Reservoir Gas Management in the Brae Area of the North Sea

Phillips, Ian

doi:10.2118/22918-ms

Cited by 5 publications

References 5 publications

Supporting

Mentioning

Contrasting

Order By: Relevance

Scale Control in the South Brae Field

Hardy¹,

Barthorpe

Rhudy

1994

SPE Production &Amp; Facilities

View full text Add to dashboard Cite

Summary Severe scaling conditions exist in South Brae because of the high barium content of formation water and low pH downhole. Formation water is also susceptible to calcium carbonate scaling. This paper presents experiences with scale control on topsides and downhole during field development. Topsides control has been achieved at the expense of high dose rates and secondary effects on produced-water quality. A sulfonate-based inhibitor was developed and applied for downhole control of BaSO4. This paper presents the benefits achieved by the use of desulfated seawater to minimize the BaSO4 potential and describes the methods developed to control calcium carbonate scale. Introduction Deposition of mineral scale is a common problem in the oil industry, nowhere more so than in the North Sea.1–5 The type of scaling and its severity vary among fields; however, calcium carbonate and barium sulfate scaling are common problems. The barium content of most North Sea formation waters ranges from 10 to 200 ppm. By comparison, the barium concentration in South Brae formation water is as high as 2,500 ppm. This high barium content in injection seawater presents a severe scale mitigation problem that is compounded by a relatively low downhole pH. Although similar high barium levels have been found in other North Sea fields (e.g., T Block),6 South Brae is the first such North Sea field to be developed. This paper presents an overview of the experience gained with the scale problem and the control measures developed. The South Brae field is located in Block 16/7a of the U.K. sector of the North Sea. Phillips7 recently described the reservoir and its geology. The field has been on production since 1983. Reservoir pressure maintenance and voidage have been achieved by a combination of downdip water injection and crestal-gas injection. Seawater injection began in 1984. In 1988, the first phase of a 120,000-bbl-capacity facility to reduce sulfate levels of injected seawater was installed. Scaling Predictions Formation-Water Composition. Assessment of the scale potential was initially uncertain owing to the large variation in the compositions evident in the limited number of formation-water samples. Samples obtained subsequently have confirmed the heterogeneity in water compositions. Table 1 gives examples. Salinity and barium content increase with depth, the barium concentration varying from approximately 500 to 2,500 mg/L. Barium Sulfate Scale Potential. The theoretical mass of scale formed upon mixing formation water with seawater and the mixing ratio at which it occurs vary, depending on the barium content. However, for a typical formation water containing 800 ppm barium, the highest mass of BaSO4 is formed at a 80:20 formation/seawater mixing ratio. The highest saturation index (i.e., driving force for scaling) occurs at a mixing ratio of approximately 50/50. These predictions agree closely with Mazzolini et al.'s6 for similar high-barium-content T Block water. It was apparent that, because of the high supersaturation, barium sulfate scale would be difficult to inhibit. The high CO2 content of the produced gas (30 to 32 mol%) and consequent low pH further contribute to the difficulty of inhibition. Downhole pH is estimated to be between pH 4 and 4.5, at which point the efficiency of many conventional inhibitors is limited. Calcium Carbonate Scale Potential. In addition to severe barium sulfate scaling, because of the significant calcium and bicarbonate content, South Brae formation water is prone to calcium carbonate scaling. Oddo and Tomson's8 method was used to calculate the downhole CaCO3 scaling tendency.

show abstract

Scale Control in the South Brae Field

Hardy¹,

Barthorpe

Rhudy

1994

SPE Production &Amp; Facilities

View full text Add to dashboard Cite

show abstract

Improved Hydrocarbon Recovery in the United Kingdom Continental Shelf: Past, Present and Future

Jayasekera¹,

Goodyear

2002

All Days

View full text Add to dashboard Cite

Gas production from the UKCS commenced in 1967 and oil production in 1975. The North Sea area is now very much a mature province with the large fields in the Southern, Central and Northern North Sea producing at significantly below their early plateau production rates. Here the drive is to maximise the overall economic hydrocarbon recovery from the province, by making the best use of the infrastructure that has been built up to bring in new discoveries and improve recovery from the mature fields. New areas (deeper, harsher climate) are being opened up for exploration on the Atlantic Margin. This paper reviews the evolution of the mature areas of the UKCS, with case studies to illustrate the technical challenges that have been overcome. Over the years government and industry have expended considerable resources in developing innovative techniques for improved hydrocarbon recovery. These range from developments in the application of EOR processes to advances in drilling and reservoir management technology, including novel seismic techniques to identify new or bypassed oil. Technological advances have also unlocked reserves in heavy oils and in high-pressure high-temperature (HPHT) condensate fields, which were left undeveloped until the 1990s. Finally the potential for further exploitation and life extension of the UKCS as a significant hydrocarbon province will be reviewed. This will cover perceived technology gaps in opening up the new areas in deeper water, opportunities for redeveloping mature fields using new technology, combining IOR with carbon dioxide sequestration, and the need to drive down costs to be competitive in the international arena, while honouring environmental commitments. Introduction Oil exploration and production in the UK began onshore in the early part of the 20th century in the East Yorkshire, Lincolnshire and East Midlands areas. Later the interest extended to include the Dorset basin in the south of England. These were typically mechanical pump assisted fields producing a few 100 bbls/day/well. The first offshore gas field, West Sole in the Southern North Sea (SNS), was discovered in 1965 and brought onstream in 1967. Oil was first discovered in the Central North Sea (CNS) in 1969 and the first oilfield to come onstream was Argyll in 1975, followed soon after by the Forties field. The UK became self-sufficient in oil around 1980. Oil production on the UKCS has followed a typical exploitation path for a hydrocarbon producing area with large conventional fields being developed first and thereafter smaller fields utilising the infrastructure. It has now entered a third phase with the development of technically more difficult fields such as heavy oil fields and High Pressure High Temperature (HPHT) fields. A recent paper1 reviewed the UKCS heavy oil fields, so the primary focus of this paper is light oil fields. In the early days the industry used the term Enhanced Oil Recovery (EOR) to describe the deliberate injection of an alternative fluid to displace further oil from reservoir rock, over and above the standard pressure maintenance strategy (waterflooding for most UKCS oil fields). In the 1990s the industry began to use the term Improved Oil Recovery (IOR) to cover any operation (including the EOR techniques) that increased oil recovery above the figure that had been initially accepted as economically and technically exploitable. ‘Improved Hydrocarbon Recovery’ is a more general term that will cover all hydrocarbon types, including gas, but it is not commonly used as an acronym.

show abstract