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.
There is an increased demand for the design and application of non-damaging fluids in reservoirs that are depleted and susceptible to deep invasion of damaging mud solids. To enable a reservoir drilling fluid to function correctly, it is necessary to very rapidly deposit an external filter cake and reduce filtrate loss to a minimum. The cake must be backflowed in the production phase with minimum liftoff pressure and leave little or no permeability reduction. To achieve this, an accurate description of the pore throats in the reservoir is required. If this cannot be obtained, or the reservoir is at risk to fracture, then another approach is required. This paper illustrates the methodology of utilizing a variable calcium carbonate bridging distribution mixed with powdered graphite which overcomes the problems of drilling reservoirs with varying pore throats and fractures. The bridging materials will enable an efficient control of filter cake deposition, and also allow for easy disruption of the cake integrity, when the well is back flowed in the production phase. Results proving the effectiveness of this approach can be shown from return permeametry work in the laboratory, and successful field trials of its application in the Southern North Sea and the Middle East. The use of these non-damaging products, and the engineered size distribution, will greatly decrease the difficulty at which fractured and depleted reservoirs can be drilled and will not reduce the productivity of these wells, that have in the past experienced formation damage due to deep fluid and solid invasion. Introduction Alternative formation pressure differences between different formation types have always presented drillers with a complex and difficult problem. A prime example of this is the stratigraphic column in the eastern province of Kingdom of Saudi Arabia, where there are successive high pressure zones followed by low pressure zones, with pressure differences ranging from 500 psi to 3600 psi (static). The operator planned to drill six bi-lateral wells through these interbedded high and low pressure zones. Five out of these six wells were unsuccessful and had to be side-tracked with only one lateral drilled at the end of each well. It was decided that a novel approach was required to overcome these field difficulties. Success had been previously achieved when depleted zones were drilled in the Brent field in the North Sea by utilising graphite (figure 1) as a bridging material and laboratory tests were initiated to utilise this approach (Davison et al1). The addition of graphite to the mud strengthened the reservoir rock, enabling it to remain stable despite an overbalance beyond the point at which physical failure had previously occurred in offset wells. The advantage of using graphite over carbonate bridging materials is its deformability. This allows it to create a much more effective pressure seal in the throats of fractures, thus preventing fracture propagation and subsequent failure. This effect is illustrated in figure 2 and was commented on by J. Adachi et al 2 in their study into depleted zone drilling. In a previous joint industry project reported by Aston et al3, the study produced results that pointed towards calcium carbonate and graphitic blends as one of the best ways to reduce mud losses into fractures. A synergy effect is created by having the deformable graphite in conjunction with the sized calcium carbonate, thus enabling a large range of fracture sizes to be bridged, and also allowing the sealing of fractures that change in dimension as downhole pressures are altered during the drilling process. It was believed that by introducing a highly efficient filtrate reducer, this effect could be further enhanced.
A major operator has initiated the data-acquisition campaign in the southern North Sea for a future storage facility capable of holding 5 billion m 3 of gas. It is estimated this venture will double the existing gas supplies stored in the UK and represent more than 5% of its annual gas demand. As North Sea gas production decreases and the UK becomes more dependent on imports, the ability to store gas has become an important part of the UK energy policy.Drilling into depleted reservoirs for gas storage produces several major technical problems and issues that must be addressed. This field is a pressure-depleted reservoir with a differential pressure equivalent to 7.3 lbm/gal between the drilling fluid's hydrostatic pressure and the reservoir pressure. This differential must be controlled to eliminate the risk of differential sticking, downhole losses, and hole collapse.Because of the reservoir depletion, it would be impossible to backflow and clean up the near-wellbore region without a postdrill-in treatment fluid to remove the fluid filter cake and waterwet all the surfaces for gas injection. To ensure project success and usable fluid designs, reservoir conditions were simulated in the laboratory and fluid parameters were altered to provide the optimum properties to minimize the future risks.The paper discusses in full the laboratory design process, the verification of the drill-in and treatment fluids as being fit-forpurpose, and their successful application in the field. Initial well testing suggested that the expected injection rates of 500 scf/min at 300 psi were exceeded, with rates of 750 scf/min at 280 psi reported.Stephen Vickers is the Eastern Hemisphere Applications Engineering Manager at Baker Hughes, where he has worked since 2001. His main area of interest is drill-in fluid design with emphasis on minimizing fluid induced formation damage. He studied quarry and mining engineering at the Doncaster School of Mining and Mineral Resources.Stephen Bruce is a fluids service representative for Norway Operations for Baker Hughes. He studied chemistry at State University of New York at Binghamton and oilfield chemistry at RGU.Alistair Hutton is a technical sales representative for UK Operations for Baker Hughes. He studied chemistry at Aberdeen University and software technology at RGU.Paolo Nunzi is a well operations manager for Eni UK. He has been with Eni E&P for more than 25 years. He served as an engineer for 8 years in several different countries, primarily in northern Africa, northern Europe, and CIS. He holds an MS degree in mining engineering.
Historically, wells drilled on the Machar Field in the North Sea have experienced huge downhole losses and remedial techniques to stem losses have been marginally successful. One well experienced oil-based mud (OBM) losses exceeding 26,000 bbl. Furthermore, the massive losses of oil-based mud had threatened the future of this project.A new phase in the development of the field was planned that entailed drilling two producers and one injector well that would be tied to an existing subsea manifold, which in turn would connect to the production platform. A drilling fluid formulation was requested that would bridge off the wide range fracture widths and stop the massive ingress of well fluids, especially in the reservoir where back-flow would be hindered and remediation difficult.The design and successful application of a fit-for-purpose drilling fluid system to deal with highly fissured limestone of varying fracture widths was a key planning element for the new Machar Field drilling campaign. The knowledge gained from drilling fractured formations in the Middle East and the experience using stress cage principles in depleted reservoirs of the Southern North Sea have been adapted to successfully drill and seal limestone formations and prevent damaging losses. This paper will discuss the drilling fluids design process and the laboratory testing used to predict the bridging and sealing efficiencies needed to seal fractures ranging from 50 to 1000 microns. Testing was conducted using formulations with different materials of varying size, shape and resilience. The basis of design and knowledge gained in the laboratory was transferred to the field where losses were dramatically reduced to only six bbl in the 6-in. section. The first well was successfully flowed at the production target level and the second well surpassed the expected production index by a factor of three.
A major operator has initiated the data acquisition campaign in the Southern North Sea for a future storage facility capable of holding 5 billion m3 of gas. It is estimated this venture will double the existing gas supplies stored in the UK and represent over 5% of its annual gas demand. As North Sea gas production decreases and the UK becomes more dependent on imports, the ability to store gas has become an important part of the UK energy policy. Drilling into depleted reservoirs for gas storage produces several major technical problems and issues that must be addressed. This field is a pressure-depleted reservoir with a differential pressure equivalent to 7.3 lb/gal between the drilling fluid's hydrostatic pressure and the reservoir pressure. This differential must be controlled to eliminate the risk of differential sticking, downhole losses, and hole collapse. Due to the reservoir depletion, it would be impossible to backflow and clean up the near-wellbore region without a post drill-in treatment fluid to remove the fluid filter cake and water-wet all the surfaces for gas injection. To ensure project success and usable fluid designs, reservoir conditions were simulated in the laboratory and fluid parameters were altered to provide the optimum properties to minimize the future risks. The paper discusses in full the laboratory design process, the verification of the drill-in and treatment fluids as being fit-for-purpose, and their successful application in the field. Initial well testing suggested the expected injection rates of 500 scf/min at 300 psi were exceeded, with rates of 750 scf/min at 280 psi reported.
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