Hisham A. Nasr-El-Din

Water-soluble hydrophobically associating polymers for improved oil recovery : A literature review

Water-soluble hydrophobically associating polymers are reviewed with particular emphasis on their application in improved oil recovery (IOR). These polymers are very similar to conventional water-soluble polymers used in IOR, except that they have a small number of hydrophobic groups incorporated into the polymer backbone. At levels of incorporation of less than 1 mol%, these hydrophobic groups can significantly change polymer performance. These polymers have potential for use in mobility control, drilling fluids and profile modification. This review includes synthesis, characterization, stability, rheology and flow in porous media of associating polymers. Patents relating to the use of associating polymers in IOR are also examined.

The effect of synthetic surfactants on the interfacial behaviour of crude oil/alkali/polymer systems

Abstract The effect of synthetic surfactants on the interfacial properties of an alkali/polymer/crude oil system was examined. This system consisted of David Lloydminster crude oil, sodium carbonate (a buffered alkali), either of two synthetic surfactants with high salt tolerance (Neodol 25-3S), an anionic surfactant, or Triton X-100, a nonionic surfactant) and a partially hydrolyzed polyacrylamide (Allied Colloids Alcoflood 1175L). The partitioning of the synthetic surfactant Neodol 25-3S into David Lloydminster crude oil is greatly enhanced by sodium carbonate. Increasing the oil volume fraction in the presence of sodium carbonate enhances the amount of partitioning, the effect of the surfactant depending on the sodium carbonate concentration. Low (0.1 mass%), intermediate (0.2 mass%) and high (0.5–5 mass%) sodium carbonate concentration regions were examined. A linear relationship was observed between interfacial tension (IFT) and t −1 2 , where t is interfacial age, both before and after the minimum IFT was reached. This suggests that the dynamic IFT process is diffusion controlled. With decreasing IFT (before the minimum), the slope of IFT versus t −1 2 varies linearly with the low-shear Newtonian viscosity of the polymer solutions. This suggests that the rate controlling step of the diffusion process occurs in the aqueous phase. Diffusion was inversely proportional to the square of the low-shear Newtonian viscosity, μn2, indicating a stronger effect of viscosity on diffusion than predicted by the Stokes-Einstein equation. With increasing IFT (after the minimum), the slope of IFT versus t −1 2 does not vary linearly with the low-shear Newtonian viscosity of the polymer solutions, suggesting that the rate limiting diffusion process occurs in the oil phase.

Effect of oilfield chemicals on the cloud point of nonionic surfactants

Abstract An experimental study was conducted to assess the effect of various oilfield chemicals on the cloud point of nonionic surfactants of the Triton-X series. The effects of simple salts, alkalis, acids, polymers, scale and corrosion inhibitors, biocides, a mutual solvent and a crude oil on the cloud point of several nonionic surfactants were examined over a wide range of parameters. The study also included evaluation of several additives, including short-chain alcohols, urea, and anionic surfactants, to raise the cloud point of these surfactants under oil reservoir conditions. The results obtained in this study indicated that oilfield chemicals affect the cloud point of nonionic surfactants, and the effect depends on the number of ethylene oxide groups, n, of the surfactant. At acid concentrations greater than 1 wt.%, hydrochloric or acetic acid increased the cloud point of nonionic surfactants having n > 7, with a higher cloud point being obtained with hydrochloric acid. Alkalis caused a sharp drop in the cloud point of nonionic surfactants. This effect was enhanced in the presence of sodium chloride. Anionic and cationic polymers depressed the cloud point of nonionic surfactants. Addition of an anionic polymer to alkaline solutions of TX-100 resulted in a further drop in the cloud point. Addition of urea or methanol increased the cloud point of nonionic surfactants having n > 7. Sodium dodecyl sulfate (SDS) raised the cloud point of neutral and alkaline solutions of TX-100 at low sodium chloride concentrations only. SDS also raised the cloud point of TX-45 (n = 5) at SDS concentrations greater than 0.8 wt.%. The effect of mutual solvent on the cloud point of the four nonionic surfactants depended on the concentration of the mutual solvent and the number of ethylene groups in the surfactant.

Dynamic interfacial tension of crude oil/alkali/surfactant systems

Abstract An experimental study was conducted to examine the dynamic interfacial tension in crude oil/alkali/surfactant systems over a wide range of parameters. The system examined contained David Lloydminster crude oil, sodium carbonate (a buffered alkali) and one of two synthetic surfactants with high salt tolerance (Neodol 25-3S or Triton X-100). Crude oil/alkali systems showed a minimum interfacial tension (IFT) of 0.02 mN m −1 at an optimum alkali concentration of 0.2 mass%. The effect of the synthetic surfactant depended on the alkali concentration: at alkali concentrations of less than 0.2 mass%, the synthetic surfactant generally yielded minimum IFT values greater than 0.2 mN m −1 , except at very low surfactant concentrations (about 0.001 mass%) where IFT values as low as 0.02 mN m −1 were obtained; at an alkali concentration of 0.2 mass%, the addition of synthetic surfactant raised the minimum IFT; and at alkali concentrations greater than 0.2 mass%, the addition of synthetic surfactant produced minimum IFT values of 0.02 mN m −1 at surfactant concentrations that varied from 0.001 to 0.5 mass%. It was also found that the dynamic IFT behaviour of crude oil/alkali/surfactant systems having the same ionic strength was quite similar. In these systems, some of the sodium carbonate was replaced with sodium chloride to produce an aqueous phase of the same ionic strength and nearly the same pH. The time required to reach the minimum IFT was found to be a function of the alkali/surfactant mass ratio. The minimum time required to reach an IFT minimum was 2 min at alkali/surfactant mass ratios of 0.1–10. At higher ratios, the time required to reach minimum IFT increased. The results obtained from the present study showed that the addition of a synthetic surfactant with high salt tolerance to crude oil/alkali systems did not always lower the IFT, and consequently care should be taken when formulating such systems for enhanced recovery purposes.

Acrylamide copolymers: A review of methods for the determination of concentration and degree of hydrolysis

Abstract Polyacrylamide are used extensively in enhanced oil recovery, drilling fluids, and in gels for profile control. This review enables drilling engineers or reservoir engineers to choose the most appropriate analytical method for measuring polyacrylamide concentration for their particular project. Seventeen groups of methods were reviewed for the determination of acrylamide copolymers, whereas eight groups of methods were reviewed for the measurement of degree of hydrolysis. In each case, a description of the method, advantages, limitations and interferences is provided.

Effect of Additives on the Acid Dissolution Rates of Calcium and Magnesium Carbonates

A rotating-disk instrument was used to measure the dissolution rates of both calcite and dolomite rock samples in HCl solutions. The results of more than 60 experiments are reported in this paper. The effect of common acidizing additives on the rock dissolution rate is measured for different acids containing quaternary amines, polymer, surfactant, mutual solvent, iron-chelating additive, and dissolved iron. Measurements are made at 23 and 50°C for calcite and dolomite marble samples. Marble samples from Turkey, Greece, and Italy were analyzed to find suitable reference materials. Marble composed of 100% calcite (calcite marble) as well as 91% dolomite (dolomite marble) was used and compared very well with previously published results. Results of rock dissolution rates with common acidizing additives showed significant differences. • 1.5 vol% cationic acrylamide copolymer decreased the calcite and dolomite dissolution rates significantly. At 1,000 rpm, the calcite dissolution rate with 1.5 vol% polymer and 0.1 M (0.36 wt%) HCl had a value that was 11.4% of the value measured with 0.1 M of HCl alone. • Polymer changed the acid/rock reaction from mass-transferlimited to surface-reaction-limited with both calcite and dolomite. This surface effect is possibly caused by polymer adsorption. • 10 vol% mutual solvent increased the acid dissolution rate by 9% for calcite and by up to 29% for dolomite. • 5000 mg/L iron (III) resulted in surface deposition of iron (III) hydroxide for both calcite and dolomite. At low rotational speeds, this surface layer had an inhibiting effect on the dissolution rate. • 2 vol% corrosion inhibitor decreased the calcite dissolution rate by approximately 9%. • Citric acid at 12 g/L decreased the calcite dissolution rate by an average of 9%, possibly because of the formation of calcium citrate at the surface. • 0.2 vol% nonionic surfactant had no significant effect on the acid dissolution rate of calcite.

Evaluation of a New Barite Dissolver: Lab Studies

This paper was selected for presentation by an SPE Program Committee following review of information contained in a proposal submitted by the author(s).

Measurement of Acid Reaction Rates with the Rotating Disk Apparatus

The authors have published several papers on the rotating disk apparatus (RDA) in recent years. The RDA is used to measure acid reaction rates, reaction order and activation energy of acidizing fluids with carbonate reservoir rock. This paper summarizes the different ways that acid reaction rates are measured, the factors that affect the results and why this is important when modelling acid stimulation treatments in the field. In particular, experimental procedures used to obtain acid reaction rates vary widely and can produce very different results. These procedures are often not well-documented in the literature. The validity of different experimental procedures are carefully compared in this paper. In addition to experimental concerns, the reactivity of reservoir rock can also vary widely. It was recently reported that the reactivity of reservoir rock toward acid is strongly affected by mineralogy and by mineral impurities. In particular, clay impurities in calcite rock were found to reduce the dissolution rate by nearly an order of magnitude. Some calcite rocks with clay content as low as 1 wt% showed acid reactivity similar to that of 100 wt% dolomite. Acidizing additives such as polymers and corrosion inhibitors have been shown to significantly affect the way that acid reacts with the reservoir rock.

Characterization of Filter Cake Generated by Water-Based Drilling Fluids Using CT Scan

Filter-cake characterization is very important in drilling and completion operations. The homogeneity of the filter cake affects the properties of the filtration process such as the volume of filtrate, the thickness of the filter cake, and the best method to remove it. Various models were used to determine the thickness and permeability of the filter cake. Most of these models assumed that the filter cake was homogeneous. The present study shows that the filter cake is not homogeneous, and consists of two layers of different properties. The objective of this study is to measure the filter-cake thickness and permeability of water-based drilling fluids by a new approach and compare the results with previous models. A highpressure/high-temperature (HP/HT) filter press was used to perform the filtration process under static conditions (225 F and 300 psi). A computed-tomography (CT) scan was used to measure the thickness and porosity of the filter cake. Scanning electron microscopy (SEM) was used to provide the morphology of the filter cake. The results obtained from the CT scan showed that the filter cake was heterogeneous and contained two layers with different properties under static and dynamic conditions. Under static conditions, the layer close to the rock surface had a 0.06-in. thickness, 10to 20-vol% porosity, and 0.087-ld permeability, while under dynamic conditions, this layer had a 0.04-in. thickness, 15-vol% porosity, and 0.068-ld permeability. The layer close to the drilling fluid had a 0.1-in. and 0.07-in. thickness under static and dynamic conditions, respectively, and it had zero porosity and permeability after 30 minutes under static and dynamic conditions. SEM results showed that the two layers contained large and small particles, but there was extremely poor sorting in the layer, that was close to the drilling fluid, which led to zero porosity in this layer. Previous models underestimated the thickness of the filter cake by almost 50%. A new method was developed to measure the thickness of the filter cake, and various models were screened to identify the best model that can predict our permeability measurements.

Challenges During Shallow and Deep Carbonate Reservoirs Stimulation

Carbonate reservoir stimulation has been carried out for years using HCl or HCl-based fluids. High HCl concentration should not be used when the well completion has Cr-based alloy in which the protective layer is chrome oxide which is very soluble in HCl. HCl or its based fluids are not recommended either in shallow reservoirs where the fracture pressure is low (face dissolution) or in deep reservoirs where it will cause severe corrosion problems to the well tubular. Different chelating agents have been proposed to be used as alternatives to HCl in the cases that HCl cannot be used. Chelating agents, such as HEDTA (hydroxyl ethylene diamine triacetic acid) and GLDA (glutamic –N, N-diacetic acid), have been used to stimulate carbonate cores. The benefits of chelating agents over HCl are the low reaction, low leak-off rate, and low corrosion rates. In this study, the different equations and parameters that can be used in matrix acid treatment were summarized to scale up the laboratory conditions to the field conditions. The conditions where HCl or chelating agents can be used were optimized and in this paper. The leak-off rate was determined using the data from coreflood experiments and computed tomography (CT) scans. Indiana limestone cores of average permeability of 1 md and core lengths of 6 and 20 in. were used in this study. Chelating agents will be used at pH value of 4 and at concentration of 0.6M, and their performance will be compared with the 15 wt.% HCl. The experimental results showed that HCl has high leak-off rate and caused face dissolution at low injection rate. The model to scale up the linear coreflood results to radial field conditions was developed and can be used to design for the optimum conditions of the matrix acid treatments. Chelating agents can be used to stimulate shallow reservoirs in which HCl may cause face dissolution, because they can penetrate deep with less volume and also they can be used in deep reservoirs where HCl may cause severe corrosion to the well tubular.