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ABSTRACT Polish Oil and Gas Company (POGC) is in the process of appraising tight gas discoveries in the Polish part of the European Southern Rotliegend Basin. Encouraged by the results and experience of directional wells, it planned to assess the feasibility of drilling a horizontal well using underbalanced drilling technology. For this evaluation, an understanding of the geomechanical setting was needed, and thus constructing a field-specific geomechanical model was the underlying aim of the study. Two constitutive models were used in order to obtain a range of safe mud weights and to assess the effects of under- or near-balanced drilling operations on wellbore stability in the reservoir sands: an elastic and a poroelastic model. The two models did not agree, so we tried to assess the model quality based on which model best described the failures observed in the offset wells during drilling. The data was not sufficient to determine the best model, so we have two possible answers. If the elastic model is correct then a higher mud weight is needed to safely drill the horizontal well. If our assumptions about poroelasticity are correct, then the horizontal well can be drilled with much lower mud weights. 1. INTRODUCTION Underbalanced drilling (UBD) is a valuable method for optimization of multiple drilling objectives including: minimizing formation damage caused by drilling fluid invasion, increasing the rate of penetration and reducing drilling time, increasing bit life, performing early detection of hydrocarbons, dynamic testing of productive intervals while drilling, and minimizing lost circulation (Finkbeiner et al., 2009). The primary aim of this study was to determine the feasibility of underbalanced drilling in a horizontal appraisal well through the Permian age Rotliegend sandstone target in the Wielkopolska Province, onshore Poland. Deposition of the Upper Rotliegend occurred in arid and semi-arid continental conditions, and therefore the basin contains Aeolian, fluvial, and playa deposits. Continental Rotliegend sedimentation was terminated by the Zechstein transgression, which caused partial redeposition of poorly consolidated, porous, and permeable Aeolian sands. They are topped with the Zechstein Limestone deposits and then by the PZ1 evaporites (Wagner and Peryt, 1997).
Teatini, P. (University of Padova) | Ferronato, M. (University of Padova) | Franceschini, A. (University of Padova) | Frigo, M. (University of Padova) | Janna, C. (University of Padova) | Zoccarato, C. (University of Padova) | Isotton, G. (M3E Srl)
ABSTRACT: Underground gas storage (UGS) is a practice that is becoming widely implemented to cope with seasonal peaks of gas consumption. When the target reservoir is located in a faulted basin, a major safety issue concerns the reactivation of pre-existing faults, possibly inducing (micro-) seismicity. Faults are reactivated when the shear stress exceeds the limiting acceptable strength. It has been observed in The Netherlands that this occurrence can happen “unexpectedly” during the life of a UGS reservoir, i.e. when the actual stress regime is not expected to reach the failure condition. A numerical analysis by a 3D FE-IE elasto-plastic geomechanical simulator has been carried out to cast light in this respect, by investigating the mechanisms and the critical factors that can be responsible for a fault reactivation during the various stages of UGS in reservoirs located in the Rotliegend formation. The model outcomes show that the settings (in terms of reservoir and fault geometry, geomechanical parameters, and pressure change distribution) more prone to fault activation during primary production are also the most critical ones during cushion gas injection and UGS cycles.
Mahrous, Ramy (Halliburton) | Vader, Ronald (Halliburton) | Larreal, Enrique (Halliburton) | Navarro, Raul (Halliburton) | Salmelid, Bjarne (Halliburton) | Honey, Alastair (Nederlandse Aardolie Maatschappij B.V.) | Weir, Malcolm (Nederlandse Aardolie Maatschappij B.V.) | Lammers, Gert (Nederlandse Aardolie Maatschappij B.V.) | Rijnen, Peter (Nederlandse Aardolie Maatschappij B.V.)
Abstract For decades, wells targeting the Rotliegend reservoir in the Southern North Sea Basin have been drilled using conventional water-based mud (WBM) in the top hole section and oil-based mud (OBM) systems throughout the remaining sections of the well. The standard well design generated high waste disposal costs onshore and offshore, particularly with regard to OBM waste. This study evaluates alternative fluid systems to help reduce disposal costs for the operator. As part of the operator's environmental improvement strategy, the operator and fluids provider team identified potentially significant waste disposal cost savings for an onshore trial. Using a WBM system for drilling top holes as well as through the lower sections could result in cost savings through the reduction of top hole fluid dilution as well as a reduction in waste disposal costs. A high-performance water-based mud (HPWBM) system with similar performance to an OBM system was proposed as part of a trial to demonstrate these potential savings in disposal costs for an onshore well. The field trial was a great success compared to conventional fluid systems and methodologies. The well was drilled 11.6 days ahead of schedule and 20% under the planned budget. The time vs. depth curve was on par with what was expected when drilling with an OBM system. The HPWBM system created a saving of >5% of the total well cost and it was 16% less expensive than conventional fluid systems. A further saving of 2.5% of the total well cost was identified for future onshore/offshore applications of the HPWBM system. It was also theorized that a further reduction in waste disposal costs could be realised in offshore operations. The field trial was based on a basic onshore well trajectory as a proof of concept. Upon the success of using HPWBM in the basic well, more challenging onshore as well as offshore applications would be examined which have the potential to double the cost savings generated. This novel approach of using an environmentally acceptable HPWBM system in the Southern North Sea Basin can offer significant cost saving opportunities with regard to waste management for both onshore and offshore wells compared to conventional WBM and OBM systems.
Abstract 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.
Abstract: In recent studies on the surface subsidence caused by hydrocarbon recovery of the Groningen gas field, the predicted subsidence is overestimated if results of compaction experiments are not corrected by an empirical ‘upscaling factor’. In order to find an explanation for this ‘upscaling factor’, an analysis is presented of different laboratory experiments conducted by NAM on samples of the Groningen field. In the mentioned studies, the result of the 1 loading cycle is generally used for the compaction calculations, while in the 2 and subsequent loading cycles a lower compaction coefficient (Cm) is observed. It is also observed that stress path has a significant influence on the measured Cm. A maximum of 25 % of the discrepancy in lab and reservoir scale compaction can likely be attributed to this difference in stress path between laboratory and reservoir. The Cm values of the 2 cycle compaction experiments with a stress path similar to the stress path of the Groningen reservoir are very comparable to the best-fit line used for predicting reservoir compaction. These results would imply that a 2 loading cycle is more representative of actual reservoir compaction. Introduction The production of hydrocarbons leads to a decrease in pore fluid pressure in a reservoir and consequently to an increase in effective stress acting on the rock reservoir matrix. This increase in effective stress can lead to reservoir compaction, which can have serious negative consequences such as surface subsidence, induced seismicity and well shearing (e.g. Geertsma, 1973a-b; Nagel et al., 2001; Doornhof et al., 2006; van Thienen-Visser and Breunese, 2015; Fokker and van Thienen-Visser, 2016). The subsurface of the Netherlands contains numerous hydrocarbon reservoirs, mostly gas fields. By far the largest of these reservoirs is the Groningen gas field, located in the northeastern part of the Netherlands. The Groningen field is the largest gas reservoir of Western Europe. The gas holding layers of the Groningen reservoir are Rotliegend sandstones of aeolian and fluvial deposits (de Jager and Geluk, 2007). Gas production started in 1963 and is planned to continue for the coming decennia. Surface subsidence of the Groningen area is monitored and the maximum current surface subsidence is ~30 cm in the Loppersum area (Fig. 1; NAM, 2013).
Abstract The Bergermeer Rotliegend sandstone reservoir has been depleted by production. This has substantially reduced reservoir pore pressure and well deliverability. Pressure depletion has been accompanied by an expected decrease in minimum in-situ stress, resulting in a substantially sub-hydrostatic drilling fluid density being required to enable drilling. As a result, Managed Pressure Drilling (MPD) using two-phase fluid has been chosen as the enabling technology for drilling and completing initial wells for the Gas Storage Bergermeer Project. MPD for the Bergermeer wells is defined as the use of two-phase flow of drilling fluid including nitrogen injection via a tieback casing to maintain bottom hole pressure (BHP) below the anticipated reservoir minimum in-situ stress at a long hole depth. Application of MPD technology in the Gas Storage Bergermeer Project will allow drilling the planned boreholes without exceeding minimum in-situ stress, minimizing the risks of differential sticking and drilling fluid losses if natural fractures are present. Reservoir pressure in the Rotliegendes reservoir was originally 238 bar (3451 psi) at 2100 m (6890 ft) subsea. By mid-2009, gas reinjection was started to bring the reservoir up to an operating pressure of 133 bar for gas storage operations. By May 2013, the time of drilling the 1st of the new gas storage wells into the Bergermeer reservoir, the formation pressure had been brought up to 81 bar in block 1 and 35 bar in the adjacent block 2. Due to permitting restrictions, it was not possible to drill a test/pilot well before drilling the first gas injection/production wells to physically determine formation rock strength. Therefore a decision was made to drill into the 81 bar reservoir with a target BHP of 117 to 127 bar; this equated to an equivalent circulating density (ECD) of 0.57 to 0.63 SG. Two wells were drilled during May–June 2013, one S-shaped vertical well in block 1 and one horizontal well into block 2. This was achieved maintaining a constant BHP within the predetermined window using MPD with gasified fluid; in reality it was possible to drill the wells with a very stable BHP with a 0.6 SG ECD. Dynamic formation integrity tests (FIT) were performed to determine the formation rock strength in a controlled manner using two-phase MPD techniques at predetermined depths in the reservoir; results indicated that rock strength was adequate for using conventional drilling techniques. Despite the successful implementation of MPD, future wells will be drilled conventionally although MPD could deliver the wells should the formations turned out to be weak, and it remains as an important contingency in case formation strength turns out to be weak in future wells. For the Gas Storage Bergermeer project, significant planning into the overall system design, equipment selection, techniques, procedures and training lead to an operation where precise control of the annular pressure profile was achieved and maintained throughout the operation. This paper documents the key planning considerations required to drill and complete a highly depleted reservoir using two-phase MPD techniques.
Abstract A small angle neutron scattering experiment measures the amount and size of small irregularities within the pore system. This data can be fitted to an exponential decay constant, that describes a fractal dimension parameter. Such measurements were carried out on Rotliegend sandstones with varying porosity and permeability. They show different fitting coefficients according to rock type. Mercury and air-brine capillary data was measured on twin-plugs. Corrected capillary pressure curves recorded by an air-brine and mercury system are often different. It can be shown, that the difference is routed in the different forces that rough surfaces exposed to either brine or mercury. Using fractal dimensions from the experiments and data from optical analyses, one can compute a roughness ratio parameter, that increases the effective surface tension of the mercury system and better matches the porous plate data. The inclusion of a roughness term also helps to better understand high pressure mercury capillary data, where even at very high pressure, a non-penetrated residual pore volume remains. An interpretation in terms of possible pore throat radii leads to unrealistic small numbers, whereas an interpretation using a roughness term shows, why even with realistic pore sizes, helium porosity is higher than mercury porosity. The measured fractal parameters could be used to model the capillary pressure response with a surface roughness model instead of a capillary bundle model.
Abstract Fluid flow properties of tight Rotliegend sanstones show a strong sensitivity to stress conditions. To improve the understanding how fluid flow properties depend on the stress situation experimental measurements have been conducted on low to ultra-low Rotliegend sandstone samples from a North-German gas reservoir under simulated reservoir stress conditions. The measurements have been performed in the project DGMK 593-9/4 in the framework of the tight gas program of the DGMK (German Society for Petroleum and Coal Science and Technology). From the results of the experiments models could be derived, which describe the stress dependency of permeability and porosity. The experimental study improves the understanding of stress dependence behavior of low permeable North-German sandstones and provides relevant reference data for simulation of flow processes. The correlation models based on the experimental results presented enable the evaluation of representative in-situ effective stress, permeability and porosity in low permeable Rotliegend sandstones from routine laboratory permeability and porosity data as well as depletion effects during the gas production.
Abstract: We investigate the possibility to transform the elastic modulus to porosity by combining a Gassmann equation and Biot's theory. We have inverted the formulae to simultaneously use compressional and shear log data for porosity estimation. We apply this method to gas-filled Rotliegend sandstone with porosity around 20% and compare the results to core derived porosity, solver based porosity and other published method. Additional input parameters, such as gas-brine mixing laws and gas saturation at effective borehole distance, are taken from earlier work. This study creates an inversion scheme that requires no adjustment of critical parameters. Initially, the method is reliable in water filled portions of the reservoir but greatly underestimates porosity in the gas-filled section. A review of all input parameters leads to the conclusion that, in our case, the weakening of the bulk modulus from matrix to skeleton modulus is much stronger than the Biot's coefficient derived from the laboratory. This effect is more severe then the possible errors in the fluid mixing law. Initially we introduce an additional weakening based on the saturation exponent and aspect ratio. This modification is unable to compute a correct porosity. Then, we introduce an additional term based on the Poisson's ratio in Biot's coefficient calculation. This finally gives a good match to the core porosity in the gas-filled, highly porous sections. The results show that in this Rotliegend area, the acoustic response of gas-filled porous sandstone is governed by the weakening of the skeleton bulk modulus. Changes to the pore filling modulus through the gas phase seem to play only a secondary role in our case. It also shows that shear and compressional log data can be used for porosity estimation in a reliable way, once the mechanism at play has been analysed on a field wide basis.
Abstract This paper presents an overview of the subsurface economic and technical issues involved in developing a Southern North Sea (SNS) tight gas field using hydraulic fracturing. The paper investigates different kinds of wells (vertical vs. horizontal) and different completions; fracture spacing, fracture orientations (longitudinal vs. transverse). The investigation was performed using a range of different reservoir qualities with appropriate completion and stimulation designs. Production and Net Present Value (NPV) estimates were developed for the different scenarios for qualitative and quantitative evaluation. The result is a generic strategy to evaluate a Field Development Plan (FDP) using hydraulically fractured horizontal wells. The paper concludes with general guidelines on what type of recoveries are possible using different completion and stimulation solutions in situations with different kh distributions. The guidelines will help in initial screening of prospects to determine whether the tight gas reservoirs have significant potential for economic development. The latter is also a function of the actual development costs of pipelines and platforms, which is different for different companies and different locations. This paper also demonstrates why stimulation considerations should be put on the agenda early on in the construction of an FDP. Introduction The majority of the SNS gas fields produce from the Rotliegend sandstone formation that is of Permian age with aeolian and fluvial depositional environments. Over the past decades several completion, stimulation and production approaches have been executed in the SNS 1. In recent years the focus for new developments and redevelopments, both plans and executions, has been on horizontal wells with multiple hydraulic fractures. Execution thus far has been complicated by the lack of available stimulation equipment for the SNS. Recently this appears to have become less of an issue, with several service companies implementing and offering skid based or otherwise portable fracturing spreads for deployment on to temporary platforms or suitable temporary boats. As many before us have presented, the definition of tight gas is a purely economic question. The main purpose and value of hydraulic fracturing in a low permeability formation is to accelerate production, see Figure 1 for a generic example. This acceleration improves the NPV of the complete investment dramatically and therewith hydraulic fracturing directly impacts the definition of "tight gas" itself for a given economic environment. The reservoir quality range investigated in this study includes permeability values covering the range of what is considered, in current day perspective, as "tight-gas" in the North Sea i.e. 0.5 mD, 0.1 mD and 0.01 mD. The reservoir layering was chosen to represent a typical Rotliegend field that has a laminated sand-shale sequence (Figure 2). A range of different net/gross ratios (NGR) scenarios was also examined, to demonstrate the effect that fracture height growth can have on recovery in a laminated reservoir with several non-pay intervals as well as the impact of uncertainty in net pay determination on project economics. The reservoir pressure gradient and stress situations were selected to cover common values for the SNS. A horizontal well with a horizontal section of 3000 feet was investigated, with a range of different fracture spacings and two different fracture orientations. The production simulations performed assumed a single phase (dry gas). Table 1 shows the basic reservoir parameters used in the study.