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Europe
Nitrate Based Souring Mitigation of Produced Water - Side Effects and Challenges from the Draugen Pproduced Water re-Injection Pilot
Vik, Eilen Arctander (Aquateam) | Janbu, Astrid Oust (Aquateam) | Garshol, F. Kristi (Aquateam) | Henninge, Liv Bruas (Aquateam) | Engebretsen, Stian (Aquateam) | Kuijvenhoven, Cornelis (Shell) | Oilphant, David (Shell Expro) | Hendriks, Willem Pieter (Shell)
Abstract 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 m/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 m/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.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- Geology > Mineral (0.35)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.49)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6407/9 > Draugen Field > Rogn Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6407/9 > Draugen Field > Garn Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6407/12 > Draugen Field > Rogn Formation (0.99)
- (3 more...)
Abstract Most carbonate reservoirs are naturally fractured and typically produce less than 10% OOIP during primary recovery. Spontaneous imbibition is an important oil recovery mechanism from these types of reservoirs. In some situations, imbibition of water can be promoted by chemical stimulation with surfactants to alter the reservoir wettability toward water-wetness such that oil is expelled at an economic rate from the rock matrix into fractures. Here, we investigated the use of chemicals to modify the wettability of reservoir rock to a more water-wet state in order to produce additional oil via imbibition. Five chemicals that effectively improved water-wetness were used in the imbibition tests: two nonionic surfactants Tomadol T91–8 and Pluronic L-64, two anionic surfactants Rhodacal A-246L and Rhodapex CD 128, and an amphoteric surfactant Mirataine CB. The San Andres formation in the Permian Basin of Texas and New Mexico is a great oil-producing formation in the United States. An estimated 50,000 wells produce oil from this oil-wet carbonate reservoir. Laboratory imbibition tests were conducted on core plugs and fluids from the Fuhrman Masho and Eagle Creek fields. Thin section analysis indicated that both fields contain dolomite, calcite, and anhydrite. The core plugs were soaked in imbibition cells containing formation water at a reservoir temperature of 40°C (104°F). For Fuhrman Masho cores, maximum oil recovery via water alone was less than 4% of the original oil in place (OOIP). After the oil production stopped, the water was replaced with a surfactant solution at a concentration of 1500 to 3500 ppm. The imbibition process then continued until no oil was produced. The incremental oil recovered varied from 0 to 48% OOIP; higher permeability and bulk volume of oil in the cores resulted in higher oil recovery by surfactant imbibition. No oil was produced by brine imbibition for some Eagle Creek cores; however, others produced up to 34% of the OOIP. Surfactant treatment did not improve oil recovery every core. The laboratory tests indicated that the improved oil recovery by surfactant treatment depended on rock mineralogy, porosity, permeability, and pore heterogeneity. Each field must be individually evaluated. Introduction Spontaneous imbibition can be especially important to oil recovery from fractured reservoirs. However, spontaneous imbibition does not take place if rocks are oil-wet or neutral-wet. Spontaneous imbibition only occurs when the pore surfaces are effectively water-wet so that water imbibes into the rock matrix, and oil is expelled into the fractures where the oil can be flushed along the fractures toward the production wellbore. The focus of this project was to investigate the use of chemicals for modifying the wettability of reservoir rock to a more water-wet state in order to produce additional oil via spontaneous imbibition. The significance of spontaneous imbibition as a recovery mechanism was first recognized for the naturally fractured Spraberry field of west Texas in the early 1950s. Oil recovery by spontaneous imbibition from the Spraberry field is still being promoted. Surfactants have been used to alter the rock surface to a more water-wet state in order to promote imbibition of water into the matrix. Craig showed that surfactants could alter the rock surface from oil-wet to surfactant-wet, thus allowing oil to be displaced from the pores. Stone et al. improved oil recovery by altering the rock surface to oil-wet. Spinler et al. and Austad and coworkers have reported extensive laboratory research on improved oil recovery from carbonate cores by imbibition of cationic and nonionic surfactant solutions. The surfactant interacts with and removes the adsorbed organic materials from the rock surface, which then becomes water-wet, and imbibition is enhanced. Chen et al. reported the use of a nonionic surfactant to stimulate oil wells in the San Andres reservoir of the Yates field. The average oil-production rate for one well increased from 35 to 67 barrels per day for an incremental 17,000 barrels of oil at the time of publication. Improved recovery was ascribed to altering the wettability of the rock surface and/or gravity segregation of oil and water between the fracture and the matrix. Hirasaki and Zhang have proposed the use of anionic surfactant with sodium carbonate. At a high pH, the carbonate ion is the potential determinant and reverses the charge of the carbonate surface so that the problem of adsorption is mitigated.
- North America > United States > Texas > Midland County (0.44)
- North America > United States > Texas > Martin County (0.44)
- North America > United States > Texas > Howard County (0.44)
- (2 more...)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.89)
- Geology > Mineral (0.87)
- North America > United States > Wyoming > Bighorn Basin > Phosphoria Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (31 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (1.00)
Abstract This paper presents field results from scale squeeze treatments carried out on platform wells within a high temperature (150C) field in the Norwegian sector of the North Sea. Scale control and the resulting squeeze treatments to production wells were highlighted as the most expensive item in the production chemical budget. The development of a cost-effective squeeze and monitoring policy has been critical to reducing the operating cost of this asset as the produced water cut rose. The decision to use both aqueous and emulsified scale inhibitor for treating these high temperature production wells was arrived at after an extensive series of laboratory tests including formation damage coreflood studies and an assessment of chemical retention at this elevated temperature. The field data from these wells will be presented comparing treatment lifetimes and clean up rates between conventional treatments and the novel emulsion technology A key factor to the success of such treatment is an understanding of chemical placement and the effectiveness of the treatment chemicals. Evaluation of residual chemical concentration or scaling ion chemistry has long been used in monitoring programs and more recently probes have been developed which increase the rate of evaluation/interpretation. All these monitoring methods prove that the chemical is present in the brine when sampled or that scale formation is not occurring at the point of brine analysis. This paper outlines the experimental methods developed to evaluate the suspended solids collected from the produced brine by environmental scanning electron microscope (ESEM) and the associated brine chemistry to evaluate the scale risk within the produced fluids. The combination of these methods has improved the integrated scale management program in terms of evaluating scale squeeze placement effectiveness, squeeze lifetime and provides the confidence t0 extend the period between scale squeeze treatments. Also, and in some cases treatments were stopped where brine analysis alone would have suggested further scale squeeze applications were required. Introduction The Gyda field lies on the North-Eastern margin of the North Sea Central Trough, on the Norwegian Continental Shelf, 270 km (168 miles) southwest of Stavanger and 43 km (27 miles) northeast of Ekofisk Centre. The offshore installation comprises a conventional 6-legged steel jacket which supports integrated production, drilling and living quarters. Peak oil production topped 20,100 m/day (126,000 stb/day) during 1993. Gyda is currently operated by Talisman-Energy Norge A/S (61 %) on behalf of DONG (34 %) and Norske AEDC A/S (5 %). It was originally operated by BP Norway Ltd., and when it came on stream in July 1990, it was the deepest, hottest and lowest permeability oilfield in the North Sea. Gyda receives limited aquifer support and is developed by waterflood. There are 32 well slots of which currently 15 are for producers with a further 10 wells dedicated to water injection. From the outset it was recognised by BP that the formation water / injection water mix would lead to a severe scaling tendency. The current operator, Talisman, have sought to review the scale management process to ensure that any lessons that can be learned from analysis of the earlier stages of production may be applied to ensuring effective scale control to the end of the field life cycle. It is the results of that review process that are presented in this paper.
- Europe > United Kingdom > North Sea (1.00)
- Europe > Norway > North Sea (1.00)
- Europe > Netherlands > North Sea (0.74)
- (3 more...)
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.51)
- South America > Brazil > Campos Basin (0.99)
- North America > United States > Texas > East Texas Salt Basin > Alba Field (0.99)
- Europe > United Kingdom > North Sea > North Sea Basin (0.99)
- (9 more...)
Abstract This paper presents field results from scale squeeze treatments carried out on platform and subsea horizontal wells from a oilfield in the UK sector of the North Sea. Downhole scale control and the resulting squeeze treatments to production wells were highlighted as one of the most expensive items in the production chemical budget and impacted topside separation during treatment back production. The development of optimized scale squeeze treatments and monitoring policy has been critical to reducing the operating cost and deferred oil production of this asset as the produced water cut rose. Scale squeeze treatments have been optimised over the years with the aid of detailed reservoir simulation indicating water rates along the production wells being input into scale squeeze design software. The requirement to extend treatment life while minimising the deferred oil was one of the critical factors in selecting improved scale inhibitor chemistry. The field data from these wells will be presented comparing treatment lifetime rates between conventional treatments and the improved scale inhibitor chemistry. Evaluation of residual chemical concentration or scaling ion chemistry has long been used in monitoring programs. All these methods prove that the chemical is present in the brine when sampled or that scale formation is not occurring at the point of brine analysis. This paper outlines the experimental methods developed to evaluate the suspended solids collected from the produced brine by environmental scanning electron microscope (ESEM) and the associated brine chemistry to evaluate the scale risk within the produced fluids. The combination of these methods has improved the integrated scale management program in terms of evaluating scale squeeze placement effectiveness, squeeze lifetime and providing the confidence to extend the period between scale squeeze treatments and in some cases stop treatment where brine analysis alone would have suggested further scale squeeze applications. Introduction Field Description and Scaling Tendency The Field A is located in the UK Central North Sea in Block 16/26 approximately 225 km NE of Aberdeen. It overlies the Mesozoic Witch Ground Graben, south of the Fladen Ground Spur and north of the Renee Ridge. The field was discovered by the well 16/26–5 in 1984 with first oil production in late 1994. The Field is approximately 12 km long by 1.5 km wide trending NW to SE and consists of three parts; viz. the main field, the 15-area and the 12-area. The reservoir is of earliest Late Eocene age and comprises a series of stacked high density turbidite sands, which are unconsolidated in nature and have been deposited within a pre-cut channel on an intra-slope terrace. Intra-reservoir shales occur throughout the reservoir. They show reworked paleontological signatures derived from pre-reservoir strata out with the pre-cut channel. The origin and thus distribution of the shales is not fully understood and these shales are commonly below seismic resolution. The platform was installed as a minimum facilities module in the north of the field exporting oil by a floating storage unit (FSU). Oil production is currently conducted through eighteen horizontal producers and reservoir pressure support is provided by water injection through five injectors, including a sub-sea injection manifold. Due to the highly unconsolidated nature of the reservoir, the earlier horizontal producer wells were completed with pre-packed gravel screens.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.56)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.39)
- South America > Brazil > Campos Basin (0.99)
- Europe > United Kingdom > North Sea > North Sea Basin (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Moray Firth Basin > Witch Ground Graben > P.213 > Block 16/26a > Brae Field > Alba Field > Caran Sandstone Formation (0.99)
- (8 more...)
Sandstone Matrix Stimulation Can Improve Brownfield Oil Production When the Chemistry and Procedures Are Correct
Samuel, Elsamma (Schlumberger Well Services) | Shaikh, Ahmed Karim (Brunei Shell Petr. Sdn Bhd) | Queiros, Joao GR (Schlumberger) | Yong, Yin-Chong (Brunei Shell Petr. Sdn Bhd) | Samuel, Mathew | Chan, Keng Seng
Abstract Improving oil and gas production from the Brown Fields is now more important than ever to the operating companies, as the oil price remains record high. Matrix stimulation is often preferred as it could generate additional production gain with relatively low level of investment. In the recent acidizing campaign in Brunei, a particular challenge was the flowback of tubing pickling and spent acids, and neutralization of the spent acid on the surface. A series of effective methodologies for the stimulation of offshore multilayer sandstone oil reservoirs was implemented. The chemistry and art of four different acidizing methods involving Tubing Pickling, Bullheading, Diversion and Coiled Tubing placement were used. Stimulation of over forty wells utilizing different acid systems and procedures resulted in noticeably different production gains. The short and long term results are correlated with the stimulation procedures and practices. The present paper describes a comparison of procedures and production gains during these acid stimulation treatments. The cost, logistics and operational constraints due to specific Brunei offshore environment and conditions will also be discussed. Post-treatment production gain is correlated with the efficiency and timing of the flowback process. Use of computer-based virtual laboratory tool for the fluid selection, coreflow laboratory testing for the fluid optimization at downhole conditions and evaluation of fine migration tendencies were investigated before the treatment. The results were compared with the one from other operators in the same environment and reservoir conditions. Review of post acidizing results came up with recommendations and lesson learnt for future campaigns. This effort will certainly enhance the success ratio of the sandstone acidizing treatments. Significance: Developed lessons learnt to increase the success ratio of sandstone stimulations. Introduction Sandstone acidizing is possibility the most complicated stimulation method as it involves complex chemical reactions in the near wellbore matrix. Unlike carbonate acidizing where the simulation fluids are used to dissolve the rock around the damage materials, sandstone acidizing aims at dissolving and dispersing the minerals and damage materials in the pores of the reservoir formation. For this reason, the stimulation results using the known standard acid fluid formulations for different reservoir formations and for different wells in the same reservoir can vary widely. Optimization of the sandstone acid stimulation fluids may now be done by numerical simulation of chemical reactions. However, it will need a large amount of data not only on detailed mineral compositions of the targeted simulation zones but also on nature, location and extent of the damage materials in the near wellbore matrix. In addition, reaction products due to the reactions of the stimulation fluids with various mills and scales in the tubular and in the pumping equipment can also upset the optimized acid formulation; cause adverse reactions with the formation minerals; and further aggravate the overall complex chemistry involved in the sandstone stimulation process. Accordingly, the need to have a proper tubing pickling procedure with proper pickling acid fluid had been repeatedly emphasized. Recent marked effort in this regard included an analytical modeling of the tubing pickling process and its verification using field acidizing job data. The studies showed that the process again involved the three basic mechanisms namely surface reaction, diffusion, and convection, and the art of balancing these three fundamental forces encountered in all sandstone and carbonate stimulation. Generic Sandstone Acidizing Procedure Summarizing the known arts of sandstone acidizing, the following can be served as a recommendation for a generic but minimum standard sandstone acidizing fluid pumping procedure: Tubing Pickle and Return Brine Preflush Acid Preflush Main Acid Stimulation Fluid
- North America > United States > California > Sacramento Basin > 2 Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/8 > Heidrun Field > Åre Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/8 > Heidrun Field > Tilje Formation (0.99)
- (7 more...)
Abstract The formation of calcium naphthenate solids and stabilised emulsions continues to be a major flow assurance issue. The ability to replicate the conditions under which naphthenates form in the laboratory has, until recently, been an unresolved challenge. Recent work by the authors has resulted in improved test methodologies, utilising a novel flow rig. The rig enables the study of the formation and control of naphthenate solids and stabilised emulsions under field-representative conditions, and allows the prediction and control of their occurrence in the varying production conditions that may be experienced over a field's lifetime. This paper describes the use of the flow rig to test a number of crude systems, some of which have known calcium naphthenate problems, and some of which are known to have no calcium naphthenate issues. The results from the flow rig have been compared with field observations and show excellent correlation. Data is then presented which more directly assess the influence of a number of variables, such as water-cut, brine composition, bicarbonate level, and pH, on emulsion stability and naphthenate formation than has previously been possible under conventional laboratory test methodology. This work therefore extends our understanding of "practical" naphthenate formation. Introduction The presence of naphthenic acids in crude oil and their impact on emulsion stability and the formation of sludges, soaps, stabilised emulsions and other production problems have been known for many decades, however, little direct evidence of calcium naphthenate deposits has been reported until relatively recently. Over the last 10 years the issue of calcium naphthenate deposits has become an increasing problem, especially for fields producing oils which have been subject to biodegradation resulting in relatively low wax contents and high dissolved naphthenic acids. An increasing number of fields, especially in areas such as West Africa, the North Sea and Venezuela, have reported problems with naphthenate deposition leading to significant flow assurance issues for several major field developments. Sodium naphthenate sludges have also been observed in Indonesian fields in addition to bicarbonate and metal ion stabilised naphthenate sludges. Most work to date has focussed on specific fields and their problems, although some work has progressed over recent years to consider the generic problem and to rationalise and unravel the relative importance of the various factors involved in this complex reaction system (e.g. amount and type of naphthenic acids present in the oil phase, emulsion stability, interface activity, metal cations (particularly Ca and Na), bicarbonate concentration and pH in the brine phase, water cut and system temperature etc.). Naphthenic acids are defined as having the structure R-CO2-H, where R is often considered to have a saturated cyclic structure, but can also be a long-chain aliphatic compound, as seen in the soap industry. Robbins states that naphthenic acids are C10-C50 compounds with between 0 and 6 fused, saturated rings with carboxylic acid attached to a ring with a short side chain. However, negative ion electron spray mass spectrometry (ESMS) has indicated the presence of naphthenic acids as small as C7 in various calcium naphthenate samples. Goldszal et al. have proposed some theoretically determined structures of naphthenic acids and it is considered that the carboxylic acid groups are attached to an alkyl chain (both straight chain and branched) rather than directly onto the ring structures. In general naphthenic acids can be considered as organic carboxylic acids present primarily in the oil phase.
- Europe (1.00)
- North America > United States > Texas (0.69)
- Africa > Middle East > Libya > Murzuq District (0.28)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Block 13/29b > Blake Field > Captain Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Block 13/24 > Blake Field > Captain Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/8 > Heidrun Field > Åre Formation (0.99)
- (12 more...)
Abstract The effective placement of chemical squeeze treatments in heterogeneous wells and long reach horizontal wells has proved a significant challenge, with various factors including heterogeneity, crossflow and pressure gradients between otherwise non-communicating zones within the well, all contributing to an uneven placement of the scale squeeze treatment into the reservoir. Work recently presented by the authors has however illustrated the potential benefits of using modified injection fluids (in particular, lightly viscosified shear-thinning fluids) to aid uniform scale inhibitor placement in such wells to effect more even placement. This paper describes the various options available for achieving self diversion and describes the potential drawbacks associated with the viscous placement fluids commonly used for acid simulation techniques. In addition, the paper presents the results of laboratory and computer simulation investigations into the application of such fluids using novel laboratory core flood techniques, and discusses the implications of these results for field treatments. The work describes the importance of obtaining accurate in situ viscosity properties under realistic flow conditions to provide appropriate input data for computer simultaion studies and describes novel laboratory test methods for the determination of such properties. This work also illustrates the effectiveness of the use of dual core testing to provide experimental data to validate model algorithms prior to field applications. Introduction The effective treatment of oil wells with scale inhibitor chemicals is often confounded by the presence of a number of factors which act to place the majority of the treatment slug in an undesired region of the well. For heterogeneous wells and long reach horizontal wells, these factors can include reservoir heterogeneity, fluid crossflow, pressure gradients, wellbore friction and presence of fractures. The presence of some or all of these may result in the majority of the squeeze treatment volume being placed in an inappropriate zone in the near-wellbore, which can result in reduced squeeze lifetimes and inadequate scale protection of vulnerable near-wellbore mixing zones. The influence of these factors on chemical placement has been summarised in previous papers. In this paper we discuss the theory and application of self-diverting fluids for achieving more uniform chemical placement of the treatment slug in bullhead squeeze treatments. A novel near-wellbore simulator has been specifically designed to model the placement of these fluids, and its use is illustrated in both laboratory and field applications. The Placement Challenge In general, anything which creates a resistance to fluid flow in one zone will promote placement of an injection fluid away from that zone. This resistance to flow may be caused by the rock matrix itself (permeability factors, fluid mobility, the presence of fractures), zonal pressure differences, fluid crossflow in the well etc. In addition to these factors, the type of completion used can also affect fluid placement, for example due to wellbore friction effects.
- Europe (0.71)
- North America > United States > Texas (0.69)
- North America > United States > Texas > Permian Basin > Central Basin > Nelson Field > Ellenburger Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6407/9 > Draugen Field > Rogn Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6407/9 > Draugen Field > Garn Formation (0.99)
- (2 more...)
Abstract This paper discusses the development of a holistic water and scale management plan for a green-field development, which faces a new order of scale management challenges. Specifically, this paper documents a scale risk assessment and the development of a scale management plan during the front-end engineering design of the Tombua-Landana development in West Africa. The complexity of scale management is compounded by the presence of multiple reservoirs with very different scaling potentials and by the plans for produced water reinjection. The objective of the study was to define a complete scale management plan, which incorporates flexibility for future unknowns and minimizes the total cost of scale management, without over-capitalization. The Tombua-Landana field will produce from multiple reservoirs that incorporate several distinct formation waters with barium content as high as 800 mg/l and will require seawater injection for reservoir pressure maintenance from day one. Scaling tendency predictions were made for the major groups of formation water, both with and without seawater injection. In addition, a variety of produced water reinjection scenarios were investigated. Due to the predicted severity of barite scaling, it was determined that scale would not be effectively controlled solely by scale inhibitor chemicals. It was therefore necessary to investigate alternative mitigation strategies, primarily sulfate removal. The impact of sulfate ion removal from seawater on barite scaling was investigated in order to determine the level of sulfate ion removal that would be necessary for each water type to limit the extent of scale deposition to a level that most residual scaling could be controlled by downhole chemical injection. Because of the considerable cost associated with processing low sulfate injection water, it was necessary to optimize the size of the sulfate removal membranes (SRM) primarily by using produced water reinjection. This field study typifies several industry trends in inorganic scale management:Deepwater West Africa is emerging as a new focus area for sulfate scaling; Deepwater economics require co-production of multiple reservoirs in order to reach threshold reserves and will necessitate the installation of major infrastructures; Economic and environmental drivers support the use of produced water reinjection, even though this exacerbates water compatibility problems and creates new challenges for reservoir monitoring. Introduction The Tombua-Landana (TL) Development area is located in Block 14 offshore Cabinda, Angola as shown in Figure 1, in water depths of 800–1,300 feet. The development involves production from multiple reservoirs within the Tombua and Landana fields. The reservoirs consist of high permeability deepwater turbidite channel sands of Miocene age. The TL field will be developed from a compliant tower, drilling and production platform (DPP), located in 1,212 feet of water. This platform will act as a production and water injection hub for both dry tree and subsea satellite wells. During the appraisal phase, 16 water samples from the Tombua and Landana reservoirs were analyzed. The formation waters were found to have a wide variety of chemical compositions, ranging from a total dissolved solids (TDS) content less than seawater to an extremely high TDS (270,000+ mg/l). The high TDS waters have high calcium (up to 20,000 mg/l) and very high barium (up to 800 mg/l) concentrations, so there is a potential for moderate calcium carbonate and severe barium sulfate scaling upon mixing with sulfate-rich waters.
- Geology > Mineral > Sulfate > Barite (0.96)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment > Deep Water Marine Environment (0.54)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.87)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Blocks 16/7b > Miller Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/8b > Miller Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/7b > South Brae Field > Brae Formation (0.99)
- (3 more...)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
Abstract During the 1980's, studies initiated to resolve problems due to the activity of sulfate-reducing bacteria in oilfield systems were instrumental in the early recognition of the importance of biofilms in natural environments, the use of radiotracers to measure bacterial activity, the application of molecular techniques to study nonculturable bacteria and the detection of previously unknown Archaea in subsurface aquifers. Over the past 15 years, however, oilfield microbiology practices have not kept pace with other fields of environmental microbiology research and now the ideas and practices applied in the oilfield lag significantly behind the most recent scientific advances. This is despite the fact that the oil industry is currently attempting to control very diverse and extensive sulfide producing microbial populations by the application of nitrate to bring about a shift in the population dynamics in a process of biological competitive exclusion. Environmental microbiology is now in the midst of a revolution in the understanding of the marine and subsurface microbial world, much of which is resulting in completely new concepts of the interaction between microbes and the environment and vice versa. These advances must be recognized and wherever possible incorporated into oilfield microbiology technology. This paper describes how the application of even a few of the recent advances in environmental microbiology offers a huge potential to improve our understanding of control and remediation of sour reservoirs using nitrate treatments. Introduction The application of nitrate treatments as an alternative to biocide for the control of the activity of sulfate-reducing bacteria and Archaea in seawater waterfloods has progressed faster than our ability to understand and effectively monitor the complex microbiological mechanisms stimulated within heterogeneous oil reservoirs and seawater injection systems. Whilst the increasing application of the treatment has been driven by case histories reporting success [1, 2] there are still a number of directions by which further optimization of the technology could be addressed: Until recently, treatment recommendations were based upon historic application case histories (from other industries), laboratory tests and the stoichiometry of simplistic nutrient interactions. The conditions within the systems that are being treated may be known (i.e. topside water injection facilities) but are mainly unknown (i.e. within the subsurface formation). The mechanistic action of nitrate treatment is not defined and it may involve any one of, or a combination of, at least four processes. There are no standardized methodologies for monitoring treatment effectiveness nor for defining Key Performance Indicators (KPI's) for benchmarking treatment effectiveness. Lab studies employ planktonic batch bioreactors, whereas continuous biofilm mesocosms are far superior models. There have been logistical issues with regard to the transportation of large volumes of liquid product. Whilst there will be significantly more work required before the full mechanistic action of biocompetitive control of sulfate-reduction activity in a nitrate treated system is elucidated, there have already been advances which improve our understanding of treatment efficacy and treatment optimization which have not yet been fully exploited by those charged with dosing, monitoring and optimizing nitrate treatments in the field. Whilst guidance documents are available [3, 4], universally applied protocols have not yet been developed such that equivalent inter-field and inter-company generated data can be compared and interrogated to improve our overall understanding of the microbial mechanisms involved.
- Geology > Mineral > Sulfide (0.37)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.34)
- Health & Medicine (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.34)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 050 > Block 34/10 > Gullfaks Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 050 > Block 34/10 > Gullfaks Field > Lunde Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 050 > Block 34/10 > Gullfaks Field > Lista Formation (0.99)
- (3 more...)
Abstract Mixing of injected seawater with formation brines may cause scale precipitation at production wells and surface facilities, but does not generally cause significant damage within the formation itself. Indeed, mixing within the reservoir may be beneficial, if the concentration of scaling ions is reduced due to ion stripping as the brine mixture approaches the production well. One potential exception to this is when the availability of produced water for re-injection (PWRI) is insufficient to maintain voidage replacement, and must be supplemented with seawater. Under such circumstances, seawater and formation brine may be completely mixed before injection. This will not lead to a loss of injectivity if scale inhibitor chemicals are appropriately applied to the injected brine stream. However, scale inhibitors are retained by the reservoir rock as they are displaced away from the wellbore, resulting in the inhibitor front propagating more slowly than the saturation front - usually referred to as chemical retardation. As brine is displaced away from the injection well, the upshot is a growing zone of mixed brine with chemical concentration below the threshold required to inhibit the scaling reaction. The question this paper considers that has not been addressed before is whether the ratio of produced water to seawater that is injected, the possibility of treating the injection brine mix with inhibitor, and field specific details such as the location of the injection wells relative to production wells and the aquifer can impact how this zone of unprotected mixed brine is displaced and reacts deep within the reservoir, away from both injection production wells. If the scaling reaction can be limited to a region deep within the reservoir where the volume of rock is large compared with the potential mass of scale that may deposit, then the sulphate ions associated with seawater may be stripped from the brine mixture before the water is produced. Thus, by considered yet straightforward management of the PWRI scheme, it may be possible to protect the production wells from scale damage in a way that is not possible under conventional seawater injection. This hypothesis is tested using conventional reservoir simulators and reaction-transport modelling. Various conditions are considered, including brine reactions, extent of brine displacement through the oil leg or aquifer, as well as management of the PWRI wells. Prediction of scale damage potential at production wells is made for an example field system. Introduction Produced Water Re-Injection (PWRI) is a method for maintaining reservoir pressure and sweeping hydrocarbons towards production wells in which water separated from hydrocarbons at the surface facilities is re-injected into the same or another hydrocarbon bearing formation. Optionally, produced water may be re-injected into a specially selected aquifer. The primary objective is generally to dispose of the produced water in a manner that causes minimum damage to the environment. In addition to the environmental benefits, there are other potential benefits including making cost, space and weight savings through the optimisation of water treatment facilities. The principal disadvantage is that usually the quality of the produced water (in terms of oil-in-water and solids content, etc) is lower than that of other potential sources of injection water, and hence damage to the rock matrix into which the water is being injected has to be considered.
- Europe (1.00)
- North America > United States > Texas (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.55)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 21/10 > Forties Field > Forties Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 019 > Block 7/12 > Ula Field > Ula Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > King Lear Area > Block 7/12 > Ula Field > Ula Formation (0.99)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)