This paper describes the development and application of a laboratory procedure for the evaluation of screens for sand control. The driving force for this study was to provide an independent evaluation of all screens on the market, in particular, the new generation of premium screens. The test addresses both aspects of screen performance, namely sand retention efficiency and plugging potential. The difficulties in setting up such a test are discussed, with particular attention paid to the elimination of experimental artefacts. Some of the pitfalls that may be encountered in laboratory evaluation of screens are highlighted. The developed method has been used in screen selection tests for a particular field, and these results are also presented. The data illustrate the sensitivity of the technique for evaluating a range of screens on the same sand, and reasons for the differences in screen performance are explored. Furthermore, it was observed that the method of particle size analysis will affect the apparent particle size distribution of a sand. As a result such parameters as the uniformity coefficient may be completely different for the same sand depending on the method of size measurement.
Owing to the narrow drilling margin that exists between the pore pressure and fracture pressure gradients, drilling in depleted reservoir, HPHT and deep water environments is universally recognized as being technically challenging.A number of field techniques are available for mitigating against many of the drilling problems encountered. Included amongst these are specialized fluid engineering that involve use of chemical-and particulate-based treatments for minimizing or preventing losses. In many instances these techniques can be used to strengthen or stabilize the wellbore when drilling on or near the fracture gradient thereby potentially eliminating the need for intermediate casing strings.This paper discusses particulate-based treatment design for sealing fractures. Substantial experience gained from innovative laboratory testing has highlighted the mechanisms and many factors that determine the effectiveness of the fracture seal. The particle size distribution relative to the fracture aperture, particle morphology, volumetric concentration, fluid rheology and fluid-loss-control influence whether the seal is established within the fracture or at the fracture mouth. Understanding this distinction is important with respect to selecting the optimum treatment and its application for given field conditions. Parameters critical for optimizing the treatment have been identified and are discussed in the context of laboratory and field experience.
Owing to the narrow drilling margin that exists between the porepressure and the fracture-pressure gradient, drilling in depletedreservoir, high-pressure/high-temperature, and deepwater environments is universally recognized as being technically challenging.A number of field techniques are available for mitigating many of the drilling problems encountered. Included among these are specialized fluid engineering that involves the use of chemical-and particulate-based treatments for minimizing or preventing losses. In many instances, these techniques can be used to strengthen or stabilize the wellbore when drilling at or near the fracture gradient, thereby potentially eliminating the need for intermediate casing strings.This paper discusses particulate-based-treatments design for sealing fractures. Substantial experience gained from innovative laboratory testing has highlighted the mechanisms and many factors that determine the effectiveness of the fracture seal. The particlesize distribution (PSD) relative to the fracture aperture, particle morphology, volumetric concentration, rheological properties of the fluid, and fluid-loss control influence whether the seal is established within the fracture or at the fracture mouth. Understanding this distinction is important with respect to selecting the optimum treatment and its application for given field conditions. Parameters critical for optimizing the treatment have been identified and are discussed in the context of laboratory and field experience.
A unique oil-based drilling fluid system weighted with treated micronized barite (TMB) slurries has been developed and successfully introduced to the field. The utilization of this weight material provides the fluid system with low viscosity, reduced torque values, superior sag stability thus giving a fluid with low Equivalent Circulating Density (ECD) contribution and excellent hydraulics performance. These exceptional fluid characteristics make the fluid system an excellent solution for drilling sections with narrow mud-weight windows, coiled tubing operations, managed pressure drilling and extended reach drilling. Many of these drilling challenges are encountered in high-temperature, high-pressure (HTHP) and ultra-deepwater field developments and in depleted, mature fields. Much of the early fluid system development focused on design, the system's physics and chemistry, and the optimization of mineralogy of the weighting agent. Also of concern was the variability of results seen both from return permeability as well as from standard fluid-loss experiments. On this basis a comprehensive study was undertaken to identify and understand the damage mechanisms operating in the formation and filter cake. During this period the fluid system was used in a number of operations in the North Sea such that the current available database includes 5 different types of field applications. The paper presents the findings of the formation damage study including relevant productivity data from the various field applications. The results demonstrate that while invasion of the formation by treated micronized barite can occur, it does not necessarily lead to permanent productivity impairment. Furthermore, the micronized barite does not interfere with the added fluid-loss-control material over a wide range of fluid densities and formation permeabilities. The authors discuss the processes observed relating them to current field experience describing why the formation damage mechanisms do not concur with previous preconceptions and moreover describes where the limitations of the system occur. Introduction The paper summarizes field experiences and a collection of formation damage studies to identify and understand the damage mechanisms that may arise from the use of an oilbased drilling fluid weighted with Oil-Based Treated Micronized Barite (OB TMB). Typically productivity impairment by oil-based drilling fluids arises due to poor fluid-loss control whereby drilling fluid filtrate and occasionally fine drill solids, emulsifiers and other additives that may modify wettability or that may be incompatible with the reservoir fluids enter the near wellbore formation and reduce the permeability. In many of these cases, the poor fluid-loss control is a result of the suboptimal design of the bridging material that allows ingress of fluid through an unnecessarily permeable filter cake. In the case of treated micronized barite, the weighting material has a particle size distribution of 0.01 - 5µm. This means that the barite particles are so fine that they act as part of the fluid filtrate rather than as a separate solids phase. As such, if the filter cake is insufficiently impermeable then the micron-sized particles may penetrate with the fluid filtrate and enter into the formation. This then naturally poses the question of whether this leads to permanent damage and impairment of permeability. To address this issue, the paper presents field experience from a number of North Sea field operations in combination with the results from relevant laboratory formation damage studies. Together the data is used to identify and describe potential damage mechanisms, how they occur, and how they can be avoided through good fluid engineering design. Treated Micronized Barite Technology (TMB) A unique oil-based drilling fluid system weighted with treated micronized barite (TMB) has been developed and successfully introduced to the field. The specially treated barite weighting material has a particle size distribution of 0.01 - 5µm with a mean value less than 2 µm. It is typically supplied in the form of a 2.3-sg (19-lb/gal) liquid concentrate (slurry) and is blended into the base oil to give the required mud weight.
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.
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