A fundamental knowledge of microbial community structure in petroleum reservoirs can improve predictive modeling of these environments. We used hydrocarbon profiles, stable isotopes, and high-density DNA microarray analysis to characterize microbial communities in produced water from four Alaskan North Slope hydrocarbon reservoirs. Produced fluids from Schrader Bluff (24–27°C), Kuparuk (47–70°C), Sag River (80°C), and Ivishak (80–83°C) reservoirs were collected, with paired soured/non-soured wells sampled from Kuparuk and Ivishak. Chemical and stable isotope data suggested Schrader Bluff had substantial biogenic methane, whereas methane was mostly thermogenic in deeper reservoirs. Acetoclastic methanogens (Methanosaeta) were most prominent in Schrader Bluff samples, and the combined δD and δ13C values of methane also indicated acetoclastic methanogenesis could be a primary route for biogenic methane. Conversely, hydrogenotrophic methanogens (e.g., Methanobacteriaceae) and sulfide-producing Archaeoglobus and Thermococcus were more prominent in Kuparuk samples. Sulfide-producing microbes were detected in all reservoirs, uncoupled from souring status (e.g., the non-soured Kuparuk samples had higher relative abundances of many sulfate-reducers compared to the soured sample, suggesting sulfate-reducers may be living fermentatively/syntrophically when sulfate is limited). Sulfate abundance via long-term seawater injection resulted in greater relative abundances of Desulfonauticus, Desulfomicrobium, and Desulfuromonas in the soured Ivishak well compared to the non-soured well. In the non-soured Ivishak sample, several taxa affiliated with Thermoanaerobacter and Halomonas predominated. Archaea were not detected in the deepest reservoirs. Functional group taxa differed in relative abundance among reservoirs, likely reflecting differing thermal and/or geochemical influences.

Summary Waterflood thief zones in communication with the rest of the reservoir are a severe and previously challenging problem. This paper gives an introduction to the nature of a novel, heat-activated polymer particulate. Details are presented of a trial of this in-depth diversion system, resulting in commercially significant incremental oil from a BP Alaskan field. The system of one injector and two producers was selected because of a high water/oil ratio and low recovery factor, which was recognized as an indicator of the presence of an injection-water thief zone and was confirmed by study of a previous injection survey. The area around the wells is bounded by faults, so the system can be considered to be isolated from surrounding wells and operations. The position of the thermal front in the reservoir, tracer transit times, injection rates, and interwell separations indicated that the slowest reacting of the three commercial grades available was most appropriate for the trial. The treatment was designed using laboratory tests and numerical simulation informed by pressure and chemical-tracer tests. Long- sandpack tests indicated permeability-reduction factors of 11 to 350 for concentrations of 1,500 to 3,500 ppm active particles in sand of 560- to 670-md permeability at 149°F. 15,587 gal of particulate product was dispersed using 8,060 gallons of dispersing surfactant, into 38,000 bbl of injected water, and was pumped over a period of 3 weeks at a concentration of 3,300 ppm active particles. Placement deep in the reservoir between injector and producer was confirmed by pressure-falloff analysis and injectivity tests. The incremental oil predicted from the simulation was 50,000 to 250,000 bbl over 10 years. In fact, more than 60,000 bbl of oil was recovered in the first 4 years at a cost comparable with that of traditional well work and less than that of sidetracking.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractWaterflood thief zones in communication with the rest of the reservoir are a severe and previously challenging problem. This paper gives an introduction to the nature of a novel, heat-activated polymer particulate. Details of a trial of this in-depth diversion system, resulting in commercially significant incremental oil from a BP Alaskan field are presented. The system of one injector and two producers was selected because of a high water oil ratio and low recovery factor, which was recognized as an indicator of the presence of an injection water thief zone and confirmed by study of a previous injection survey. The area around the wells is bounded by faults so the system can be considered to be isolated from surrounding wells and operations. The position of the thermal front in the reservoir, tracer transit times, injection rates and inter-well separations indicated that the slowest reacting of the three commercial grades available was most appropriate for the trial.The treatment was designed using laboratory tests, and numerical simulation informed by pressure and chemical tracer tests. Long sandpack tests indicated permeability reduction factors of 11 to 350 for concentrations of 1500 to 3500 ppm active particles in sand of 560 to 670 mD permeability at 149°F. 15,587 gallons of particulate product was dispersed, using 8,060 gallons of dispersing surfactant, into 38,000 barrels of injected water and pumped over 3 weeks at a concentration of 3300 ppm active particles.Placement deep in the reservoir between injector and producer was confirmed by pressure fall off analysis and injectivity tests. The incremental oil predicted from the simulation was 50,000 to 250,000 bbl over 10 years. In fact over 60,000 barrels of oil was recovered in the first 4 years at a cost comparable with traditional well work and less than sidetracking. Bright Water injectionMixing surfactant : EC 9360A

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe paper outlines the experimental work that has been carried out to develop an effective treatment strategy for production wells, specifically those with electrical submersible pumps (ESP's) that suffered significant performance impairment at water cuts of less than 5% due to carbonate scale deposited within the ESP's. These Alaskan production wells had been treated for a couple of years using aqueous based scale inhibitor squeezes. Many of these treatments resulted in a significant 10% to 20% reduction in the oil production rate following the squeeze. The damage mechanism was investigated by coreflooding and revealed to be a combination of water block and relative permeability effects. Following the damage investigation coreflood, a second study was undertaken to investigate a chemical treatment to remove the damage already present within the near well bore and prevent further deposition of scale. The result of this test program was the development of a treatment strategy which used a solvent package followed by an oil soluble scale inhibitor. Field results of this type of treatment suggest that the wells treated with this chemical system did not suffer any reduction in oil production rate and were effectively protected from carbonate scale. Wells that had been damaged by the previous aqueous treatments could be stimulated and the lost oil production recovered. Reference is also made to the development of an improved aqueous based squeeze treatments for the treatment of higher water cut wells.

Summary This paper outlines the development of an effective treatment strategy for production wells that suffered significant performance impairment at water cuts of less than 5% caused by carbonate scale deposited within the electrical submersible pumps (ESPs). These Alaskan production wells had been treated for a couple of years with aqueous-based scale-inhibitor squeezes. Many of these treatments resulted in a significant reduction (10 to 20%) in the oil production rate following the squeeze. The damage mechanism was investigated by coreflooding and was revealed to be a combination of water block and relative permeability effects. Following the coreflood damage investigation, a second study was undertaken to investigate a chemical treatment to remove the damage already present within the near wellbore and to prevent further deposition of scale. The result of this test program was the development of a treatment strategy that used a solvent package followed by an oil-soluble scale inhibitor. Field results of this type of treatment suggest that the wells treated with this chemical system did not suffer any reduction in the oil production rate and were effectively protected from carbonate scale. Wells that had been damaged by the previous aqueous treatments could be stimulated, and the lost oil production could be recovered. Reference is also made to the development of improved, aqueous-based squeeze treatments for the treatment of higher water-cut wells. Introduction The formation of inorganic mineral scale within onshore and offshore production facilities around the world is a relatively common problem. Scale can form from a single produced connate or aquifer water, owing to changes in temperature and pressure, or when two incompatible waters mix. An example of the latter would be seawater support of a reservoir, where the formation water is rich in cations (Ba, Sr, Ca) and the injection water is rich in anions (SO4). The production of such comingled fluids results in the formation of inorganic scale deposits. The type of scale and their solubility is a function of the water chemistry and the physical production environment. This paper will outline the scale types observed at the Milne Point field, North Slope, Alaska, the associated production problems, and the strategies used, past and present, to control the deposition of scale. Field Location and Scale History Field Location and Description. Milne Point is an onshore field on the northern coast of Alaska. There are approximately 270 wells that produce from and inject into three different reservoirs. The field production is currently on plateau at 53,000 BOPD. Roughly 90% of the production wells are lifted with ESPs. Typical completions are perforated and fractured. A waterflood is currently in progress with produced water and source water from a freshwater aquifer. The fieldwide water cut is currently 30%. Scale Problems Observed. Over the production history of the field, pump failures have been a constant problem, resulting in increased lifting costs owing to rig workovers, lost oil, and logistics. The root cause of pump failures has ranged from reservoir solids, such as sand and fracture proppant eroding the ESPs or being trapped within the intakes and pump stages, to deposition of different types of carbonate and sulphate scale within the pumps. One quarter of all pump failures in 1997–98 were associated with the deposition of scale in or on the ESPs. The remainder were associated with mechanical problems, erosion caused by sand, and electrical problems.1,2 The formation of such scale deposition is not unusual, and the formation mechanism will be discussed later. However, the fact that scale deposition and associated pump failures occurred in wells with water cuts of <1% is more unusual. Scale deposits were initially addressed by removal with acid washes followed by typical aqueous-based scale squeeze treatments. In the low water-cut wells (<5%), these treatments resulted in significant oil production losses. Additional deployment options, such as capillary tubing, solid scale inhibitor deployed in baskets below the pumps, scale inhibitor included in data fractures, and scale inhibitor within impregnated fracture proppant, have been tried at Milne Point. These methods were met with limited success, were economically prohibitive, or were opportunity driven, as in the case of the fracture options. Water Chemistry. The formation and injection water compositions are presented in Table 1. The scale potential for the formation water is relatively slight at reservoir temperature, and, in fact, the scaling tendency, with respect to carbonate, declines as injection watercut rises (see Figs. 1 and 2). The decline in the supersaturation ratio, which is the thermodynamic driving force to form scale, is caused by the reduction in bicarbonate concentration within the injection brine. The tendency for the formation of sulphate scale also declines as injection water breaks through, owing to the dilution of the barium ions within the formation water. From this analysis, it follows that scale has not been observed within the near-wellbore or production tubing. However, scale has been observed in the ESPs because of increased fluid temperature from the motor heat and pressure changes throughout the pump. Figs. 3 and 4 show the scaling tendency for the formation water at elevated temperatures and across a range of pressures. By comparison with Figs. 1 and 2, it is clear that the scale potential of the brine is much higher as a result of the ESPs as opposed to natural production of the fluids.