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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.
A new methodology for a "Level 2" Seismic Hazard Assessment has been developed for a geothermal project. Geomechanical models were created to understand the thermo-mechanical effects in the lifetime of a specific geothermal operation. Two types of geomechanical models are used, a 3-D Mohr-Coulomb model using both a deterministic and a probabilistic methodology, and a 2-D elastoplastic finite element model, simulating the lifetime and the associated mechanical changes caused by the geothermal operation. The simulated results show that, under maximum production conditions, there is a 1% likelihood of induced seismicity. Using published correlations, the movement along a fault is used to calculate the maximum magnitude of the unlikely seismicity, projected to be the order of 1.5 to 2 M w . As a mitigation method, a Traffic Light System is proposed. This allows the geothermal operation to continue while staying within the expected safety margins.
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. China National Offshore Oil Company (CNOOC) has brought its Dongfang 1-1 gas field Phase I adjustment project on line ahead of schedule.
ABSTRACT: Rock salt formations are a common reservoir seal worldwide with excellent sealing capacity. Restoring the sealing capacity of rock salt caprocks penetrated by wells using the same rock salt as plugging material is therefore an attractive, safe and environmentally friendly option. The concept is based on the removal of a section of casing over a part of a formation consisting of rock salt and creation of a sealing well barrier (plug) by the creep of rock salt. Geomechanical numerical simulations were conducted to estimate wellbore closure times for a range of conditions representative of the Zechstein evaporites overlying Rotliegend reservoirs in the Northwestern Europe. Results showed that the salt creep largely depends on the salt properties, differential stress and in-situ temperature. Estimated closure times of a reamed interval, for the maximum underbalance, were in the range of a few weeks for a depth of 3100 m, a few months for a depth of 2500 m and a few years for a depth of 2000 m. Reamed intervals should be at least 10 m long to avoid slowing down the process of creep that occurred for shorter reamed intervals.
The most common caprock lithologies are shales, evaporites and in particular rock salt (halite). These natural sealing materials have held hydrocarbons over geological timescales and are generally regarded as proven hydraulic seals. Using the same caprock material for well plugging and abandonment (P&A) is therefore an attractive option as the initial sealing capacity of caprocks penetrated by wells could be restored by well plugs made of the native caprock lithology. However, this option of using natural formation sealing for well isolation and P&A is currently underutilized.
The use of creeping formation for annular sealing of oil and gas wells has been encouraged by the regulatory agency in Norway. Creeping formation has been accepted as a new well barrier element (NORSOK Standard D-010, 2013). In practice, creeping formation was mainly used for annual sealing of oil and gas wells (Williams et al., 2009). An example is Green Clay or Green Shale, found in the Norwegian Central Graben. This creeping shale incorporates several stratigraphic units of the Tertiary Hordaland Group. The shale is usually over-pressured, contains high amounts of smectite and exhibits fast creep strain rates. The green shale has been relatively unaffected by diagenesis and preserved its ductility despite burial depths of 3 km.
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.
Because of the importance of natural gas for energy production, the interest to develop underground gas storage (UGS) projects is continuously increasing worldwide. In May 2015, 268 UGS facilities existed or were planned in Europe and over 400 in the USA. UGS is traditionally used to ensure a relatively smooth delivery from gas reservoirs to the gas consumption pattern dictated by daily and seasonal oscillations. The hazard and risk associated with subsurface gas storage are a recurrent issue whenever a new UGS is planned. Many different aspects are involved, such as formation integrity, health and safety as related to public perception, economic risk, and environmental impacts. Among the latter, the geomechanical effects induced by seasonal gas injection and withdrawal may play a very important role.
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.
Stoljarova, Anastasia (Freie Universität Berlin / Institute for Chemistry and Biochemistry) | Regenspurg, Simona (German Research Centre for Geosciences) | Bäßler, Ralph (BAM Federal Institute for Materials Research and Testing)
Geothermal wells are a feasible energy source to replace fossil fuel supply. Hence, many technologies have been developed to take advantage of geothermal energy. Nevertheless, service conditions in geothermal facilities are due to the chemical composition of hydrothermal fluids and temperatures, in many cases, extreme in terms of corrosion. Therefore, materials selection based on preliminary material qualification is essential to guarantee a secure and reliable operation of the facilities. However, some additional aspects might rise.
During circulation tests at the geothermal research facility in Groß Schönebeck (Germany), massive copper precipitation has been observed downhole clogging the production well. Occurring mechanisms and measures to prevent copper precipitation or scaling needed to be investigated.
This contribution deals with the evaluation of the corrosion behavior of different metals ranging from carbon steel via stainless and duplex steels to titanium in a copper containing artificial geothermal water, simulating the conditions in the Northern German Basin, using electrochemical measurements and exposure tests. While carbon steel exhibits copper deposition (scaling) and copper precipitation, higher alloyed materials show different response to Cu-species in saline geothermal water. Here, no relevant formation of insoluble Cu-species could be detected.
Based on these results, the suitability of the investigated high alloyed materials and Ti-alloy can be concluded for use in such conditions, as long as no crevice conditions in combination with non-metallic parts occur. Carbon steel is not recommended to be used.
Since geothermal reservoirs are a feasible energy source to replace fossil fuel supply, many technologies have been developed to take advantage of geothermal energy. Nevertheless, due to the chemical composition of hydrothermal fluids and temperatures, service conditions in geothermal facilities are demanding in many cases in terms of corrosion. Therefore, materials selection based on preliminary material qualification is essential to guarantee a secure and reliable operation of the facilities.
Since operational conditions in geothermal power plants are crucial in terms of corrosion special attention is paid to materials selection1-3
Compartmentalized reservoirs are often segmented by a sealing fault acting as a barrier to pressure communication between neighboring reservoirs. However, changes in reservoir pressure, due to either fluid withdrawal or injection, can induce changes in local stresses that can lead to fault slip and associated alteration of fault permeability, which can transform the initially sealing fault into partially conductive. This paper examines the transient pressure response to a sudden change in anisotropic fault permeability as an indicator of fault seal breakdown. Analytical solutions for pressure-transient response for a linesource, constant-rate well in a compartmentalized reservoir where fault permeability is rapidly enhanced, are presented. The fault is modeled as a linear interface between semi-infinite homogeneous and isotropic formation layers. Laplace-Fourier transform technique is used to solve the governing equations analytically. Pressure-transient solutions are presented as type curves for the scenarios of across-fault and simultaneous across-along-fault permeability enhancement. Characterization of enhanced fault transmissibility using asymptotic late-time solutions is discussed.
This paper presents an innovative method for inclusion of two-phase fault rock properties into upscaled flow simulation models. Faults are generally represented in conventional full-field flow simulation models of clastic reservoirs as 2D planar surfaces. Often, however, faults are structurally complex 3D zones containing numerous fault segments each accommodating a portion of the total fault displacement and associated with particular single-phase (absolute permeability and thickness) and two-phase (relative permeability and capillary pressure) fault rock properties. Ignoring this structural and petrophysical complexity of 3D fault zones may impart considerable inaccuracy on the predictive performance of the upscaled simulation model. Therefore, this study has developed a flow-based geometrical upscaling method capable of representing the geometrical and saturation-dependent flow properties of realistic fault zones at the resolution of a conventional full-field simulation model.
Geometrical upscaling is the process of calculating transmissibilities for tortuous flow paths through a 3D fault zone, and representing these as appropriate neighbor and non-neighbor connection properties in a conventional upscaled model. In flow-based geometrical upscaling, all transmissibilities associated with an individual cell adjacent to the fault are calculated using a high resolution flow model in which the geometrical and petrophysical heterogeneities of the complex fault are included explicitly. Running each model with different fractional flows of oil and water results in saturation dependent upscaled pseudo relative permeability curves for each across-fault or up-fault flow path out of the cell in question, and repeating for all cells allows representation of the two-phase properties for the entire fault zone structure.
This study has been performed to account for the effects of two-phase fault rock properties as well as sub-seismic fault zone structure in reservoir flow simulation modeling. Flow results of a high resolution truth model are compared with those of the upscaled model to test the accuracy of the method. The results show that the two-phase flow-based geometrical upscaling method is a very promising method for representing two-phase fault rock properties associated with fault zone structure.
In the recent years, it has become popular to represent single-phase fault rock properties as fault transmissibility multipliers. The effects of two-phase fault rock properties and 3D fault zone structure are widely recognized to be potentially significant in reservoir management studies, but their inclusion into production flow simulation models is technically very challenging. The newly developed two-phase flow-based geometrical upscaling method accounts rigorously for both effects and is applicable at a full-field scale. The value of the method is highlighted through application to a compartmentalized reservoir model in which the two-phase fault rock properties are more influential on production than the single-phase ones.
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