Drilling hazards can lead to significant cost overruns during the drilling phase and might cause unsafe situations or potentially harm the environment. Often the local geology, when poorly understood, is the trigger of a drilling incident. By sharing past drilling experience and in particular observations on Geo-Drilling Hazards, via a suitable platform, well planning and risk assessment can be carried out more effectively. After analysing historic drilling reports, observations on drilling incidents have been compiled using a structured approach. Classification schemes allow systematic capture of key information in a format suitable for a database. In this process the observations (
The Geo-Drilling Events (GDE) database currently covers some 1000 boreholes from the Netherlands. Around 1400 geo-drilling events have been analysed systematically allowing to identify drilling hazard hotspots in a statistically meaningful sense. Examples of geo-drilling events include
Planned well trajectories can now be screened efficiently for geo-drilling hazards. The GDE Tool based on advanced classification criteria allows to share relevant well information across all operators active in the Netherlands. This includes newcomers, like geothermal operators who carry out a lot of drilling nowadays. The GDE Tool allows everyone to learn from the experience on drilling hazards gathered over the years by oil companies.
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) Bowleven began drilling operations at its Zingana exploration well on the Bomono permit in Cameroon. Located 20 km northwest of Douala, Cameroon's largest city, the well will target a Paleocene (Tertiary) aged, three-way dip closed fault block. The company plans to drill the well to a depth of 2000 m and will then spud a second well in Moambe, 2 km east of Zingana. Bowleven is the operator and holds 100% interest in the license. Asia Pacific China National Offshore Oil Company (CNOOC) has brought its Dongfang 1-1 gas field Phase I adjustment project on line ahead of schedule. The field is located in the Yinggehai basin of the Beibu Gulf in the South China Sea and has an average water depth of 70 m. The field is currently producing 53 MMcf/D of gas and is expected to reach its peak production of 54 MMcf/D before the end of the year.
The Slootdorp field has a complex structure with most reserves in Rotliegend sandstone, which is communicating with gas bearing Zechstein carbonates. The Rotliegend reservoir is bounded by a large fault, which might become seismogenic during depletion. A 3D geomechanical model was built, based on the faults and horizons in the geological model. Both the Rotliegend and Zechstein reservoirs were included in the model. The model was populated with geomechanical properties derived from logs, LOT's (leak off tests) and regional data on the stress field. Also, overburden properties from previous studies on nearby fields were used.
The pressure input was obtained from reservoir simulation. It is important to include the water leg pressure in the pressure input since the Rotliegend gas reservoir is in contact with an active aquifer. Pressure reduction drives the compaction of the reservoir, which induces stresses on the faults causing slippage. Since the water is quite incompressible, a large pressure reduction in the water leg may be caused temporarily by a rising gas water contact.
It turned out that slippage is not expected at the lowest gas pressure using a conservative estimate of the critical friction coefficient on the fault of 0.55. Sensitivity analysis on the most important input parameters was performed with a range that can be expected for such a field. The result was that the maximum critical stress ratio could range between 0.46 and 0.53 for the expected uncertainty of input parameters. The geomechanical modeling shows that an active aquifer has a dominant, mitigating effect on seismic risk, which can explain why many reservoirs show no seismicity in the Netherlands, although other effects could also play a role.
In the last decade, many gas reservoirs with permeabilities from 0.1 to 10 mD have been developed with horizontal wells with transverse fractures. The potential negativeimpact of convergent flow in the fracture seems to have been forgotten. The widespread use of resin coated proppant (RCP) in offshore wells appears to make this problem worse. Using both case studies and reservoir simulations, we examine why RCP could make the problem of convergent flow worse compared to uncoated proppant.
A number of North Sea horizontal and deviated multi-frac gas wells that used RCP and had a significant mechanical skin are presented. Pressure buildup data confirms the presence of a near-wellbore pressure drop in the fracture. Reservoir simulation with a fine grid reproduces the observed pressure drop, due to convergent flow, using realistic proppant pack permeabilities with gel damage.
The effect of proppant production on the convergent flow skin is shown using production data before and after discrete proppant production events, demonstrating how proppant production has a beneficial effect on removing convergent flow skin. We also compare the performance of a new horizontal multi-frac well to the original discovery well in the same location, where a vertical well was fracture stimulated with uncoated proppant, and had comparable productivity.
If there is a large convergent flow skin in a fracture with uncoated proppant, this usually leads to some proppant production, which could create "infinite conductivity" channels at the perforations. This removes the convergent flow pressure drop. If RCP is used to prevent proppant flowback, such channels cannot form easily and convergent flow acts as a downhole "choke" on production. This "choke" can produce a significant positive skin. In unfavorable cases, a horizontal multi-frac well with 3 or 4 transverse fractures will produce the same as a fully perforated vertical well with a single fracture.
Based on a number of real-world incidents of proppant production during the post-fracture cleanup, we show strong evidence that a small amount of proppant production can result in an increase in well PI and decrease in apparent fracture skin. Convergent flow is the most likely mechanism to explain this. This paper highlights the potential reduction in well productivity due to using resin coated proppant for fracturing in gas wells (0.1 to 10 mD) with limited inflow area (transverse or oblique fractures) where convergent flow pressure loss is significant. We show the potential positive effect of small amounts of proppant production in such cases, forming infinite conductivity channels and removing the convergent flow skin.
Use of seismic data in exploration has evolved from simple structural mapping in 2D to complex reservoir characterization studies aimed at predicting reservoir properties prior to drilling. The success of these studies hinges on proper assessment of all subsurface data collected throughout the exploration process to determine the hydrocarbon potential of the target. This case study illustrates the exploration process associated with the Guhlen discovery in Brandenburg State, northeastern Germany, from early stage 2D seismic interpretation to a full rock physics study.
The first exploration well was drilled in 2012 based on 2D seismic data into a low permeability, hydrocarbon bearing carbonate reservoir. In order to test a hypothesis that seismic could be used as a tool to identify areas of better porosity within the target interval; a 3D seismic survey was acquired. Once processed and interpreted, a pre-stack inversion was performed that identified undrilled areas of low acoustic impedance and Vp/Vs, which were interpreted to represent good porosity areas based on log data analysis. A well was subsequently drilled in one of these prospective areas, resulting in a discovery with a test flow rate ranking among the highest in the past 20 years.
Presentation Date: Thursday, September 28, 2017
Start Time: 11:25 AM
Presentation Type: ORAL
Reinsch, Thomas (GFZ German Research Centre for Geosciences) | Kranz, Stefan (GFZ German Research Centre for Geosciences) | Saadat, Ali (GFZ German Research Centre for Geosciences) | Huenges, Ernst (GFZ German Research Centre for Geosciences) | Rinke, Manfred (Geothermie Consulting-Engineering-Supervision) | Brandt, Wulf (Geothermie Consulting-Engineering-Supervision) | Schulz, Peter (H. Anger's Söhne Bohr- und Brunnenbaugesellschaft mbH)
During production of geothermal brine at the Groß Schönebeck research site, large and heavy solid particles accumulated within the cased reservoir interval of the production well. A wellbore obstruction at a depth of approximately 4100 m (13,452 ft) was caused by copper-, barite-, lead-, and iron-mineral precipitates with a size of up to 1 cm and elongated coating fragments from the production tubing with a length of up to 10 cm. After a failed reverse-cleanout operation by use of 2-in. coiled tubing (CT), lifting the fluid column within the drillstring (DS) was considered to be the most cost-efficient option to clean out the wellbore while simultaneously minimizing fluid invasion into the reservoir. Here, preliminary considerations for the operation and field observations are presented together with a monitoring concept. The field data are used to calibrate a hydraulic model that is then applied to understand hydraulic processes downhole. On the basis of the hydraulic considerations, aspects to optimize the cleanout efficiency are discussed.
Wassing, B. B. T. (TNO, Applied Geosciences) | Buijze, L. (TNO, Applied Geosciences) | Ter Heege, J. H. (TNO, Applied Geosciences) | Orlic, B. (TNO, Applied Geosciences) | Osinga, S. (TNO, Applied Geosciences)
ABSTRACT: In The Netherlands gas is produced from over 150 onshore gas fields. In several fields induced seismicity has been recorded during production. These seismic events are interpreted as induced by pore pressure changes in the reservoir rocks, resulting in stress changes on faults within and in close vicinity of the gas fields. Understanding the underlying processes of production-induced seismicity is crucial for the assessment and mitigation of seismic hazards during ongoing production in the onshore gas fields. In this study, we use a numerical geomechanical model in FLAC3D to analyze the relation between changes in reservoir pore pressures and fault stress changes. We address the effects of fault strength, reservoir and fault geometry and the presence of a viscoelastic caprock on the timing of fault reactivation, the nucleation of seismic events and the main characteristics of the fault rupture process. Results of our models show that the presence of viscoelastic caprock can strongly influence the timing and extent of fault reactivation and rupture. Faults with offset are generally reactivated at an early stage of reservoir depletion and involve relatively small slip displacements, stress drops and rupture lengths. The presence of a viscoelastic caprock even further promotes fault slip and nucleation of a seismic events at an early stage of depletion. Faults without offset are reactivated during later stages of depletion and involve larger slip displacements, stress drops and more extensive slip lengths than in case of early reactivation.
In The Netherlands gas is produced from over 150 onshore gas fields. In several of these onshore fields seismicity during production has been recorded by the regional seismic monitoring network installed by the Dutch seismological survey. Figure 1 shows the location of the onshore gas fields in the northern part of the Netherlands and related seismic activity. To date, no seismicity has been recorded in the gas fields in the southern part of The Netherlands. Magnitudes of seismic events are generally below Ml 3.0, though in a limited number of fields magnitudes up to and above Ml 3.0 have been recorded. Largest magnitudes recorded to date are Mw 3.6 in the Groningen field, Ml 3.5 in the Bergermeer Field and Ml 3.4 in the Roswinkel Field.
ABSTRACT: We conduct a quantitative microstructural investigation of Slochteren sandstones recovered from the Groningen gas reservoir in the NE Netherlands, aiming to identify the micromechanical processes controlling inelastic strain accommodation. Core samples were provided by the Nederlandse Aardolie Maatschappij (NAM), from the Stedum (SDM)-1 and Zeerijp (ZRP)-3a wells, respectively drilled before and after gas depletion in 1965 and 2015. Sectioned samples were imaged using a scanning electron microscope for constructing section-scale, backscattered electron micrograph mosaics, which were interpreted by manual grain tracing and image processing to obtain digital phase and crack maps. Digitization of the sandstone microstructure in this way yields data on grain mineralogy, shape, (contact) size and orientation, as well as on coordination number and crack density and orientation. We investigated ways to improve the microstructural digitization method, including preparation of thin sections using Au vapor deposition, injection of copper sulphate (CuSO4) at elevated pressure, and etching using hydrogen fluoride (HF). Finally, an image analysis method was developed to enable semi-automatic phase/ crack mapping, which we first applied to a layered sample from the ZRP-3a core. Comparison of phase/ crack maps of layered sandstone samples may provide the key to help identify the processes controlling pore pressure depletion-induced compaction.
Hydrocarbon production causes changes in the effective stress state of the reservoir rock, frequently leading to compaction (Geertsma, 1957; Segall and Fitzgerald, 1998; Hettema et al., 2000) and surface subsidence (Geertsma, 1973; Nagel, 2001; Doornhof et al., 2006), causing major economic damage and social upheaval (e.g. Chan and Zoback, 2007; Muntendam-Bos and De Waal, 2015). Models predicting surface subsidence rely on constitutive relations describing compaction. Linear poroelastic compaction models are frequently insufficient (Hettema et al., 2002; van Thienen-Visser et al., 2015), suggesting that inelastic processes also play a role. An improved understanding of the strain-accommodating processes operating on the grain-scale, and how this scales to reservoir compaction, is necessary for adequate forecasting of surface subsidence.
Gassmann equations (Gassmann, 1951) are used to calculate seismic velocity changes that result from variations in reservoir fluid saturation. These equations became predominant in the analysis of a direct hydrocarbon indication from seismic data through their use in analyzing the compressional to shear velocity ratio, Vp/Vs. This Vp/Vs ratio is used in many industry analyses, such as the amplitude variation with offset (AVO) analysis developed by Castagna et al. (1993). Multiple authors have since published a variety of Vp/Vs seismic interpretation techniques that use empirical relationships with Vp, Vs, and porosity terms. Unfortunately, however, there is a gap in the use of Vp/Vs relationships in petrophysical interpretation.
The Vp/Vs ratio analysis was expanded in 1995 when Brie et al. proposed the application of a Vp/Vs vs. Vp crossplot for gas trend indication and included a correction for shale effect. The crossplot of Vp/Vs vs. Vp was published in 2015 by Quirein et al. and was applied to organic shale reservoirs for kerogen volume and anisotropy trend indications.
This paper explores the use of a crossplot of Vp/Vs vs. Vs for quantitative petrophysical interpretation. A relationship developed in the paper is used to describe water-wet and gas-saturated sandstone trends, and to independently calculate water saturation from a proposed crossplot in low and medium porosity isotropic sandstones. These proposed Vp/Vs vs. Vs crossplot water saturation results are compared to traditional resistivity-based results. This proposed simplified method provides a suitable approach for determining gas saturation when resistivity logs yield inadequate results in, for example, medium porosity or low-resistivity pay formations.