Due to an increased understanding of the effects of formation damage, it has become commonplace to test the damage potential of drilling fluids with reservoir core, prior to drilling. This preventive approach has shown to be more effective than neglecting pre-drilling laboratory testing. However, the current approaches are lacking in many areas. Through research, as part of an E.U. funded project, well productivity 2002, a standard procedure for testing the formation damage of drilling fluids has been developed. The research provides a number of explanations as to why previous "round robin" studies display large variations in results between laboratories. False ranking of drilling fluids and formations were subsequently produced due to the varied procedures currently used. Explanations and solutions are specified in order to allow future testing to be repeatable in any laboratory and most importantly, representative of the wellbore situation. The result of the research is a cost-effective procedure, which can be scaled to the reservoir after testing. Although the laboratory equipment used is not greatly different from that used in many laboratories, there are procedural changes. These changes allow accurate testing and ranking of formation damage potential. The results detail representative fluid application, basic fluid ranking procedures and a more advanced investigative procedure, which determines type and extent of damage expected from the formation and fluids. Additions to these procedures allow for the testing of solid and chemical completions, to provide a strong tool for well planning. The research was part of Work Package 1 of the E.U. project "Well Productivity 2002" and the recommended methods are already being used in a number of reservoir studies. It is intended to present future work using these methods, in parallel with well data. Introduction The existence of formation damage is the existence of lost revenue. To reduce or prevent formation damage is to control that loss of revenue. One approach that has come to the forefront of formation damage prediction and mitigation is to utilise core analysis. Recent studies have shown that preventative formation damage testing, using representative core and reservoir conditions of temperature and pressure, have proved successful (Watson et al1). Previous recommended practices have attempted and failed to allow an acceptable level of repeatability (Marshal et al2). It is our suggestion that the relevance of the conditions in the wellbore should first be determined. In our research we examined the ability of the formation damage test to represent the conditions present in the wellbore in terms of:Filtrate loss control propertiesCake developmentDamaging mechanismsReturn permeability The intention is for a further publication to examine well data in comparison to laboratory work, utilising different fluid compositions and rock lithologies. Methodology Core Material Blaxters sandstone was selected as representative of a medium permeability North Sea reservoir. Blaxters is medium grained sandstone with framework grains of predominantly quartz and also mica. An open macro-pore network was present. Abundant kaolinite clay cement partially fills intergranular pores, which increases the relative proportion of microporosity. The occurrence of abundant crystal faces of quartz suggests that extensive precipitation of quartz cement has taken place at the surface of quartz grains (overgrowths). Long needles of illite were occasionally observed.
The newly developed high-temperature high-pressure (HPHT) exploration oil-based reservoir drill-in fluid (RDF) was specifically designed with formation damage, pressure logging and geochemical analysis in mind. Requirements for a reservoir drill-in fluid that performs well under HPHT conditions, has good pressure log response and is geochemically distinguishable from reservoir fluids were the driving forces for the development of this system. The high-performance, low-damaging system combines several new products. Laboratory results have shown good rheology profiles, tight HPHT fluid loss control, high return permeability values and excellent long-term fluid stability. The system was developed to replace today's standard paraffin systems which occasionally struggle with irregular and too high viscosities with poor fluid stability over time. This occasionally leads to various drilling issues and barite sag problems during low shear or static conditions. Laboratory testing has documented the qualities of the new system, followed by a very successful field trial, where low impact on geochemical tests was obtained. This paper details the development of the fluid, the testing performed to qualify it for the field trial and the successful results from that field trial. Furthermore, the paper also details the high return permeability values and the mechanisms within the system that allow these goals to be achieved. The fluid has properties that make it an extremely strong candidate for reservoir drilling in general.
Valemon, operated by Statoil, is a high-pressure/high-temperature (HP/HT) gas/condensate field on the Norwegian Continental Shelf. Production started at the beginning of 2015 from a development consisting initially of cased-and-perforated wells. However, during early field development, the orginal concept was for a standalone-screen (SAS) lower completion. A potassium/cesium (K/Cs) formate water-based system with a density of 2.02 specific gravity (sg) was considered as a candidate drilling-and-completion fluid for the wells completed with screens, one of which could potentially be suspended in formate brine for up to 10 months before the arrival of the platform and before cleanup and the onset of production. An unknown was the possibility for any near-wellbore interaction with these fluids during extended contact and the possible detrimental impact on productivity. Computational-fluid-dynamics (CFD) modeling was performed to determine the length of time formate would be in contact with the near wellbore, demonstrating that, especially for the lower-permeability intervals, a contact time of approximately 45 days was a possibility. In light of this, a sequence of corefloods was performed that involved extended soaks in formate along with preand post-test analyses to identify potential damage mechanisms. Those identified included kaolinite dissolution, precipitation of barium and cesium silicate, and swelling of kaolinite because of the incorporation of potassium and cesium into the kaolinite lattice. To confirm the findings from the CFD and coreflood modeling, a field review was made of Statoil's experiences with suspending wells for extended time in formate before cleanup and production. The field review demonstrated positive experiences in the use of formates in suspended wells with respect to productivity. Lower than expected productivity was experienced for some wells, but this could not be related conclusively to the use of formates. This paper provides an overview of lessons learned from coreflooding, CFD modeling, and actual field data on wells suspended in formate before cleanup and production.
Numerous papers have been published on the influence that kaolinite mobilization has on well productivity. However, less attention has been directed toward identifying methods to minimize the detrimental impact of this mobilization. This paper will detail the pro-active approach that the authors took in engineering solutions to enhance oil productivity by reducing kaolinite mobilization. Specifically the paper will focus on the experiences from Oseberg Sør (North Sea). Significant formation damage has been attributed to kaolinite mobilization in this field. This damage can occur at any stage within the well lifetime from initial drilling and through the production lifecycle. SPE 107758 provided details of a unique chemical that can be incorporated into scale inhibitor squeeze treatments to reduce kaolinite mobilization while a well is in production. This paper will focus on the development of smart mud filtrate technology that incorporates kaolinite fixation agents that minimize clay mobilization within the near wellbore during drilling. Introduction There are countless ways to cause formation damage; however the most difficult mechanisms to prevent are those which are caused by a combination of the nature of the reservoir and production from that reservoir. These mechanisms can be considered "natural" and affect productivity whether the drilling and completion fluids are present or not. Examples of "natural formation damage" are organic and inorganic precipitation resulting from a reduction of pressure in the near-wellbore region1 or the migration of native fines towards the wellbore and subsequent plugging of pores. Fines migration and in particular the issue of kaolinite fines migration, causing formation damage, is described extensively in the literature.2,3,4 In answer to the problem highlighted here and in the 2007 paper by Fleming et al.,5 we have extensively researched the issue of formation damage created by kaolinite fines and have designed an advanced drilling fluid filtrate to combat this problem. The filtrate is designed to treat the near-wellbore area even before and during the penetration of the specific depth by the drill bit. This early treatment of the formation is intended to stabilize the fines in the near-wellbore area before they have a chance to migrate. The treatments are designed to prevent the migration of kaolinite during production. A significant development in the study of treating kaolinite migration in the Oseberg Sør formations was the realisation that it is oil flow causing the most significant migration in these formations. The reason for this is that the fines range from mixed wettability to oil-wet. Theory A number of return-permeability tests have previously been performed on Oseberg Sør core material from the Ness, Middle & Upper Tarbert and Upper Jurassic formations in a number of different laboratories. A common damage mechanism was noted throughout the core floods. The mechanism was migration and plugging of pores by kaolinite clay particles even at very low flow rates. Evidence for fines migration was observed both in the increasing differential pressure during steady state dead crude oil flooding of the core plugs @ Swi and in post-test geological analysis (SEM, Cryogenic SEM and thin section). An indication of the mechanism was also highlighted in SPE 107758 where a squeeze treatment provides a marked increase in production which then declines with continued oil production. Semi-quantitative mineral analysis in the form of X-Ray Diffraction (XRD) was performed on the core material and displayed approximately 15% kaolinite. Muecke15 explained that fine particles tend to remain in phases that wet them. This was taken into account when the cores were found not to display fines migration during water flooding, as the flowing water could not migrate the oil coated fines, but crude oil did during oil flooding.
Reservoir drilling and completion fluids are affected by temperature. Fluids that perform well at one temperature range can experience major problems at higher temperature ranges. A series of studies have been conducted over the last four years looking in detail at the effect of reservoir drilling fluid design for high-temperature, high-pressure (HTHP) reservoirs, with significant developments in the understanding of the role of fluid loss additives. The focus of these studies was to reduce and control formation damage, in addition to allowing efficient drilling and effective logging of exploration wells. This paper reviews and explains the findings of these investigations and the significance on past and future reservoir exploration and drilling operations.The studies were all required to assist in a number of specific drilling campaigns where logging of reservoir pressures was planned or had been performed and was believed to be influenced by formation damage. The investigations were initiated with sufficient time to allow hundreds of formulations to be tested with regards to drilling properties, stability and formation damage.Very distinctive improvements in HTHP return permeability and filter cake thickness were obtained, which was accompanied by logging success. The most notable controlling factor of return permeability under HTHP conditions was determined to be the fluid loss additive. The selection and quantity of fluid loss additive was so significant that it alone could vary the return permeability by more than 80%.The findings from these investigations have been put to practical use in a number of exploration wells where pressure measurements have been taken with great success. One notable investigation focused on a formulation used 10 years ago on a reservoir where pressure measurements could not be taken. The reservoir was abandoned until recently due to the apparent lack of pressure. This paper details the problems encountered and the results of the investigation in addition to the techniques used to prevent similar problems occurring again. IntroductionDrilling fluids are designed to ensure that rotary drilling of subterranean formations is possible and economically viable. As well as carrying cuttings to surface, cooling and cleaning the bit, reducing friction, maintaining wellbore stability and preventing pore fluids from prematurely flowing into the wellbore, drilling fluids are designed to build a filter cake. The filter cake is intended to reduce filtrate loss to the formation, be thin, and hold the drilling fluid in the wellbore. Two components of the drilling fluid are specifically designed to assist in the development of a desirable filter cake: 1) Bridging particles which have a specific size range to create a solid framework for the filter cake 2) Fluid loss additives which are designed to create deformable particles to fill small gaps and improve the seal The design of the drilling fluid when drilling the reservoir section of a well is particularly important. In the reservoir section the ...
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