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.
Completing offshore horizontal wells often requires killing the wellsimmediately after perforating before pulling the gun out of the hole andinstalling the rest of the completion hardware.Perforating practicevaries from operator to operator. Some operators prefer to perforate in a clearfluid and spot a kill fluid for well control afterwards.While othersperforate directly in a solid containing kill fluid.Both methods are donein overbalance. A two-year extensive research program was carried out toquantify the formation damage caused by these perforating practices. The testing was conducted under downhole conditions in a large-scalelaboratory setup, which physically simulates the wellbore and the reservoir, aswell as the perforating and production processes. Tests were designed to studythe pressure dynamics during perforating; to gain understanding of the effectof the perforating pressure dynamics on fluid loss control and formationdamage; to select the most suitable kill fluid; and finally to provideoverbalanced perforating design guidelines for production optimization. The core test results showed that perforating design not only determines theskin damage caused by debris and grain crushing, but also plays a key role incontrolling fluid loss, which strongly influences the permeability andproductivity of the reservoir. Therefore, proper perforating design not onlyinvolves selecting the right shaped charges and gun hardware, but also it needsto take into account the perforating pressure dynamics, fluid formulation, andcompletion sequence. In addition to the core flow testing, petrographic studies were performed onthe perforated core samples to allow visual observation of the rock alterationscaused by perforating and kill fluids. This paper presents the findings in formation damage mechanisms duringoverbalanced perforating and kill processes and provides recommended practicesin both job design and fluid selection for this type of operation in longhorizontal wells. Introduction Conventionally there are two major techniques in completing long horizontalwells.One calls for underbalanced operation, in which the uppercompletions are already installed before running gun to depth andperforate.The well is controlled on surface after perforating and duringthe gun retrieval.This is believed to create less formation damagebecause the entire completion process is conducted underbalanced.However, cost and time of the operations are of concerns to manyoperators.Besides, this completion procedure may not be feasible at allin some situations due to the capacity of the required hardware.The othertechnique calls for overbalanced operations which requires killing the wellsafter perforating to maintain well control while retrieving the gun andinstalling the completion system. This perforating process is often referred asshoot-and-pull.Some operators prefer to run shoot-and-pull perforating ina thoroughly cleaned wellbore environment filled with clear completion brine tominimize formation damage.A specially formulated pill is then spotted tokill the well afterwards.During the kill process, the completion brine isdisplaced into the formation, causing undesirable formation damage in acarefully perforated wellbore[1].Hence the concern for this overbalancedoperation is its productivity impairment potential.
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