At South Arne a highly repeatable time-lapse seismic survey (normalized root-mean-square error or NRMS of less than 0.1) allowed us to reliably monitor reservoir production processes during five years of reservoir depletion. Time-lapse AVO (amplitude v. offset) inversion and rock-physics analysis enables accurate monitoring of fluid pathways. On the crest of the field, water injection results in a heterogeneous sweep of the reservoir, whereby the majority of the injected water intrudes into a highly porous body. This is in contrast to a pre-existing reservoir simulation model predicting a homogeneous sweep. On the SW flank, time-lapse AVO inversion to changes in water saturation DS w reveals that the drainage pattern is fault controlled. Time-lapse seismic data furthermore explain the lack of production from the far end of a horizontal producer (as observed by production logging), by showing that the injected water does not result in the expected pressure support. On the highly porous crest of the reservoir compaction occurs. Time-lapse time shifts in the overburden are used as a measure for compaction and are compared with predictions of reservoir compaction from reservoir geomechanical modelling. In areas where compaction observations and predictions disagree, time-lapse seismic data give the necessary insight to validate, calibrate and update the reservoir geomechanical model. The information contained in time-lapse seismic data can only be fully extracted and used when the reservoir simulation model, the reservoir geomechanical model and the time-lapse seismic inversion models are co-visualized and available in the same software application with one set of coordinates. This allows for easy and reliable investigation of reservoir depletion and gives deeper insight than using reservoir simulation or time-lapse seismic individually.

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This paper demonstrates a field case study where large volumes of deferred oil, due to calcite deposition, have been reduced by effective scale modeling and a strong focus on optimised well performance. The South Arne field, operated by Hess Denmark, on behalf of the South Arne Partnership, is an oil field in the Danish sector of the North Sea. Production is from a chalk reservoir using de-sulphated seawater injection for pressure support. Calcite deposition has been problematic in some of the wells with a variety of mitigation and clean-up methods being employed. The deferred production peaked with 100,000 barrels of oil in 2006. Since then, the oil deferment has been reduced by 75 % by continuously improving the calcite scale prediction and prevention for the wells. Modeling carbonate scale deposition is challenging and many scale prediction models can be over-conservative, leading to unnecessary chemical injection, excessive use of chemicals and sub-optimal oil production. A new methodology for predicting calcite scale has been applied to the South Arne field, becoming a successful tool for downhole scale management. This new approach is based on scale kinetics as a function of temperature, integrated with detailed pressure-temperature traverse data derived from the interpretation of well tests and gas lift performance. Results have been used to guide well operation decisions and to support a new scale prevention strategy based on deep injection of large volumes of lift gas. Accurate calcite scale prediction is sensitive to the carbonate alkalinity. The approach described here is based on simulating the calcite scaling kinetics from reservoir to wellbore. Model results show that produced water is close to calcite saturation from deep reservoir to the wellbore, and this has been used as the basis for calculating carbonate alkalinity in the produced water. Hence in this paper the calcite saturation index for the onset of scaling has been defined using calcite kinetics to give a fixed scaling rate rather than the more customary use of a fixed saturation index. In addition, well performance models were completely re-worked to include observations from recent well interventions and new data input parameter validations. The calcite scale prediction methodology described here has provided the South Arne field with benchmarked operating scale envelopes that on a regular basis are utilised to optimise well performance in terms of risk and reward.

This paper demonstrates how innovative data acquisition, phased planning and world class placement of filler material in a short circuit lead to a successful water shut-off restoring 477 m3/day (3,000 BOPD). Hess operates the South Arne Field located offshore Denmark. Two flank horizontal wells, a producer and a water injector, started short-circuiting water via an abandoned sidetrack. High pressure (517 barg) water from the injector flowed directly into the producer (172 barg) killing the oil production. The wells’ horizontal length is 3 km and is completed with a cemented liner. The liners are subdivided into 17 zones with production/injection tubing, iso-packers and sliding sleeve doors. Each zone has been stimulated with acid fractures. The vital part of the data acquisition was multiple tracer tests from different zones at different production and injection ratios, which increased the tracer recovery from 15% to 100%. In addition, tracer data revealed transit time, sidetrack volume and number of paths; all crucial information for a successful water shut-off. A gel mimic test was performed to account for differences in rheology. Pressure and temperature logging tools in the wells provided the pressure and temperature gradient along the sidetrack, which was crucial data for placement of the temperature sensitive filler material. The decision was to approach the challenge in three phases; firstly, data acquisition; secondly, interpretation of data, filler material laboratory tests, design of job; thirdly, implementation of the water shut-off. This proved to be advantageous as it allowed time for appropriate adjustment and planning of the complex setup. The 19 m3 (120 barrels) of filler material was mixed on the platform and pumped into the injection well tubing while producing from the production well at controlled condition with one optimal sliding sleeve door open in each well and an optimal production/injection ratio The temperature of the filler material increased as it travelled to its final destination in the sidetrack leaving a 450 m (1475 ft) solid isolation plug. One year after the water shut-off, oil production has increased from 0 to 477 m3/day (3,000 BOPD) saving an expensive and challenging re-drill. This project underlines the importance of spending time and money, upfront, on innovative acquisition and planning to increase a project's chance of success.

fax 01-972-952-9435. AbstractThe Joint Chalk Research (JCR) initiative is set up by a group of operators and partners in the Southern North Sea. The objective of the initiative is to increase the ultimate recovery in their respective chalk assets to 60%.Analyzing the different production technology options used in the assets thus far was the next step in better understanding the different recovery increment options. The initial 4 year productivity from 4 assets was analyzed.This paper presents the results of a study focused on increasing the understanding of productivity drivers using a database on well productivity related to different completions, stimulations and production options. The database contains 56 wells from 4 different assets and 750 acid and proppant treatments in 663 perforated intervals.It was found that the absolute total production per interval is similar for all assets; however the drawdown applied in 1 asset is 4 times lower than the other assets.The performance of the wells in most assets dropped strongly over time, except in the low drawdown asset. It was found that in addition to transient effects, it is likely that a decline in hydraulic fracture completion efficiency also contributes to this decrease in production performance.The low drawdown asset has a much better normalized production performance than the other assets. Other factors might also influence this result, however, compelling evidence has been found that the much lower drawdown may cause the better performance over time.The normalized recovery of propped fracced wells was better than the acid treated well in 2 of 3 assets using both stimulation types. The higher recovery of the propped treatments was mainly from better productivity over time compared with the acid fracture treatments. However, the initial productivity of the acid fractured well was much better, hence the economic balance could still tip to the acid treatments.The analysis showed that, for all assets except one, there is a significant difference in the performance of acid fractured wells and propped fractured wells over time. Indications are that production declines are not only due to depletion, but also related to deterioration of the completion efficiency as a function of pressure drawdown and suboptimal efficiency of acid treatments. An extensive statistical analysis indicated a strong dependency on asset grouping, which hampers the extrapolation of experience from one asset to the others Bart Vos and Hans de Pater