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Africa (Sub-Sahara) Sahara Group discovered hydrocarbons in three wells drilled in Block OPL 274, located onshore in Nigeria's Edo State. Olugei-1 was drilled to a measured depth of 4537 m and encountered five hydrocarbon zones, with 33 m of net pay. Oki-Oziengbe South 4 was drilled to a measured depth of 3816 m and encountered 64.3 m of net pay in 13 hydrocarbon-bearing zones. Oki-Oziengbe South 5 was drilled to a measured depth of 3923 m and encountered 91 m of net pay in 19 reservoirs. Sahara Group (100%) is the operator. The well will be drilled to a total depth of approximately 1655 m, which is expected to take 1 week.
Africa (Sub-Sahara) Circle Oil's CGD-12 well, located onshore Morocco in the Sebou permit, encountered natural gas at different levels within the Guebbas and Hoot sands. Wireline logging analysis confirmed a net 9.7 m of pay. The first test, over the Intra Hoot sands, flowed gas at a sustained rate of 2.21 MMscf/D through an 18/64‑in. The primary target, the Main Hoot sands, flowed at a sustained rate of 4.62 MMscf/D through a 24/64-in. The well was drilled to a total depth of 1232 m and will be completed for future production. Circle Oil (75%) is the operator, with partner ONHYM (25%), Morocco's national oil company. Algeria awarded four of 31 oil and gas field blocks on offer to foreign consortiums in its first auction since 2011.
Algeria awarded four of 31 oil and gas field blocks on offer to foreign consortiums in its first auction since 2011. Shell and Repsol won permits for the Boughezoul area in the north of the country, while Shell and Statoil won permits for the Timissit area in the east. A consortium of Enel and Dragon Oil was awarded permits for both the Tinrhert and the Msari Akabli areas. Circle Oil's CGD-12 well, located onshore Morocco in the Sebou permit, encountered natural gas at different levels within the Guebbas and Hoot sands. Wireline logging analysis confirmed a net 9.7 m of pay.
Conformance efforts in the Cooper Basin, Australia have been focused on treatments that have the potential to increase hydrocarbon rates. This paper describes the candidate selection process and field application of two different types of conformance treatments that were designed to increase hydrocarbon rates by reducing water rates. In all cases, production of reserves was thought to be impaired by excessive water production. In the cases where water production was decreased as a result of the conformance treatment, the wells produced at significantly higher hydrocarbon rates. Descriptions of both conformance systems (a minimally-penetrating porosity-fill sealant and a hydrophobically-modified relative permeability modifier, RPM) are provided.
The process of identifying wells that have a potential for increased oil-production rates if the water rates are reduced required modification of the traditional candidate-selection criteria. This ultimately changed how the water-production mechanisms were defined. For instance, when supported by production data, channeling was still considered as a plausible water-production mechanism even if the CBL appeared to show good cement bonding to the formation and casing. In addition, RPM technology was considered viable for upwards fining reservoir sections, even if water was coning up into the well. However, special conditions also needed to apply.
In this paper, the details of how treatment candidates were selected, treatment designs, placement techniques, and results are presented. The wells and reservoirs for each case are discussed, illustrating how water production compromised the oil or gas production. The way that these details and the conformance-fluids' capabilities and characteristics were used to design the conformance treatments is also discussed.
Typical run lives of electric submersible pumps (ESPs) in the Cooper Basin in Australia are in the range of 600 to 900 days. ESPs have been used in 15 different reservoirs in this area. When highly productive oil reservoirs were recently discovered in the Moomba area similar run lives were expected.
However, the first 12 installations in the Moomba fields only ran an average of 87 days. In 2001 a team was formed to target improved run lives. The team included production, manufacturing, engineering and management personnel from the operating company and equipment supplier.
The main problem areas identified were protector and electrical wellhead feedthru failures and power supply quality. This paper outlines the operational, engineering and equipment changes made in each of the problem areas and the resulting increase in run lives.
Failure analysis of pulled equipment demonstrated that the elastomers utilized for motor protection were being degraded. Compatibility testing of elastomers, produced fluids and injected chemicals revealed that the produced oil and water were causing the elastomers to breakdown. Although the wells were vertical, conventional labyrinth protectors could not be used because of the low gravity of the crude. The solution was to engineer a new motor protection system that was virtually elastomer free. The design utilizes metal bellows, high-density oil for gravity separation protection and high-grade o-rings. This design resulted in the first ESP motor protection system that can be used in environments with light crude that is incompatible with standard elastomers.
In addition, analysis of the power quality showed that the crude fuel utilized to power the generator sets was affecting power quality. The poor quality of the power supplied to the ESPs was potentially contributing to motor burns and wellhead penetrator failures. To improve power quality a cleaner fuel supply was sourced.
The run life improvement project is ongoing and the outcome of increased run lives is readily demonstrated.
The Moomba Field
In 1997, after 31 years of gas production, oil was discovered in the Namur and Hutton formations overlying the Moomba gas fields. To date, five oil pools have been discovered. These pools have strong aquifer support and each contain between one and five wells. Initial rates of between 3000 and 5000 barrels of low gravity (50 °API) oil per day (bopd) were typical for the wells. The primary method adopted for artificial lift was ESPs although some of the wells' productivity has declined over time requiring the installation of lower rate artificial lift systems.
The Moomba 94 pool was discovered in 1997 during the drilling of Moomba 87, a gas development well. Moomba 94 was drilled as a twin of Moomba 87 and Moomba 97 was the subsequent development well in the pool. Both wells came online at initial free flow rates of 5000 bopd. Initially both wells were completed with ESPs, with Moomba 97 later being recompleted to a jet pump due to decreased productivity.
In 1998, Moomba 95, another gas development well, also intersected oil. This oil discovery was developed by Moomba 102, a high angle development well. Moomba 102 was completed with an ESP but was also later recompleted to jet pump.
Moomba 104 exploration well, targeting oil, was drilled in 2000 and discovered the third economic oil pool in Moomba. The well tested 5000 bopd on free flow. Four further oil development wells (Moomba 118, 135, 160, 161) were subsequently drilled on this pool. Moomba 104 and 135 were completed with ESPs. The remaining wells had lower initial rates and were completed with other artificial lift methods.
The Murta Member within the Murteree Horst area consists of a very thin, high permeability sand (HPS) within predominantly low permeability, thinly laminated, carbonaceous siltstones collectively referred to as the low permeability region (LPR). This HPS has a thickness of about 1 foot and a large lateral extent of about 10,000 acres.
The HPS and LPR together have been postulated to contain an OOIP of up to 74 million bbls in the Murteree Horst area, however the LPR also acts as a capillary seal to the underlying Mckinlay reservoir. The production behaviour of the Murta reservoirs has remained enigmatic since their discovery.
Under production the HPS initially shows a rapid pressure drop indicative of oil expansion drive in a closed or almost closed system. However eventually a water drive develops which behaves as though there is a very large or possibly infinite aquifer.
Although most of the postulated 74 MMB of oil was thought to be in the LPR it appeared none of the LPR oil was being produced. It was not clear whether this oil could be mobilised. This investigation suggests that oil contained within the LPR is largely immobile and may even be representative of oil migration conduits only.
1. (a) Introduction
The Murta Member oil pools occur in four fields Alwyn, Jena, Ulandi and Limestone Creek/Biala on the Murteree Horst in the Nappacoongee-Murteree Block about 50km south of Moomba (Figure 1) in central Australia.
The Murteree Horst is part of the Nappacoongee Murteree Trend, a northeast-southwest aligned high which separates the Cooper Basin Nappamerri and Tennaperra Troughs to the northwest and southeast respectively. Cooper Basin sediments are absent on the horst with the Eromanga Basin sequence occurring directly on pre-Permian basement.