As companies have focused on giant capital investments onshore and offshore to drive growth, they have often focused less on field operations, especially OPEX. In a $60 to $70 oil environment, the subsea market is poised to grow around 7% annually up to 2025. But a significant portion of this activity is at risk if the price of Brent crude falls to $50 per barrel. Approximately $200 billion in projects worldwide are racing to be approved over the next 2 years. The race is not just to make FIDs on projects, but also to enter FEED work to lock in contractors before others do.
In a $60 to $70 oil environment, the subsea market is poised to grow around 7% annually up to 2025. But a significant portion of this activity is at risk if the price of Brent crude falls to $50 per barrel. The subsea operations company said its most recent campaign is the first fully unmanned offshore pipeline inspection completed “over the horizon,” surveying up to 100 km from the shore. One of the largest industrial projects in the UK in recent years, Mariner marks Equinor’s first operated field on the UK Continental Shelf. It is expected to produce 70,000 BOPD at peak rates.
One of the largest industrial projects in the UK in recent years, Mariner marks Equinor’s first operated field on the UK Continental Shelf. It is expected to produce 70,000 BOPD at peak rates. The Norwegian Petroleum Directorate has given clearance to start up facilities at the North Sea field, which straddles the line between the UK and Norwegian sectors. Production is set to begin in September. Lundin reports that the hookup and commissioning of installed facilities at the large North Sea field is progressing as planned.
Lundin reports that the hookup and commissioning of installed facilities at the large North Sea field is progressing as planned. Phase 1 startup is still scheduled for November. Is Optical Gas Imaging the New Solution for Methane Detection? Thermal imaging helps operators maintain regulatory compliance on methane-emissions requirements. Optical gas imaging technology may be an answer in allowing for faster, more efficient inspections, but there are hurdles to its adoption.
Cedeño, Freddy (Halliburton) | Deen, Larry (Halliburton) | Martinez, Juan (CARDON IV) | Rojas, Ybrendiz (CARDON IV) | Martinez, Valentina (CARDON IV) | Plazola, Pedro (CARDON IV) | Segatto, Michele (CARDON IV) | Martinez, Ricardo (CARDON IV)
The Perla-7 well experienced lost circulation while drilling the naturally fractured carbonate reservoir. To cure the losses, 285 bbl of various lost-circulation materials (LCMs) were pumped. This plugged the 300-micron slotted liner and resulted in an impairment of production. This paper describes a study of the solids retention by a 300-micron slotted liner and the design, testing, and application of a delayed-release acid system to remediate the plugged well and recover productivity.
The well was closed while spotting the delayed-release acid treatment; gas was filling the well from the previous well testing. Coiled tubing (CT) was used along with a proven fluidic oscillator technology that enables better control when matching fluid rates to the most desirable frequency and amplitude of the pressure pulses. When the pressure began rising from the last recorded surface pressure, the well was bled off on the surface to maintain a balanced condition. After the treatment, the well was opened and cleaned out using well testing equipment, flaring hydrocarbons, and spent acid.
Logistical considerations resulted in the selection of the in-situ acid-release system instead of conventional treatments. The pumped LCMs dissolved successfully, helping to swiftly recover well productivity. The acid-release treatment was split into two stages, with a 30-minute soaking time between the pumping of the two designed engineered pills. A total of 270 bbl of the delayed-release acid were pumped at a 25% volume/volume concentration. No special tanks were necessary for this operation; the acid-release treatment is neutral on surface and is easily handled until required. The well test interpretation was developed based on a pressure buildup period before and after the treatment. The results returned a fairly good reservoir property, with a Kh of approximately 10 000 md-ft with a consistent skin reduction from 14 to four. There was also a corresponding reduction in the drawdown of 120 psia, which was necessary to achieve the same gas rate of 50 million scf/D.
The Perla field is the largest offshore gas reservoir discovered to date in Latin America. The Perla-7 well was drilled in the Cardon IV block, located in the shallow water eastern part of the Gulf of Venezuela. The in-situ acid release treatment is now an alternative option through which to support offshore operations where logistics can be challenging, especially when well remediation is required.
The early integration of geological concepts and seismic (qualitative and quantitative) interpretation is a powerful tool to enhance the probability of success of an appraisal campaign. The presented example of an integrated workflow was applied to Perla Field (offshore Gulf of Venezuela), an Early Miocene carbonate reservoir containing gas and condensates. The work was therefore tailored on the integration of geological data and advanced seismic interpretation since exploration project start-up is a key to improve success of appraisal campaign and early production phases.
The presented case refers to an Early Miocene gas-bearing carbonate asset, Giant world-class reservoir. 3D Seismic data shows an isolated bank developed on basement high, thickness decreasing from crest-to-flanks. Wildcat well found 200m high-porous bio-GRST/PKST having moderate diagenetic imprint.
The red algae-dominated system formed low-angle ramps more than classical flat-top platforms. AVO attributes (Gradient) fully supported detailed seismic interpretation, since Carbonate reflections responded to elastic changes rather than subtle acoustic contrasts, negligible on conventional seismic. A petroelastic model and strict quantitative amplitude reliability were validated.
Acoustic Seismic inversion was performed right after the wildcat well.
Efforts devoted to realistic a-priori model building accounted for overburden trend and carbonate sequences velocity fields. The inversion results permitted seismic to effective porosity calibration (Seismic Pseudo-Porosity Volume), a significant tool for the delineation campaign.
Inversion properties vs depositional facies geometries relationships also allowed facies belts areal definition; jointly with structural attributes they were used to optimize the number, locations and trajectories of delineation wells. Appraisal wells confirmed the porosity predictions at seismic scale, and approach stability. No needs for acoustic inversion or calibration revision were considered, due to the high-quality blind tests results on appraisals. The availability of hard-data from extensive core campaign, re-enforced the geophysical calibration to reservoir facies, via petrophysics and rock-physics lab measures.
Seismic Porosity, Non-Supervised, and Supervised Facies cubes got into reservoir model, driving the areal distribution of Sw and K.
Elastic-Porosity large variability was tentatively correlated with the factor Gamma-K, representing the frame flexibility, hence pore structure of different sed-petro-facies.
Manipulation of Elastic Inversion data and more stable Rock Physics Model would be the next development to capture internal reservoir model microstructure variances.
The comprehension of the fracture network at different scales is mandatory for understanding and developing a sub-surface fractured reservoir. The different scales of fractures are investigated using several approaches and then integrated in the final fracture distribution model.
For example the micro-fractures (from cm to meter length) are analyzed, for characteristics and distribution, from oriented cores and well logs, instead faults (macro-fractures, more than hundred meters length) are interpreted and mapped from seismic. The meso-fractures (tens to hundred meters length) are the most problematic since it is impossible to analyze them with direct tools as they are hard to be detected and described in the seismic volumes. This type of fractures, also called sub-seismic fractures, is extremely important for fractured reservoir permeability characterization.
We have developed a workflow which integrates data from analogous outcrops/cores and an automatic detection of structural features in seismic volumes enhanced by attributes as continuity or positive/negative curvature.
The seismic attribute volume is scanned and lineaments are detected and collected. The resulting dataset is statistically analyzed for length distribution (histograms), for strike (rosette diagrams and fracture sets detection) and for density (P21 and P20 maps or 3D grids).
The comparison with the fault network coming from seismic interpretation allows the detection of different fractured domains or fractures corridors related or not to the faults and to better constrain the structural evolution of the studied reservoir.
It is also possible to use these lineaments to compute probabilistic fracture surfaces that can be easily imported in a DFN (Discrete Fracture Network) model for the reservoir characterization.
The results are finally checked taking into account the stress/strain evolution through time of the studied area.
This workflow was successfully applied on the main fractured reservoir operated by eni as: Kashagan field (Kazakhstan), Perla field (Venezuela), Val d’Agri field (Italy).
The description and detection of the real fracture network in a sub surface reservoir is an extremely complex task as it isn’t possible to use a direct and unique approach. The fractures network is always related to the interaction of fractures and faults of different scales (from millimetric to kilometric scale) not uniformly distributed in the rocks volume. There are different and well known approaches to investigated fractures at each particular scale: for example the micro-fractures (from cm to meter length) are analyzed from cores, oriented or not, and well image logs, instead faults (macro-fractures, more than hundred meters length) are interpreted and mapped from seismic. Nevertheless there is a problematic scale to be investigated: the meso-fractures (tens to hundred meters length). It is impossible to analyze them with direct tools as they are hard to be detected and described in the conventional seismic volumes. This type of fractures, also called sub-seismic fractures, is extremely important for fractured reservoir permeability characterization.
The final fracture network models must be reached by the integration of all the available analysis and approaches, at the different scales, with any other useful information about geology, drilling and reservoir engineering. So integration is the only possible solution to the fracture network characterization problem.
We have developed an integrated workflow for collecting all the available data and approaches and to characterize the final fracture network. This workflow essentially focuses on the sub-seismic fracture detection and characterization. Here we present mainly this last point.