This paper presents an overview of the factors involved in the selection of an active souring management solution for the Mars field, at which waterflood operations are due to commence in March 2004. It is well documented that the majority of similar seawater injection applications have experienced increased down-hole sulfate-reducing bacteria activity and the reservoir souring and H2S control difficulties associated with this. The Mars field was initially commissioned in 1996 with non-NACE MR0175 compliant materials used for well tubing and casing. Following detailed reservoir modeling, and HSE Risk Assessment, a plan was developed to change-out all production tubing to NACE materials, and a 100 % redundant H2S monitoring system was installed. However, replacement of production casing materials was cost prohibitive so a plan was developed to mitigate the predicted levels of souring by the use of an active souring control approach. Investigation into the various alternatives available, including sulfate removal membranes, biocide treatment and nitrate or nitrite injection, has determined that nitrate injection is likely to be the most effective souring prevention tool.


The Mars field in the Gulf of Mexico has been producing since 1996 via a Tension-Leg Platform (TLP) host, located approximately 130 miles South East of New Orleans and moored in 3000ft of water. In order to prevent sand compaction and maintain high levels of production in the coming years it has become necessary to waterflood the reservoir. Due to the lack of a local aquifer and the distance of the TLP from shore, the only viable option has been to use a seawater flood injecting directly into the oil leg. The maximum output of the present injection system is 90,000 barrels of water per day (BWPD), although provision has been made for this to be increased to 130,000 BWPD later in the field life if this proves necessary.

It is well known that waterflood operations, undertaken with the aim of prolonging field life and increasing ultimate hydrocarbon recovery levels, often lead to souring of reservoirs as a consequence of the activity of sulfatereducing bacteria (SRB) within the reservoir being stimulated by seawater injection (1). Souring can increase production costs due to the requirement for the use of sour service materials, the need for chemical treatments to reduce H2S to acceptable levels, the generation and consequences of iron sulfide scaling, increased corrosion rates, health and safety considerations and, potentially, the shutting-in of affected wells.

A management of change (MOC) was issued in June 1995 documenting a change to P110 and CYP-110 sweet service casing for the production strings from NACE MR0175 compliant (2) C100 sour service materials on the grounds of a cost saving and on the basis that sulfate removal membranes would become a viable technology. It is this decision to specify non-H2S tolerant materials downhole that has subsequently shaped the requirement for the work considered in this document. This work has been performed in order to assess the uncertainties involved in the prediction of the future extent of reservoir souring and, ultimately, to develop an active souring management plan to allow continued production in a situation where the reservoir will have a propensity to sour following the commencement of waterflood operations.

A comprehensive study to determine the H2S exposure limits of the existing production metallurgy has resulted in the replacement of production tubing strings and their associated components. However, the original well casing is still in place due to the prohibitive cost of fully recompleting the

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