Currently, the application of nitrate/nitrite is considered one of the most promising souring mitigation solutions during Produced Water Re-Injection (PWRI). Norske Shell tested nitrate based souring mitigation as part of a PWRI feasibility study in the Draugen field. Prior to the pilot, the application of both nitrite and nitrate had been tested on Draugen using a Souring Mitigation Cabinet (SMC) specially developed to mimic the microbial activity in the near well reservoir. From this pre-study, the dosage of nitrate was selected based upon bio-available carbon and the required stoichiometric concentration of nitrate. During the PWRI pilot, corrosion rates were measured continuously Downstream (D/S) the Water Injection (WI) pumps in the High Pressure (HP) system, and after three months testing, significant increases in corrosion rates were seen. These were thought to be related with the addition of nitrate to the Produced Water (PW). To investigate this more closely, the SMC was modified by including a dedicated Low Pressure (LP) Corrosion Sidestream Monitoring (CSM) system. The results obtained in the CSM system verified the results obtained in the HP corrosion monitoring system in place on Draugen. The results of the Draugen PWRI pilot also showed that the addition of nitrate to the PW was efficient to control near-well reservoir souring. However, as mentioned above the corrosion rates increased logarithmically when nitrate was used. At the same time, a few ppm nitrite was seen in the nitrate treated PW water. The addition of biocide resulted in an instantaneous decrease in nitrite and corrosion rates to background levels. The result clearly indicates that bacterial activity, resulting from the addition of nitrate, was the causative agent of the increased corrosion seen in the Draugen PW treated for re-injection. It was concluded that the increase in corrosion rates most likely was Microbiologically Influenced Corrosion (MIC). Details of the PWRI pilot and the observed effects when applying nitrate are discussed in this paper. Because of the negative side-effects observed when applying nitrate to PW, Norske Shell re-evaluated the requirement to mitigate souring with nitrate. The testing during the PWRI pilot showed a low tendency to develop SRB activity, probably because of the low VFA concentration in the PW. Consequently it was decided to terminate the application of nitrate to PW on Draugen and control bacterial activity in the surface facilities with biocide. As nitrate is still promising to be applied in PW in other field applications, dedicated research has been initiated to learn more about the mechanisms leading to the increased corrosion rates seen when applying nitrate in PW. Introduction The Draugen field The Draugen field is situated in block 6407/9 at Haltenbanken and the platform is operated by A/S Norske Shell E&P (Exploration and Production). Haltenbanken is considered to be an environmental sensitive area on the Norwegian Continental Shelf (NCS). The water depth varies between 240 and 290 meters. Oil and gas is produced from a sandstone reservoir, consisting of the Garn and the Rogn formations (Figure 1) and is situated at 1610 meters the below seafloor.The bottom-hole temperature is 71°C and the pressure is 165 bars. Oil production started in October 1993 and is predicted continuing until year 2025. Seawater injection, at an average of 40 000 m3/day, was initiated in 1994 to maintain the pressure in the reservoir. In 2002, significant water production on a continuous basis started, and in September 2006, 50% water cut was reached. The water cut in later field life is expected to reach >90%. The maximum water production is expected around year 2012 (34–37 000 m3/day) and a rather flat profile is expected until 2024. As the water production increases, it is expected that the existing produced water system would not meet the zero discharge goals on the NCS. PWRI was considered a promising solution. As part of the Norwegian Government Commitment to Zero Harmful Discharges (ZHD) by 2005 and the Shell Group Minimum Standard Targets incorporating PW injection, A/S Norske Shell adapted a produced water management strategy with a ZHD objective. As a result, a PWRI pilot was planned in the Draugen field.

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.

fax 01-972-952-9435. AbstractCurrently, the application of nitrate/nitrite is considered one of the most promising souring mitigation solutions during Produced Water Re-Injection (PWRI). Norske Shell tested nitrate based souring mitigation as part of a PWRI feasibility study in the Draugen field. Prior to the pilot, the application of both nitrite and nitrate had been tested on Draugen using a Souring Mitigation Cabinet (SMC) specially developed to mimic the microbial activity in the near well reservoir. From this pre-study, the dosage of nitrate was selected based upon bio-available carbon and the required stoichiometric concentration of nitrate.During the PWRI pilot, corrosion rates were measured continuously Downstream (D/S) the Water Injection (WI) pumps in the High Pressure (HP) system, and after three months testing, significant increases in corrosion rates were seen. These were thought to be related with the addition of nitrate to the Produced Water (PW). To investigate this more closely, the SMC was modified by including a dedicated Low Pressure (LP) Corrosion Sidestream Monitoring (CSM) system. The results obtained in the CSM system verified the results obtained in the HP corrosion monitoring system in place on Draugen.The results of the Draugen PWRI pilot also showed that the addition of nitrate to the PW was efficient to control near-well reservoir souring. However, as mentioned above the corrosion rates increased logarithmically when nitrate was used. At the same time, a few ppm nitrite was seen in the nitrate treated PW water. The addition of biocide resulted in an instantaneous decrease in nitrite and corrosion rates to background levels. The result clearly indicates that bacterial activity, resulting from the addition of nitrate, was the causative agent of the increased corrosion seen in the Draugen PW treated for re-injection. It was concluded that the increase in corrosion rates most likely was Microbiologically Influenced Corrosion (MIC). Details of the PWRI pilot and the observed effects when applying nitrate are discussed in this paper.Because of the negative side-effects observed when applying nitrate to PW, Norske Shell re-evaluated the requirement to mitigate souring with nitrate. The testing during the PWRI pilot showed a low tendency to develop SRB activity, probably because of the low VFA concentration in the PW. Consequently it was decided to terminate the application of nitrate to PW on Draugen and control bacterial activity in the surface facilites with biocide.As nitrate is still promising to be applied in PW in other field applications, dedicated research has been initiated to learn more about the mechanisms leading to the increased corrosion rates seen when applying nitrate in PW.

Summary Big reservoirs in deepwater Gulf of Mexico (GOM) typically produce at world-class rates. The scale of investment is likewise world class. The energy industry's drive to invest in enhanced oil recovery from deepwater basins is sustainable in a world of volatile oil prices and increasing demand for energy. However, project economics will continue to depend on accurate risk assessment, risk-mitigation strategies, and, more fundamentally, progressive deployment of evolving technologies in brownfield deepwater secondary-recovery projects. Details of well geometry and design optimizations may prove to be minor sensitivities in high-cost deepwater developments; however, rig rate has a major impact on economics. The assessment required to minimize the number of injectors and ensure their proper placement logically takes more time than exotic choices of injection patterns. With such major constraints in mind, an optimal design for wells and materials has to take precedence. Accepting this as a given, additional, more common challenges would then follow. The waterflood-study team for the deepwater Ursa/Princess field in the GOM has spent appreciable time and effort evaluating various potential challenges affecting the surface and subsurface aspects of the development plan. The design for an optimum injection rate was a bottom-up process starting from the reservoir up to the topsides injection facilities. Reservoir-sweep efficiency and reservoir-pressure distribution logically dictated injection-well designs and injection-pump sizing. Subsurface risks, such as reservoir souring and hydrate formation, dictated materials selection and completions design. This paper addresses the challenges primarily affecting the design of the deepwater subsea-injection wells. In addition to the well cost, several other underlying factors have played an influential role in defining the boundary conditions for the injectors design. Background Industry-wide experience in the execution and the operation of waterflood projects in deepwater environments is relatively limited. With relatively few analogs, the Ursa and Princess fields are set to embark on major facilities expansion and subsea development. The aim is to deliver a high rate of specific-quality water through four subsea-injection wells into a vast and, largely thirsty, reservoir. Ursa and Princess reside 100 miles south/southeast of the Mississippi River mouth in the Mars basin, GOM. The Ursa field was discovered in 1990 and has been on production since 1999. The Princess field was discovered in 2000 and has been producing since December 2003 through a subsea tieback to Ursa. The fields have their main reservoirs in common and are in pressure communication. The working interest in the Ursa and Princess fields are Shell (45--operator), BP (23%), ExxonMobil (16%), and ConocoPhillips (16%). The Yellow reservoir is the main reservoir at both Ursa/Princess and Mars, the other major field in the Mars basin. It is a world-class Upper Miocene turbidite reservoir that stretches across the Mars basin, including the Mars field. This 12,000-acre reservoir is charged with light-oil type, though with slight variations in properties, as indicated by the analysis results of the abundant pressure-volume-temperature measurement samples. Because of limited TLP well availability, the high cost of subsea wells and the limitations of the subsea system to handle large water cuts, the waterflood will use relatively few injectors. The proposed base plan has four water injectors: two into Princess and two into Ursa. Producing wells will include three Princess subsea wells and four Ursa TLP wells. Five TLP wells are to be sidetracked updip or recompleted at a later stage. High injection rates are required to replace voidage and maintain reservoir pressure above bubblepoint. Initial injection rates per well (annual average) of 30 to 40 thousand BWPD are required. This injectivity can only be maintained by creating fractures. With the wide well spacing relative to fracture length, this is not expected to negatively impact sweep efficiency. However, because of the uniqueness of well spacing and reservoir volumes, there is a lack of analog-data points to calibrate the outcomes. Parallel evaluation of the viability of artificial lifting has shown that TLP waterflood producers would benefit from gas lifting. The base plan for waterflood wells thus includes the requirement for gas-lift completions and facilities. The original Operating Health Safety and Environmental (HSE) case for the asset did not include the potential threat of reservoir souring after seawater injection. The well casing and tubular materials, therefore, have limited resistance to sulfide-stress corrosion cracking. This resulted in the need to recomplete the Ursa TLP direct-vertical access (DVA) wells with Shell-qualified tubing. Princess producers already have Shell-qualified C100 sour-resistant casing, and will not require pre-emptive intervention for tubing change out.

This paper discusses technical drivers that influence the produced/flowback water management goals and decisions in unconventional hydrocarbon developments and then presents case studies and a decision tree chart for effective water treatment. Produced/flowback water quality in shale projects is influenced not only by the formation, but also by the fracturing fluid introduced to the formation during hydraulic stimulation. The water produced by shale wells can contain suspended solids, dissolved solids, organics including hydrocarbons and residual fracturing fluid chemicals, and bacteria. Furthermore the water composition can change rapidly during the short flowback period followed by gradual stabilization during the production phase. The clean-up treatment of water with complex and highly varying quality with an effective and robust treatment process presents specific challenges. Conventional oilfield water treatment technologies may not be always effective in unconventional gas projects due to specific constituents in produced/flowback water such as residual polymers. This paper describes the functional water treatment steps, which target the most common removal of suspended solids and oil/condensate from flowback water/produced water for recycling or disposal operations. In addition pilot tests were run to validate and assess the performance of solids and oil/condensate removal processes. One key learning is that residual guar gum polymer in the water has a major impact on treatment effectiveness and thus the equipment selection process.