|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Bentonite is not typically used as the primary fluid-loss agent in normal-density slurries. In low-density slurries, where higher concentrations can be used, it may provide sufficient fluid-loss control (400 to 700 cm 3 /30 min) for safe placement in noncritical well applications. Fluid-loss control, obtained through the use of bentonite, is achieved by the reduction of filter-cake permeability by pore-throat bridging. Microsilica imparts a degree of fluid-loss control to cement slurries because of its small particle size of less than 5 microns. The small particles reduce the pore-throat volume within the cement matrix through a tighter packing arrangement, resulting in a reduction of filter-cake permeability.
Remedial cementing requires as much technical, engineering, and operational experience, as primary cementing but is often done when wellbore conditions are unknown or out of control, and when wasted rig time and escalating costs force poor decisions and high risk. Squeeze cementing is a "correction" process that is usually only necessary to correct a problem in the wellbore. Before using a squeeze application, a series of decisions must be made to determine (1) if a problem exists, (2) the magnitude of the problem, (3) if squeeze cementing will correct it, (4) the risk factors present, and (5) if economics will support it. Most squeeze applications are unnecessary because they result from poor primary-cement-job evaluations or job diagnostics. Squeeze cementing is a dehydration process.
Perhaps the most common formation damage problem reported in the mature oil-producing regions of the world is organic deposits forming both in and around the wellbore. These deposits can occur in tubing, or in the pores of the reservoir rock. Both effectively choke the flow of hydrocarbons. Table 1 shows the gross composition of crude oils, tars, and bitumens obtained from various sources. It is evident that crude oils contain substantial proportions of saturated and aromatic hydrocarbons with relatively small percentages of resins and asphaltenes.
Introduction Any unintended impedance to the flow of fluids into or out of a wellbore is referred to as formation damage. This broad definition of formation damage includes flow restrictions caused by a reduction in permeability in the near-wellbore region, changes in relative permeability to the hydrocarbon phase, and unintended flow restrictions in the completion itself. Flow restrictions in the tubing or those imposed by the well partially penetrating a reservoir or other aspects of the completion geometry are not included in this definition because, although they may impede flow, they either have been put in place by design to serve a specific purpose or do not show up in typical measures of formation damage such as skin. Over the last five decades, a great deal of attention has been paid to formation damage issues for two primary reasons: (1) the ability to recover fluids from the reservoir is affected very strongly by the hydrocarbon permeability in the near-wellbore region, and (2) although we do not have the ability to control reservoir rock properties and fluid properties, we have some degree of control over drilling, completion, and production operations. Thus, we can make operational changes, minimize the extent of formation damage induced in and around the wellbore, and have a substantial impact on hydrocarbon production. Being aware of the formation damage implications of various drilling, completion, and production operations can help in substantially reducing formation damage and enhancing the ability of the well to produce fluids. On this page, we discuss methods to measure and to quantify the extent of formation damage and provide criteria that can be used to identify various types of formation damage. The goal is to define the mechanisms involved better so that an operator can recommend and design the correct remedial action and/or make changes to drilling, completion, and production operations to minimize damage in the future. It is generally true that, whenever possible, preventing formation damage is more effective than remedial treatments such as acidizing and fracturing. We do not discuss such treatments in this chapter. However, for each type of damage mechanism, potential remedial treatments are suggested. It is evident that, to quantify formation damage and to study its impact on hydrocarbon production, one must have reasonable estimates of the flow efficiency or skin factor. Several methods have been proposed to evaluate these quantities for oil and gas wells.
Deposition of the high-molecular-weight components of petroleum fluids as solid precipitates in surface facilities, pipelines, downhole tubulars, and within the reservoir are well-recognized production problems. The deposits also can contain resins, crude oil, fines, scales, and water. Asphaltenes and waxes are a general category of solids and, thus, cover a wide range of materials. Understanding the fundamental characteristics that define the nature of asphaltenes and waxes is valuable in reducing or avoiding the production impacts of their deposition. This page examines the general chemical classifications and types of asphaltenes and waxes, in addition to their solidification behaviors.
Abstract During a drilling operation, rock cuttings are often sampled off a shale shaker for lithology and petrophysical characterization. These analyses play an important role in describing the subsurface; and it is important that the depth origin of the cuttings be accurately determined. Traditionally, mud-loggers determine the depth origin of the sampled cuttings by calculating the lag time required for the cuttings to travel from the bit to the surface. These calculations, however, can contain inaccuracies in the depth correlation due to the shuffling and settling of cuttings as they travel with drilling fluid to the surface, due to unplanned conditions like drilling an overgauge hole, and due to other unforeseen drilling events, especially critical in horizontal sections. We therefore aimed to remedy these inaccuracies by developing a series of styrene-based nanoparticles that tagged the cuttings as they were generated at the drillbit. These “NanoTags” were tested while drilling in Q4, 2019; and the results indicated that the NanoTags did in fact have the potential to identify some systematic errors compared with traditional mud logging calculations.
Abstract Fluid saturation data obtained from core analysis are used as control points for log calibration, saturation modeling and sweep evaluation. These lab-derived data are often viewed as ground-truth values without fundamentally understanding the key limitations of experimental procedures or scrutinizing the accuracy of measured lab data. This paper presents a unique assessment of sponge core data through parameterization, uncertainty analysis and Monte-Carlo modeling of critical variables influencing lab-derived saturation results. This work examines typical lab data and reservoir information that could impact final saturation results in sponge coring. We dissected and analyzed ranges of standard raw data from Dean-Stark and spectrometric analysis (including, gravimetric weights, distilled water volumes, pore volumes and sponge’s absorbance), input variables of fluid and rock properties (such as, water salinity, formation volume factors, plug’s dimension and stress corrections), governing equations (including, salt correction factors, water density correlations and lab mass balance equations) and other factors (for instance, sources of water salinity, filtrate invasion, bleeding by gas liberation and water evaporation). Based on our investigation, we have identified and statistically parameterized 11 key variables to quantify the uncertainty in lab-derived fluid saturation data in sponge cores. The variables’ uncertainties were mapped into continuous distributions and randomly sampled by Monte-Carlo simulation to generate probabilistic saturation models for sponge cores. Simulation results indicate the significance of the water salinity parameter in mixed salinity environments, ranging between 20,000 to 150,000 ppm. This varied range of water salinity produces a wide uncertainty spectrum of core oil saturation in the range of +/- 3 to 10% saturation unit. Consequently, we developed two unique salinity variance models to capture the water salinity effect and minimize the uncertainty in the calculation of core saturation. The first model uses a material balance to solve for the salinity given the distilled water volume and gravimetric weight difference of the sample before and after leaching. The second model iteratively estimates the salinity required to achieve 100% of total fluids saturation at reservoir condition after correcting for the bleeding, stress and water evaporation effects. Our work shows that these derived models of water salinity are consistent with water salinity data from surface and bottom-hole samples. Despite the prominence of applications of core saturation data in many aspects of the industry, thorough investigation into its quality and accuracy is usually overlooked. To the best of our knowledge, this is the first paper to present a novel analysis of the uncertainty coupled with Monte-Carlo simulation of lab-derived saturation’s data from sponge cores. The modeling approach and results highlighted in this work provide the fundamental framework for modern uncertainty assessment of core data.