Ian D. Robb

The adsorption of poly(acrylic acid) onto insoluble calcium salts

Abstract The adsorption of sodium polyacrylate onto calcium phosphate particles was studied using EPR techniques to give estimates of their configuration in the adsorbed state. The calcium phosphate particles were produced, containing a varying composition of calcium and sodium in the crystal, so that the surfaces contained differing densities of adsorbing sites for the polymer segments. The higher the Na + Ca 2+ ratio in the crystal surface the more loops and tails were present in the adsorbed polymer. The sedimentation volumes of the crystals containing the polymer showed that in those samples having polymers lying flat on the surface little flocculation occurred whereas in those where the polymer contained more loops and tails, considerable flocculation occurred. This result is what would be expected from a bridging mechanism.

Effect Of Permeability Impairment By Suspended Particles On Invasion Of Drilling Fluids

This study experimentally and numerically investigates formation damage induced by suspended particles in the drilling fluid and its effect on limiting their near-wellbore invasion. The study applies the NMR and X-Ray digital radiography tprovide valuable insights into damage mechanisms along the formation and depth of invasion. Formation damage caused by drilling fluids is one of the key factors for economic success in oil and gas field developments. The measured permeability reduction obtained from laboratory test by injecting particulate drilling fluid in a representative core sample is used to determine empirical parameters used to model the particle migration and deposition in porous media by means of a robust simulation of the relevant processes. The study provides a concept to develop the ability to evaluate drilling fluids in term of their formation damage potential. Introduction Argiller et al. (1999) analyzed the formation damage potential of water-based drilling fluids. They conducted experiments with three water-based formulations. It was found that static filtration was mainly governed by external mud cakes. They also stated that formation damage caused by water-based fluids can be avoided by optimizing the fluid loss reducer and particle size distribution Bailey et al. (1999) studied the particle invasion from drilling fluids. The particulate invasion was found to be one of the primary mechanisms of formation damage caused by drilling fluids. Particles are forced into the formation generally during the earlier stages of the filter cake growth. The experiments were done with KCl polymer fluid and different grades of barite and carbonate weighing agents. They found that fine particles penetrated deeply into the formation and could not be easily removed by back-flushing. Larger particles were observed to deposit near the surface of the injection point. The permeability reduction was greatest in single-phase brine conditions. Ding et al. (2004) studied near wellbore damage and natural clean-up of horizontal wells. Near wellbore properties were altered by drilling fluid, fluid-fluid interaction, and fluid-filtrate invasion during overbalanced drilling operations. The degree of formation damage was affected by many properties, and operating conditions. The permeability reduction factor was correlated with flow rate. A rapid fluid loss, indicating as a spurt loss, when the drilling bit contacts the reservoir, was observed. A deeper particle invasion of the internal filter cake decreased the flow efficiency while preventing the filtrate 2 IADC/SPE 133724 invasion. Serious loss of production occurred with damaging and non-optimized drilling fluids. The formation damage was much severe with a water-based mud than an oil-based mud. One key factor in the economics of drilling and completion projects is the performance of wells during their lifetime. Productivity maintenance requires minimum formation damage. The basic feature that causes formation damage is particle capture by the porous medium and the consequent permeability reduction (Nabzar et al. 1997; Roque et al. 1995). The trend toward single well completion places additional emphasis on avoiding formation damage. During drilling and completion, near-well bore permeability impairment can cause a significant reduction of well productivity; however, the damage may be avoided if drilling/completion fluid conditions are properly selected. Formation evaluation has been improved using well logging to provide accurate information on porosity and formation fluid saturation. However, well logging can not provide a systematic estimation of permeability. Nuclear Magnetic Resonance (NMR) can be used to determine porosity and permeability impairment during the core flood tests (Coates et al, 1999). In the past decate, X-ray computed tomography (CT) has provided a valuable core analysis tool (Withjack et al., 2003).The philosophy behind the approach of this paper was to investigate various formation damage mechanisms developed for a single-phase fluid system based on laboratory core tests using NMR and CT image technologies. Experimental System and Procedure The coreflood experimental apparatus included five main components (shown in Fig. 1): (1) an electrical pump (Ruska), (2) an accumulator which contained fluid with suspended particles, (3) a Hassler-sleeve core holder, (4) back pressure regulator, and (5) a computer based data acquisition system. The effluents were collected in a graduate cylinder. A laser diffraction particle size distribution analysis system (LDPSDA) was used to measure the particle size distribution of the particles in the core flood experiments. The LDPSDA is a system of multifunctional particle characterization tools. Its laserbased technology permits analysis of particles without risk of missing either the largest or the smallest particles in a sample. The laser diffraction technology is based on both Fraunhofer and Mie theories of light scattering. All the samples had to be dried carefully prior to analysis since the system works only with dry samples. Prior to a core flood test, the equipment was completely cleaned. Water-based drilling muds were prepared by mixing water and bentonite with additives at desired concentrations. The fluid samples were aged for 48 hours. Fluid viscosities were measured with a Chann 35 viscometer. Vacuum was used on the test fluid to make sure there were no trapped air bubbles. The Berea core samples used were 6.0 inch long and 1.0 inch in diameter. Prior to injection, the cores were saturated with 3% KCl brine. Different barite particle sizes were added into drilling muds to study the effect of particle size and concentration on permeability impairment. The flow rate was held constant at 90 cm/hour. Data Analysis NMR and LDPSDA techniques were used to provide particle and pore size distribution of the formation before and after being damaged. Particle and Pore Size Distributions: The volume-average mean particle diameter of barite suspensions used in this study ranged from 2 to 6 μm, while the minimum particle diameter was 0.5 μm and maximum was 15 μm. Fig. 2 shows particle size distributions expressed in volume frequency using LDPSDA system. IADC/SPE 133724 3 When a water-wet rock is fully saturated with water, the T2 value of a single pore is proportional to the surface-tovolume ratio of the pore, which is measured of the size of the pore. Therefore, the observed T2 distribution for all the pores in the rock represents the pore size distribution of the rock. The T2 NMR relaxation parameter is related to the pore surface, S, to volume, V, ratio by the following equation: b r T V S T 2 2 1 1 + = ρ ------------------------------------------------------------------------------------------------------------------------------(1) Assuming a cylindrical geometry and ignoring the bulk term in the equation (1), the relationship reduces to: r T r 2 1 2 ρ = --------------------------------------------------------------------------------------------------------------------------------------(2) where ρr is the rock surface relaxivity, r is the diameter of the pore body of the formation. The T2 relaxation spectrum is a reflection of the variation of pore sizes. Hence, T2 NMR data was scaled to provide pore size distributions using a relaxivity value of 25.5 μm/s and 16.9 μm/s for sample#1 and sample#2, respectively. Fig. 3 shows the pore size distribution for the two samples#1(Ko =1,240 mD) and #2 (Ko = 265 mD) using the T2 relaxation data. The mean pore diameter of the 1,240 mD core was 26.1 μm while that of the 265 mD core was 15.7 μm. Fig. 4 is the SEM pictures of the two core samples at magnification of 100 times. The T2 distribution from NMR data offered a reasonable estimate pore size distribution when the zone was 100% water-saturated. This information is very helpful for reservoir quality and depositional environment evaluation. Porosity Variations: Fig. 5 represents the T2 distribution for the sample#1 at time t = 0, 5, and 18 hours of the core flood experiment. The injection rate was a constant 36 cm/hour. Barite (5.4 μm mean diameter) concentration was 5% by weight. Porosity was estimated using equation (2). It was shown that the overall porosity reduced from 20.6% to 17.6% after 5 hours of flooding. The porosity did not reduce further as fluid injection was continued. The porosity dropped only 0.1% after another 13 hours. The cumulative porosity corresponding to relaxation time T2 are also shown as Fig. 6 to illustrate the total porosity of the core sample at different times during the core flood test. Several observations can be made from Fig. 5 and 6. The porosity was reduced due to particle capture and deposition over five hours and then remained constant. The probability of particle being captured inside the core sample increased as the pore diameter-to-particle size diameter decreased. In another word, the smaller pores would be blocked and filled with particles before the larger pores. As particles were injected into the core sample, more small pores were blocked. The flow was diverted to larger size pores and the capture probability rate decreased. When all the capture sites were filled, no-more particles could be captured. They would be flushed through the large pore paths. This explains the steady state in porosity established after 18 hours. Additional proof of establishing a steady state during the particle injection test is examined in Fig. 7. The effluent particle size distribution was analyzed using the LDPSDA method. The particle size of 5.4 μm mean diameter was injected at the inlet. The particle size distribution in the effluent was smaller than in the inlet. This shows that larger particles were captured, while smaller particles were flushed out. As injection proceeded, the outlet particle size distribution shifted to larger diameter until the inlet particle distribution was almost matched