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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.
Fluid-Loss-Control Additives (FLAs) are used to maintain a consistent fluid volume within a cement slurry to ensure that the slurry performance properties remain within an acceptable range. The variability of each of these parameters (slurry performance properties) is dependent upon the water content of the slurry. If the water content is less than intended, the opposite will normally occur. The magnitude of change is directly related to the amount of fluid lost from the slurry. Because predictability of performance is typically the most important parameter in a cementing operation, considerable attention has been paid to mechanical control of slurry density during the mixing of the slurry to assure reproducibility.
Calcium carbonate (CaCO3) has been used to make high-density drilling muds. To minimize sticking, barite (BaSO4) is added to reduce the amount of solids needed. However, barite is damaging because it does not dissolve in commonly used acids. Drilling fluids have been developed at a wide range of densities using calcium chloride (CaCl2) salt with manganese tetroxide (Mn3O4). The small particle size, spherical shape, and high specific gravity of Mn3O4 make it good weighting material to reduce solids loading and settling compared with CaCO3 and BaSO4.
A major operator manages multiple deepwater projects in the Gulf of Guinea. This paper describes one of these, a recent 44-well project. The operator required an ISO 28781-qualified bidirectional subsurface isolation barrier valve (IBV) to be installed in each well. This paper presents the results of the IBV deployment in the field. The Egina field was discovered in 2003 in Oil Mining Lease 130 located in deep water (1150–1750 m) approximately 200 km offshore Port Harcourt, Nigeria.
Many viscosifiers currently used in high-density solids-free reservoir drilling fluids (RDFs) and completion fluids (CFs) are incompatible with high-density brines or require the use of prohibitively expensive brines to achieve target densities. There is substantial commercial benefit to developing a brine viscosifier with a higher temperature tolerance than is currently offered. A supramolecular viscosifier package has been developed that uses noncovalent associations between additives to enhance the thermal resilience of divalent brine fluids. Static aging-test data indicate that the supramolecular viscosifier outperforms high-performance, commercially available starch/xanthan brine viscosifier. The exploitation of oil and gas reservoirs found at increasing depths and the development of horizontal and slimhole drilling have increased the demand for high-density solids-free RDFs, CFs, and workover fluids (WFs).
Two forms of derivatized cellulose have been found useful in well-cementing applications. The usefulness of the two materials depends on their retardational character and thermal stability limits. This is commonly used at temperatures up to approximately 82 C (180 F) for fluid-loss control, and may be used at temperatures up to approximately 110 C (230 F) BHCT, depending on the co-additives used and slurry viscosity limitations. Above 110 C (230 F), HEC is not thermally stable. HEC is typically used at a concentration of 0.4 to 3.0% by weight of cement (BWOC), densities ranging from 16.0 to 11.0 lbm/gal, and temperatures ranging from 27 to 66 C (80 to 150 F) BHCT to achieve a fluid loss of less than 100 cm3 /30 min.
Abstract Many application and operational methods have been developed for applying carbonate matrix acidizing to successfully stimulate heterogeneous and long horizontal openhole zones. These methods have also been implemented during acid fracturing to various degrees of success. This paper discusses in detail the laboratory assessment of a biodegradable material for acid diversion in highly fractured formations. Diversion in fracture acidizing is extremely challenging because of the high pumping rate, extreme pressures, and larger volumes of acid compared to matrix acidizing. To effectively stimulate natural or pre-existing fractured formations, the diverting agent should be able to bridge not only at the perforations, but inside the fracture system, too. Historically, several methods have been implemented for acid-fracturing diversion, such as ball sealers, viscous fluids, packers, etc., resulting in limited success in formations with natural or pre-existing fractures. This paper discusses the use of an acid diverter that consists of biodegradable particles with different sizes and hardness. The particle size ratios are specifically designed where large particles will bridge in the fractures while the smaller particles "nest" in the pore throat of the bridged larger particles. This leads to quick, efficient blockage of fractures and acid diversion. The laboratory assessment of this biodegradable material was conducted at various temperatures up to 300°F and consists of (1) degradation in 3% KCl, live 15 wt% HCl, and spent 15% HCl, and (2) fluid loss using slotted disks at different diverter concentrations. The fractures were mimicked in the laboratory using a stainless steel slotted disk in a high-pressure/high-temperature (HP/HT) cell. The dissolution rate of the particles was observed to be a function of time and temperature. The dissolution rate of the diverter was higher in water as compared to 15 wt% HCl acid. The stability of the biodegradable diverter was conducted at 300°F. The filter cake was stable up to 30 minutes when 1.0 ppt of the biodegradable diverter was used. The results of this study indicate that the biodegradable diversion material can be used as an effective alternative diversion method to seal natural or pre-existing fractures.
Summary This paper focuses on the application of polyelectrolyte-complex (PEC) nanoparticles to fluid-loss control of oilwell cements. Cement-slurry design involves considerable complexities, including the interplay of viscosity, yield point (YP), fluid-loss control, setting time, sedimentation, gel-strength development, and density. Polymers such as hydroxyethyl cellulose (HEC), carboxymethyl HEC (CMHEC), and polyvinyl alcohol have been used extensively for fluid-loss control in oilwell cementing. However, the resulting increase in slurry viscosity often led to unwanted side effects, such as increased pumping requirements. PECs were originally developed as drug carriers for pharmaceutical applications. Our previous work (Cordova et al. 2008; Lin et al. 2014; Johnson et al. 2016) showed that they can also be effective in improved-oil-recovery applications. In this study, we explore the potential of using PEC nanoparticles to achieve effective fluid-loss control while maintaining good fluid properties of the cement slurry. Results from this proof-of-concept study demonstrated that a PEC system comprising common oilfield polymers can be used to achieve effective fluid-loss control. Simultaneously, the system shows improved rheological properties over control samples while maintaining other desirable slurry characteristics.
Abstract Controlling fluid loss into the formation is of critical importance during overbalanced workover operations to minimized near-wellbore damage invasion by the completion fluid, which can yield problems associated with poor wellbore cleanout and loss of hydrocarbon reserves. In addition, fluid loss can increase costs associated with rig time and treatments devoted to restore the initial condition of the formation. Traditional techniques to minimize fluid loss use solids or viscous pills, although it has been amply documented that these systems can damage the formation if not properly removed after the treatment. This paper presents the laboratory development and validation of a novel solids-free fluid-loss (SFFL) system used during overbalanced workover operations. This system relies on an ionic polymer that decreases matrix permeability to aqueous fluids, limiting leakoff into treated zones. This polymer immediately adsorbs to the surface of the rock, eliminating the need to shut the well in. In addition, this system does not require the use of breakers, which eliminates negative impact on post-stimulation well productivity. Laboratory test data show the capability of the material to control fluid leakoff and achieve high levels of regained permeability to hydrocarbons. To date, about 60 jobs have been performed with this novel SFFL system. The paper discusses field results from the application of this system during overbalanced workover operations and other applications where maintenance of a hydrostatic column is necessary for well control. This system has been proposed for solving partial and total loss to full circulation in overbalanced operations such as: (1) lost-circulation events occurring during cementing, fracturing, and drilling, (2) well intervention cleanouts by coiled tubing (CT) and hydraulic workover (HWO), (3) gravel packing, (4) replacement of artificial lift equipment (i.e., electrical submersible pumps), and (5) overbalanced tubing-conveyed perforating (UTCP), among others.