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) An 816-mile 2D seismic acquisition program was completed on the Ampasindava block, located in the Majunga deepwater basin offshore northwest Madagascar. The data will provide improved subsurface imaging of the large Sifaka prospect and will potentially mature additional prospects in the Ampasindava block to drill-ready status. Sterling Energy (UK) holds a 30% interest in the Ampasindava production sharing contract, which is operated by ExxonMobil Exploration and Production (Northern Madagascar) (70%). Asia Pacific Production began on the Liuhua 19-5 gas field in the Pearl River Mouth basin in the South China Sea. The field is expected to hit peak production of 29 MMcf/D this year. China National Offshore Oil Corporation (100%) is the operator. Drilling began on the YNG 3264 and the CHK 1177 development wells onshore in Myanmar.
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.
Ruoff, Matthijs (Oranje-Nassau Energie B.V.) | Costa, Driss (Oranje-Nassau Energie B.V.) | Rosenberg, Steven (Weatherford) | Ameen, Sayamik (Weatherford) | Krol, Dariusz Krol (Weatherford) | Salomonsen, Halvard (Weatherford) | Tan, Ming Zo (Weatherford)
While drilling through the Permian Zechstein Group, North Sea operators can encounter a permeable overpressured interval which cannot be statically stabilized with conventional methods. An operator proposed drilling with Liner (DwL) in combination with managed pressure drilling (MPD) and continuous circulation technologies as a potential solution to this drilling hazard. In case that the overpressured interval was not seen, the DwL BHA could be retrieved after which the remaining section would be drilled conventionally. The DwL process allows a hazardous interval to be isolated in a single trip resulting in less risk and exposure compared with conventional drilling methods. Realizing the potential benefits automation brings, many operators have turned to MPD techniques as a technical and cost-rewarding solution to hard-to-reach assets, an approach which not only saves time but also enhances the safety capabilities of the operation. More importantly, MPD is increasingly being considered for other operations requiring precise pressure control to maintain wellbore integrity in constricted drilling envelopes. Continuous circulation technology provides a method to ensure continuous flow downhole while making connections which supplements the controlled annular pressure profile to avoid a drilling fluid / formation fluid change out. The prompt collaboration within the operator-service provider team determined which combination of these technologies would be the safest and most effective means for managing the overpressured interval should it be encountered.
This collaborative effort consisted of well engineering analysis and risk assessment sessions to ensure that the 12 ¼-in. hole objectives could be met in a safe and efficient manner aligning with the overall well objectives. The analyses included DwL, MPD, continuous circulation procedures and related simulation modelling for the running, drilling and cementation of the 9-5/8-in. × 13-3/8-in. liner. The combined technologies encompass a multitude of engineering disciplines; these were integrated into the operator's drilling plan in a seamless manner. Potential concerns and drilling hazards were identified and reduced to a manageable level. Ultimately, the 9-5/8-in. DwL system was used without encountering the overpressured interval and therefore the DwL BHA was retrieved with the remaining 12-1/4-in. hole interval conventionally drilled to planned depth without incidents. This paper will illustrate inclusion of DwL, MPD and continuous circulation technologies in the drilling plan as an effective solution for the mitigation of hazardous intervals. It will also reinforce the value of a close working relationship between operator and integrated service providers to eliminate uncertainties and provide sufficient risk mitigation to ensure that intended well objectives will be met.
The IADC and SPE are committed to delivering a balanced agenda around Diversity and Inclusion, to support member companies as they strive to address the gap in the Oil & Gas Sector. In 2019 the SPE/IADC International Drilling Conference and Exhibition in The Hague will host a session that allows delegates to explore the challenges facing the industry and hear firsthand, how it can be addressed. This initiative aims to build on the efforts already being undertaken at individual company levels to attract, develop and retain female staff - especially in technical and senior management roles, and to remove barriers that may currently hinder or discourage women from rising through the ranks into leadership roles. The aim is to address the factors contributing to the gender gap and to advantage all companies, their owners and shareholders through the incremental performance and value that parity will generate. This is good for our people, good for our stakeholders, and good for our business. Whilst in 2017 the session focused on subjects arising from DAVOS 2016 namely Leadership, Aspiration, goal setting, STEM, recruitment and retention, corporate culture and work life balance, the panel now feel it is time to move the conversation forward with some hard-hitting topics that affect the lives of many. Make sure you join us for this special session in The Hague.
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
The uncertainties of overpressure estimation are among the major challenges to the development of deep and hot reservoirs in many sedimentary basins especially with regards to drilling safety and well economics. However, because of the anticipated huge economic benefits of HPHT geological environments, stakeholders in the oil and gas industry consistently seek to have a good understanding of subsurface pressure systems in order to promote safe and sustainable investments therein. Accordingly, information is required to improve the regional knowledge of geopressures and for the calibration of functions aimed at optimising pre-drill pore pressure estimates for future wells. The Central North Sea, with its vast number of HPHT wells, pressure data, drilling information and documented operational experiences in exploration, drilling, development and production activities stands in a good stead as a "geopressure laboratory" for the fine-tuning of pore pressure prediction concepts, improvement of current geopressure practices and ultimately guide investment and operational decisions in the unexplored areas of the basin itself and elsewhere as geological realities could permit. For this reason, this study utilised downhole pressure-related data and wireline logs to evaluate the pressure regimes in the Central North Sea. The approach involved the quantification of overpressures using standard pore pressure prediction methods that make use of the density and velocity logs of mudstones. The results show that the estimated pore pressure profiles are consistent with measured pressure data in the Cenozoic formations, which makes it reasonable to assume that disequilibrium compaction is the cause of overpressure in this shallow section of the wells. Going deeper into the wells, within the sub-Chalk section, typical calibration parameters from log data could not be used to achieve reliable estimates of overpressures as was the case in the Cenozoic section. Remarkably, while it is possible to adjust the Eaton exponents in order to match estimates with measured data, a wide range of exponent values of between 4.0 and 7.0 is however required. The implication is that there is no systematic variation of the Eaton exponents with the amount of overpressure or depth of burial of the sub-Chalk strata.
Ramstad, Kari (Statoil ASA) | McCartney, Ross (Oilfield Water Services Limited) | Aarrestad, Henriette Dorthea (Statoil ASA) | Lien, Siv Kari (Statoil ASA) | Sæther, Øystein (Statoil ASA) | Johnsen, Rita Iren (Statoil ASA)
The Johan Sverdrup field will, at maximum, contribute 25% of the total oil production from the Norwegian Continental Shelf (NCS). Plateau production from the fully developed field is estimated at 550,000 to 650,000 BOE/D. Geochemical formation-water interpretation and development of a scale-management strategy have been performed to ensure high well productivity and process regularity of the field.
Uncertainty over the composition of formation water made the decision to inject normal seawater or low-sulfate seawater into the reservoir for pressure support a challenge. Water compositions in samples obtained from appraisal wells were unusual for the Norwegian North Sea, being sulfate-rich with negligible barium. This was suspected to be an artifact of drilling-fluid contamination, and corrections were applied to obtain representative estimates. These estimates confirmed that the formation waters had variable salinity (21–48 g/L chloride), and were indeed sulfate-rich (94–746 mg/L) and barium-depleted (<6 mg/L). The compositions may reflect (a) mixing of formation waters across the field over geological time and/or (b) interactions with the underlying Zechstein group (anhydrite). The focus here is on issue (b) because a detailed evaluation of local/regional aquifer movements in geological time, communication patterns, and flow restrictions is beyond the scope of this paper.
Three appraisal wells in the Geitungen Terrace showed barium-rich formation water outside the main reservoir area where no underlying Zechstein group was present. Initially, there were concerns about the scaling risks associated with mixing sulfate- and barium-rich formation waters. However, present geological understanding indicates insignificant aquifer volumes with barium, implying that full-field development and scale strategy do not need to consider barium-rich water.
Scale predictions were performed for various strategies: formation-water production, seawater injection, produced-water reinjection, and low-salinity/low-sulfate-water injection. Moderate strontium sulfate (SrSO4) and calcium carbonate (CaCO3) scalings are expected in the production wells. If third-party barium-rich waters are tied in, the topside barium sulfate (BaSO4) scaling risk increases.
This work has shown
The implications for field development are
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.)
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.