The $100 Million Question:
Will I Need A Sulphate Removal Plant For Oilfield Souring Control?
Rawwater, the UK-based specialist in oilfield souring control, is providing oil majors globally with greater levels of insight than have previously been available into whether or not their oilfields will sour.
Only recently, Rawwater used its considerable knowledge of oilfield souring to demonstrate to a leading operator that downhole conditions within one of its assets meant that a costly sulphate removal plant (SRP) would not be required. The resultant savings in plant and infrastructure were estimated to exceed $100 million. It is an established fact of geology and geochemistry that crude from some oilfields is sweet, whereas from others it is sour. More expensive to refine, due to higher concentrations of highly corrosive sulphur (typically more than 5%), sour crude requires the use of corrosion-resistant topsides equipment, expensive sulphate removal technologies and chemical dosing regimes.
The phenomenon of microbiological reservoir souring
Geology and geochemistry aside, the process of pumping sulphate-containing water (typically seawater) into oil reservoirs – to maintain pressure during secondary recovery operations – can introduce sulphate-reducing bacteria into a sweet oil environment. Where conditions are right, the result is the production of hydrogen sulphide and a phenomenon known as ‘microbiological’ reservoir souring. However, as it can take several years of microbial activity before higher levels of souring are noticed in output, the challenge is to identify the likelihood of souring early enough to establish cost-effective treatment strategies – particularly as reservoir souring is thought to take up as much as a third of production budgets.
Concerned that platforms originally set up for sweet oil production will be unsuitable for the receipt of sour crude, topsides operators may, understandably, choose to invest in costly sulphate removal plants for souring control where there is a risk of microbiological souring. Thanks to Rawwater’s work into the causes of oil reservoir souring and its development of predictive software modelling, however, an oilfield’s propensity to sour can be forecast over the life of operation.
Leading the understanding of microbiological oilfield souring
For more than 30 years, Rawwater has been cultivating oilfield bacteria strains and, today, operates what is widely regarded as the world’s most advanced facility for the study of microbiological oilfield souring under laboratory conditions.
Oilfield souring studies were once completed through the use of simple sand, oil and seawater bottle tests or ‘up-flow’ sand packs subjected to atmospheric pressure. These ‘simple’ tests, however, were unable to replicate the temperature and pressure conditions found downhole, meaning that it was not possible to establish the effects of temperature and pressure on oilfield microbiology. By comparison, Rawwater operates a suite of more than 50 pressurised bioreactors – specially constructed corrosion-resistant columns that are filled with sand, seawater and crude, inoculated with oilfield bacteria, and then subjected to the same pressures and temperatures as found in the reservoir environment. Testing pressures range from atmospheric pressure to 12,000psig, with testing temperatures ranging from 5°C to just below the boiling point of water.
The DynamicTVS© predictive oilfield souring tool
To establish if, when, and to what level an oilfield will sour, data from Rawwater’s pressurised bioreactor studies is then entered into the organisation’s DynamicTVS© (TVS = Thermal Viability Shell) predictive oilfield souring tool. Developed over many years, DynamicTVS© can forecast a reservoir’s propensity to sour in good time for cost-effective remedial strategies to be put in place. By applying its DynamicTVS© souring forecasting model to data from the asset, Rawwater was able to show the operator that the pressure and temperature conditions found within the well were too extreme to support the microbiological growth that would lead to sulphide production. To corroborate the findings, a 12-month pressurised bioreactor study then took place.
About Rawwater’s pressurised bioreactor programme
Generating high levels of interest from oil majors and chemical service companies, Rawwater’s pressurised bioreactor research programme commenced in 2006. The programme was instrumental in the birth of the Seriatim series of work into oilfield souring, with $10 million in funding being set aside for Rawwater to establish a pressurised bioreactor dataset. By October 2018, just 12 years after the programme’s start date, Rawwater had built up no less than the equivalent of 400 years’ worth of oilfield souring data.
Rawwater’s software modelling programme, DynamicTVS©, can forecast a reservoir’s propensity to sour in advance of well completion. The DynamicTVS© model describes the cooling of an oil reservoir due to water flooding, the opportunity for growth of sulphate-reducing microorganisms (SRMs) in the cooled zone, the movement of resultant hydrogen sulphide to the producer and the downhole and topsides partitioning of the sulphide at specified pressures and temperatures. DynamicTVS© was developed at UMIST – the University of Manchester Institute of Science and Technology. To date, more than 130 souring forecasts, including single injector/producer (I/P) pair forecasts and full-field statistical analysis, have been completed for clients worldwide.