Weijermans, Peter-Jan (Neptune Energy Netherlands B.V.) | Huibregtse, Paul (Tellures Consult) | Arts, Rob (Neptune Energy Netherlands B.V.) | Benedictus, Tjirk (Neptune Energy Netherlands B.V.) | De Jong, Mat (Neptune Energy Netherlands B.V.) | Hazebelt, Wouter (Neptune Energy Netherlands B.V.) | Vernain-Perriot, Veronique (Neptune Energy Netherlands B.V.) | Van der Most, Michiel (Neptune Energy Netherlands B.V.)
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.
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 dual-porosity 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.