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The L12/L15 area is located in the Dutch sector of the Southern North Sea, some 5–10 km from the coastline of the Wadden Islands. Exploration in the 1970s led to the discovery of five small, near-tight (permeability ~1 mD) gas accumulations in a Rotliegend sandstone reservoir, located at a depth of ~3000m. Two of the fields were developed in the 1990s with 5 production wells drilled from a central 9-slot processing platform. The three remaining discoveries, all within drilling reach of the platform, were considered too small, marginal and risky to develop. In 2009, it was decided to fully re-assess the area. This resulted in successful development of two of the undeveloped discoveries in the past five years. Both fields have been drilled with a single long-reach well (>4 km step-out), stimulated with a massive hydraulic fracture from a stimulation vessel. Similar development of the third accumulation is being prepared. An integrated approach was key to the success of the developments. For both fields, detailed static and dynamic reservoir modeling was performed to select the optimum well location and estimate potential recovery. Optimising the stimulation treatments involved hydraulic fracture modeling and defining a suitable completion, perforation and clean-up strategy. Extensive post-job analysis of the hydraulic fracture treatments was performed, integrating core data, wireline log data, fracture treatment data, welltest data and production data. Results of the analysis clearly show the value of hydraulic fracturing in these marginal near-tight gas fields. The first well showed a post-frac well performance which exceeded expectations, while in the second well the fracture performance was below expectation after initial clean-up, although well productivity improved during the first weeks of production, which was attributed to continued clean-up of the formation from frac fluids. One of the fields discussed in the underlying paper illustrates the typical challenges associated with compartmentalised reservoirs in the Rotliegend play in the Southern North Sea. This field has a Northern compartment which is depleted from an initial pressure of 340 bar to a pressure of less than 100 bar after more than 15 years of production. The Southern compartment of the field was known to form a separate accumulation (within the same structural closure) with a deeper GWC and different gas composition compared to the Northern compartment, based on data from an appraisal well drilled in 1982. The new development well targeting this field was drilled in a compartment located between the Northern and Southern compartment, with an unknown GWC. The well found the same (deep) GWC and gas composition as the 1982 appraisal well in the South, but nevertheless found the reservoir to be depleted by up to 50 bar which is attributed to direct communication with the Northern compartment. The case illustrates the complexities involved in compartmentalisation over geologic vs. production times.

Wellbore tortuosity can be defined as any unwanted deviation from the planned well trajectory. As wells become more complex, oil companies increasingly perceive wellbore tortuosity as a concern in the process of drilling, completing and producing wells. Tortuosity is a potential source of additional torque/drag and can lead to problems while running casing, liners and completions. In specific applications, excessive tortuosity in horizontal wells can even impair productivity. Due to the conceptual difference in steering principle between conventional directional drilling systems, utilizing steerable bent housing motor technology, and rotary steerable systems, it has been claimed that rotary steerable systems produce a less tortuous wellbore. This effect has so far not been quantified, mainly due to the absence of a sufficient body of comparative data. In this paper, results of a tortuosity analysis of a number of North Sea wells drilled with rotary steerable systems, and offset wells drilled with steerable motors systems is presented. Various mathematical definitions of wellbore tortuosity and their implications are also discussed. The analysis shows that drilling with rotary steerable systems significantly reduces tortuosity. In tangent sections drilled with the rotary steerable system, superior inclination hold performance was observed and in areas of the wellbore where deviation changes were planned, more continuous curve sections were drilled. In order to illustrate potential benefits this may have with respect to drilling conditions, results from the evaluation were used to carry out torque/drag simulations. Levels of tortuosity produced by steerable motor systems and rotary steerable systems were calculated from the well data studied. These values were superimposed on a generic well profile. It was found that the torque reducing effect of the lower tortuosity delivered by the rotary steerable system is quantifiable and in some cases significant. Introduction The term wellbore tortuosity refers to the crookedness of an "as-drilled" wellpath. It is not a measure of the complexity of a three dimensional wellplan in itself - though the term is sometimes used incorrectly in this context - but a measure of the inevitable, unwanted undulations around it. As directional wells become longer, deeper and more complex, oil and service companies increasingly perceive tortuosity as a concern in the process of drilling, completing and producing wells. Tortuosity is a source of additional torque and drag while drilling and may result in problems while running casing, liners and completions. In addition, the increase in drillstring-casing contact can add to drillstring and casing wear. In specific applications, excessive tortuosity in horizontal wells can even impair productivity. In principle, wellbore tortuosity can be evaluated based on the directional wellplan and the survey of a well or section of a well. There is no industry standard for the numerical evaluation of wellbore tortuosity. In this paper, various mathematical expressions for tortuosity and their implications are discussed. In addition, the tortuosity of a number of North Sea wells has been evaluated in terms of these definitions, focusing in particular on differences in tortuosity levels of sections drilled with steerable bent housing motor technology as opposed to sections drilled with a rotary steerable system, the AutoTrak™ Rotary Closed Loop System. As an illustration of the impact of tortuosity on drilling efficiency, implications for torque/drag of the differences in tortuosity levels found have been further investigated and quantified.

TX 75083-3836 U.S.A., fax 01-972-952-9435.Abstract NAM in the Netherlands is currently conducting studies to redevelop the Schoonebeek oil field, onshore in the Netherlands. Steam flooding is the envisaged process.Large volumes of produced water from this field are to be re-injected in regional depleted Zechstein fractured carbonate gas fields. Estimates of injection rates and volumes are required for reservoir selection and pumping requirements. This paper demonstrates a methodology which permits injection rate and volume predictions to be made in a simple spreadsheet model based on historical measured gas production rates and volumes. The paper describes how to convert an analytical gas productivity index solution for dualporosity systems to a water injectivity index. The conversion was validated using rigorous dual-porosity simulations and sensitised to a broad range of matrix and fracture properties. It was found that injectivity in the fractured Zechstein carbonate is constrained by the effective permeability of the fracture system and is relatively insensitive to matrix permeability and fracture spacing. This behavior was verified by calculation of a dual-porosity pseudo skin factor. Partially fractured models also demonstrate that some matrix pore space which was capable of producing gas, cannot be effectively accessed by injected water volumes.The converted water injectivity index combined with other nonlinear repressurisation, relative permeability and water viscosity effects were combined with surface pump curve and wellbore head/friction calculations to construct a spreadsheet capable of predicting long term injectivity on an individual well basis. A large number of wells were screened and optimized using this practical tool.This methodology can be readily applied to other water disposal projects targeting depleted, naturally fractured or matrix only gas fields.

The E17a-A gas field, located offshore The Netherlands in the Southern North Sea, started production in 2009 from Upper Carboniferous sandstones, initially from three wells. Since early production history of the field, the p/z plot extrapolation has consistently shown an apparent Gas Initially In Place (GIIP) which was more than 50% higher than the volumetric GIIP mapped. The origin of the pressure support (e.g. aquifer support, much higher GIIP than mapped) and overall behavior of the field were poorly understood. An integrated modeling study was carried out to better understand the dynamics of this complex field, evaluate infill potential and optimize recovery. An initial history matching attempt with a simulation model based on a legacy static model highlighted the limitations of existing interpretations in terms of in-place volumes and connectivity. The structural interpretation of the field was revisited and a novel facies modeling methodology was developed. 3D training images, constructed from reservoir analogue and outcrop data integrated with deterministic reservoir body mapping, allowed successful application of Multi Point Statistics techniques to generate plausible reservoir body geometry, dimensions and connectivity. Following a series of static-dynamic iterations, a satisfying history match was achieved which matches observed reservoir pressure data, flowing wellhead pressure data, water influx trends in the wells and RFT pressure profiles of two more recent production wells. The new facies modeling methodology, using outcrop analogue data as deterministic input, and a revised seismic interpretation were key improvements to the static model. Apart from resolving the magnitude of GIIP and aquifer pressure support, the reservoir characterization and simulation study provided valuable insights into the overall dynamics of the field – e.g. crossflows between compartments, water encroachment patterns and vertical communication. Based on the model a promising infill target was identified at an up-dip location in the west of the field which looked favorable in terms of increasing production and optimizing recovery. At the time of writing, the new well has just been drilled. Preliminary logging results of the well will be briefly discussed and compared to pre-drill predictions based on the results of the integrated reservoir characterization and simulation study. The new facies modeling methodology presented is in principle applicable to a number of Carboniferous gas fields in the Southern North Sea. Application of this method can lead to improved understanding and optimized recovery. In addition, this case study demonstrates how truly integrated reservoir characterization and simulation can lead to a revision of an existing view of a field, improve understanding and unlock hidden potential.