Unexpected water accumulation (called perched water) can be present inside hydrocarbon bearing reservoirs. In case of limited or poor geophysical data, the prediction of this accumulation may be difficult.
In this paper, a real case is used to show how the presence of perched water was initially supposed and then verified through production data analysis.
During the development campaign of a deep water reservoir in West Africa, a water injector well found an unexpected shallower water table. To understand the nature of this water, the gas while drilling data of two oil producer drilled in the same area of the water injector were analysed. Based on this analysis the last meters of the open hole section of both oil producers were in water. The integration of gas while drilling data, stratigraphy, sedimentology and structural settings knowledge of the area suggested that this water was locally trapped during oil migration, most likely due to the presence of a structural barrier.
The two oil producer wells, located in the supposed perched water area, were successfully started-up. The behavior of both wells was daily monitored to understand and confirm the nature of perched water phenomenon. From day one, the two wells showed water production. After few weeks, the water cut of one well clearly started to reduce. For the other well, the water cut behavior was constant and only after one year of production the declining trend was appreciated. The observed declining trend of water production was the final confirmation that aquifer in this sector of the field is isolated and with limited extension. The water cut trend was also captured in the 3D dynamic reservoir model. In addition, tracers were implemented in the model to identify different water production sources (injected or perched) and to forecast their evolution during the field life.
The literature on perched water is quite limited and usually this kind of phenomenon is detected and described only on the geological side, but the production behavior of this water is rarely observed. This case study is integrating the geological and geophysical knowledge of the field with production data analysis to understand perched water behavior and can be considered a reference for other similar situation.
Sabine Pass Train 6 gets the nod, Bechtel gets the go-ahead for construction. Apache Corp. signed a deal with Cheniere to supply natural gas produced from its Permian Basin Alpine High area to the Corpus Christi LNG facility Startup comes 8 months after the initial discovery in March, marking the second successful tieback since 2017 to the Beryl Alpha platform in the UK North Sea. The rising oil production and produced water volumes in the Permian are expanding the scope and scale of recycling. Apache is targeting 50% of its frac water to be made up from recycled produced water this year. Industry CIOs examine the challenges operators and service companies face in understanding cybersecurity threats.
Production from the Hibernia platform was shut down again on 17 August after its second oil spill in a month, while Husky Energy began to ramp up output from the White Rose field following the largest-ever spill off Canada’s easternmost province. Anchored by the Khaleesi-Mormont and Samurai fields, the King’s Quay FPS will receive and process up to 80,000 B/D of crude oil. Marathon Oil says its shale fields are producing more oil and gas with less hands-on work from company personnel thanks to a growing arsenal of digital technologies and workflows. Expected to start up in mid-2022, Liza Phase 2 will produce up to 220,000 B/D of oil. Hydrocarbon processing and treating systems often require large and elaborate surface facilities.
With the purchase, the growing, privately-held Chrysaor Holdings will expand its UK North Sea production to 185,000 BOE/D. The state-run offshore company has found a gas and condensate field that holds an estimated 250 million BOE. The latest example of the offshore sector's march toward automated wellbore construction will take shape later this year in the North Sea. Just 2 months after issuing more than a hundred licenses, the Oil and Gas Authority begins the process again for a whole new set of blocks. The company announced it would “initiate the process” of marketing its UK Central North Sea fields as part of a portfolio review.
The Turritella FPSO (Figure 1 above) is the deepest floating production system in the world and presented many challenges to successful execution of the surface host facilities. The long-term decommissioning of the historic Brent field has necessitated redevelopment of the younger Penguins field in the North Sea, where the UK hopes to see more revival projects in the coming years. Despite major advancements in deepwater projects in the Gulf of Mexico, FPSO usage has yet to increase. This paper describes the CLOV deepwater megaproject in Block 17 offshore Angola, which cost USD 8.4 billion to first oil. This paper describes the measures put in place so that the mooring system of the Gryphon Alpha FPSO could be replaced and reconnected on an efficient schedule.
Tight gas well stimulation has a long and sporadic history in the North Sea and Europe and it is still far from being an easy development option in the current economic climate. Onshore, the pause in activity in Germany continues, but there appears to a light at the end of the tunnel, after recent new legislation has been passed. In Poland and Hungary, activity has fallen sharply, but there has been renewed interest in offshore tight gas in the Dutch and UK sectors (stranded gas). In addition to new field development, there is also potential development of tight gas horizons within existing fields. The economics of such developments are much more attractive than standalone tight gas projects, although there are often operational issues that need to be considered. This session will examine recent developments in tight gas stimulation, both onshore and offshore, and focus on case studies. The emphasis will be building on the recent experience to push the envelope of tight gas stimulation practices.
The subsea operations company said its most recent campaign is the first fully unmanned offshore pipeline inspection completed “over the horizon,” surveying up to 100 km from the shore. One of the largest industrial projects in the UK in recent years, Mariner marks Equinor’s first operated field on the UK Continental Shelf. It is expected to produce 70,000 BOPD at peak rates. The Norwegian Petroleum Directorate has given clearance to start up facilities at the North Sea field, which straddles the line between the UK and Norwegian sectors. Production is set to begin in September.
Africa (Sub-Sahara) Cairn Energy has flowed oil from its SNE-2 well offshore Senegal. Drillstem testing of a 39-ft interval achieved a maximum stabilized but constrained flow rate of 8,000 B/D of high-quality pay. A flow rate of 1,000 B/D of relatively low-quality pay was achieved from another zone. Drilled to appraise a 2014 discovery, the well lies in the Sangomar Offshore block in 3,937 ft of water 62 miles from shore. Drilling reached the planned total depth of 9,186 ft below sea level. Cairn has a 40% interest in the block with the other interests held by ConocoPhillips (35%), FAR (15%), and Petrosen (10%).
One of the largest industrial projects in the UK in recent years, Mariner marks Equinor’s first operated field on the UK Continental Shelf. It is expected to produce 70,000 BOPD at peak rates. The Norwegian Petroleum Directorate has given clearance to start up facilities at the North Sea field, which straddles the line between the UK and Norwegian sectors. Production is set to begin in September. Lundin reports that the hookup and commissioning of installed facilities at the large North Sea field is progressing as planned.
Equinor announced that it had drawn first oil from the Mariner field in the UK North Sea, its first operated field on the UK Continental Shelf (UKCS) and one of the largest industrial projects in the region in recent years. Mariner holds an estimated 3 billion bbl of oil in place, a 50% increase on Equinor’s initial projections, and the estimated recovery rate at startup was 20% higher than initially presumed. Mariner is expected to produce annual average plateau rates of approximately 55,000 BOPD and up to 70,000 BOPD at peak production. Located on the East Shetland platform in UK Block 9/11a in the northern North Sea, approximately 93 miles east of the Shetland Islands, Mariner was first discovered in 1981. Equinor acquired operatorship of the field in 2007 and sanctioned the project five years later.