This paper summarises the results of extensive laboratory work carried out in recent years to determine the performance of a number of experimental and commercially available lubricants for reservoir applications. The laboratory work included a series of tests to determine formation damage potential in both completion brines and low-solids, water-based reservoir drilling fluids, as well as reduction in friction coefficient. The testing to evaluate formation damage potential included brine miscibility, greasing and emulsion formation potential, as well as return permeability testing on outcrop sandstone. Introduction In recent years, improvements in equipment and fluids have allowed extended reach wells to be drilled to and beyond limits that were unthinkable previously. Environmental and technical requirements can make water-based reservoir drilling fluids the preferred option. Good drilling practices and the inherently thin filter cake and lubricious nature of the polymer additives of low-solids, brine-based reservoir drilling fluids can reduce the torque and drag values associated with water based fluids.1 However, in many cases, an additional chemical lubricant is required to drill these extended reach wells to total depth. The choice of the correct lubricant for water-based reservoir drilling and clear brine completion fluids is primarily driven by technical performance and environmental restrictions. In the last few years, increasingly strict environmental legislation imposed in many parts of the world has changed the choice of chemistries utilised for water-based fluid lubricants. Whereas hydrocarbons and fatty acids previously constituted the majority of effective additives, there has been a move towards more environmentally acceptable alternatives, such as esters and naturally occurring vegetable oils. These chemical families are a source of highly lubricious materials that can significantly reduce metal-to-metal and metal-to-rock coefficients of friction in water-based fluid environments, in some cases by as much as 70% in laboratory tests. Typically, the most effective additives have a relatively high degree of surface activity, which improves their adhesion to materials (i.e. metal casing or drilling mud solids), and so enhances the lubricity of the surface. However, this surface activity makes them more capable of reacting with other components of the fluid - whether deliberately added, or present as a contaminant. For example, many effective water-based fluid lubricants may act as an emulsifier in the presence of even small quantities of oil. Under moderate shear conditions, the combination of oil, lubricant and brine can produce an ultra low oil:water ratio invert emulsion with the consistency of cottage cheese. This highly viscous material is at best a drilling hazard, stripping lubricant from the fluid and possibly blinding shaker screens. At worst, the ‘cheese’ may damage the production zone or plug the completion assembly, particularly where sand screens are applied. Another potential problem is the reaction between the lubricant and divalent ions, resulting in the formation of a grease-like precipitate. Depending on the chemical nature of the lubricant, this ‘grease’ may be formed with relatively low concentrations of calcium or magnesium ions, in some cases with concentrations as low as 1000 mg/L, which may easily be encountered in freshwater or monovalent salt fluids while drilling. The potential consequences of the formation of this grease are similar to those of the creation of the ‘cheese’-like emulsion. These issues need to be addressed when selecting suitable lubricants for water-based drilling fluids - most importantly those used for drilling reservoir in order to prevent fluid related formation damage.2 In addition, the effect of the lubricant on the reservoir fluids needs to be evaluated, in case of any interaction with lubricant in the filtrate.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractSelecting the components of fluids for reservoir drilling and completion can require extensive laboratory work to determine the most compatible fluid. Well temperatures in excess of 300°F (150°C) create additional challenges, as the additives required to give water-based reservoir drilling fluids the rheological and fluid-loss characteristics needed to successfully drill and complete long horizontal wells degrade at such elevated temperatures. In addition, supplying the necessary additives to a drilling operation in a remote location can be a major logistical burden, leading to a compromise in the fluid formulation.The Belanak field lies off the coast of Indonesia in the Natuna Sea. The reservoir temperature is high (315°F), and the reservoir sections are drilled horizontally, typically between 3,500 and 4,500 ft and often feature particularly tortuous well paths. A low-solids, brine-based reservoir drilling fluid was required because the wells use premium screens for sand control.Six wells were drilled using the sodium formate-based reservoir drilling and completion fluids. The particle size distribution and concentration of the calcium carbonate bridging solids were monitored closely while drilling to ensure that filter cake quality was not compromised. A chelating agent-based breaker was used to break down the filter cake prior to the onset of production.The laboratory work required to optimize the fluids for this project had to take into account not only the requirements for the best fluid technically, but also the effect of the limitations created by working in a remote location. Considerations included minimum loading of calcium carbonate required to deposit a clean, high-quality filter cake and the effect of mixing brine for the reservoir drilling fluid or completion using seawater in case of a shortage of drill water.Fluid testing carried out in the laboratory included drilling performance at temperature, fluid compatibilities, bridging solids optimization, scale inhibition testing, and breaker selection. The fluid selected was based on sodium formatethe first application of a formate-based fluid in Indonesia.

fax 01-972-952-9435. AbstractHistorically, wells drilled in East Africa and mainly in Sudan have experienced drilling related problems due to the highly reactive and dispersive shales of the Aradeiba formation. Hole instability problems have included washed out hole sections combined with tight hole and poor coring efficiency. Frequent wiper trips were required and logging of the wells was not always successful.Over time, several conventional inhibitive water-based drilling fluid types have been used, such as KCl/polymer, KCl/lime/polymer, KCl/PHPA, and KCl/glycol, but with only marginal improvements in hole stability and drilling performance. A sodium silicate/KCl system was designed to provide the necessary inhibitive qualities. The first field trial well in East Africa was drilled with a sodium silicate/KCl system and the following benefits were observed:• 24% reduction in drilling days • Shale drill cuttings with exhibited excellent integrity • No evidence of cuttings hydration or dispersion • Reduced wiper trips • Caliper logs indicated in-gauge wellbore • Logging program completed as per program • Excellent coring efficiency • Low filtrate invasion This paper describes the extensive technical teamwork between the service company and the operator that led to the development and successful application of a sodium silicate drilling fluid for use in the Aradeiba stressed shale sections.The paper includes a description of the formulated silicate fluid and test data from the extensive laboratory testing.Enhancements in drilling and coring performance over other inhibitive water-based drilling fluid systems are documented and reviewed, in particular coring efficiency (hole stability in the shale zones, elimination of core jamming) and improved core data acquisition (obtaining fresh-state core samples with minimal mud filtrate invasion).As a result of this fluid design and application, an additional thirty wells have been drilled with the sodium silicate system in the area, including the highest temperature well ever drilled in the world with a silicate drilling fluid.

Over the last decade, the challenge of drilling narrow Equivalent Circulating Density (ECD) window wells has put increasing pressure on the performance of the drilling fluid. As a result of this, so-called ‘Fragile Gel’, or ‘Flat Rheology’ fluids have been developed by the industry and have become widely utilised across the globe. Although the design of these fluids is primarily aimed at optimising performance in deepwater environments, the lower pressure fluctuations imposed on the formation (as compared to more conventional invert emulsion fluids) that is attributed to these fluids has contributed to their increased use in other, non-deepwater areas, where ECD management is still viewed as critical. Although the perceived benefits are now widely understood and accepted, the industry has not yet developed a comprehensive and universally-accepted benchmark for the properties that satisfactorily define these fluids. The authors of this paper believe this to be due to a number of factors, including the different approaches taken within the service industry in developing chemistries that either significantly reduce, or even completely replace, the requirement for conventional organophilic clay-based viscosifiers. BP have developed an internal set of guidelines based on operational experience in regions where these fluids have been successfully implemented; however, these have limitations when universally applied, particularly as new fluids featuring novel chemistries are introduced. This paper discusses the key engineering parameters used to define the engineering guidelines for what BP refers to as ‘Flat Rheology Fluids’. A description of these parameters and how data collected from recent field trials in Norway is being used to help refine and validate these parameters is also described.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper presents a case history of the completion procedures applied to a four-well gas reservoir development in the Norwegian sector of the North Sea where open-hole gravel packing was utilized as the sandface completion technique.The chosen technique to gravel pack the wells was based upon Alternate Path Technology, which incorporates shunt tubes with nozzles on the outside of the gravel pack screen. These shunts create an alternative flow path, allowing slurry to bypass premature bridging and fill any voids beyond the bridge. The use of shunt tubes gives the opportunity of achieving a complete gravel pack without the requirement of a filtercake-sealed wellbore. This introduces the possibility for the filter cake to be removed during the packing operation. As a result, a low-solids drilling fluid that deposits a chemically degradable filter cake can be utilized.The reservoir pressure in this field required relatively highdensity, reservoir drilling and gravel pack fluids (1.65 SG / 13.75 lb/gal). This paper describes the design and development work involved in formulating a mutually compatible, calcium bromide-based reservoir drilling fluid and a Viscoelastic Surfactant (VES) based gravel pack fluid and the subsequent successful application in a subsea field development.