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.
Africa (Sub-Sahara) Oil samples have been recovered in the FAN-1 exploration well, being drilled offshore Senegal. Elevated gas and fluorescence were encountered in a shallow secondary target, and the presence of oil was confirmed by an intermediate logging program. Oil samples from thin sand were collected by a wireline formation tester for further analysis. The well will be deepened to a planned total depth of approximately 5000 m. Cairn is the operator (40%), with partners ConocoPhillips (35%), FAR (15%), and Senegalese national oil company Petrosen (10%). A drillstem test of BG Group's Mzia-3 well--located in Block 1, offshore southern Tanzania, at a water depth of around 1800 m--reached a maximum sustained flow rate of 101 MMscf/D of natural gas. The Mzia prospect is a multilayered field of Upper Cretaceous age with a gross gas column estimated at more than 300 m.
Ruoff, Matthijs (Oranje-Nassau Energie B.V.) | Costa, Driss (Oranje-Nassau Energie B.V.) | Rosenberg, Steven (Weatherford) | Ameen, Sayamik (Weatherford) | Krol, Dariusz Krol (Weatherford) | Salomonsen, Halvard (Weatherford) | Tan, Ming Zo (Weatherford)
While drilling through the Permian Zechstein Group, North Sea operators can encounter a permeable overpressured interval which cannot be statically stabilized with conventional methods. An operator proposed drilling with Liner (DwL) in combination with managed pressure drilling (MPD) and continuous circulation technologies as a potential solution to this drilling hazard. In case that the overpressured interval was not seen, the DwL BHA could be retrieved after which the remaining section would be drilled conventionally. The DwL process allows a hazardous interval to be isolated in a single trip resulting in less risk and exposure compared with conventional drilling methods. Realizing the potential benefits automation brings, many operators have turned to MPD techniques as a technical and cost-rewarding solution to hard-to-reach assets, an approach which not only saves time but also enhances the safety capabilities of the operation. More importantly, MPD is increasingly being considered for other operations requiring precise pressure control to maintain wellbore integrity in constricted drilling envelopes. Continuous circulation technology provides a method to ensure continuous flow downhole while making connections which supplements the controlled annular pressure profile to avoid a drilling fluid / formation fluid change out. The prompt collaboration within the operator-service provider team determined which combination of these technologies would be the safest and most effective means for managing the overpressured interval should it be encountered.
This collaborative effort consisted of well engineering analysis and risk assessment sessions to ensure that the 12 ¼-in. hole objectives could be met in a safe and efficient manner aligning with the overall well objectives. The analyses included DwL, MPD, continuous circulation procedures and related simulation modelling for the running, drilling and cementation of the 9-5/8-in. × 13-3/8-in. liner. The combined technologies encompass a multitude of engineering disciplines; these were integrated into the operator's drilling plan in a seamless manner. Potential concerns and drilling hazards were identified and reduced to a manageable level. Ultimately, the 9-5/8-in. DwL system was used without encountering the overpressured interval and therefore the DwL BHA was retrieved with the remaining 12-1/4-in. hole interval conventionally drilled to planned depth without incidents. This paper will illustrate inclusion of DwL, MPD and continuous circulation technologies in the drilling plan as an effective solution for the mitigation of hazardous intervals. It will also reinforce the value of a close working relationship between operator and integrated service providers to eliminate uncertainties and provide sufficient risk mitigation to ensure that intended well objectives will be met.
A narrow hydraulic window was the main challenge for a Dutch operator drilling various slimhole wellbores into the Carboniferous-aged Rotleigend reservoir formation in the North Sea, offshore Holland. The targets were reached by first drilling through the Zechstein salt, Silverpit, and Lower Slochteren formations. This paper discusses the application of a high performance organo-clay-free invert-emulsion fluid (OCF-IEF) with low equivalent circulating density (ECD) characteristics to help drill well targets through depleted formations.
The objective, referred to as ZeRoOne, was to drill the Zechstein and Rotliegend formations in one section. The decision to drill ZeRoOne was based on a risk and value assessment for extending field life and maximizing production in the maturing asset. A primary factor in the basis of design was selection of a fluid system capable of delivering low ECD margins, thus mitigating risks involved in drilling a 1200 m (3,937 ft) long section through the overburden and into the reservoir. Design mud weight was set at 1.62 SG with an expected fracture gradient (FG) of 1.86 SG (15.49 lbm/gal). Though a relatively wide margin, there was a marked downside risk—it is difficult to quantify a lower fracture gradient in overburden-reservoir transition zone because of depletion.
The OCF-IEF system delivered ECDs well within the critical mud-weight window, minimizing risks through the 6-in. section. ECDs ranged from 1.70 to 1.72 SG (14.20 to 14.33 lbm/gal), resulting in a 0.14 SG (1.2 lbm/gal) margin below FG.
The operator was able to successfully drill the well and penetrate the depleted reservoir, overcoming the challenge through Lower Slochteren formation. In contrast, offset wells in the same field development, drilled with conventional invert-emulsion fluids, showed much higher ECD values ranging from 1.79 to 1.84 SG (14.91 to 15.33 lbm/gal), with a margin of only 0.2 SG below FG; some of these wells did not reach target total depth (TD) because of the restrictive (minimal) drilling margin.
The successful trial application of the OCF-IEF while drilling the ZeRoOne objective allows more challenging, longer stepouts, directional, and extended-reach drilling (ERD) wells to be drilled as part of the ongoing extended-life field development. The technical objectives of the well would not have been achieved without the use of this system.
This paper presents the analyses of well tests and production logging carried out on three multi-fractured horizontal wells in the Babbage tight gas field, UK Southern North Sea. The actual performance observed in these wells was compared to the forecasts made based on open-hole well data and the data gathered during hydraulic fracturing operations. Some of the drawbacks in analysing well test data are discussed along with the uncertainties in modelling hydraulic fractures. Horizontal wells with multiple hydraulic fractures are used to increase productivity and recovery in tight reservoirs. Understanding and predicting fracture performance is essential to the field commerciality considering the associated high development costs, especially in the North Sea.
The results of this study indicate that based on several pressure transient analyses, the clean-up time can be up to several months, which was observed in the form of gradual skin reduction over time. The PLT data also confirmed that there is cross flow during the shut in periods, usually flowing from the outer fractures into the inner fractures. This was believed to have an impact on the interpretation of the build-ups. Moreover it was shown that during build-up tests of more than 500 hours, linear flow was the dominant flow regime and therefore the final radial flow stabilization had not yet been reached.
There are many studies in the literature on the design, operations, characterization and numerical modelling of similar multifractured horizontal wells. However there are not many publications presenting real field data and the performance of these wells. This paper covers the well performance data in addition to the design, modelling and operations of the multi-fractured horizontal wells.
The Cavendish gas field is located off-shore in the Southern Gas Basin of the UK North Sea. The Westphalian and Namurian Fluvial Sandstones are at a depth of circa 11,500 ft (3,500 m). The gas wells showed an initial reservoir pressure of 6,100 psia (420 bara) and a temperature of 230 °F (110 °C). During gas production starting in 2007 the initial gas production rate of 60 to 70 MMscf/d per well decreased significantly after seven months of production. The condensate-gas-ratio was between 3.5 and 11.0 stb/MMscf for the two active producers. During a well a work-over at the end of 2010, down-hole solids and liquid samples were taken for analysis to identify possible formation damage processes. The solids were identified by x-ray diffraction as rust and scale, mainly carbonate scale. The liquids were characterized by gas chromatography as hydrocarbon condensate, with no trace of residual drilling mud. Two formation damage or productivity impairment mechanisms were identified; scaling and hydrocarbon banking.
Carbonate scale was caused by the interaction of reservoir brine and the high concentration of carbonate ions in the high pH K-formate drilling fluid. Due to the comparatively long exposure times (ca. 16 days) and thermal degradation of the drilling fluid, hydrogen-carbonate ions were formed and because of the relatively high calcium content of the formation water and presence of ferroan dolomite as intergranular cement within the matrix, carbonate scale was precipitated.
2. Hydrocarbon Banking
Liquid hydrocarbons condensed as a result of the lean-retrograde gas condensate character of the reservoir fluids and reservoir pressure decreasing below the respective dew point pressures. This was confirmed by the interpretation of the PVT and fluid compositional analysis with computational software tools.
In order to restore productivity, the reservoir section of the two affected wells was milled and re-perforated. After this treatment their productivity was observed to increase significantly. A proactive scale inhibition treatment for the future was not regarded as necessary because all technical (non-formation) fluids were removed and the wells are not regarded as significantly self scaling. Also the reservoir pressure had decreased sufficiently to prevent any severe further retrograde hydrocarbon condensation in the wellbore area.