Indiana Limestone Cores Research Articles

Chelating-Agent Enhanced Oil Recovery for Sandstone and Carbonate Reservoirs

Summary Recently low-salinity waterflooding was introduced as an effective enhanced-oil-recovery (EOR) method in sandstone and carbonate reservoirs. The recovery mechanisms that use low-salinity-water injection are still debatable. The suggested possible mechanisms are: wettability alteration, interfacial-tension (IFT) reduction, multi-ion exchange, and rock dissolution. In this paper, we introduce a new chemical EOR method for sandstone and carbonate reservoirs that will give better recovery than the low-salinity-water injection without treating or diluting seawater. In this study, we introduce a new chemical EOR method that uses chelating agents such as ethylenediaminetetraacetic acid (EDTA), hydroxyethylethylenediaminetriacetic acid (HEDTA), and diethylenetriaminepentaacetic acid (DTPA) at high pH values. This is the first time for use of chelating agents as standalone EOR fluids. Coreflood experiments, interfacial and surface tensions, and zeta-potential measurements are performed with DTPA, EDTA, and HEDTA chelating agents. The chelating-agent concentrations used in the study were prepared by diluting the initial concentration of 40 wt% with seawater and injecting it into Berea-sandstone and Indiana-limestone cores of a 6-in. length and a 1.5-in. diameter saturated with crude oil. The coreflooding experiments were performed at 100°C and a 1,000-psi backpressure. Low-salinity-water and seawater injections caused damage to the reservoir because of the calcium sulfate scale deposition during the flooding process. The newly introduced EOR method did not cause calcium sulfate precipitation, and the core permeability was not affected. The core permeability was measured after the flooding process, and the final permeability was higher than the initial permeability in the case of chelating-agent injection. The coreflooding effluent was analyzed for cations with the inductively coupled plasma (ICP) spectroscopy to explain the dissolution-recovery mechanism. The effect of iron minerals on the rock-surface charge was investigated through the measurements of zeta potential for different rocks containing different iron minerals. HEDTA and EDTA chelating agents at 5 wt% concentration prepared in seawater were able to recover more than 20% oil from the initial oil in place from sandstone and carbonate cores. ICP measurements supported the rock-dissolution mechanism because the calcium, magnesium, and iron concentrations in the effluent samples were more than those in the injected fluids. The IFT-reduction mechanism was confirmed by the low IFT values obtained in the case of chelating agents. The type and concentration of chelating agents affected the IFT value. Higher concentrations yielded lower IFT values because of the increase in carboxylic-group concentration. We found that the high-pH chelating agents increased the negative value of zeta potential, which will change the rock toward more water-wet.

Performance of PAM/PEI gel system for water shut‐off in high temperature reservoirs: Laboratory study

ABSTRACTA polymer gel is one of the common remediate methods to either reduce or totally block excessive water production in oilfields. Some systems demonstrated an excellent performance in treating the problem like polyacrylamide tert‐butyl acrylate (PAtBA)/polyethylenimine (PEI). In this study, polyacrylamide (PAM) was introduced as a cheap alternative to PAtBA that can tolerate high salinity reservoirs. The thermal stability of the PAM/PEI polymeric gel in saline water was examined at 150°C (302F). Samples prepared in sea water showed better stability compared with distilled and field water. Dynamic rheology and core‐flooding experiments were used to evaluate the PAM / PEI gel system at high temperatures. NaCl and NH4Cl were evaluated as a possible retarders for delaying the gelation time in order to achieve a successful placement. NH4Cl was found to be more effective retarder. Core‐flooding tests were conducted in sandstone and carbonate cores. The subject polymer gel was injected at rates typical of those in field applications. The injectivity of PAM/PEI was tested in Berea sandstone cores with initial permeability of ∼45 mD. The post‐treatment of the system showed a permeability reduction of ∼94% for a period of two weeks. The injectivity in low permeability carbonate cores required more retardation compared with the injectivity in sandstone cores. The gel reduced the permeability to brine in Indiana limestone core by 99.8% for more than 5 months. Rheology of cured gel samples indicated that the gel strength needs about one day of curing in the core for the strength to stabilize. © 2015 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2015, 132, 41869.

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.

Effect of Oil Saturation on the Flow of Emulsified Acids in Carbonate Rocks

Summary Matrix acid treatments in carbonate reservoirs target stimulation of the near-well region. Emulsified acid can be used in matrix acidizing and acid-fracturing treatments. The delayed nature of emulsified acid is useful in creating deep wormholes and etched fracture surfaces. Almost all previous coreflood work was performed on cores fully saturated with water. Therefore, the main objective of the present work is to study the effect of oil saturation in the formation on the flow of emulsified acids in carbonate cores and assess the performance of emulsified acid in stimulating carbonate formations. A coreflood study was conducted using Indiana limestone cores that were 1.5 in. in diameter and 6 in. in length. The effect of the presence of crude oil on the volume of acid to breakthrough was studied. Also, the size, number, and distribution of the wormholes were determined with computed-tomography (CT) images. The effect of the acid injection rate on the performance of emulsified acid was investigated. Cores that were fully saturated with water, fully saturated with crude oil, and saturated with crude oil at irreducible water saturation were used. There was no optimum injection rate for emulsified acids when they were injected into Indiana limestone cores with permeabilities of 47 to 238 md. In such a range of permeability, emulsified acid enhanced the rock permeability when the acid was injected at both high (10.0 cm3/min) and low (0.5 cm3/min) rates. For cores fully saturated with crude oil, the volume of emulsified acid to achieve breakthrough was 2.2 times more than that required to achieve breakthrough in cores fully saturated with water. The increase in emulsified-acid volume refers to the increase in the volume of the continuous phase resulting from the mixture of the crude oil and diesel and the subsequent change in the acid/diesel volume fraction. As a result, more acid was consumed to create wormholes and achieve the breakthrough. The emulsified-acid system was effective in stimulating limestone cores, whether these cores were saturated with water, oil, or oil at irreducible water saturation.

Removal of water-based filter cake and stimulation of the formation in one-step using an environmentally friendly chelating agent

Chelate solutions, GLDA (pH of 3.3 to 13) and HEDTA (pH of 4 and 7) were incompatible with α-amylase over a wide range of temperatures. GLDA (pH 3.3) and HEDTA (pH 4) can be used to remove the filter cake in one step. GLDA (20 wt% in a 200 g solution and pH of 3.3) and HEDTA (20 wt% in a 200 g solution and pH 4) had 100% removal efficiency of the filter cake. The retained permeability was 110% and 106% for Berea sandstone and Indiana limestone cores, respectively when using GLDA (13.3 wt% in 300 g solution and pH of 3.3). The retained permeability was 115% and 100% for Berea sandstone and Indiana limestone cores, respectively when using HEDTA (20 wt% in 200 g solution and pH of 3.3). No core damage was observed when using GLDA and HEDTA solutions as a breaker to remove water-based filter cake.

Fractured carbonate reservoirs sweep efficiency improvement using microbial biomass

Selective plugging by microbial biomass is one of the proposed mechanisms for improving reservoir sweep efficiency in fractured reservoirs. In this study, the potential of Bacillus licheniformis strains isolated from oil contaminated soil from the Sultanate of Oman was tested for their ability to grow in induced fractures in carbonate rocks and to divert subsequent injection water to the unswept matrix zones. Three B. licheniformis strains were tested with name codes; B29, B17 and W16. Their growth behavior using different nitrogen sources – yeast extract, peptone and urea – was investigated. Glucose, sucrose and date molasses were tested as carbon sources. Carbon/nitrogen ratios were optimized where it was found that sucrose was the carbon source that maximized bacterial growth at 2% concentration and yeast extract was the selected nitrogen source with concentration of 0.1%. The combination of B. licheniformis strain W16 in a minimal medium containing sucrose was the optimum condition for maximum cell growth within 10–12 h of incubation. Standard Indiana limestone core plugs were used for coreflooding experiments where a fracture was simulated by slicing the cores vertically into two sections using a thin blade. The bacterial cells were injected into the cores and the ability of the microbes to grow and plug the fracture was examined. Scanning electron microscopy was used to prove the growth of the microbial cells in the fracture after the experiment. Coreflooding experiments showed promising results where enhancement of oil recovery was observed after bacterial injection. A total of 27–30% of the residual oil was produced after 11 h of incubation. This shows the high potential of using microbial biomass for selective plugging in fractured reservoirs.

Evaluation of a New Environmentally Friendly Chelating Agent for High-Temperature Applications

Summary Matrix acidizing is used in carbonate formations to create wormholes that connect the formation to the wellbore. Hydrochloric acid (HCl), organic acids, or mixtures of these acids are typically used in matrix-acidizing treatments of carbonate reservoirs. However, the use of these acids in deep wells has some major drawbacks, including high and uncontrolled reaction rates and corrosion to well tubulars, especially those made of chromium-based tubulars (Cr-13 and duplex steel); and these problems become severe at high temperatures. To overcome problems associated with strong acids, chelating agents were introduced and used in the field. However, major concerns with most of these chemicals are their limited dissolving power and negative environmental impact. L-glutamic acid diacetic acid (GLDA), a newly developed environmentally friendly chelate, was examined as a replacement for acid treatments in deep oil and gas wells. The solubility of calcium carbonate (CaCO3) in the new chelate was measured over a wide range of parameters. Coreflood tests were conducted using long Indiana limestone cores 1.5 in. in diameter and 20 in. in length, which allowed better understanding of the propagation of this chemical in carbonate rocks. The cores were X-ray scanned before and after the injection of chelate solutions into the cores. The concentration of calcium (Ca) and chelate was measured in the core effluent samples. To the best of our knowledge, this is the first study to examine the fate and propagation of chelating agents in coreflood studies. GLDA has a very good ability to dissolve Ca from carbonate rocks over a wide pH range by a combination of acid dissolution and chelation. The addition of 5 wt% sodium chloride (NaCl) did not affect the GLDA performance at pH = 13 but significantly accelerated the reaction at pH = 1.7. Compared with other chelating agents, GLDA dissolved more Ca than ethanoldiglycinic acid (EDG) but less than hydroxyethyl ethylenediamine triacetic acid (HEDTA) at high pH values. GLDA of pH = 1.7 was able to form wormholes at 2 and 3 cm3/min. GLDA was found to be thermally stable at temperatures up to 350°F.

A Novel Application of Closed-Fracture Acidizing

Summary The success of acid fracturing depends on the conductivity created and retained under closure stress in addition to the length of conductive fracture. The majority of acid-fracturing treatments show a sharp decline in conductivity with increasing closure stress, with almost no significant conductivity after a short production time. As a result, many wells are refractured to restore them to the original productivity after the initial fracture. However, the success of these refracture treatments has been diverse with respect to extent of stimulation. A new approach to overcome productivity decline of acid-fractured wells is to perform closed-fracture acidizing (CFA) at the appropriate time in the life of the well to keep fractures conductive. An experimental study was conducted to investigate the effect of CFA on already-acid-fractured cores exposed to a certain level of closure stress. Indiana limestone cores were acidized with a typical acid system of 15 wt% hydrochloric acid (HCl) viscosified with a polymer under typical field conditions. After the first acidizing process, conductivity measurements were conducted on acid-etched core faces up to a certain closure stress. While the fracture was kept under the closure stress, a CFA treatment was conducted under the same conditions as the initial acidizing. The re-etched fractures were once again placed under different levels of closure stress, and conductivity measurements were taken at each stress. Experiments were conducted under different conditions of leakoff, polymer concentration, and closure stress after the first acidizing in order to determine the influence of these parameters on the refracturing conductivity. In all cases, CFA enhanced fracture-face etching, while it significantly increased fracture conductivity under closure stress. However, leakoff, polymer concentration, and closure stress did influence the degree of success of CFA. Leakoff allowance and lower polymer concentration resulted in the most enhanced fracture conductivity in comparison to the initial acid-fracturing process.

Effect of Shear Rate on the Propagation of Polymer-Based In-Situ-Gelled Acids Inside Carbonate Cores

Summary In-situ-gelled acids that are based on polymers have been used in the field for several years and were the subject of many laboratory studies. An extensive literature survey reveals that there are conflicting opinions about using these acids. These acids were used in the field with mixed results. Recent laboratory work indicated that these acids can cause damage under certain conditions. There is no agreement on when this system can be applied successfully in the field. A coreflood study was conducted using Indiana limestone cores (1.5-in. diameter and 20-in. length) at high temperatures and pressures. Propagation of the acid, polymer, and crosslinker inside the long cores was examined in detail. Samples of the core effluent were collected, and the concentrations of calcium, crosslinker, and acid were measured. Permeability enhancement and location of any precipitation was detected using a computed-tomagraphy (CT) scanner on the core before and after the acid injection. Different sections were cut from the core to investigate the propagation and precipitation of polymer and crosslinker. Material balance was conducted to determine the amount of crosslinker retained in the core. Experimental results show that this acid system caused damage in some cases. At low shear rates, in-situ-gelled acid formed a gel inside the core as indicated by the cyclic behavior noted in the pressure drop across the core, and the acid changed direction inside the core several times. However, this gel reduced the core permeability significantly. At high shear rates, a smaller amount of gel was formed inside the core, and the acid's ability to change its direction inside the core was less than that noted at low shear rate. A significant permeability enhancement was achieved. The wormhole length increased as the shear rate was increased, while the diameter of the wormhole increased as the cumulative injected volume of acid increased. CT scan indicated the presence of gel residue inside and around the wormhole. Gel residue increased at low shear rates. Material balance performed on the crosslinker indicated that a significant amount of the crosslinker was retained in the core. This amount increased at low shear rates.

Investigations on Capillary and Viscous Displacement Under Ultrasonic Waves

Abstract In this paper, the influence of ultrasonic waves on capillary and viscous displacement of oil in porous media was investigated. Capillary (spontaneous) imbibition experiments were conducted using various fluid pairs such as air-water, mineral oil-brine, mineral oil-surfactant solution, kerosene-surfactant solution, and mineral oil-polymer solution. Berea sandstone and Indiana limestone cores were used as the matrix. Oil saturated cores were immersed into the aqueous phase and subjected to high intensity ultrasound from a specially designed ultrasonic chamber. The resulting recovery was recorded against time, and compared to a control experiment without ultrasound. A substantial increase in ultimate recovery was observed for most of the fluid pairs, with some improvements in recovery rate. To further investigate whether ultrasound induces a perturbation at the liquid-liquid interface of immiscible fluids, a series of Hele-Shaw type experiments were run. The resulting fingering pattern was strongly dependent on the interfacial tension of the fluid pair, and the injection rate. Ultrasound stabilized the fluid-fluid front of high interfacial tension fluid pairs, but generated larger instabilities when interfacial tension was low. Introduction For the past four decades, researchers have explored the use of acoustic energy to improve oil recovery that could potentially be an economic and environmentally-friendly alternative to current IOR methods. Beresnev and Johnson(1) provide an extensive review of the major developments of acoustic stimulation and its limitations. Guo et al.(2) discuss recent field results of seismic stimulation in China. Despite numerous promising field trials and patents, the exact mechanism behind ultrasonic stimulations is poorly understood. Most of the findings have been speculative with little experimental verification. The reason is two-fold. Firstly, the problem is very complex, involving a superposition of several different mechanisms. Secondly, it is not certain how far an acoustic wave propagates into the reservoir, or how such propagation occurs. Ultrasonic applications are limited to the near-wellbore area due to the high attenuation through the rock or fluids. As a consequence, most research in recent years has shifted to low energy, low frequency waves that can propagate several kilometres into the reservoir. However, because low frequency waves disperse into high-frequency harmonics as they travel through a porous medium, one would still expect ultrasonic waves to be present in the reservoir. An analytical treatment of compression and shear wave propagation in saturated porous media was first developed in two classic papers by Biot.(3, 4) . Acoustic waves are usually applied in three ways: pressure pulsing, down-hole vibration, and surface vibration. Applications range from enhanced oil recovery (EOR) to well stimulation, in situ upgrading, wellbore cleaning, and soil remediation. Acoustic stimulation is believed to positively contribute to the flow of oil in porous media by:Increasing the relative permeability of the phases;Reducing the adherence of wetting films onto the rock matrix, due to non-linear acoustic effects such as in-pore turbulence, acoustic streaming, cavitation, and perturbation in local pressures(5);Reducing surface tension, density, and viscosity as a consequence of heating by ultrasonic radiation(6);Altering of rheological properties of non-Newtonian fluids;

Core Flood Evaluation of Solvent Compositional And Wettability Effects On Hydrocarbon Solvent Foam Performance

Abstract Foams are used for mobility control or blocking and diversion of injected fluids in oil recovery by gas or solvent injection. The combined effects of gas or solvent composition, the presence of crude oil, and wettability on foam flow resistance or gas mobility reduction by foam in porous media were investigated. Experiments were carried out at Rainbow Keg River conditions (85 ° C, 17.3 MPa) with a commercial surfactant formulated for hydrocarbon miscible flooding at high salinity (Chaser GR- 1080). Foam floods were performed in clean and in asphaltenetreated Indiana limestone cores containing Rainbow Keg River crude oil and injection water, using two miscible (propane and a field solvent mixture) and an immiscible (methane) solvent. Hydrocarbon solvent-foam effectiveness, asssessed by the level of gas or solvent mobility reduction by foam, is strongly influenced by solvent composition. Methane-foam Mobility Reduction Factors (MRFs) up to 74 were measured, while the solvent mixture-foam generated slightly lower MRFs up to 52. Propane-foam was comparatively ineffective with MRFs up to only six. Propane-foam effectiveness was increased significantly at lower pressure, independently of a phase change from liquid to gaseous propane. The presence of crude oil at a saturation of approximately 15% reduced the effectiveness of methane-foam. However, methane-foam displaced oil gradually, leading to improved foam performance. Oil did not affect the solvent mixture- foam or propane-foam substantially, because both solvents were miscible with the oil and rapidly displaced the oil. Foam performance was unaffected by wettability, because the surfactant reversed the wettability of the asphaltene-treated solid from intermediately wet to water-wet. Chaser GR-1080 adsorbed moderately (at approximately 0.25 mg/g) in clean and in asphaltene- treated Indiana limestone cores. Introduction Canada's improved oil production is dominated heavily by hydrocarbon miscible flooding, mostly in carbonate pools(1). Gravity override and viscous instabilities, caused by the low density and viscosity of the injected fluids, often result in poor sweep efficiency and early gas breakthrough. Foams can significantly increase the effective viscosity of a gas phase, thus decreasing gas mobility, or, if effective foam viscosity is sufficiently high, block preferential flow channels. While foams generated with nitrogen, steam, or CO2 have been extensively studied, limited laboratory(2–8) and field(5,6,9) data are available on hydrocarbon solvent-foams. The properties of solvent- foams may be different from those of nitrogen-, CO2-, or steam-foams for several reasons:Depending on reservoir conditions, a miscible solvent may be gaseous, liquid, or supercritical, and may approach a light oil phase in properties. Oil can affect foam performance strongly (and usually negatively).Solvent composition varies depending on the application, and compositional effects on foam behaviour have to be accounted for.Foam properties are determined by interfacial and thin film properties which are affected by solvent composition. These properties are not well understood or easily measured for systems containing light hydrocarbons at high temperature and pressure. This work is an investigation into the effects of solvent composition, wettability, and oil on foam performance at reservoir conditions typical for a solvent-flooded pool in Alberta.

The Influence of Reservoir Rock Properties On Ultimate Oil Recovery In Radial-core Waterfloods

Abstract The most commonly used secondary oil recovery technique is waterflooding. The effects of rock properties such as porosity and permeability and fluid properties such as viscosity have been shown by previous investigators to influence the results of waterflooding and consequently ultimate oil recovery. The objectives of this present study are to consider the influence of rock properties such as tortuosity, wettability, pore-throat diameter, pore length and surface area on ultimate oil recovery realized in radial-core waterfloods and to incorporate the results of these analyses into generalized stochastic models for waterflooding performance predictions. To accomplish these objectives, waterflood experiments were conducted in Berea sandstone and Indiana limestone radial cores. Core plugs were obtained from each of these cores and further analyzed using the Amott-Harvey method to determine wettability and mercury injection to determine surface area, median pore-throat diameter and pore length. The analyses of the data indicated that pore-size distribution in water-wet systems is the principal factor in a direct proportionality relationship between the average initial oil saturation and the average residual oil saturation. Mercury porosimetry was used to characterize Berea sandstone and Indiana limestone cores. The analyses of the results of mercury porosimetry experiments suggested that steep-convex uni-modal capillary pressure curves are characteristic of Berea sandstone. By contrast, poly-modal capillary pressure curves are characteristic of Indiana limestone cores. The results of these analyses were incorporated into stochastic models. The stochastic models indicated that oil recovery is strongly correlated to surface area, wettability, median pore-throat diameter, initial water saturation, residual oil saturation and tortuosity. Introduction The most commonly used secondary oil recovery technique is waterflooding. A prerequisite of the understanding of waterflood performance is a knowledge of the basic properties of the reservoir rock. Craig(1) indicated that these properties consist of two main types:rock skeletal, such as porosity, permeability and pore-size distribution, andcombined rock-fluid properties such as capillary pressure (static characteristics) and relative permeability (flow characteristics). Besides porosity and permeability, pore-size distribution expressed in terms of pore-throat diameter, surface area and pore length and surface rock wettability, is used to determine the mechanisms by which oil is recovered by waterflooding. The objectives of this study are:To investigate the influence of rock properties such as porosity, permeability, surface area, pore-throat diameter, pore length, wettability and tortuosity on ultimate oil recovery.To determine the functional relationships between ultimate oil recovery and these rock properties using statistical analyses.To incorporate these functional relationships into a generalized stochastic model for predicting oil recovery by waterflooding. Mercury Porosimetry Mercury porosimetry analysis is used to investigate the mechanisms of non-wetting phase trapping and the influence of rock microscopic properties on ultimate oil recovery. Lowell and Shields(2) pointed out that the experimental method of mercury porosimetry for the determination of porous properties of solids is dependent on several variables such as wetting or contact angle between mercury and the surface of the solid. To monitor changes in these variables, Ritter and Drake(3) u