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Dark Zim Lit Up By Neighbours

Namibia will help Zimbabwe ramp up power production from the current 450 MW to at least 750 MW at the Hwange thermal power station. Botswana is aiding Zimbabwe in the revival of the Bulawayo station.

NamPower invested $45million in the Zimbabwe power project, which includes the addition of two more generation units later in 2009. Botswana Power Corporation (BPC) is investing $8million in the revival of the 90MW Bulawayo station, with a view to boosting the capacity to 120MW.

The Hwange station is already using four units, all revived with the help of NamPower in return for the exportation of an unspecified percentage of the power produced to Namibia. Botswana Power Corporation expects to have a 50:50 share with Zimbabwe, so both countries will get substantial benefits out of the deal.

Zimbabwe has a lot of power generation infrastructure rotting at Harare, Manyame and [the] Kariba thermal power stations. Undeveloped projects include the Gokwe north power station, which has the capacity to produce 1 400 MW, the Lupane methane gas project which has a potential for 300 MW and the Batoka Gorge hydroelectric project, which can generate up to 1 600 MW.

The country’s hydroelectric potential remains underutilised, as it has many projects, which have been on the cards for years. Projects are stalled because investors, who left the country when the farm invasions began in are still largely unwilling to return. Zimbabwe has a peak demand of 2 000 MW, produces only 1 100 MW and imports up to 500 MW from neighbours Zambia, Mozambique and the Democratic Republic of Congo. It also has a stand-by agreement for emergency power supplies with South Africa.

Application of Outcrop Analogues to Optimize LWD Acquisition for More Confident Formation Evaluation in High Angle and Horizontal Wells, E. Tyurin and M. Benefield’, Baker Hughes, INTEQ

Outcrop analogues are very helpful in generation of the reservoir depositional model but are restricted in their application to formation evaluation. They represent a missed opportunity, in particular in the interpretation of high angle and horizontal (HA/HZ) well log response. In our vision they give us access to the depositional controls on vertical and lateral petrophysical rock properties variations as well as actual geometry of the geological bodies; both matters are critical for confident formation evaluation in HA/HZ well setting. The primary objective of this study is the integration of geological answers and petrophysical information to construct forward models of our high technology LWD datasets. We assign a major significance to the visual comparison of the rock picture and a simulated tool response, supported by a detailed petrophysical analysis. We initially used the Ainsa 1 Pyrenean deepwater turbidite outcrop with the petrophysical properties of analogous offshore West Africa reservoirs. Across- channel geological complexity (thin layering and low NTG in marginal part; pinch-outs, amalgamations and rock property variation in the axial part) is valuable to demonstrate improved strategies of interpretation solutions in channel to lobe turbidite settings. Steps to forward model the LWD data include many of today’s reservoir characterization procedures: sedimentological description, lithofacies to petrofacies associations, core and field scale 3D petrophysical properties simulation, upscaling, true resistivity matrix generation and resistivity anisotropy evaluation. Forward modeling of tool response accounts for different measurement natures, geometries and DOl’s (from meters in resistivity to cm in radioactivity, images and magnetic resonance). The range of the results acquired shows that basic LWD suites often do not provide an accurate result in a heterogeneous environment. For example, in our case water saturation is overestimated by around 30% total through improper use of the classical data. Our study highlights that reservoir parameterization in the presence of all scales of heterogeneities, sand mixtures and thin laminations is enhanced through proper application of gamma ray, resistivity, density, neutron and NMR for the pore volumetrics and imaging for the geobody shaping. Using the approach to a contrasted West Siberian field case with inherent low resistivity contrast and invasion of WBM demonstrates further interpretational challenges. The work ultimately permits a more confident selection of logging suites and subsequent improvement in application of the acquired data to formation evaluation in high angle and horizontal well situations.

Agip Missed The Target In Oberan 2

Agip missed the expected reservoir in Oberan -2, inspite of the large expectations created by the discovery well. Oberan -2 is located in the Agip operated Oil Mining Lease (OML)134. Delays in the approval of contract for the three dimensional seismic acquisition, led the company to go ahead and drill the appraisal well, taking advantage of an available rig. “They thought they had enough information with the existing Agip seismic data to drill the appraisal”, a source said. They were wrong. Lessons learned: “They are going to take their time with the third well, integrate all available data into the new 3D data on the structure and evaluate. Oberan 3 is not likely to be drilled until the second or third quarter 2010”.

Agbami Hit 250,000 B/D Peak in August 2009

The Chevron operated Agbami field offshore Nigeria reached peak production of 250,000 barrels per day in August 2009, or four months ahead of schedule. Commencing production in July 2008, the field contains an estimated 900 million barrels of oil equivalent of recoverable hydrocarbons, one of the largest discoveries to date in Nigeria. Agbami stretches across 45,000 acres and is located some 70 miles (113 kilometers) offshore the Niger Delta basin, straddling blocks OML 127 and 128. The field’s water depth is 4,500 feet (1,372 meters). The crude oil found in Agbami is light and sweet, with a 45-degree API gravity and no contaminants. Besides operator Chevron, other partners in Agbami are Petrobras, Nigerian National Petroleum Corp., Famfa Oil Ltd. and StatoilHydro ASA.

Advanced Geosteering with Azimuthal Deep Resistivity Helps in Optimal Well Placement, NOVEMBER 2009, By Roland Chemali

Halliburton, Sperry Drilling Services

Early production, as well as ultimate oil and gas recovery, from a reservoir often depends on the timeliness and the accuracy geosteering decisions. Exiting the reservoir during drilling results in costly non-productive intervals.Even staying within the reservoir but in a non-optimal location eventually leads to early water break-through while leaving behind valuable attic oil. In recent years, azim

Fig 1- Geosteering with deep resistivity images from azimuthal deep resistivity LWD.

uthal deep resistivity measurements have been recognized as beneficial to real-time steering decisions. Because of their deep investigation, they give adequate warning to prevent from exiting the reservoir. Their azimuthal sensitivity clearly points to the direction of preferred evasive actions. Best results are achieved by jointly interpreting several measurements from the azimuthal deep resistivity, corresponding to multiple depths of investigation. In the simplest cases, the up-down resistivity curves exhibit a characteristic behavior that has proven valuable both to petrophysicists and to geosteering engineers. When approaching overlaying shale, for example, the up-curve consistently reads the resistivity of the reservoir while the down-curve exhibits amplified horns beneficial to reservoir navigation. Resistivity images feature bright spots whose progression with increasing depth of investiga

tion facilitates avoidance of unwanted boundaries. 4 new measurement designated as Geosignal features strong lateral sensitivity. The Geosignal from the deepest spacing is best suited to provide an early indication of the approaching boundary, with a near- exponential dependence on the distance to

Fig 2- Geosteering with up-down and with bright spot resistivity images from an azimuthal deep resistivity LWD.

boundary. Examples from around the world are shown in detail to help illustrate the applications.

Addax Buys More In Gryphon

GABON Swiss independent Addax Petroleum, has acquired an additional 18.75% interest in the Gryphon Marin license area, bringing its total interest in the license area to 68.75%, prior to third party back-in options. Addax Petroleum is the operator of the Gryphon Marin license area, which covers a gross area of approximately 2,409,200 acres (9,750 km2) and lies immediately west of the Iris Marin and Ibekelia license areas, and immediately north of the Corporation’s Etame Marin license, offshore Gabon.

Addax plans to commence exploration activities on the acreage with the spudding of the Ajomba North and Pompano North prospect wells during the first half of 2009, a company release said. Addax Petroleum holds a 5 1.33% interest in the Iris Marin license area and a 31.36% interest in the Etame Marin license area. The Gryphon Marin license area is in an exploration period ending in November 2009 and carries a commitment to drill two wells. Addax Petroleum has budgeted to drill the Ajomba North and Pompano North prospects in the Gryphon Marin license area in the first half of 2009.

Ex OPEC Secretary General Named NNPC Chief

For the second time in 18 months, Nigeria has fired the group managing director of the state hydrocarbon company, Nigeria National Petroleum Corporation NNPC. The latest appointee to the insecure position is Mohammed Barkindo, a former Acting Secretary General of the elite Organisation of Petroleum Exporting Countries(OPEC). Mr Barkindo, who was Coordinator of Special Duties at the NNPC, took over from his boss, Lawal Yar’adua.

The appointment, though made by President Umar Yar’adua, took place less than a month into the appointment of Mr Rilwanu Lukman, as minister of Petroleum. Businessday, Nigeria’s influential financial daily, interpretes it as a Lukman move, but Mr Barkindo has operated at the very top echelon of Nigerian oil industry for some time. He was at various times head of the London office of the NNPC, Deputy Managing Director at the Nigerian Liquefied Natural Gas Limited and Managing Director of Hyson and Carlson, a joint venture between Vitol and the NNPC, which lifts more than a quarter million barrels of Nigeria’s crude oil daily. The new NNPC chief holds a Bachelor’s degree in political science from Ahmadu Bello University in Nigeria, and an MBA from South-eastern University in Washington DC.

EGYPT: Dana Gas Strike Gas, Condensate in Egypt’s Nile Delta

Dana Gas has announced a significant gas and condensate discovery at its El Basant-2 well in the Nile Delta Concession in Egypt.

The El Basant-2 well, located 1.4 kilometers northeast of the El Basant-1 discovery in the West El Manzala Concession, was spudded on December 6, 2008, reaching a total depth of 3,050 meters and encountered 37 meters of net sand pay with good porosity and permeability in the Qawasim formation.

“The El Basant hydrocarbon accumulation significantly raises Dana Gas’s reserves in Egypt”, according to Hany Elsharkawi, Dana Gas country director in Egypt.

“This acreage is particularly attractive to us as we have established production in the area and we are able to bring new discoveries on production quickly and at comparatively low cost. In addition our gas is sold at a fixed price and therefore our gas revenues have not been negatively affected by the recent drop in global oil prices. Dana Gas has already applied for a Development Lease, which we expect to be granted soon, and we anticipate a production start-up by the end of March 2009.”

Following an extensive testing programme at El Basant-2, Dana Gas plans to transport the hydrocarbons produced from the well through a pipeline to its El Wastani field facilities, which lie about ten kilometers to the north of the well.

“Dana Gas ends 2008 with solid growth in production and activities and a positive outlook for the coming year, despite the global financial crisis”, said Mr. Neeraj Agrawal, Dana Gas Finance Director.

Ghana: Jubilee Serves Up A Double Whammy

Less than a week after Kosmos  reported the success of Mahogany 3, in appraising existing reservoir and coming up on new, deeper payzone, Tullow Oil put out the news that its Hyedua-2 well flowed at a stable rate of 16,750 BOPD. Both wells are located in the deepwater Jubilee field, offshore Ghana. In fact, the Mahogany field, discovered in the West Cape Points Three Points and the Heydua accumulation, located in Deepwater Tano License, are one and the same field ; they straddle and are being jointly developed (unitized) as a single (Jubilee) field.

In the ongoing appraisal activity the operators keep christening the wells with the original prospect names and this may be confusing to those who are trying to follow up the development of Jubilee field.

Kosmos reported that 33metres of net pay were encountered in Mahogany 3, “whose primary objective was to appraise the Jubilee field reservoir section away from the strong seismic amplitudes which have been the main targets to date”. The company said that the results of drilling, wireline logs and samples of reservoir fluid indicate that 16 metres of high quality stacked oil bearing sandstones have been encountered. “This confirms a significant extension of the Jubilee field to the southeast”. The company said that the secondary objective of the well was to drill Mahogany Deep, an exploration target which had been identified on 3D seismic but lies at a previously untested stratigraphic level. In this section, “the well encountered 17 metres of good quality oil bearing reservoir sandstones at levels significantly deeper than the oil water contacts previously intersected on the Jubilee field”. This success opens up further potential in the region and is the subject of ongoing evaluation.

Kosmos didn’t do any drill stem test on Mahogany 3, which reached a total depth of 4,028 metres in a water depth of 1,236 metres.

Tullow’s announcement of 16,75OBOPD as flow rates for Heydua 2 recalls the early days of deepwater discoveries in deepwater Angola. Heydua 2 reached a total depth of about 3,663 metres in a water depth of 1,246 metres and was tested via 88/64” choke with a tubing head pressure of 1,380psi( pounds per square inch). It intersected 55 metres of high quality oil bearing reservoir sandstones of which a 41 metre section was tested.

The flow rates, “at nearly 17,000 BOPD of high quality crude, from a well not even in the centre of the field, is an outstanding success and indicative of a world class reservoir”, said Aidan Heavey, Tullow’s Chief Executive. Hyedua-2 is located on the north-west flank of the field and Tullow says the excellent reservoir properties measured during the flow test are expected to be even better in the core area of the field. The company reports that stable oil and gas flow rates were maintained throughout the tests and the pressure data indicated that it is connected to a large pore volume. “Excellent reservoir continuity enhances our expectation of connectivity between the planned production and injection wells and we are currently assessing the positive impact on Phase 1 reserves”.

Hess Hits A Home Run In The North

Hess Corporation, known in Africa for its cash cow Le Ceiba field in Equatorial Guinea, has announced itself as a significant player in the north of the continent.

The company encountered significant pay zones in two offshore wells in the Mediterranean region: one in Libya and the other in Egypt.

The A1-54/01 well in the Arous Al-Bahar prospect in Libya was drilled to a depth of 3376metres  in 856metres of water. The well encountered a gross hydrocarbon section of approximately 152.4 meters at various intervals. Hess holds a 100 percent working interest in Area 54, which is located 38 miles offshore in the Sirte Basin.

In Egypt, the Dekhila-lx well in the West Mediterranean (Block 1) deepwater area, located 45 miles offshore within the Nile Delta Basin, was drilled to a depth of 2707 metres in 1183 metres of water and found a gross hydrocarbon section of 45.11 meters at multiple intervals. Hess holds a 55 percent working interest in the production sharing arrangement with the state company, EGPC.  The company’s partners are RWE Dea (35 percent) and Kufpec (10 percent).  The results of Dekhila-1x will be incorporated into engineering studies for the wider West Med development.

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