The Bonga field, which is located in deep water off the Nigerian coast, started oil production at the end of 2005. In order to sustain production, seawater injection started from the beginning of the oil production at a rate of 300k bwpd. During the field development it was concluded that seawater injection in Bonga would result in reservoir souring, and that mitigation was necessary. Initially the selected strategy for Bonga seawater injection was to control reservoir souring with biocide and handle low levels of H2S with sour service materials and scavenging facilities topside. The maximum H2S the existing facilities could handle was set at 50 ppm (v). The decision to control reservoir souring with biocide and handle H2S at surface was re-evaluated in 2003, and it was concluded that there would be a risk that the maximum allowable H2S content in the facilities (i.e. 50 ppm(v)) might be exceeded during the life time of the project. Given the positive experience with the injection of nitrate in other seawater floods throughout the industry, nitrate was selected as the mitigation method and injection started directly at the beginning of the waterflood at the end of 2005. As such Bonga is one of the first waterfloods where nitrate is being used to prevent reservoir souring, the main application so far has been to reduce H2S in already sour fields. This paper presents the experience gained with the nitrate injection during the first period of the Bonga waterflood. Issues like logistics and how to ensure nitrate is applied correctly are discussed in more detail. In addition laboratory testing executed to define an appropriate nitrate injection rate under Bonga conditions are also presented. After several months of operation the Minox unit to remove the bulk of the oxygen broke down and oxygen control was done with chemical oxygen scavenger only. With this different mode of operation, the effectiveness of the nitrate as souring mitigation method was expected to be affected. Additional laboratory experiments, also reported in this paper, were performed and did not indicate any issue with respect to the predicted souring. Introduction The Bonga field lies on the continental slope in the southern part of the Niger Delta some 120 km offshore, South West of Warri in Nigeria with water depths ranging from 950 to 1200 m. The main 702 reservoir, which is expected to deliver over half of the recoverable reserves, is comprised of amalgamated turbidite channels. Typical net reservoir thickness is less than 100 ft with sand porosities range from 20 - 37% and multi-Darcy permeabilities. Seawater injection for pressure maintenance and sweep is key to the success of the Bonga development. A total of sixteen wells (nine producers and seven water injectors) were drilled during the Bonga phase 1 drilling campaign. Another twenty-four wells will be drilled in Bonga Main with eight additional "in field opportunity" wells, which started November 2006.All fluids produced are processed on an FPSO situated centrally in the field and oil is directly loaded to tankers. The associated gas is exported through pipelines. Produced water is processed to appropriate standards and disposed of overboard. During the field development it was concluded that Bonga was expected to suffer from reservoir souring and that mitigation would be necessary. Initially the expected H2S content resulting from reservoir souring was not expected to exceed 50 ppm (v) in the gas phase, but when more data became available it was realised that the reservoir souring may be more severe and the final mitigation method included the use of nitrate (Ref. 1). The nitrate injection rate was 45 ppm w/v active nitrate, which was based on field experience only as currently there is no engineering method available to optimise this injection rate.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractWith the realization that water injection is generally taking place under fracturing conditions, tools capable of better modelling fractured injection and its impact are being developed. Models integrating rock (fracture) mechanics and traditional reservoir simulation are now applied to water injection projects with a number of applications in the Middle East. Fracture dimensions are a key input to those models. Monitoring techniques to track the evolution of induced fractures with time are also being deployed. Amongst those techniques microseismic and specific fall-off test procedures are used.

Well test analysis in turbidite reservoirs is complicated by the intricate stratigraphy prevailing in this depositional environment. Because of this complexity, important reservoir architectural parameters driving flow behavior (e.g., shale drape coverage, object dimensions) cannot be estimated using simple analytical reservoir models employed in conventional well test analysis techniques. Alternatively, simulation-based well test analysis offers the advantage of being able to capture stratigraphic complexity. However, it requires a very large number of models and simulations to identify multiple solutions to such a highly non-unique inversion problem. In this work, we have developed a novel well test analysis workflow by constructing a large library of build-up type curves derived by appropriately scaling a comprehensive set of reference drawdown simulations. This set is used to rapidly identify a variety of stratigraphic scenarios matching a given well test. Key stratigraphic parameters are then estimated through statistical analysis of the results. The proposed well test analysis technique has been applied to synthetic and field examples. For the tested cases, stratigraphic interpretations derived from well tests are found to be consistent with those obtained from other data sources.

The Bonga field located in deep water off the Nigerian coast needs pressure support to effectively recover the hydrocarbons. The strategy is to inject 300k bwpd seawater from the start of oil production. During the field development in 1999 it was concluded that Bonga was expected to suffer from reservoir souring, and that mitigation would be necessary. Initial data gathering indicated that the expected H2S content resulting from reservoir souring was not expected to exceed 50 ppm(v) in the gas phase. Initially nano-filtration to reduce the sulphate level in the seawater was identified to mitigate reservoir souring but due to the high CAPEX costs it was dropped and as there were no other proven mitigation techniques available, it was decided to operate without mitigation. The strategy for this project was to let the reservoir sour and handle the H2S with sour service materials and scavenging facilities topside. The facilities were designed to handle a maximum level of 50 ppm(v) H2S. As detailed design progressed and more field data became available, doubts were raised on the suitability of this approach. The strategy to let the reservoir sour and handle the H2S at surface was re-evaluated in 2003. It was found that H2S levels are likely to exceed 50 ppm(v). Since then a new strategy with mitigation was adopted. Several operators had verified that nitrate injection is an effective mitigation technique to control H2S development. However, to date the main application for nitrate had been the reduction of H2S in already sour fields and the experience for the use of nitrate from the start of the water injection scheme was limited. This paper presents a detailed evaluation of the potential for reservoir souring due to biogenic reservoir souring in the Bonga field, and work done to predict H2S levels. The paper will also focus on the selection of nitrate as a mitigation method. Introduction The Bonga field (Figure 1) lies on the continental slope in the southern part of the Niger Delta some 120 km offshore, South West of Warri in Nigeria with water depths ranging from 950 m to 1500 m. The reservoirs are Lower Upper Miocene in age, and are interpreted as stratigraphically / structurally trapped mud rich unconfined turbidite systems in a mid-lower slope setting. The reservoirs are composed of fine-grained amalgamated channel sands derived from the shelf margin to the northeast. The main 702 reservoir, which is expected to deliver over half of the recoverable reserves, is comprised of amalgamated turbidite channels. The other reservoirs are stacked either above (690) or below (710/740, 803), and are generally less well amalgamated. Net reservoir thickness is generally less than 100 ft. Measured sand porosities range from 20–37% and are generally associated with high (multi-Darcy) permeabilities. Seawater injection for pressure maintenance and sweep is key to the success of the Bonga development. A total of sixteen wells (nine oil producers and seven water injectors) were drilled during the Bonga Phase 1 drilling campaign. All fluids produced will be processed on an FPSO situated centrally in the field and oil is directly loaded to tankers (Figure 2). The associated gas will be exported through pipelines. Water will be processed to appropriate standards and disposed of overboard.

fax 01-972-952-9435. AbstractThe Bonga field, which is located in deep water off the Nigerian coast, started oil production at the end of 2005. In order to sustain production, seawater injection started from the beginning of the oil production at a rate of 300k bwpd. During the field development it was concluded that seawater injection in Bonga would result in reservoir souring, and that mitigation was necessary. Initially the selected strategy for Bonga seawater injection was to control reservoir souring with biocide and handle low levels of H 2 S with sour service materials and scavenging facilities topside. The maximum H 2 S the existing facilities could handle was set at 50 ppm (v).The decision to control reservoir souring with biocide and handle H 2 S at surface was re-evaluated in 2003, and it was concluded that there would be a risk that the maximum allowable H 2 S content in the facilities (i.e. 50 ppm(v)) might be exceeded during the life time of the project. Given the positive experience with the injection of nitrate in other seawater floods throughout the industry, nitrate was selected as the mitigation method and injection started directly at the beginning of the waterflood at the end of 2005. As such Bonga is one of the first waterfloods where nitrate is being used to prevent reservoir souring, the main application so far has been to reduce H 2 S in already sour fields. This paper presents the experience gained with the nitrate injection during the first period of the Bonga waterflood. Issues like logistics and how to ensure nitrate is applied correctly are discussed in more detail. In addition laboratory testing executed to define an appropriate nitrate injection rate under Bonga conditions are also presented.After several months of operation the Minox unit to remove the bulk of the oxygen broke down and oxygen control was done with chemical oxygen scavenger only. With this different mode of operation, the effectiveness of the nitrate as souring mitigation method was expected to be affected. Additional laboratory experiments, also reported in this paper, were performed and did not indicate any issue with respect to the predicted souring.