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Offshore shallow gas resources, once considered potential geological hazards, are now viewed as valuable unconventional oil and gas sources. Despite growing interest, there is a notable lack of comprehensive literature on production characteristics, leaving many aspects of shallow gas production unclear. This study addresses these gaps using test production data and well log analysis from a shallow gas well in the South China Sea to simulate the long-term gas−water−sand production dynamics of an interlayerburied shallow gas reservoir (IBGR) with thick sequences of thin gas layers interspersed with water-filled interlayers. The simulation showed that after 3 days, the gas production rate was around 64,000 m 3 /day, close to the field rate of 55,000 m 3 /day. Over 2 years, the rate dropped to about 23,000 m 3 /day, indicating a rapid decline. Initially, the pressure drop affected the gas layer, but later, water invasion from the interlayer shifted the pressure drop toward the middle of the IBGR, reducing gas production. Key sensitivity factors affecting gas production were analyzed. Higher gas layer permeability increased both the gas and water output. High residual water saturation in the gas layer reduced water production but boosted gas output, whereas higher interlayer permeability led to more water invasion, decreasing gas production. The risk of sand production was also predicted. During the 2 years of depressurization, sand production ranged from 0.18 to 0.9 m 3 , posing minimal risk. The contributions of different gas layers to production and the impact of the gas layer distribution on production were evaluated. Different gas layers contributed variably to production, with Gas 5's contribution rising from 27.3% to 44% over 2 years. Centrally placing productive layers resulted in higher long-term production rates than placing them at the edges due to reduced water invasion. This research provides critical insights into optimizing production strategies for offshore shallow gas reservoirs.
Offshore shallow gas resources, once considered potential geological hazards, are now viewed as valuable unconventional oil and gas sources. Despite growing interest, there is a notable lack of comprehensive literature on production characteristics, leaving many aspects of shallow gas production unclear. This study addresses these gaps using test production data and well log analysis from a shallow gas well in the South China Sea to simulate the long-term gas−water−sand production dynamics of an interlayerburied shallow gas reservoir (IBGR) with thick sequences of thin gas layers interspersed with water-filled interlayers. The simulation showed that after 3 days, the gas production rate was around 64,000 m 3 /day, close to the field rate of 55,000 m 3 /day. Over 2 years, the rate dropped to about 23,000 m 3 /day, indicating a rapid decline. Initially, the pressure drop affected the gas layer, but later, water invasion from the interlayer shifted the pressure drop toward the middle of the IBGR, reducing gas production. Key sensitivity factors affecting gas production were analyzed. Higher gas layer permeability increased both the gas and water output. High residual water saturation in the gas layer reduced water production but boosted gas output, whereas higher interlayer permeability led to more water invasion, decreasing gas production. The risk of sand production was also predicted. During the 2 years of depressurization, sand production ranged from 0.18 to 0.9 m 3 , posing minimal risk. The contributions of different gas layers to production and the impact of the gas layer distribution on production were evaluated. Different gas layers contributed variably to production, with Gas 5's contribution rising from 27.3% to 44% over 2 years. Centrally placing productive layers resulted in higher long-term production rates than placing them at the edges due to reduced water invasion. This research provides critical insights into optimizing production strategies for offshore shallow gas reservoirs.
The Southern North Sea Basin area, stretching from the UK to the Netherlands, has a rich hydrocarbon exploration and production history. The past, present and expected future hydrocarbon and geothermal exploration trends in this area are discussed for eight key lithostratigraphic intervals, ranging from the Lower Carboniferous to Cenozoic. In the period between 2007 and 2017, a total of 95 new hydrocarbon fields were discovered, particularly in Upper Carboniferous, Rotliegend and Triassic reservoirs. Nineteen geothermal systems were discovered in the Netherlands onshore, mainly targeting aquifers in the Rotliegend and Upper Jurassic/Lower Cretaceous formations. Although the Southern North Sea Basin area is mature in terms of hydrocarbon exploration, it is shown that with existing and new geological insights, additional energy resources are still being proven in new plays such as the basal Upper Rotliegend (Ruby discovery) for natural gas and a new Chalk play for oil. It is predicted that hydrocarbon exploration in the Southern North Sea Basin area will probably experience a slight growth in the coming decade before slowing down, as the energy transition further matures. Geothermal exploration is expected to continue growing in the Netherlands onshore as well as gain more momentum in the UK. Since the publication of the Petroleum Geological Atlas of the Southern Permian Basin (SPB) (Doornenbal & Stevenson 2010), which gave a comprehensive overview based on more than 150 years of petroleum exploration and research from onshore UK to Poland, the basin has continued to see successful exploration wells drilled together with a diversification of drilling targets. This paper summarizes the activities over the period 2007-17 to give an update on new exploration insights. The focus of this paper is more limited than the entire SPB Atlas area and concentrates on its western part between latitudes
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