Africa (Sub-Sahara) A drillstem test was performed on the Zafarani-2 well--located about 80 km offshore southern Tanzania. Two separate intervals were tested, and the well flowed at a maximum of 66 MMscf/D of gas. Statoil (65%) is the operator, on behalf of Tanzania Petroleum Development Corporation, with partner ExxonMobil Exploration and Production Tanzania (35%). The FA-1 well--located in 600 m of water in the Foum Assaka license area offshore Morocco--was spudded. The well targets Eagle prospect Lower Cretaceous resources. Target depth is 4000 m. Kosmos Energy (29.9%) is the operator, with partners BP (26.4%),
Africa (Sub-Sahara) Tullow Oil announced in mid-August that first oil has flowed from the Tweneboa, Enyenra, and Ntomme (TEN) fields offshore Ghana, which was on time and on budget for the project's development plan approved by the government in May 2013. The company expects oil output to ramp up gradually through the rest of the year toward a production facility capacity of 80,000 B/D. Tullow is the operator of the TEN fields with a 47.18% stake. Its joint-venture partners are Anadarko (17%), Kosmos Energy (17%), Ghana National Petroleum Corporation (15%), and PetroSA (3.82%). Asia Pacific Rosneft has made a discovery at the PLDD well in the Wild Orchid gas condensate field in Block 06.1 of the Nam Con Son Basin offshore Vietnam. The discovery is being evaluated for the volume of reserves and commercial attractiveness, and there is a potential synergy with the nearby Rosneft-operated Lan Tay production platform, the company said.
For many years, geologists and engineers have used volumetric methods to quantify or estimate hydrocarbon volume contained in reservoirs. The economic producibility of the reservoirs, also depend on the flow characteristics. The overall level of uncertainty of the estimation depends on the uncertainty of the parameters that determine the oil volume such as porosity and the reservoir characteristics such as pay thickness. However, uncertainty of estimation increases when estimating hydrocarbon in place for complex fluids systems (i.e. heavy oil) since mobility can have an adverse effect on fluid movement. Determination of net pay cut-offs should be based on parameters that include flow and storage capacity.
Considering the requirement to establish a relationship between petrophysical cut-offs and rock types to estimate hydrocarbon in place, five different cases were used to quantify net pay parameters of the reservoir in the Cerro Negro field, Venezuela. The workflow that was applied:
1. Identification of petrophysical rock types (PRT) from porosity and permeability data using core-based and log-derived petrophysical analysis,
2. Definition of the relationship between PRT and facies
3. Determination of pay cut-offs for reservoir and each PRT using conventional and contemporary methodologies,
4. Comparison of the conventional and contemporary methodologies results,
5. Estimation of pay cut-offs impact on the prediction of rock types and reservoir petrophysical properties in the estimation of volumetric.
This study demonstrates that the definition of PRT distribution is controlled by pore throat size instead of facies. From the six rock types defined in the field just three rock types (1, 2, and 3) are oil producing rock reservoir. The OOIP results vary significantly over a range of 500 MMstb, depending on which of the parameters are used as pay cut-offs.
In conclusion, estimating OOIP by applying petrophysical rock typing is an improved way to decrease uncertainty than OOIP estimation by reservoir unit. The results demonstrated that the choice of good pay cut-offs was the key to reduce the uncertainty in the estimation of the OOIP in the Cerro Negro field.