External Filter Cake Research Articles

Innovative Use of Kaolinite in Downhole Scale Management: Squeeze-Life Enhancement and Water Shutoff

Summary Applied research has been undertaken to examine the potential of kaolinite combined with a kaolinite-fixation agent to increase squeeze lifetime through alteration of near-wellbore surface characteristics and mineralogy, and to provide water-shutoff control. With respect to enhancing squeeze lifetime, it is documented that kaolinite increases the quantity of inhibitor adsorbed. Conversely, clean sandstone with low clay content commonly provides a poor substrate for adsorption. Furthermore, in reservoirs that experience near-wellbore formation damage because of kaolinite mobilization, it has been shown that the use of a fixation agent as part of a squeeze treatment can increase squeeze lifetime. Using these facts, research has assessed the feasibility of injecting micro-crystalline kaolinite (average particle size 2 μm) combined with the fixation agent and scale inhibitor as a means of mechanically altering near-wellbore mineralogy and surface-property characteristics within clean, high-permeability sandstones. The testing has been designed to mimic the squeeze procedure used in the field for performing such a job and involves no additional steps to those used in a normal squeeze (i.e., preflush, main treatment, overflush). The paper presents the results of coreflood experiments that demonstrate "proof of concept," along with examples of potential field applications. A further concept, born from the initial idea, was the use of kaolinite and fixation agent for efficient, low-cost, environmentally friendly water shutoff. There are several available products for water shutoff, but the disadvantage of these is that they are not acceptable for use in Norway because of poor environmental characteristics. Hence, there was a need to fill this gap by developing water-shutoff technology to meet country-specific environmental legislation. The paper provides details of coreflood testing where an excess of kaolinite has been used to form an internal and external filter cake that is attached to the wellbore face and within the near-wellbore region using the fixation agent. The paper draws on data from StatoilHydro-operated fields in order to highlight the potential of this innovative approach to downhole scale management and water control.

Modeling of External Filter Cake Build-up in Radial Geometry

The problem of formation damage (i.e., permeability reduction due to injection of particulates), is a matter of interest in several engineering fields. In the previous attempts to model the external cake formation, cake thickness has been considered to be only dependent on time; even though in practical applications, the dependency of the cake profile on space can be important. In this article, a novel model has been developed to describe the steady state external filter cake thickness profile along the wellbore. A set of equations is derived from the force balance for a deposited particle on the cake surface and the volume conservation of the fluid in the wellbore. These equations are combined with Darcy's law in radial geometry and the equation of flow in the wellbore, and solved numerically to obtain the cake thickness and fluid velocity profiles along the wellbore.

Improved oil recovery by raw water injection using horizontal wells

Injectivity formation damage with water-flooding using sea/produced water has been widely reported in the North Sea, the Gulf of Mexico and the Campos Basin in Brazil. The damage is due to the capture of solid/liquid particles by the rock with consequent permeability decline; it is also due to the formation of a low permeable external filter cake. Yet, moderate injectivity decline is not too damaging with long horizontal injectors where the initial injectivity is high. In this case, injection of raw or poorly treated water would save money on water treatment, which is not only cumbersome but also an expensive procedure in offshore projects. In this paper we investigate the effects of injected water quality on waterflooding using horizontal wells. It was found that induced injectivity damage results in increased sweep efficiency. The explanation of the phenomenon is as follows: injectivity rate is distributed along a horizontal well non-uniformly; water advances faster from higher rate intervals resulting in early breakthrough; the retained particles plug mostly the high permeability channels and homogenise the injectivity profile along the well. An analytical model for injectivity decline accounting for particle capture and a low permeable external filter cake formation has been implemented into the Eclipse 100 reservoir simulator. It is shown that sweep efficiency in a heterogeneous formation can increase by up to 5% after one pore volume injected, compared to clean water injection.

Multidimensional Velocity-Based Model of Formation Permeability Damage

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 97169, "Multidimensional Velocity-Based Model of Formation Permeability Damage: Validation, Damage Characterization, and Field Application," by R.S. Mojarad, SPE, and A. Settari, SPE, U. of Calgary, prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9–12 October. The loss of injectivity in produced-water and seawater injectors results from formation plugging. Reliable modeling of the permeability loss is key to analysis of field data and to the design and economics of projects. Standard formulation of damage mechanics uses the concentration-based, classical deep-bed filtration (DBF) model, which is not easily implemented in reservoir simulators. This alternative damage-modeling approach is based on the formulation proposed by Bachman et al.: "Coupled Simulation of Reservoir Flow, Geomechanics, and Formation Plugging With Application to High-Rate Produced-Water Reinjection," paper SPE 79695. The numerical implementation of this empirical, velocity-based damage model (VBDM) is extended to 2D flow and is validated by a comparison with the DBF model. The velocity model provides a remarkably accurate approximation of the more complex concentration model. Introduction Injectivity decline caused by particles in the injection water occurs to some extent in most injection wells. To understand and predict this decline, it is necessary to know about the water quality, formation characteristics, and deposition rate. In the classical DBF model, injectivity decline is characterized by two parameters: filtration coefficient, λ, and formation-damage coefficient, β. Methods to determine these parameters involve difficult measurements, scaling problems, and simplifying the assumptions of analytical solutions. Moreover, the model is not easily implemented in reservoir simulators. An empirical VBDM was developed previously that could be tuned to field or laboratory data and easily implemented in reservoir simulators. However, the model was formulated only in 1D, and its extension (and validity) in multidimensional flow was not shown. The full-length paper presents a 2D formulation and numerical implementation of permeability impairment that uses the VBDM. The results were compared with the classical DBF approach to validate the result against the DBF theory. A unique relation between the parameters of the two models was found that was key to developing a new method to determine the λ and β damage-characterization parameters on the basis of matching laboratory or field data with the velocity-based model. In this way, the number of parameters that need to be determined experimentally can be reduced. Mechanisms The injectivity decline caused by contaminated-water injection can be attributed to several primary mechanisms including internal filtration and external filter-cake buildup and its associated permeability reduction. Depending on details of the case studied (e.g., particle-size/pore-throat-size ratio, surface charge, or injection rate), either of the mentioned mechanisms could dominate. Large particles will be intercepted at the porous formation face, resulting in an external filter cake. Small particles can travel through the formation and initially plug the pore throats by bridging, thus creating internal pore restrictions. Continued buildup of internal plugging over time can also lead to an external filter cake. Once valid models have been obtained for each of these mechanisms, they can be coupled to describe the complete system of formation damage.

Filtration Properties of Oil-in-Water Emulsions Containing Solids

Summary This paper describes a laboratory study of the factors controlling the filtration and fluid-leakoff properties of emulsions containing solid particles. Such fluids are sometimes used as low-leakoff completion fluids. High-pressure/high-temperature (HP/HT) filtration tests clearly demonstrate that emulsions have the ability to reduce filtrate loss to the formation. However, the emulsion droplets tend to invade the formation and form an internal filter cake. This is evident from the liftoff pressures needed to initiate flowback and deep invasion of emulsion droplets in long-core experiments. Emulsions containing solids (CaCO3, in our case) had lower filtrate volume and higher return permeabilities than solids-free fluids. The effects of percent oil, filtration pressure, core permeability, temperature, and viscosity of the continuous phase were investigated. Filtration pressure and core permeability had major influences on the filtration properties of the emulsified completion fluids. Higher injection pressures increased internal damage and lowered the return permeability. Higher-permeability cores had higher filtrate loss. Emulsion droplets were observed in the effluent, and solid particles are needed to form a stable external filter cake. Long-core experiments showed that using emulsions containing acid-soluble solid particles have 100% return permeability after an acid squeeze, showing that the emulsion-droplet invasion depth is less than 1 in. It is shown that solids-free fluids had the highest formation damage and higher liftoff pressures. Analysis of the fluid-leakoff data indicates that emulsions containing solids do not behave as classical filtration theory predicts because of the invasion of emulsion droplets into the formation. Sizing the solid particles and emulsion droplets in completion fluids and muds according to the permeability of the rock is important in forming stable external filter cakes. This increases the return permeability and results in easier cake removal (low liftoff pressures).

Experimental and Numerical Approach for the Productivity Study of Open Hole Completed Horizontal Wells

Abstract Formation damage in horizontal wells, often open hole completed, is a critical point for oil fields developed in deep offshore, where acceptable development costs are based upon a limited number of highly productive wells. This paper describes a simplified numerical approach to model filter cake removal by natural cleanup when the well is put under a drawdown pressure difference. A flow simulator taking into account the near-well permeability variation has been developed using a cylindrical grid with very small gridblocks around the well. Laboratory data obtained on sandstones damaged with an oil-based mud have been used as input data to model filter cake removal by natural cleanup. The purpose of this modelling is to optimize the applied drawdown pressure, to study the variation of well productivities as a function of the pressure drawdown, and to get the best possible well performance preventing sand production problems in poorly consolidated formations. Introduction Deep offshore reservoirs are usually developed in very severe conditions, thus, their development costs are very high. The profitability of such developments requires a production scheme involving a limited number of wells having very high productivities and acceptable life spans of several years without any dramatic interruption. To reach these objectives, horizontal wells of great length are generally considered. These wells are mostly completed open-hole (non-cemented), avoiding any possibility of efficient remediation or stimulation in the case of any major damage created in the vicinity of the wellbore. Therefore, the clean up of these wells when they are put initially into production must resorb the greatest part of the damage generated during drilling and completion operations. An additional complication comes from the fact that these wells can exhibit sand production from the formation when drilled in non- or poorly-consolidated reservoirs (turbidites) if the clean up process is not carefully optimized. The questions are: which pressure drawdown has to be applied, and according to which procedure? In this paper, a simplified methodology is proposed to simulate the flow of a single liquid phase, namely oil, in the close vicinity of an horizontal well during its clean up period when a pressure drawdown is imposed between the wellbore and the reservoir formation. This work constitutes a first approach in order to provide qualitative information on the capacity of self cleaning of a horizontal well drilled in an oil pool with an oil-based mud. Numerical results are presented that show the influence of the pressure drawdown imposed during the clean up period on both the velocity of the produced oil at the wellbore, and the respective contribution of contrasted permeability zones on the total flow rate of the well. The presence of an external filter cake, together with an internal damage zone due to mud filtration, is also studied. Ultimately, these results will be used within more complete wellbore modelling that will include other features such as sand grain pulling from the reservoir formation. Afterwards, an extension of the model will take into account the mechanisms of formation damage and permeability restoration while assuming that the wells are drilled with a water-based mud.

Evaluation of Clay Stabilizers for a Sandstone Field in Central Saudi Arabia

Summary An oil field in central Saudi Arabia produces super-light crude from a sandstone reservoir. The formation contains up to 7.0 wt% authigenic clays dominated by kaolinite and illite/montmorillonite mixed layer clays. To mitigate sand production and improve well productivity, a frac pack stimulation treatment was conducted on most producing wells in this field. The treatment introduced several fluids, which might invade the formation and induce formation damage. An experimental study was conducted to determine potential formation damage due to fines migration and clay swelling, and to design an effective clay stabilizer treatment. The work included performing coreflood experiments using reservoir cores under reservoir conditions. The critical salt concentration (defined, as the salt concentration below which there is loss of permeability) was first determined. Several commercial clay stabilizers, cationic polymers, were evaluated. The effects of stabilizer type, concentration and acids on core permeability were investigated in detail. The experimental results indicated that the critical salt concentration (KCl brine) was nearly 5 wt%. Severe loss of permeability was observed when brines of lower salt concentrations were injected into reservoir cores. The effectiveness of clay stabilizers was found to be a function of chemical type and concentration. Some ofthe chemicals caused loss of injectivity at higher concentrations. It was found that these chemicals did not readily dissolve in water and formed fish eyes. When these chemicals were injected into reservoir cores, they formed an external filter cake, which caused loss of permeability. Good mixing of the stabilizer and proper filtration solved this problem. Hydrochloric acid at 15 wt% did improve the performance of at least one of the clay stabilizers examined. Based on lab testing, a cost effective clay stabilizer was tested in the field. Field results indicated that the chemical did not cause loss of injectivity, and minimized formation damage due to fines migration and clay swelling.

An Investigation of Fluid Leakoff Phenomena by Use of a High-Pressure Simulator

Summary This paper describes the results of fluid-loss tests conducted with various hydraulic fracturing fluids through the use of a large-scale, high-temperature, high-pressure simulator (HPS) that has several unique capabilities. Among these capabilities is the ability to perform dynamic fluid-loss experiments over a large surface area under 1,000 psi differential pressure. Nearly all fluid-loss studies previously reported in the literature have described laboratory tests involving small-core plugs with a surface area of approximately 1.7 in.2. In contrast, the fluid-loss data collected in the HPS are over a significantly larger surface area, approximately 606 in.2. Results from the HPS were compared to laboratory data, and significant differences in spurt-loss values were found. Surface texture was also found to be a significant factor in determining the extent of filter cake formation. The paper provides insight into the differences between fluid-loss control mechanisms displayed by linear polymer solutions and crosslinked gels. Experiments specifically designed to evaluate various hypotheses were performed to determine the significance of external filter cake on fluid-loss control of crosslinked fluids. Conventional fracturing fluids and additives were found to be inefficient in controlling fluid loss to natural fractures in a rock matrix.

Dynamic Fluid Loss in Hydraulic Fracturing Under Realistic Shear Conditions in High-Permeability Rocks

Summary A study of the dynamic fluid loss of hydraulic fracturing fluids under realistic shear conditions is presented. During a hydraulic fracturing treatment, a polymeric solution is pumped under pressure down the well to create and propagate a fracture. Part of the fluid leaks into the rock formation, leaving a skin layer of polymer, or polymer filter cake, at the rock surface or in the pore space. The fluid-loss behavior depends on the extent to which the polymer invades the porous rock and the thickness of the polymer filter cake, which is limited by the shear stress that the flowing fracturing fluid exerts on it. The effect of shear rate on the dynamic fluid-loss behavior of linear gels and crosslinked borate guars was studied using cores of permeabilities ranging from 0.5 to 70 md, pressure drops of 1,000 psi, and temperatures between 75 and 150°F. The effect of shear on the formation of external filter cake and on the effectiveness of particulate fluid-loss additives was also studied. A shear rate history representative of that experienced by a rock segment in the fracture was used. In this history, the shear rate drops from a very high rate of 380 sec−1 down to 40 sec−1 because of the widening of the fracture width as time advances. Constant shear rate results show that high shear rates eliminate external filter cakes. In the absence of external cakes, the formation of internal filter cakes controls fluid loss, especially in high-permeability cores. The effectiveness of particulate fluid-loss additives increases with the permeability of the rock and decreases with shear rate and viscosity of the fluid. Shear history results show that the highest leakoff rates and volumes occur during the first 10 minutes of leakoff, i.e., when the rock surface is exposed to high shear rates. Once the shear rate drops below a critical shear value, polymer filter-cake deposition begins and the rate of leakoff slows down. The effect on fluid loss is that a majority of the fluid is lost at high shear rates during a fracturing treatment (i.e., when no polymer filter cake is formed), especially at the beginning of the treatment. To have a major effect on reducing fluid loss, the emphasis has to be placed on plugging the pore throats at the surface of the rock.

Simple Approach to the Cleanup of Horizontal Wells With Prepacked Screen Completions

Openhole completions with prepacked screens are increasingly the completion of choice for horizontal wells requiring sand control. For maximum productivity from these wells, preventing mud damage to the formation and the screen or removing it before bringing the well onto production is vital. A common industry approach to this problem is to displace the drilling mud to an aqueous clear fluid before production, typically followed by a breaker fluid. This paper details an alternative approach: bringing the well on without cleanup. The paper outlines the decision-making process, shows how the drill-in-fluid ad cleanup operations are designed, explains how laboratory resting can be used to support the design philosophy, and highlights that quality control of the mud system while drilling is critical to the success of such a well. Case histories in two very different reservoirs are presented that illustrate the success of this approach.