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.
The Grove field is located in the Southern North Sea and has been in production since 2007. The Grove A well lies within block 49/10a and was originally planned by Centrica as an infill well, drilled horizontally in the central fault compartment of the Grove field structure. The well targeted the relatively undepleted basal "A" sandstone unit of the Late Carboniferous, Westphalian reservoir, also known as the Barren Red Measures (BRM).
The well objectives were to 1) target the Grove A sand from the G1 "donor" well, 2) establish a suitable completion strategy for field development, 3) assess the performance of a multiple stage (four to five) hydraulically fractured horizontal well, 4) acquire sufficient log data to fully evaluate the reservoir, and 5) acquire reliable permeability and reservoir pressure measurements to assist in reservoir simulation.
The A sand reservoir unit has a porosity of approximately 10% and permeability between 0.05 to 1 md, with a reservoir with true vertical thickness (TVT) of approximately 140 ft at the heel and 40 ft at the toe. The reservoir unit is poorly drained by the other wells, and the Grove infill well is the first horizontal gas well in the field to be stimulated by means of multistage hydraulic proppant fracturing. The hydraulic fracturing treatment used sand plug isolation to separate consecutive fracture stages, and the fracture stimulation operations were performed with the rig in place by means of a converted stimulation vessel. The stimulation treatments successfully used a modified sand plug methodology that employed aggressive breaker schedules and fluid injections rates that were determined to be more efficient than previous treatments based on employing strict "sand plug setting" criteria. The findings are presented, as well as analyses of both prefracturing and fracturing data for the treatments together with results of the well post-completion and hook-up production.
This work should be of interest to offshore operators world-wide performing multiple hydraulic fractures in both horizontal and vertical wells using sand plug isolation technology.
Gerling, P. (Federal Institute for Geosciences and Natural Resources (BGR), Germany) | Kockel, F. (Federal Institute for Geosciences and Natural Resources (BGR), Germany) | Krull, P. (Federal Institute for Geosciences and Natural Resources (BGR), Germany) | Stahl, W. J. (Federal Institute for Geosciences and Natural Resources (BGR), Germany)
DEEP NATURAL GAS-THE HC POTENTIAL OF PRE-WESTPHALIAN ROCKS IN NORTH GERMANY P. Gerling, F. Kockel, P. Krull and W. J. Stahl, Federal Institute for Geosciences and Natural Resources (BGR), Hannover, Germany Abstract. The reserves of natural gas in Germany are limited. Hence, new exploration concepts are necessary to meet the future requirements. The BGR has studied in collaboration with German and European universities and the Germany oil industry the possibilities for deep gas generation in northern Germany. The term `deep gas' defines natural gas generated from organic matter in pre-Westphalian Sediments. A multidisciplinary geo- logical and geochemical approach has been followed in this research program: Structural geology of the pre- Permian and palaeogeographical studies of potential pre-Westphalian source rocks. Organo-petrographical studies in order to set up maturity maps of Base Zechstein and Top pre-Permain. Modelling of burial and subsidence. Source rocks evaluation including hydrous and anhydrous pyrolysis experiments. Extensive gas and isotope geochemistry on reservoir gases and pyrolysis products. The integration of all results verify that the prerequisites for the existence of deep gas in Germany are fulfilled in several cases and allow `perspective areas' to be defined.
As a contribution to securing the mid and long- term domestic supply of natural gas, but also in the run-up to industrial exploration, the Federal Insti- tute for Geosciences and Natural Resources (BGR), has being carrying out the interdisciplinary study `Deep Gas' (Stahl et al. 1996). The aim was to gain evidence for the existence of deep gases of pre-Westphalian origin, to narrow down their genetic origin, to estimate the timing of gas generation and to highlight the circumstances under which deep gases in the North German Basin can be expected. DISTRIBUTION OF PRE-WESTPHALIAN SOURCE ROCKS Early Paleozoic source rocks and Devonian source rocks certainly play only a subordinate role in the North German Basin. The source rock potential in the pre-Westphalian carboniferous Sediments however is extremely inter- esting, especially since the natural gas fields Altmark- Wustrow and Alfeld-Elze are situated outside the distribution of coal-bearing Westphalian. In the Dinantian, coal-bearing delta-plain and lacustrine deposits as well as alternations of shallow- marine and deltaic deposits (Yoredale facies) with source rock potential are limited to the northern and north eastern fringe of the depositional area (Mid North Sea high, Ringköbing-Fyn high, Lublin area). Intra-platform basins, known from Central Britain and containing marine and non-marine source rocks, may also occur in the southern North Sea basin and in the north German plains. South of the graben- dissected carbonate platform the large, starved Rheno-Hercynian basin with marine source rocks (alum shales, silicious shales) extended from the Rhine to Upper Silesia.