penetrations at Pomboo-1 and DSDP-241. Pomboo in particular has a significant interval of sands of Middle Cretceous age with good reservoir quality.

Palaeocene clastic reservoir sediments are predicted to have been funneled into the area of PSA 192 as a result of the uplift of the onshore Bur Massif in the latest Cretaceous and Palaeocene, Sediments were delivered across the coastal plain and into an inversion-related trough adjacent which onlaps onto the PSA 192 flank of the inversion high
Sediment Input Systems
Literature studies show that the Cretaceous sands in the Pomboo-1 well were derived from the intra-cratonic Anza Graben, which actively funneled clastic sediments out through the onshore/nearshore Lamu Basin into the rift. Sedimentation rates are inferred to have been very rapid, as overloading of the shelf-edge triggered the gravitational collapse of the margin and formation of the Kismaayo thrust belt. Block 192 lies in the northern part of this input system.
a geological map highlighting the Anza Graben and Bur Acaba High regions. It indicates various geological features with arrows and outlines, likely for exploration or structural analysis purposes.

Hydrocarbon Migration

Contour map with depth variations, highlighted by blue arrows pointing to significant areas along "Line 084." Advatages of PSA 192 Structurally, PSA 192 is in an advantageous position on the flank of an inversion-related structural nose that not only provides a geometry for both structural (Lower Cretaceous) and stratigraphic (Palaeocene) trapping , The image shows the general idea of migration up from the jurrasic up on to the inversion high, which is a migration focus on to inverted Nose of hydrocarbons migrating up from the deeper basin.

Seismic Depth Domain Line PSA 192
Depthline Trapping configurations in the Cretaceous and Paleaocene and potential migration pathways from the deeper Jurassic source rocks.
Trapping Configurations on Time Domain Seismic
In PSA 192, potential structural traps in the Middle to Upper Cretaceous are associated with the inversion crest, and onlaps to the rising high are a potential site of Upper Cretaceous and Palaeocene stratigraphic traps
Economic Modeling at a Glance
Soma OG is embarking on a significant offshore exploration project in Somalia. Our scoping economics analysis reveals promising potential with robust financial metrics and substantial recoverable resources. Below is a summary of our key economic findings and project details that highlight the viability and expected outcomes of this exploration initiative.

This summary is intended for pre-NDA public dissemination.
  • For detailed financial models and proprietary data, please refer to the confidential project documentation available under NDA.
  • This ensures that sensitive and detailed financial data is protected and shared responsibly.
Commitment:
  • This project underscores Soma OG's unwavering commitment to unlocking Somalia’s hydrocarbon potential.
  • By leveraging advanced exploration techniques, we aim to maximize resource discovery and development.
Economic Growth:
  • The project is poised to significantly enhance the region's economic growth, fostering new opportunities.
  • Through state-of-the-art production methods, we aim to bolster energy security and create sustainable economic benefits.
500
Million Bbls
Estimated Recoverable Resources (Small Case)
920
Million Bbls
Estimated Recoverable Resources (Large Case)
20%
IRR
Internal Rate of Return (IRR) for both cases
Small Case

1

USD 2.2 Billion
Net Present Value (NPV) at 10% Discount Rate

2

$ 42 per BOE
Full Cycle Unit Cost

3

10 Production Wells

4

10 Injection Wells
Large Case

1

USD 4.7 Billion
Net Present Value (NPV) at 10%

2

$ 40.3 per BOE
Full Cycle Unit Cost

3

17 Production Wells

4

16 Injection Wells
120,000
BPD FPSO Capacity
Small Case
250,000
BPD FPSO Capacity
Large Case
Initial Capital Expenditures (Capex):
  • Includes costs for drilling, subsea systems, and FPSO procurement.
Operating Expenditures (Opex):
  • Ongoing costs for production and maintenance.
Capex & Opex:
  • In line with comparable deepwater developments globally.

Government and Contractor Economics

Profit Oil Sharing Based on R-Factor: Government’s Share: Ranges from 15% to 50% based on profitability. The government’s share varies between 15% to 50%, adjusting to the project's profitability to ensure fair revenue distribution. This tiered structure aligns government revenue with the project's success, incentivizing efficient operations. Government Share The government captures 62.1% of the total economic rent in this conservative scenario. This ensures substantial revenue for public welfare and infrastructure development. Contractor Share Contractors receive 34.7% of the economic rent, ensuring a healthy return on their investment. This incentivizes continued participation and investment in the project. NOC's Share The National Oil Company (NOC) retains 3.2% of the economic rent, reflecting its investment and operational role. This share supports the NOC's reinvestment in future exploration and development activities. Government Share The govs share increases to 62.8% in the optimistic scenario, max national benefits. This higher share underlines the project’s importance to the country's economic strategy. Contractor Share Contractors are allocated 34.4% of the economic rent, ensuring their profitability in the more lucrative scenario. This maintains contractor interest and investment in the project’s success. NOC's Share The NOC's share is slightly reduced to 2.8%, balancing increased government revenue. This allocation still supports the NOC's operational and development activities. Contractor’s Share: Ranges from 50% to 85%. Contractors' share ranges from 50% to 85%, reflecting the balance between risk and reward. Higher profitability results in a greater share for contractors, encouraging investment and performance.

These metrics have been meticulously reviewed and validated by Rystad Energy.
This confirmation ensures that the financial projections meet industry standards and best practices.
The Small Case represents a conservative economic estimate, designed to be cautious.
It provides a lower-bound scenario to ensure project viability even under less favorable conditions.
The Large Case represents an optimistic economic estimate, showcasing potential high returns.
This scenario highlights the upside potential of the project, attracting investor interest.

For a full probabilistic model, further analysis is required to accurately classify scenarios as P10 and P50.
  • Detailed probabilistic analysis is essential to categorize the economic cases accurately as P10 and P50.
  • This further analysis will provide a more comprehensive understanding of the project's financial outlook.
Learn about our Future
Continue reading about our Future & Vision for Soma OG and Somalia