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.
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
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.
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.
InSAR (Interferometric Synthetic Aperture Radar) is a technology used to measure changes in surface elevation between successive passes of orbiting satellites. These changes can be used to understand imbalances in the subsurface between fluid withdrawal and injection, as well as near-surface ruptures caused by failure of well integrity.
Satellites have recorded SAR data since the 1990s, and the data have become increasingly higher resolution and more frequently acquired. Combined with faster algorithms and processing chains for interferometry, this has enabled detection of smaller and faster changes at the surface. This in turn has caused a step-change in the usefulness of the data and the interpretations. The result is the ability to depend on the data to monitor the effects of production and injection processes almost continuously.
We review several cases to demonstrate the value of rapid revisit, high resolution InSAR. The first is the giant Belridge field in the San Joaquin valley, California, historically the poster child for this application. The diatomite reservoir rock has 60% porosity and is fluid supported. When equilibrium between injection to production is not maintained, the volume changes in the reservoir cause the ground surface to move up or down by amounts detectable with InSAR enabling a feedback loop for injection optimization. The field also has many wells with compromised wellbore integrity that can provide a pathway for reservoir fluids to move upwards towards the ground surface. When water, oil, or steam move out of the reservoir and into the overburden, a potential precursor can be detected provided InSAR is configured carefully. In a second case, InSAR also provides visualizations of ground level changes over gas fields and gas storage fields. At the Groningen gas field in the Netherlands, long term InSAR time series measurements of elevation changes are used to constrain models about compaction and reactivation of buried faults. Parts of the field that are used for seasonal gas storage and charging/discharging cycles can also be effectively monitored.
Measurement of surface deformation by high resolution, fast revisit, optimized InSAR provides an insight into the reservoir and the efficiency of its management. It also provides an early warning of potential problems that, if not corrected, may result in harm to the environment. These step changes in quantity and quality of available InSAR data mean that the remaining barrier to being used for actionable insights is in the widespread inverse modeling of the surface data to sub-surface mass flows.
Geomechanical numerical simulations were conducted to analyze the stability of faults during gas production. A FLAC3D model of a fault intersecting a producing gas reservoir was developed which incorporates the fully dynamic behavior of the fault and surrounding rock mass, and a fault frictional behavior based on a slip-weakening law. The simplified reservoir and fault geometry of the model are representative for the Dutch gas fields. Simulated fault slip displacements and fault slip lengths were used to calculate moment magnitudes of induced seismic events. In addition, results of the fully dynamic model with slip-weakening frictional behavior were compared to results of a static geomechanical model with slip-weakening. Comparison of model results shows that, for a first-order assessment of induced seismicity, the static models can be used as a simplified and computationally less expensive alternative to the fully dynamic fault rupture models.
The operation of a gas field causes dynamic changes of the pore pressure and therefore changes in the stress state of the reservoir and surrounding rocks. Production-induced stress changes can destabilize faults which transect or bound the reservoir, or are located in the vicinity of the reservoir, causing associated seismicity. Whether or not faults are (seismically) reactivated during reservoir depletion depends on a complex interplay of many factors, such as the combination of initial stress state of the reservoir and faults, the magnitude of pore pressure changes, the geometry of the reservoir and faults, such as orientation, dip and fault offset, and the geomechanical properties of the rocks and faults.
In many onshore producing gas fields in the Netherlands seismicity has been observed during the depletion of the gas reservoirs. Induced seismicity has been recorded in 26 out of 150 producing gas fields, with maximum magnitudes of the seismic events up to Mw 3.6. In all of the gas fields pressure depletion was significant prior to the onset of recorded seismicity (Van Wees et al., 2014). The marked delay between the start of reservoir depletion and the onset of seismicity has been interpreted as an indication that the in-situ stress conditions in the northern part of the Netherlands are non-critical.
The L12/L15 area is located in the Dutch sector of the Southern North Sea, some 5–10 km from the coastline of the Wadden Islands. Exploration in the 1970s led to the discovery of five small, near-tight (permeability ~1 mD) gas accumulations in a Rotliegend sandstone reservoir, located at a depth of ~3000m. Two of the fields were developed in the 1990s with 5 production wells drilled from a central 9-slot processing platform. The three remaining discoveries, all within drilling reach of the platform, were considered too small, marginal and risky to develop. In 2009, it was decided to fully re-assess the area. This resulted in successful development of two of the undeveloped discoveries in the past five years. Both fields have been drilled with a single long-reach well (>4 km step-out), stimulated with a massive hydraulic fracture from a stimulation vessel. Similar development of the third accumulation is being prepared.
An integrated approach was key to the success of the developments. For both fields, detailed static and dynamic reservoir modeling was performed to select the optimum well location and estimate potential recovery. Optimising the stimulation treatments involved hydraulic fracture modeling and defining a suitable completion, perforation and clean-up strategy. Extensive post-job analysis of the hydraulic fracture treatments was performed, integrating core data, wireline log data, fracture treatment data, welltest data and production data. Results of the analysis clearly show the value of hydraulic fracturing in these marginal near-tight gas fields.
The first well showed a post-frac well performance which exceeded expectations, while in the second well the fracture performance was below expectation after initial clean-up, although well productivity improved during the first weeks of production, which was attributed to continued clean-up of the formation from frac fluids. One of the fields discussed in the underlying paper illustrates the typical challenges associated with compartmentalised reservoirs in the Rotliegend play in the Southern North Sea. This field has a Northern compartment which is depleted from an initial pressure of 340 bar to a pressure of less than 100 bar after more than 15 years of production. The Southern compartment of the field was known to form a separate accumulation (within the same structural closure) with a deeper GWC and different gas composition compared to the Northern compartment, based on data from an appraisal well drilled in 1982. The new development well targeting this field was drilled in a compartment located between the Northern and Southern compartment, with an unknown GWC. The well found the same (deep) GWC and gas composition as the 1982 appraisal well in the South, but nevertheless found the reservoir to be depleted by up to 50 bar which is attributed to direct communication with the Northern compartment. The case illustrates the complexities involved in compartmentalisation over geologic vs. production times.
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 a decrease in minimum in-situ stress, resulting in a substantially sub-hydrostatic drilling fluid density 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 Bergermeer Gas Storage Project. MPD for the Bergermeer wells is defined as the use of two-phase flow drilling fluid including nitrogen injection via a tieback casing to maintain bottom hole pressure below the anticipated reservoir minimum in-situ stress at or near hole depth. Using MPD technology in the Bergermeer Gas Storage Project will enable drilling the planned boreholes without exceeding minimum in-situ stress, minimizing the risk 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 120 to 180 bar for gas storage operations. By May 2013, when the first of the new gas storage wells in the Bergermeer reservoir was drilled, the formation pressure had been brought up to 81 bar. Due to permitting restrictions, it was not possible to drill a test/pilot well before drillingthe 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 ECD of 0.57 to 0.63 SG. Dynamic formation integrity tests were performed to determine formation rock strength in a controlled manner using two-phase MPD techniques at predetermined depths in the reservoir. TAQA drilled two wells during May and June 2013, one S shaped vertical well and one horizontal well into the two depleted formations. This was achieved maintaining a constant BHP within the predetermined window using MPD with gasified fluid; in fact it was possible to drill the wells with a very stable BHP with a 0.6SG ECD. For the TAQA Bergermeer Gas Storage 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.
Orlic, B. (TNO, Earth, Environmental and Life Sciences) | Mazurowski, M. (Polish Oil & Gas Company) | Papiernik, B. (AGH University of Science &Technology) | Nagy, S. (AGH University of Science &Technology)
A field scale geomechanical model was developed in an early phase of the feasibility study considering geological CO2 storage in a depleted gas field in Poland. Geomechanical model of the gas field was adequate to evaluate the induced stress changes, the geomechanical effects on the top seal and induced surface deformation. The estimated geomechanical effects on the top seal are weak and do not pose a risk for the containment. The effects on the regional sub-vertical faults intersecting the reservoir are not expected to cause fault destabilization, except in the case of partial re-pressurization of non-connected neighbouring compartments. However, the reliability of fault stability assessment is low due to the lack of seismic data that would have made detailed mapping of faults at field scale possible. Our future work will include updating the existing model with a more detailed fault interpretation and dynamic reservoir simulation results when they become available.
Gas extraction and CO2 injection into depleted hydrocarbon reservoirs will change the state of stress in the reservoir and the surrounding rock. As a result of induced stress changes natural fracture systems and faults can be reactivated, and new fractures formed. Open and connected fracture systems in the mechanically damaged seal pose the risk for loss of containment of injected CO2. Besides the effects on the containment, stress changes due to withdrawal and injection of fluids into the subsurface will induce deformation of the storage reservoir (compaction/expansion), surrounding rock (various deformation modes) and ground surface (subsidence/ uplift). Sudden slip on pre-existing faults can lead to induced micro-seismic and (felt) seismic events.
In this paper we describe a geomechanical modelling study carried out to evaluate the geomechanical effects associated with gas extraction and possible future CO2 injection in a depleted gas field in Poland. The study area is located in southwestern Poland on the Fore-Sudetic Monocline (Fig. 1). The two largest fields located in the study area are the Załeęcze and the Ouchlów gas fields. In this paper we report preliminary results of 3D field-scale geomechanical modelling of the Załęcze gas reservoir.