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.
Wuestefeld, P. (RWTH Aachen University) | Hilgers, C. (RWTH Aachen University) | Koehrer, B. (Wintershall Holding GmbH Germany) | Hoehne, M. (RWTH Aachen University) | Steindorf, P. (RWTH Aachen University) | Schurk, K. (RWTH Aachen University) | Becker, S. (RWTH Aachen University) | Bertier, P. (RWTH Aachen University)
Upper Carboniferous sandstones in NW-Germany consist of thick successions of cyclothems and are major tight gas reservoirs. This study presents the heterogeneity exposed in a large quarry near Osnabrueck, Germany, which contains faulted and jointed third-order coarse- to fine-grained tight sandstone cycles separated by anthracite coal seams. First, we characterize the rocks and the lateral variation of rock properties such as porosity, diagenesis and structural inventory. Than we test whether the quarry may act as a reservoir analog to better constrain input data for reservoir modelling.
The tight sandstones are intensely compacted and cemented with quartz and generally characterized by low matrix porosities < 8 % (He-pycnometry on plugs and cuttings) and very low permeabilities (<0.01 mD). Porosity is generally secondary, formed by detrital and authigenic carbonate dissolution and dissolution of feldspars. Matrix porosity significantly increases up to 25% in corridors around faults. Rock types can be distinguished by spectral gamma ray in the quarry. Fluid flow within and around faults is indicated by quartz veins and fault mineralizations. Normal faults show and bands of clay smear and gouge, forming compartments. Fractures were analyzed in a 50 x 50 m section of the quarry wall using Lidar laser scanning. This digitized quarry face also allows the characterization of the lithology and quantitative measurement of bedding, fracture and fault orientation data in inaccessible areas.
Our high resolution field analog enables a better understanding of unconventional reservoir properties and reservoir quality at a subseismic scale, considering both the change of porosity during diagenesis and the formation of structures. Results may be used to develop data-driven exploration strategies and improved development options for similar subsurface tight gas reservoirs.
This paper describes the application of dual lateral, level 4 junction - technology to successfully develop a marginal field in the Carboniferous area of the Southern North Sea (SNS) on the United Kingdom Continental Shelf (UKCS). This is the first known use of this technology in this area of the SNS where significant drilling risks have previously led to relatively simple well designs to mitigate the risk of failure.
The Rita Field straddles blocks 44/21b and 44/22c and lies 110km due east of the United Kingdom coastline and 35km west of the UK-Dutch offshore boundary. The field is composed of adjacent, tilted, Carboniferous fault block structures containing Westphalian reservoir sandstones sealed by Silverpit shale and halites at the regional Base Permian Unconformity. The NW-trending fault blocks are separated by a NE - striking normal fault. The eastern fault block was successfully tested by 44/22c-9 in 1996 whilst the western fault block was targeted by 44/21b-11 in 1998 but failed to find gas. Well results, however, indicated the likely presence of up-dip reservoir quality Westphalian sandstones, although the development risk was higher.
A North Sea coring record was set by Conoco UK Ltd (CUKL) and service provider Baker Hughes INTEQ (BHI) on 20 January 2001. A 179-ft core was cut and recovered in 6" hole from the Rotliegendes formation in the Southern North Sea.
In-depth operational planning, which included offset core viewing by a multi-discipline well team was undertaken in an effort to identify potential coring hazards. Physical testing of offset cores, rock strength data, and other relevant data sets were used to model the length of core that could be safely cut.
The coring operation was executed with the selected coring assembly and 179 ft of high quality core was recovered. Subsequent testing and analysis was performed on the core, which satisfied all evaluation requirements of the sub surface team. CUKL and BHI have successfully applied these planning techniques on a number of other wells resulting in significant improvements in coring efficiency, recovery and core quality.
The North Sea coring record was set on the Venus 49/21 - 8A well. Block 49/21 is located at the south-eastern margin of the Sole Pit Inversion Axis some 115 km east of the Norfolk coast in the United Kingdom (Figure 1). The surface location was selected to avoid a sandbank, which is a potential site of special scientific interest, consequently the well was moderately deviated at 16° to the west.
This paper provides an explanation of the concept of the AG-itator, presents field performance results and examines the potential use of the tool in CT (Coiled Tubing) drilling and workover operations. The tool has been widely used as a solution to the major problems associated with slide or oriented drilling. The concept of the tool is based on reducing friction and providing accurate weight transfer to the bit. Typical applications include; sliding with a PDM-PDC combination where previously difficult or impossible; overcoming motor stalling problems; increasing ROP and extending the length of oriented intervals. The technology is to be developed as a CT tool and is expected to be particularly useful, as CT operations are characterised by constant non-rotation and high levels of friction. These two factors ultimately lead to helical buckling which can limit the effective reach of CT drilling or workover operations.
The fluid action of the tool creates pressure pulses that generate an axial force of approximately 15,000lb at a frequency of 16Hz (refer to Fig 1). These pulses gently oscillate the bottom hole assembly (BHA), reducing friction and improving weight transfer. In this way, weight is transferred to the bit, continuously and accurately without harsh impact forces. It has been demonstrated that the tools' fluid action is benign, as it has not damaged the bit, tubulars or more sensitive equipment such as MWD/LWD. Consequently, standard downhole equipment can be used with the tool.
It is argued that accurate weight transfer improves drilling performance in several ways (1) PDC bit life can be extended as the bit is prevented from constantly spudding into the formation. Additionally, both roller cone and PDC bits can be run without the risk of damage to bit teeth or bearings; post run bit characteristics have shown that no damage to the bit occurred as a result of impact forces. (2) Higher levels of WOB can be achieved using lower off hook weight. (3) There is reduced drill pipe compression as weight is transferred effectively and not dissipated at points where the BHA or drillstring hangs up. (4) Tool face control is enhanced. (5) Gross rates of penetration are increased.
Applications for the technology exist in all modes of drilling but usage appears particularly beneficial in non-rotating drillstrings and BHAs. Such applications are increasingly common as well profiles become more tortuous and the limits of extended reach and directional drilling are reached. Run data shows that the tool is a simple way of extending the reach and capability of conventional steerable assemblies. Accurate weight transfer and exceptional tool face control have been logged using PDC bits, even in significantly depleted formations after large azimuth changes. Intervals have been extended and drilled with higher ROPs while problems associated with setting and maintaining tool face have been minimised. The technology is compatible with MWD systems and is a viable means of extending targets whilst improving ROP, reducing rock bit runs and lowering the risk of differential sticking. Before assessing the use of the technology to extend the reach of CT BHAs, it is worth looking at field performance.
Extending the reach of Conventional Steerable Assemblies - A Case History in the Dutch sector of the North Sea
The 5 7/8" section of a development well was to be drilled in the Silverpit, Lower Slochteren and Westphalian formations in the Dutch Sector of the North Sea. The drilling objectives for this section were to build inclination from 42° to 84° at the top of the Lower Slochteren, and then to maintain a tangent before dropping angle to TD. The measured depths were recorded as 3,645 and 4,373 metres respectively. Subsequently, a sub-horizontal drain of 85° was to be drilled by a BHA incorporating the AG-itator (Refer to Fig 4). The purpose of using the technology was to provide accurate weight transfer to the bit during slide drilling, thereby minimising motor stalling, the BHA hanging up and to make tool face orientation easier.
In our Southern North Sea gas reservoirs, we have acquired a number of Nuclear Magnetic Resonance (NMR) logs under various conditions. Nuclear magnetic resonance tools respond primarily to the fluids present in the reservoir. Objectives of NMR logging are: to improve permeability estimation in non-cored wells and to quantify fluid volumes. In several wells the log interpretation was calibrated by NMR laboratory analysis on core. We interpreted NMR logs in-house using advanced tools developed by Shell.
The application of NMR logs in low to moderate quality gas reservoirs is widely regarded as challenging. Reasons for this are the low NMR signature of gas due to the combined effect of low porosity and a low hydrogen index.
Key findings of our work are:(1)
If properly used, NMR tools confirm the interpretation by conventional tools and improve on permeability and fluid estimation.(2)
Some of our logging jobs could have provided more information with better planning (of acquisition parameters, tools and mud systems) and more experience available.(3)
Porosity and permeability by NMR are less dependent on core calibration than conventional derivation from porosity tools.(4)
Our in-house interpretation increased accuracy and insight into the reservoir.
In this contribution, we will report our experiences with NMR logging and interpretation and comment on the added value of NMR logging in lower quality gas reservoirs