An increasing number of wells are being drilled in formations with a high risk of well bore instability. Historically, the majority of instability was a result of drilling reactive clays with water-based fluids. This is still a common risk and is usually addressed by using oil-and synthetic-based fluids. However, we now more commonly have to overcome the problems associated with drilling depleted or weak formations which can be difficult to drill even with oil-or synthetic fluids. This is especially common in fields that have been producing for many years and where geological pressures have been altered. More and more often, stress caging techniques are being used to drill these unstable formations. Effective stress caging is relatively straight forward if all the parameters are known; however, this is rarely the case and accurate fracture and pore throat measurement in-situ is nearly impossible. To seal these fractures, which are sometimes a few microns or less, a new form of micro-or nano-sized sealant is required in addition to the conventional calcium carbonate/graphite particle blend. This paper presents a novel drilling fluid additive that utilises particles of approximately 200nm to seal fractures and pores to stop the invasion of drilling fluid filtrate and reduce pore pressure transmission. This enables wells to be drilled in depleted formations without losses, use very high overbalances with no differential sticking, and also plug micro pores and micro fractures found in shales to reduce instability and improve hole integrity. Laboratory testing is described that demonstrates the advantages of using this technology and case histories proving its usefulness in the field are described. Utilisation of this new nanotechnology will enable many problematic formations to be drilled safely and trouble-free by reducing the risk of wellbore failure.
The Rita gas field was the first dual lateral well aimed at carboniferous reservoirs drilled in the UK Southern North Sea. This method enabled both the East and West fault segments of the field to be produced from the same upper well bore, thus reducing drilling costs and improving field economics. An invert emulsion drilling fluid was chosen for this field application due to the risk of shale instability over the long horizontal sections of each wellbore. The West segment was drilled and suspended with a whipstock placed above the sand screen completion. The positioning of this whipstock would not allow for re-entry, making remediation of the West lateral impractical. A remediation treatment for this leg was required as the planned suspension fluid was an invert emulsion system that would be in contact with the completion screens and reservoir for more than a month whilst the East leg was drilled and completed. The chosen suspension fluid in the East leg removed the requirement for remediation with enhanced well productivity. This paper describes the design and testing of the reservoir drilling and suspension/completion fluids that were used on this multi-lateral project to minimise drilling time and maximise productivity. Introduction The well described in this paper was a complicated design and consisted of a dual lateral to produce gas from two unconnected reservoirs. The Rita well (44/22–12) was spudded in early July 2008. The first (West) leg of the well had a TD of over 17,000 ft with a 6" horizontal section of over 2,700 ft. After the lower completion was run in the first leg a whipstock was set to enable drilling of the second (East) leg. The East leg had a TD of 15,600 ft and a 6" horizontal section of over 2000 ft. The plan was to suspend the first leg for a period of time that might exceed 2 months to allow for the drilling of the second leg and the running and installing the novel completion. This industry has experienced lower than expected production rates from wells which have been suspended for long periods with oil-based, solids-laden fluids before a clean up has been initiated. This raised the question of what type of fluid to leave below the whipstock, as re-entry to this leg for clean-up or well remediation was not economically feasible if production was lower than expected. Due to the diametrically opposed shape of the well, with long horizontal sections the drilling team was strongly in favour of using an oil-based reservoir drill in fluid (OBRDIF). This fluid would give a stable wellbore and provide a low friction co-efficient for drilling and running the completion assemblies. Using OBRDIF would reduce the risk of hole instability and minimise non-productive time. However if OBRDIF was used in the drilling phase, it would mean that a solids-laden invert emulsion would be left in the hole when the first leg was suspended with the sand screens below the whipstock. This presented several risks. The fluid would require fine screening to prevent blocking of the completion equipment with drill solids. Also, there was a risk that the solid particles in the suspension fluid would agglomerate as the fluid remained static for an extended period. If agglomeration did occur, these solids would probably not pass through the mesh of the completion screens and could potentially reduce their conductance. The size and concentration of the solids in the suspension fluid were recognised as areas of concern that should be addressed to ensure maximum productivity of this well.
Minimising drilling costs is an ongoing concern, especially with global uncertainty and volatile oil prices. One area in which costs can be reduced is in the wellbore cleanup phase. Inefficient cleanup can result in large volumes of liquid waste that must be treated or disposed of, particularly if a non-aqueous drilling fluid (NADF) is used. In addition, completion fluid costs can be significant, especially where high-density brines are required for wellbore safety. Improved cleaning efficiency can lead to significant cost savings.Wellbore cleanups in high-temperature, high-pressure (HTHP) wells can be particularly challenging. Not only is high-density brine required to maintain hydrostatic overbalance to control formation pressures, the brine is often at or close to its saturation point. The selection of surfactants that function effectively in high-salinity fluids can be very challenging. Extensive laboratory testing must be performed to ensure compatibility between the cleanup spacer and the drilling fluid. The performance of the cleanup is then assessed through a series of bottle and viscometer sleeve tests to ensure the solids and metal surfaces were rendered fully water-wet.A significant challenge when designing cleanup spacers is balancing excellent performance of oily residues and solids removal with thermal and chemical stability. Microemulsion cleanup spacers have been used to perform efficient wellbore cleanups in deepwater applications, resulting in reduced volumes of waste fluids. This paper describes the field application of a high-density caesium formate brine microemulsion cleanup spacer to efficiently displace and remove a high-density barite and manganese tetraoxide-weighted NADF. Results show that microemulsions exhibit excellent displacement and cleanup performance of a challenging drilling fluid. Microemulsion technology results in a quicker cleanup with reduced waste volumes, thereby minimising costs.The high value of caesium formate brine means that maximising the recovery of this valuable asset is essential to justify the economics of the cleanup process. This paper describes the transfer of microemulsion cleanup technology used in deepwater environments to HTHP applications.
With the passing of "easy oil," the need for high-pressure, high-temperature (HP/HT) drilling and completion fluids has increased. This has, in turn, increased the need for sufficiently robust cleanup methodology. This requirement for high density, solids free cleanup fluids drove the investigation into the use of cesium formate as the base brine. The use of cesium formate brings unique challenges to the cleanup, most notably, the cost implications. The high price of cesium formate brine means that any losses could severely impact upon the cost of the cleanup operation. Furthermore, any brine used in cleanup pills that could not be recovered for re-use would have to be considered as lost. It was, therefore, imperative to return the brine to its original condition, thereby avoiding the need to dispose of a very expensive commodity. This paper will look at the laboratory testing surrounding the development of a high density cleanup fluid (HDCUF) and the ability to remove the contamination from the brine to bring it back to an acceptable condition.The cleanup spacers were made up with cesium formate brine and several approaches to remove the contamination were investigated. Contamination was from both the chemicals used to formulate the cleanup spacer and from the oil based drilling fluid that would be used to drill the wells. Nuclear Magnetic Resonance (NMR) Spectroscopy was used to measure the level of contamination in the brine.The results of the study showed that, using the method selected, it was possible to remove the cleanup chemicals to an acceptable level where the cesium formate brine was able to be re-used. This would enable the operator to recover the brine and avoid the significant costs from losing the volume and disposing of the waste.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
customersupport@researchsolutions.com
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.