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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.
Reservoir compaction in depleting gas fields can cause seismicity, as has been observed in a dozen countries (Foulger
For a few gas reservoirs, the evolution of potential fault slippage is simulated using the commonly adopted Mohr-Coulomb failure criterion. This shows that fault criticality is expected for reservoirs that showed seismic as well as non-seismic behavior. Apparently, some characteristic property is missing to explain the difference in behavior.
Using published pressure histories for seismically active gas fields, the relation is shown between seismic magnitude and relative depletion. It appears that in many cases, the first induced earthquake is relatively strong which suggests substantial cohesion of the faults. It is plausible from the geological history that in non-seismic regions, fault cohesion is larger, so that slippage is inhibited.
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 negative effect of convergent flow in the fractures 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 with uncoated proppant.
Several North Sea horizontal and deviated multifracture gas wells that used RCP and had a significant mechanical skin are presented. Pressure-buildup data confirm the presence of a near-wellbore pressure drop in the fractures. Reservoir simulation with a fine grid reproduces the observed pressure drop because of 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 multifracture well to the original discovery well in the same location, in which 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 the worst case, a horizontal multifracture well with three or four transverse fractures can produce the same as a fully perforated vertical well with a single fracture.
On the basis of a number of real-world incidents of proppant production during post-fracture cleanup, we show strong evidence that a small amount of proppant production can result in an increase in well productivity index (PI) and a decrease in apparent fracture skin. Convergent flow is the most likely mechanism to explain this. In this paper we highlight the potential reduction in well productivity from using RCP 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.
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.
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.
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.