Saga Petroleum ASA was a Norwegian upstream petroleum company established in 1972 that was acquired by Norsk Hydro in 1999. In October 2007 it was made part of Statoil. The company was the only fully private oil company in Norway. It had partial ownership of 60 oil field licenses and was operator of 18. Saga had an international profile, including major operations on the British continental shelf as well as minor operations in Angola, Indonesia, Libya and Namibia.
Abstract CO2 based fluids are commonly used to fracture stimulate formations with low reservoir pressure as well as formations that are more sensitive to water treatments (high capillary pressure, swelling clays etc). In particular, the Frontier Formation located in Bighorn Basin, Wyoming, has seen a variety of stimulation fluids used over the past years with varying degrees of success. When dealing with water sensitive formations, a common practice has been to use oil-based fluids. However, fluids of this nature can have detrimental effects on gas zones with low reservoir pressure and this might be the reason for erratic well performance of previously treated Frontier completions. It has also been determined that oil-based fluids can alter the reservoir wettability and hence cause formation damage. With this in mind and considering the environmental and economical benefits of using a water-based fracturing fluid, a novel visco-elastic surfactant based, CO2-compatible, high foam quality (>60%) fluid was proposed as the main fracturing fluid. This paper will discuss the first application of this visco-elastic based fluid on wells in Park County, Wyoming. This paper will discuss stimulation with the new fluid and how pin-point pressure measurement enabled the operator to make informed decisions to define fracturing/completion strategy. We also present the additional benefits of incorporating existing dipole sonic tool information to calibrate "in-situ" stress, Young's Modulus and Poisson's ratio. Finally, a production history match is conducted on wells treated with the new fluid.
SummaryA new method for zone isolation in horizontal wells with chemical packers has been developed and tested with a 60-ft-long, full-scale horizontal-well apparatus. The method involves setting two chemical wellbore plugs in the horizontal section to straddle the problem zone, squeezing gel into the problem zone, and cleaning out the borehole before production. A crosslinked hydroxyethyl cellulose was used as the wellbore plug, while a monomer gel was used to shut off the problem zone. Tests confirmed the viability of the new zone-isolation method.
Abstract The paper describes the laboratory development of a new Low Solids Oil Based Mud System (OBMS) with a very high specific gravity (2.04 SG; 17 ppg) for high-temperature and high-pressure applications. The system can also be applicable as solid free oil based mud with very low viscosity at densities up to 1.52 SG, especially suggested for Extended Reach Drilling Wells. The main goals of the new system are: Optimization of fluid rheology by reduction of the solids contents in the mud. Temperature and system stability at 170 °C. The objectives have been pursued in the following ways: – by using a very heavy brine as the internal phase; – by decreasing the oil / brine ratio; – by using a weighting agent with higher density than barite. In this way, the amount of weighting solids which needs to be added can be drastically reduced to even below 22% v/v for a 2.04 SG mud, compared to 35% v/v as in traditional oil based muds. Also the PV values have been reduced from typically round 60 cP to even below 25 cP. The addition of new components to the system has lead to the need of a new emulsifier package, which has been optimized with the development of a primary emulsifier and a wetting agent based on innovative chemistries.
Knowledge of the timing and location of petroleum formation is important in assessing the extent of available reserves in hydrocarbon-forming basins. This can be predicted from the thermal history of a basin and the kinetic parameters that characterize the thermal breakdown of kerogen in source rocks. At present, the kinetic parameters of kerogen breakdown are experimentally determined using immature rock samples from basin margins1, but questions remain about the accuracy of this approach2, especially when significant variability is observed within individual source units3,4,5. Here we show that the kinetics of hydrocarbon generation from petroleum asphaltenes can be used to determine the temperature conditions of the actual source rock at the time of expulsion of the sampled petroleum. This relationship reflects the structural similarity of asphaltenes to the parent kerogen6,7. We expect that our approach may be used as a comparatively simple alternative method for assessing the petroleum generation characteristics of a given basin, which will allow for better estimates of the available oil resources and the risks associated with their exploration.
A stratigraphic framework has been developed for the Cainozoic succession of the Norwegian continental shelf and margin. This framework is consistent for the entire margin from the central North Sea to the Barents Sea and also facilitates a correlation with the deep sea record of the Norwegian Sea and North Atlantic. A local system, mainly utilising planktonic and benthic foraminiferal assemblages and Bolboforma species, is developed. It can be potentially used for regional stratigraphic syntheses. Using this framework, a more precise and detailed identification and age assignments of Cainozoic, and in particular Neogene, strata can be performed. Several revisions of previous age assignments and a more detailed dating of the various sediment packages are presented. The most complete Neogene succession is recorded in the central North Sea. Further north the succession is interrupted by an increasing number of hiati of increasing duration. After a period of erosion in the late Middle to early Late Miocene there is a marked increase in the influx of terrigenous sediment in the Late Miocene. A period of transgression in the Early Pliocene resulted in strongly reduced rates of deposition, and sediments of this age are preserved mainly in the central North Sea. A period of regression in earliest Late Pliocene probably resulted in erosion of most of the Norwegian continental shelf with the exception of the deeper areas of the Central and Viking Grabens. This period was immediately followed in the later part of Late Pliocene, by rapid deposition of glacially derived sediment prograding along the entire shelf. In general, Pleistocene development is a continuation of the Late Pliocene evolution, but is marked by more extensive erosion of the inner shelf. This is inferred from the flat truncation of underlying prograding strata and the extensive build up of debris flow sediments within glacial fan depocentres. The entire Neogene development is closely related to the climatic evolution of high latitude regions surrounding the North Atlantic and the Norwegian-Greenland Sea.
