Some 70 industry young professionals (YPs) attended an event in Luanda last July on ethical conduct and corporate responsibility in the oil and gas industry. The program, organized by the Angola YP Section, provided YPs with exposure to issues surrounding common situations they will face throughout their careers and also gave them an opportunity to build their networks with other YPs. The speakers were Eunice de Carvalho, Policy, Government, and Public Affairs general manager, Chevron, Luanda, and Madalena Fernando, API coordinator, Chevron, Luanda.
Africa (Sub-Sahara) Eni discovered up to 250 million bbl of light oil in the Ndungu exploration prospect in Block 15/06 offshore Angola. A well in 1076 m of water reached TD of 4050 m and proved a single oil column of approximately 65 m with 45 m of net pay of 35 API oil. Well results indicate production capacity in excess of 10,000 B/D. Eni operates Block 15/06 with 36.8421% Joint venture partners are Sonangol P&P (36.8421%) and SSI Fifteen (26.3158%). Eni discovered gas and condensate on the Akoma prospect in CTP-Block 4 offshore Ghana. The Akoma-1X exploration well was drilled in 350 m of water approximately 50 km offshore and 12 km northwest of the FPSO John Agyekum Kufuor.
Africa (Sub-Sahara) Sonangol's deepwater Orca-1 well encountered oil in the presalt layer of Block 20/11 in the Cuanza basin offshore Angola. The well reached a measured depth of 12,703 ft. Initial well tests saw flow rates of 16.3 MMcm/D of gas and 3,700 BOPD. Cobalt International Energy (40%) is the operator, with partners Sonangol Research and Production (30%) and BP Exploration Angola (30%). Asia Pacific Premier Oil's Kuda Laut-1 well in Indonesia's Tuna production sharing contract has encountered 183 net ft of oil-bearing reservoir and 327 net ft of gas-bearing reservoir. Following evaluation operations, the well will be sidetracked to drill the Singa Laut prospect in an adjacent fault block. Premier is the operator (65%), with partner Mitsui Oil Exploration Company (35%).
Africa (Sub-Sahara) Eni started production from the West Hub development project's Mpungi field in Block 15/06 offshore Angola. The startup follows the project's first oil from the Sangos field in November 2014 and the Cinguvu field last April. Mpungi will ramp up West Hub oil production to 100,000 B/D in the first quarter from a previous level of 60,000 B/D. The project also includes the future development of the Mpungi North, Ochigufu, and Vandumbu fields. Eni is the block operator with a 36.84% stake. Sonangol (36.84%) and SSI Fifteen (26.32%) hold the other stakes.
Africa (Sub-Sahara) Petroceltic International said that the first of up to 24 new development wells planned in Algeria's Ain Tsila gas and condensate field was successful. The AT-10 well, situated about 2 miles from the AT-1 field discovery well, reached a total depth of 6,578 ft. Wireline logs indicated that the expected initial offtake rate would be comparable to the AT-1 and AT-8 wells, both of which test-flowed at more than 30 MMcf/D. Petroceltic is the operator with a 38.25% interest in the production-sharing contract that covers the Ain Tsila output. The remaining interests are held by Sonatrach (43.375%) and Enel (18.375%). Sonangol reported that it has found reserves in the Kwanza Basin of Angola that could total 2.2 billion BOE, including reserves in a block jointly owned with BP. Block 24, operated by BP, holds an estimated 280 million bbl of condensate and 8 Tcf of gas, totaling 1.7 billion BOE, Sonangol said in a statement seen by Reuters.
Africa (Sub-Sahara) Eni announced an oil discovery in Block 15/06 offshore Angola in the Kalimba exploration prospect that is estimated to contain between 230 and 300 million bbl of light oil in place. The Kalimba-1 NFW well, which led to the discovery, is located approximately 150 km off the coast. The well was drilled in a depth of 458 m and reached a total depth of 1901 m. The data acquired in the well indicate a production capacity in excess of 5,000 B/D. The discovery creates opportunities for exploration in the southern part of Block 15/06, so far considered mainly gas-prone. The joint venture, with stakes held by Eni (operator, 36.8421%), Sonangol (36.8421%), and SSI Fifteen Limited (26.3158%), will work to appraise the updip of the discovery and will begin studies to fast-track its development.
Africa (Sub-Sahara) Eni has begun production from the Vandumbu field and made a new oil discovery in the Afoxé exploration prospect in Block 15/06 offshore Angola. First oil from the Vandumbu field, through the N'Goma floating production, storage, and offloading vessel, was achieved in late November, 3 months ahead of schedule. Vandumbu is approximately 350 km northwest of Luanda and 130 km west of Soyo. This, along with the startup of a subsea multiphase boosting system in early December, boosts oil production from Block 15/06 by 20,000 B/D. The rampup of Vandumbu is expected to be completed in 1Q 2019. Block 15/06 is being developed by a joint venture formed by Eni (36.84%, operator), Sonangol (36.84%), and SSI Fifteen (26.32%). Asia Pacific Ophir Energy's Paus Biru-1 exploration well in the Sampang production-sharing contract (PSC) offshore Indonesia has resulted in a gas discovery.
Africa (Sub-Sahara) Eni successfully completed a new production well in the Vandumbu field, 350 km northwest of Luanda and 130 km west of Soyo, in the West Hub of Block 15/06 offshore Angola. The VAN-102 well is being produced through the N'Goma FPSO and achieved initial production of 13,000 BOED. Production from this well and another well in the Mpungi field will bring Block 15/06 output to 170,000 BOED. Anglo African Oil & Gas encountered oil at the TLP-103C well at its Tilapia license offshore the Republic of Congo. The well intersected the targeted Djeno horizon, and wireline logging confirmed the presence of a 12-m oil column in the Djeno. Total started production from the ultra-deepwater Egina field in approximately 1600 m of water 150 km off the coast of Nigeria. At plateau, the field will produce 200,000 B/D.
Efficiently and accurately estimating fluid-flow movement information from time-lapse data is a prime deliverable of any 4D acquisition and analysis. The key to success in this depends on a few factors including optimum 4D seismic acquisition, the seismic frequency bandwidth at the reservoir level and being able to deliver the 4D analysis or results in a very rapid and efficient manner. Maximum value of 4D is derived not from the data quality alone but also from the efficiency of delivering a 4D image and analysis. The value of the 4D decreases significantly with time, as results and analysis need to be delivered promptly to make an impact on the in-fill well program as well as on the reservoir development.
From the 4D seismic image analysis (based on a calibrated broadband PSDM seismic processing), a dynamic warping algorithm was implemented for estimation of time-shift and delta velocity on this non-conventional typical “broadband�? 4D seismic i.e. new multi-component over a conventional streamer legacy survey. The 4D analysis results were then compared with the 4D rock physics analysis at the available wells over the survey and related to the production-injection mechanism. This paper will review the project results and their impact in term of reservoir management understanding.
Presentation Date: Monday, October 15, 2018
Start Time: 1:50:00 PM
Location: 204C (Anaheim Convention Center)
Presentation Type: Oral
Carragher, Paul (BiSN) | Bedouet, Sylvain (BiSN) | Talapatra, Didhiti (BiSN) | Hughes, Andrea (BP) | Curran, John (BP) | Hou, Wei (BP) | Kosi, Orlando (BP) | Ralph, Stan (BP) | Gao, Qiang (BP) | Gracia, Jesse (BP) | Galvan, Jeanine (BP) | Calvert, Patrick (BP) | Alcoser, Luis (BP) | Dean, Doyle (BP) | Mason, David (BP)
Achieving water shut-off in gravel packed wells is challenging, particularly being able to place a mechanical barrier to flow into a gravel packed annulus. Gravel packed wells, often in deepwater environments, are often high rate wells and interventions can be costly, therefore only techniques with a high probability of success are typically sanctioned.
Many gravel pack wells are completed in multiple sands. If there are barriers between the sands that are believed to be laterally extensive, and if water is entering the lower sand, then isolating the lower sand can be a cost-effective intervention. Deepwater wells in Angola were reviewed as to whether a chemical solution or a mechanical solution would be preferred.
Providing a suitable mechanical methodology could be developed, it was felt this would provide a preferred solution. Further criteria for applying a mechanical solution were developed, to increase the chances of success. Extensive well modelling was also conducted to identify an optimum set of plugs to be placed in the well.
The operator identified a company that had an emerging technology that could offer such a solution. They then worked together to mature the technology through a series of proof-of-concept tests, through trials in Alaska, an early application in a deepwater well in the Gulf of Mexico, followed by a series of qualification tests to be ready for application in Angola. The qualification tests considered not only the mechanical configuration of the wells, but temperature, pressure and wellbore deviation. The application would require placement using a tractor, therefore testing with connecting to the relevant equipment was also incorporated in the plans for the wells.
Using a deepwater rig, several plugs were run in each well, including a meltable alloy plug. The latter plug provided a barrier to flow in both the annulus and inside the sand screens. Although not providing a barrier to shunt tubes, extensive modelling work at Cambridge university showed that it was possible to influence gravel movement in the annulus and shunt tubes, so as to maximise the pressure loss.
Two wells have had plugging systems run. The first well has reduced water cut from 100% to ca. 40% and shown a significant oil rate benefit. The second well has also shown a reduced water cut (from 70% to 40%).