THE KILAWANI NORTH-1 (KN-l) WELL has encountered what operator Aminex describes as substantial natural gas column, in offshore Tanzania’s Nyuni/East Songo- Songo license area. The fluid is in Lower Cretaceous sandstones, the same formation that produces gas commercially in the neighbouring SongoSongo gas field. Preliminary evaluation indicates a gas-water contact approximately 30 metres deeper than at the adjacent Songo-Songo Gas field. This indicates that the KN-1 discovery is in a separate structure to the Songo-Songo field, thus enhancing the prospectivity of the remaining leads and prospects within the Nyuni licence. Formation pressures confirm the presence of gas over a gross interval of approximately sixty metres. KN- 1 was drilled as a vertical hole to a depth of 2030 metres (6,687 ft), ahead of schedule. Electric logging has been completed. KN- 1 will now be completed as a gas production well pending hook-up for production and a test will be conducted to determine flow capacity and reservoir properties. Further appraisal drilling will be required to define the extent of this discovery. This is a positive outcome for the potential of other exploration prospects and leads in the Nyuni licence area. KN- 1 also encountered minor oil shows in the Neocomian reservoir section, as well as confirming the presence of potential reservoirs in the Tertiary section at an earlier stage in the well.
The Nyuni/East Songo-Songo licence is a component of Aminex’s acreage portfolio in East Africa, which includes the highly prospective Ruvuma Basin area of Tanzania as well as large acreage positions in Madagascar and Kenya, on all of which new seismic has now been acquired. Aminex is also currently participating in the Malak- 1 exploration well in the West Esh ElMeilahah concession in Egypt, which spudded on 25 February and is drilling ahead on schedule. “We are now seeing the first real fruits of our work on the East African margin over several years, says Aminex chairman Brian Hall. “Our exploration team has long believed in the potential of this area, both for oil and gas. KN-1 is a totally new, deep structure which opens up several avenues for further exploration on the licence and strengthens the case for oil on the East African margin. This frontier area, where we were an early pioneer, is now the subject of strong industry interest. Credit is due to our explorationists and operations personnel, as well as to our JV partners who have made a strong technical input to this project and to TPDC (Tanzanian national oil company) and the Tanzanian Ministry who have provided invaluable cooperation from the outset. ”Partners in the license are Ndovu Resources Ltd. (Aminex subsidiary and operator) 40%, RAK Gas Commission with 25%, Key Petroleum Ltd. holds 20%, East African Exploration Ltd. 10%, and the remaining 5% is held by Bounty Oil & Gas Ltd.
A 90 DAY, 700 SQ KM 3D SEISMIC SHOOT ended in February 2008 in the 1,305-sq Bock J offshore Equatorial Guinea. The crew was BJP Pioneer SV.
THE DRILLSHIP DEEPWATER Pathfinder moved from the deepwater Agbami 3 ST2 to spud Aje 4 in the first week of February. Aje 4 is located in less than 200metres of water. By February 18, two casings had been run in the well and the operation was in the 12-1/4’ hole. The technical operator, Chevron (18%), doesn’t plan to test this well in the event of a successful outcome. The idea is to run production casing and suspend the well as a potential producer. Aje 4 is expected to confirm that the field indeed has 1 .2Trillion cubic feet of gas as well as up to 200million barrels of oil. The first two wells encountered two main hydrocarbon rich reservoirs, each of Turonian and the Cenomanian age, but Aje 3 encountered the Cenomanian reservoir at a level significantly down-dip from the discovery well, as well as below the existing oil-water contact defined in Aje-2. The well did indeed “see” the Turonian level updip of the two earlier wells and located above the gas water contact encountered in both Aje-1 and Aje-2 but the presence of gas in the reservoir could not be tested due to poor reservoir properties at the Aje-3 location. Participants in the 1,840 sq km OML 113, which contains the Aje field, include Yinka Folawiyo (holding operator 60%),Vitol Exploration (12.83%), Energy Equity Resources (6.50%) as well as Providence Resources (2.67%).
DEVON ENERGY, THE LARGE American Independent, is embarking on a three-well programme to evaluate the Venus oil discovery in Offshore Block P in Equatorial Guinea. The Crosco semi-submersible rig “Zagreb 1 “is being deployed to drill three locations, to test some of the identified prospects in the vicinity of the Venus discovery. Devon’s geoscientists have identified at least three play types along the western limit of the block, one at Tertiary level and two in the Cretaceous. From north to south of the block, Devon has defined such playtypes as Luna (channel complex overlying the Upper Cretaceous series), Estrella, Marte, Jupiter and Sol (Tertiary valley fill). The prospects, which are located in the southern portion of the block, have similarities to Upper Cretaceous structures in former Block G. Block P has an area of 1.619 sq km and covers grid blocks H- 17, 1-17, H- 18 and 1-18 in the Rio Muni Basin. The acreage lies mainly on the shelf, between the coastline to the east, and Block H (Atlas) plus Block L (Chevron) to the west. Devon made the Venus oil discovery in September 2005. The P-2 wildcat encountered about 45m of net oil pay in Upper Cretaceous (Campanian?) sands. The well was spudded in August 2005 with the semi-submersible Global Santa Fe rig Aleutian Key, but ended at a depth of about 2,160m. A sidetrack kicked off and reached a final depth of about 2,270m. Well P2ST encountered 35m of net oil pay downdip, but no tests were carried out. Devon says that the reservoir encountered in Venus-I is composed of multiple channel sands, similar in type to the sands in Zafiro. The operator is carrying out detailed seismic interpretation and AVO analysis. If the appraisals work, the accumulation could be brought on-stream by 2008. Well P-2 is located in the southwestern part of the acreage, about 2km south of wildcat P-1 and 30km NW of Bata in 253m of water depth. Early in October 2004, Devon had plugged and abandoned its first well in Block, wildcat P-1 on the Jupiter prospect. That well was also drilled with the semi-submersible GSF “Aleutian Key”. The company assumed that no oil show was encountered in that exploration programme. P-I is sited in 219m of water, some 60km north- northeast of the Ebano field and 30km northwest of Bata in the southwestern portion of the tract. The interests in the licence are shared between operator Devon with 38.4% and Petronas 31%, DNO 5% and Atlas Petroleum 5.6%. State hydrocarbon company GEPetrol is 20% carried.
APACHE CORPORATION’S WILDCAT natural gas well tested 16 million cubic feet (MMcf) of gas and 486 barrels of condensate per day from a 12 metre (40-foot) section in the Jurassic Lower Safa formation. Kahraman B-22 logged a total of 26 metres (84 feet) of net pay from Jurassic- age sands between 3773 -3916 metres (12,379 and 12,849 feet), but the thickest and best quality segment of this pay was perforated between 3903metres(12,805feet) and 3914metres (12,840 feet) and fracture stimulated. The well was drilled to the Jurassic Lower Safa formation at a total depth of 4213 metres(13,822 feet), in order to appraise the westward extent of the shallow Kahraman “B” Bahariya oil field and to explore for deeper traps in the Alam el Bueib and Jurassic Safa formations. The pay flowed through a 2-inch choke with a flowing well head pressure of 660 pounds per square inch (psi)resulting in the 16 MMcf of gas and 486 barrels of condensate per day.
Located 29 kilometres north of the company’s Qasr Field in Egypt’s Western Desert and 15 kilometres south of Shell’s Obaiyed field- the nearest Jurassic gas production-the prospect was mapped on a new Jurassic exploration model based on the geological and geophysical analysis of the Qasr field, which was discovered and 60 million barrels of condensate, is currently producing 362 MMcf of gas and 13,000 barrels of condensate per day from eight wells. Qasr has produced a total of 97 billion cubic feet of gas and 4.2 million barrels of condensate from the Jurassic reservoir since production started in July 2005 and also produces about 8,700BOPD from 11 wells in the overlying Alam el Buieb (AEB) and Bahariya formations.
Results from the recently drilled Kahraman UC88 well, located 5.2km to the southwest of the Kahraman B-22, indicate a possible Jurassic sandstone play expanding northward through the Kahraman B-22 well and onto Apache’s Shushan “C” concession. Apache recently acquired 215 square kilometres of new 3-D seismic over the Shushan “C” lease. The Kahraman B-22 is located on the southern edge of this play and new wells are planned in the Shushan “C” concession to extend the Jurassic play. “The Kahraman B-22 is a significant distance from known Jurassic gas accumulations and may open up a new area for development,” said Rodney J. Eichler, executive vice president and general manager of Apache ‘s operations in Egypt. Current gross production from Apache’s Jurassic fields stands at 512 MMcf of gas and 18,200 barrels of condensate per day, which is the limit of existing processing facilities. Current net production is 224 MMcf of gas and 8,000 barrels of liquid hydrocarbons per day. The company has about 23,000 square kilometers of 3-D seismic data covering nearly 56 percent of its 10 million acres in Egypt, said Eichler. “The 3-D seismic was key to identifying of deep structures missed by earlier 2-D surveys, particularly in the Qasr, Syrah, Muntaga and Matruh areas” he commented.