Tyrie, Jeb (Bridge Petroleum) | Mulcahy, Matt (Bridge Petroleum) | Leask, Robbie (Bridge Petroleum) | Wahid, Fazrie (Bridge Petroleum) | Arogundade, Olamide (Schlumberger) | Khattak, Iftikhar (Schlumberger) | Apena, Gani (Schlumberger) | Samy, Mohammed (Schlumberger) | Sagar, Rajiv (Schlumberger) | Xia, Tianxiang (TRACS International) | Nyadu, Kofi (WorleyParsons, Advision) | Maizeret, Pierre-David (Schlumberger)
This paper describes the proposed re-development of the Galapagos Field, comprising the abandoned NW Hutton field and the Darwin discovery (Block 211/27 UKCS) which forms a southerly extension. The paper covers the initial concept and analytical evaluation, the static uncertainty model build, the dynamic model history-match, the iterations between static and dynamic modelling, the development subsea and well locations, the optimisation workflow of the advanced Flow Control Valve (FCV) completions in both producers and injectors and the facilities constraints.
The redevelopment plan involved several multi-disciplinary teams. 20 years of production data from 52 wells were analysed to identify the production behaviour and confirm the significant target that provided the basis for the development concept selection. The full Brent sequence compartmentalised stochastic static model was based on reprocessed seismic plus 14 exploration and appraisal wells. Streamlines, uncertainty sensitivities and mostly good detective work honed a history match to RFT, BHP, PLT and oil and water production. P50, P90/P10 models were selected and over 100 FCVs optimised to deliver the profiles against an identified FSPO facilities’ constraints.
Over 1,000 static models were delivered consisting of sheet sands, incised valleys and channels in heterolithic facies overprinted by a depth trend with appropriate uncertainty ranges. The high well count gave a tight STOIIP probabilistic range of 790/883/937 million stb. The early RFTs illustrated extreme differential depletion between Brent zones and subzones of the Ness. To history-match these the dynamic model retained the static model definition in the Upper Ness to capture the thin but extensive shales. The early 18-month depletion and the late steady production-injection phases were simulated separately in prediction mode and matched the Production Analysis estimated ‘future’ production giving confidence to the history matched model. The initial concept development of 4 subsea-centres, to cover the large field area, with an injector in each compartment proved a robust selection. The horizontal wells increase PI where needed and mitigate internal faulting. The optimisation of the FCVs significantly increased oil production from all zones and drastically reduced water injection and production so that the identified FPSO modifications were relatively modest. The final First Stage Field Development Plan consists of 11 producers and 6 injectors across developed and undeveloped areas confirmed robust P50 reserves of 84 million boe.
Robust concept selection allowed for early identification of production units so that constraints and modifications could be accounted for within the economic model.
The Galapagos field re-development plan is an excellent example of how detailed static and fully history matched dynamic models can lay the foundations for new technology like the optimisation of the FCVs to access bypassed reserves using significantly smaller production units with reduced requirements for power, compression, gas lift, pumping pressure, injection and production. In short, they shrank the facilities.
Maintaining a stable borehole and optimizing drilling are still considered to be vital practice for the success of any hydrocarbon field development and planning. The present study deliberates a case study on the estimation of pore pressure and fracture gradient for the recently decommissioned Volve oil field at the North Sea. High resolution geophysical logs drilled through the reservoir formation of the studied field have been used to estimate the overburden, pore pressure, and fracture pressure. The well-known Eaton’s method and Matthews-Kelly’s tools were used for the estimation of pore pressure and fracture gradient, respectively. Estimated outputs were calibrated and validated with the available direct downhole measurements (formation pressure measurements, LOT/FIT). Further, shear failure gradient has been calculated using Mohr-Coulomb rock failure criterion to understand the wellbore stability issues in the studied field. Largely, the pore pressure in the reservoir formation is hydrostatic in nature, except the lower Cretaceous to upper Jurassic shales, which were found to be associated with mild overpressure regimes. This study is an attempt to assess the in-situ stress system of the Volve field if CO2 is injected for geological storage in near future.
Some of the first high-pressure/high-temperature (HP/HT) development wells from Elgin and Franklin have been exposed to sustained casing pressures in their "A" annulus, threatening the integrity of the wells. The sustained pressure in the annulus was attributed to ingress through the production casing of fluids from the overburden chalk formations of the Late Cretaceous. The mechanism triggering the ingress into the "A" annulus was uncertain until access to the production casing was achieved. A recent campaign to abandon development wells of Elgin and Franklin that had sustained "A"-annulus pressure brings new evidence on the mechanism causing the ingress. Temperature surveys have been acquired in the production tubing to identify the fluid-entry points in the production casing. Multifinger calipers have been run in the production casing, revealing several shear-deformation features. These deformations are localized along various interfaces, and are attributed to the stress reorganization associated with the strong reservoir depletion. A detailed analysis of the surveys shows that fluid ingress is occurring at distorted casing connections, if located close to weak interfaces along which shear slip occurs. The shear deformation is suspected to cause a loss of the sealing capacity of the connection, leading to gas ingress into the "A" annulus. This conclusion emphasizes the need to consider any potential for localized shear deformations in designing casing for HP/HT wells.
We present an anisotropic rock physics model which can be used to estimate velocities for different facies types (sands, shales and carbonates). The model uses a combination of the joint Self Consistent, Approximation and Differential Effective Medium model (SCA/DEM) and the Hudson model for fractures. The SCA/DEM model is used to build the frame of the rock and the Hudson model adds fractures in 3 orthogonal directions with varying concentrations inducing anisotropy. Allowing the model parameters to change gives enough flexibility to the model to model different facies including sands and carbonates. The model has been tested against sand, shale and carbonate data from well logs in the Barents Sea and the North Sea. Anisotropy for this well was estimated using the method of White (1983). Results show a good fit between the rock model and the data.
Presentation Date: Thursday, October 18, 2018
Start Time: 8:30:00 AM
Location: 202A (Anaheim Convention Center)
Presentation Type: Oral
Time-lapse changes in the overburden can be related to pore pressure variations in the underlying reservoir. The geomechanical changes observed are independent of fluid flow given the impermeable nature of the caprock, however, such deformation has the potential of causing a significant impact on the 4D signal. A physical model widely used to couple geomechanics and time-lapse seismic signatures, relates the fractional change in velocity and the vertical strain of reservoir and surrounding rocks via a constant factor
Presentation Date: Wednesday, October 17, 2018
Start Time: 1:50:00 PM
Location: Poster Station 17
Presentation Type: Poster
Constable, Monica Vik (Statoil ASA) | Antonsen, Frank (Statoil ASA) | Stalheim, Stein Ottar (Statoil ASA) | Olsen, Per Atle (Statoil ASA) | Fjell, Oystein Zahl (Statoil ASA) | Dray, Nick (Statoil ASA) | Eikenes, Sigurd (Statoil ASA) | Aarflot, Haakon (Statoil ASA) | Haldorsen, Kjetil (Statoil ASA) | Digranes, Gunnar (Statoil ASA) | Seydoux, Jean (Schlumberger) | Omeragic, Dzevat (Schlumberger) | Thiel, Michael (Schlumberger) | Davydychev, Andrei (Schlumberger) | Denichou, Jean-Michel (Schlumberger) | Salim, Diogo (Schlumberger) | Frey, Mark (Schlumberger) | Homan, Dean (Schlumberger) | Tan, Sarwa (Schlumberger)
A vision in the oil industry for decades is becoming a reality. Finally, we are able to drill and react proactively to formation resistivity properties several meters ahead of the drill bit, instead of reacting to measurements behind the bit. Through a technology collaboration between operating and service companies, a targeted technology development for measuring resistivity contrasts ahead of the bit in real time to reduce cost and risk during drilling operations was developed. Two electromagnetic look-ahead (EMLA) prototypes have been developed for 12¼- to 14-in. boreholes. The EMLA tool is modular and consists of a low-frequency transmitter inserted in the rotary steerable drilling assembly 1.8 m behind the bit and two to three receivers spaced out in the drillstring. The EMLA tool uses the same sensor technology and operates with the same multispacing and multifrequency measurements as the commercial ultradeep “look-around” directional resistivity tool. The formation structure ahead of the bit is interpreted by inversion to differentiate sensitivity around the tool from effects ahead of the bit. The look-ahead capability is dependent on the transmitter-receiver spacing, frequency, resistivity around the tool, thickness of the target, and the resistivity contrast ahead of the bit.
The EMLA tool provides a step change with regard to precision in detecting changes in resistivity properties ahead of the bit in vertical and low-angle wells. The ability to react to resistivity contrasts ahead of the bit has a direct impact on how wells are drilled. The main application of EMLA to date has been to drill the well section above the reservoir closer to top of reservoir to avoid complications in the shale above the reservoir, as presented in two case studies. Challenges related to salt drilling are addressed in another case study where the salt exit was detected 30 m ahead of the bit. Improved precision in coring-point selection is another potential application.
Constable, Monica Vik (Statoil) | Antonsen, Frank (Statoil) | Stalheim, Stein Ottar (Statoil) | Olsen, Per Atle (Statoil) | Fjell, Øystein Zahl (Statoil) | Dray, Nick (Statoil) | Eikenes, Sigurd (Statoil) | Aarflot, Haakon (Statoil) | Haldorsen, Kjetil (Statoil) | Digranes, Gunnar (Statoil) | Seydoux, Jean (Schlumberger) | Omeragic, Dzevat (Schlumberger) | Thiel, Michael (Schlumberger) | Davydychev, Andrei (Schlumberger) | Denichou, Jean-Michel (Schlumberger) | Salim, Diogo (Schlumberger) | Frey, Mark (Schlumberger) | Homan, Dean (Schlumberger) | Tan, Sarwa (Schlumberger)
AbstractA vision in the oil industry for decades is becoming a reality - we can now finally drill and react pro-actively to formation resistivity properties identified several meters ahead of the drill-bit, instead of drilling reactively on resistivity measurements at or behind the bit. Through a technology collaboration with Schlumberger, Statoil supported a targeted technology development for measuring resistivity contrasts ahead of the bit in real-time to reduce cost and risk during drilling operations.
Two Electro-Magnetic Look Ahead (EMLA) prototypes have been developed for 12 ¼" to 14" borehole diameter. The EMLA tool is modular and consists of a low frequency EM-transmitter inserted in the rotary steerable drilling tool about 1.8 m behind the bit. The transmitter induces currents at multiple frequencies around and ahead of the bit and the resulting induced magnetic field is recorded with 2 to 3 receivers spaced out in the drillstring. The formation structure ahead of the bit is interpreted by inversion of the bulk signals to differentiate sensitivity around the tool from effects ahead of the bit. The look ahead capability of the EMLA tool is dependent on the transmitter-receiver spacings, frequencies, resistivity around the tool, thickness of the target, and the resistivity contrast ahead of the bit.
The EMLA tool provides a step change with regards to the precision we now can detect changes in rock properties ahead of bit, enabling the well placement teams to “see” several meters ahead of the bit and to react before drilling into potential hazardous situations, even in near vertical wells. One key use of the EMLA technology on the Norwegian Continental Shelf is to drill and set casing for the 12 ¼" section much closer to top reservoir than we do today. This can reduce the risk of collapse in the overburden, especially for depleted reservoirs which require a significantly lower mud weight for drilling the reservoir than the optimal weight for stabilizing the overburden. The technology can also be used to pick the coring point more precisely and prior to drilling into the zone of interest. This will enable coring of the transition between overburden and reservoir which is often missed when using near bit measurements and also prevent costly coring of thin sand stringers mistaken as the main zone of interest.
Statoil has recently tested the tool in a sub salt play in the Gulf of Mexico with great success. One of the main objectives was to detect bottom salt before drilling through it. The highly resistive salt formation offers a very favorable environment for EM applications. The bottom salt was detected 30 m ahead of bit, which gave the drillers an early warning of the salt exit and potential drilling challenges.
In the near future, with the technology already there, simultaneous look around and look ahead (LALA) while drilling will be available. Interpretation of measurements in 2D and 3D environment is the main challenge to overcome to make LALA happening. To do so, a tight integration between inversions and geological scenarios will be a necessity.
The lower and upper Bakken shales are world class source rocks in the Williston Basin, sourcing reservoirs in the Bakken, upper Three Forks, and lower Lodgepole formations, which comprise the economically significant Bakken Petroleum System (BPS). 10 to 400 billion barrels of oil have been estimated to have been generated from the Bakken shales, charging both unconventional and conventional plays in the BPS, but an advanced geochemical and geological characterization of source rock property of Bakken shales enables more realistic oil resource estimation. The technical contribution of this study enhances our understanding of the source rocks' potential and sequence stratigraphy of Bakken shales and the associated relationship with Bakken oil presence in reservoirs of the BPS across the basin. Over three thousand total organic carbon (TOC) content and other geochemical results, such as kerogen type, maturity, and kinetics, have been analyzed at the Source Rock Analysis Lab of Colorado School of Mines. The correlations of wireline logs, geochemical TOC and hydrogen index (HI) logs, XRF mineralogy-associated elemental logs have been integrated to infer depositional paleo-redox conditions and establish sequence stratigraphy for the Bakken shales. The results indicate that lower and upper Bakken shales exhibit a wide range of TOC content, and the kerogen present in shales is primarily Type II kerogen.
In conventional systems, predicting gas-oil ratio and charge volumes ahead of drilling is a key element of exploration strategy. Sulphur contents, wax contents also affect viscosity, recovery and price per barrel. In shale plays the liquid-gas cut-off must be known precisely, and production from the liquid-prone zone optimised. In-place does not necessarily correspond to produced GOR. In particular the transition from volatile oil, to condensate to wet gas is crucial, and production strategies must be developed accordingly.
The first step in unravelling the fractionation phenomena occurring in both play types is to determine the bulk composition of the petroleum that is first-formed in the source rock. This is because all subsequent processes simply act upon and modify this original composition. Here we present numerous case studies where PhaseKinetics (di Primio and Horsfield, 2006), a compositional kinetic approach for predicting in-situ bulk fluid properties, has been employed in appraising acreage, and then go on to consider the critical aspects surrounding unconventional plays.
In high pressure-high temperature (HPHT) reservoirs of the North Sea, which can be considered closed systems, black to light oil GOR distributions in the North Sea Viking Graben closely matched the predictions from our MSSV pyrolysis experiments (method of Horsfield et al., 1989) performed on the Draupne Formation source rock (di Primio and Skeie, 2004). In a similar study of the Jade and Judy Fields in the Central Graben (di Primio and Neumann, 2008), GOR predictions from MSSV pyrolysis bore a close resemblance to the natural HPHT system. Other examples of excellent GOR predictive capability are provided by modelling the Egret Shale and its generated petroleum in the Jeanne d'Arc Basin, Canada (Baur et al., 2010), and the Bakken Shale and its petroleums in the Williston Basin, USA (Kuhn et al., 2010, 2012). Gas composition dominantly controls the phase behaviour of petroleum (di Primio et al., 1998). The PhaseKinetics compositional kinetic model utilises corrected gas compositions from MSSV pyrolysates, as well as pseudo-boiling ranges in the C6+ range to populate bulk activation energy potentials (di Primio and Horsfield, 2006). Examples from the Norwegian North Sea, Brazil and Mexico presented in that publication have demonstrated the close correspondence of the tuned compositional predictions with field data. Concerning unconventional play production, we draw attention to the importance of determining whether cumulative or instantaneous fluids are found within the range of pore sizes present in shale.
Constable, Monica Vik (Statoil) | Antonsen, Frank (Statoil ASA) | Olsen, Per Atle (Statoil ASA) | Myhr, Gjril (Statoil) | Nygaard, Atle (Statoil) | Krogh, Morten (Statoil) | Spotkaeff, Matthew Sergei (Schlumberger) | Mirto, Ettore (Schlumberger) | Dupuis, Christophe (Schlumberger) | Viandante, Mauro Gabriele
The last decade has shown a significant development in resistivity measurement technology providing directional resistivity at a larger scale than conventional logging tools. The latest development can identify resistivity contrasts ten's of meters around the wellbore.
Statoil has tested deep look-around resistivity on a range of fields during the last 2 years and recorded data in more than 10 wells on the Norwegian Continental Shelf. The look-around images provides information at a scale that bridges the gap between conventional logging and seismic and adds important new pieces to the reservoir characterization puzzle. In good reservoir conditions, resistivity contrast up to 30 m away from the well-bore has been observed.
This study will focus on results from the Visund and Åsgard fields, and will demonstrate how the device was used in a range of different applications in the geosteering operation:
Detection of the reservoir boundary up to 20m TVD away.
These examples will highlight why deep look-around resistivity is a step change related to the possibility for doing pro-active well placement of highly deviated wellbores as well as for gaining a larger reservoir understanding. The imaged variation in resistivity contrasts can be related to geologic zonation and fluid content on the reservoir scale, which opens up a much better cross-disciplinary communication between geophysicists, geologists, petrophysicists and reservoir engineers. Finally, the deep resistivity images contribute in optimization of completion solutions when incorporating information on the reservoir scale.