SOUTH SUDAN
MOG Energy through its subsidiary SSTO has a 5% working interest in a significant oil producing asset in Sudan Block 3&7, where further exploration and development are ongoing.
The blocks are operated by DarPetroleum Operating Company (DPOC) – a joint operating company of CNPC China, SINOPEC China, Petronas Malaysia, Nilepet and SSTO Egypt.
Blocks 3D, 3E and 7E in The Republic of south Sudan are governed by an Exploration and Production Sharing Agreement (EPSA) that was executed on 12 March 2027.
An extensive exploration campaign has been on-going since 2000. Since 2002 a world-class exploration effort has been executed, often under difficult conditions due to flooding by the Nile River. The three large Blocks cover three distinct sub-basins – the most northerly Ruat Basin, the North Melut Basin and the South Melut Basin.
By the end of 2006 a total of 153 wildcats and appraisal wells had been drilled, of which only 33 have been “dry”, and 25,466 km of 2D seismic and 3,579 km2 of 3D seismic have also been acquired to guide the exploration and development programs. The exploration campaign has led to major oil discoveries. More recent discoveries have been much smaller as the exploration effort has matured, although attention is now moving to other “play” types.
Each field typically comprises a number of separate tilted fault blocks. The main reservoirs in all the fields are fluvial sandstones in the Yabus and Samaa Formations of Palaeogene age. Each formation comprises a number of discrete highly porous and permeable sandstone layers separated by shales. Reservoir porosities are typically 20-30%, and permeability 0.5-10 Darcie’s.
The initial phase of development of Sudan Blocks 3D, 3E and 7E has been completed and oil production started in late July 2006 at an initial rate of 175 Mstb/d from ~110 wells in the Palogue, Anbar-Assel, Adar Yale and Agordeed fields.
Oil gravity ranges 20 to +30 API but is predominantly 24-28 API. The reservoirs are under saturated with solution gas ranging 50 -85 scf/bbl – all gas is currently flared but future plans include a gathering system to collect gas to fuel power generation. Water cut currently ranges are to 70%. Produced water has very low salinity and is treated to recover residual oil and then utilized for agricultural irrigation.
In 2009, two substantial fields Moleeta and Nahal were on production. The average oil production rate was about 293 MBOPD during 2010 and about 264 MBOPD during 2011. The drop in the average rate during 2011 is due to the event of Sudan splitting to two countries Sudan and South Sudan. The cumulative oil produced is 487 MMbbls exported through the pipeline and marine terminal in Port Sudan.
In Feb 2012 production and wells were completely shut-down for 15 months and production resumption was in April 2013. Oil production rate achieved +200 Mbopd from 75% from the total wells.
In 2018 the production rate is around 120-130 Mbopd from 90% of the total wells due to security issues. All wells are artificially lifted by electric submersible pump (ESP) or progressive cavity pump (PCP). Greater Palogue (currently called Paloch Field) is the largest field with over 60% of the total block reserves; Palogue, Moleeta and Gumry combined represent nearly 80% of the block reserves as of the end of 2018. Approximately 22 additional discoveries are yet to be fully appraised– many of these are one- well discoveries.
Current installed 7 major fields comprise a central processing facility (CPF – 300 Mstb/d oil export capacity), a crude oil powered power generation plant, four field production facilities (FPF), seven field transfer facilities (FTF), wells, gathering lines and power transmission and distribution systems. Oil export is by a dedicated ~1,400 km 32” diameter pipeline system to a terminal at Port Sudan. The pipeline system has six pumping-heater stations and has been sized for up to 500 Mstb/d. The pipeline is operated by BAPCO from a central control room near Khartoum.
According to the current SPE/WPC guidelines and standards, P2 STOIIP and reserves were estimated for these fields based on recoveries under natural aquifer drive alone as well as water injection for the four (4) main fields. The cumulative oil production from all field as of 31 December 2020 is 842 MMSTB.
Operator’s current is implementing water injection projects for the major four fields as (IOR) meantime taking place pilot tests for chemical enhanced oil recovery (EOR) application of “field-proven reserves” to upgrade and enhance the recovery factor.
Two technical meetings for partners and governmental representative called Exploration and Development Technical Reviews (ETR and DTR) used to be held twice a year to review all subjects, technical issues, and budget related to both exploration and development plans and field performances to follow up and guide the operator to achieve targets. In additional to JOC’s and board meetings to approved WP&B. SSTO has a significant rule in all of these technical or high level meetings as a result of high caliber contribution from technical, financial and management team.
