Indiana Limestone Cores Research Articles

A study of the optimum injection rate of carbonic acid during matrix acidizing of carbonate reservoirs: Implications for reducing CO2 emissions

This study investigates the process of optimizing the injection rates of carbonic acid during matrix acidizing in carbonate formations, highlighting its impact on wormhole formation, dissolution, and the changes in rock petrophysical properties. Indiana limestone core samples, with porosity ranging from 14 % to 16 % and permeability from 7 to 12 mD, were flooded using diffrent injection rates (0.5, 1, 2, and 5 cm³/min) to determine the optimal injection velocity. The carbonic acid is prepared by mixing 70 % fresh water with 30 % sc-CO2 at 1500 psi and room temperature. A micro-CT scan was employed to visualize the wormhole patterns, measure its size, and calculate the optimum Damköhler Number. Moreover, inductively coupled plasma (ICP) was used to measure the calcium concentrations from effluents collected at different intervals. Two models were used to ascertain the optimum injection rate; the first model based on PVBT as a function of injection rate, indicated that 2 cm³/min is the optimum injection rate with 22 pore volumes to breakthrough (PVBT). The second model considered the relationship between PVBT and interstitial velocity (Vi), leading to an optimum injection rate of 1.7 cm³/min, corresponding to an interstitial velocity of 1 cm/min. Calculations of the optimum Damkhöler number reveal a value significantly different from the 0.29 proposed by Fredd and Fogler. This study provides valuable insights into the utilization of CO2 to enhance well productivity as a replacement for conventional acids.

In-situ study of CO2-saturated brine reactive transport in carbonates considering the efficiency of wormhole propagation

Deep limestone aquifers are potential CO2 storage sites, but CO2-saturated brine reacts with the carbonate rock, changing its transport and storage properties. This study provided a preliminary investigation of the optimal injection rate of CO2-saturated brine in carbonate rocks. Indiana limestone cores were subjected to CO2-saturated brine injection at varied rates using an HPHT coreflooding setup with X-ray CT monitoring. The samples were characterized pre- and post-treatment in terms of porosity and pore size distribution using a gas porosimeter and NMR T2 measurements. Moreover, the reaction was evaluated by measuring the aqueous effluent calcium ions concentration as a function of throughput using ICP-OES analysis. A high-resolution micro-CT scan was used to capture the dissolution post-treatments and characterize the wormhole's size and patterns. Results showed that the wormholes broke through to the sample exit face after injecting 160, 48, and 36 pore volumes at 0.5, 1, and 2 cm3/min, respectively thereby revealing the importance of injection velocity. The ICP-OES analysis revealed that a larger dissolution rate was achieved at 2 cm3/min, which explained the fast wormhole propagation. An increase in rock porosity and the pore-size distributions was observed after coreflooding on all samples with minimum precipitation, as concluded from the NMR T2 relaxation time. A universal optimum Damköhler number can be obtained that enables calculating the optimum injection rate of CO2-saturated brine at different rock and fluid conditions. We speculated that the optimum Damköhler number could be different from the value of 0.29 proposed by Fredd and Fogler (1998). This study provides a preliminary understanding of the optimal CO2-saturated brine injection velocity that has an application for CO2 storage, water alternating gas (WAG) operations, and acid stimulation of carbonate formations.

Improved Amott Method to Determine Oil Recovery Dynamics from Water-Wet Limestone Using GEV Statistics

Counter-current spontaneous imbibition of water is a critical oil recovery mechanism. In the laboratory, the Amott test is a commonly used method to assess the efficacy of brine imbibition into oil-saturated core plugs. The classic Amott-cell experiment estimates ultimate oil recovery, but not the recovery dynamics that hold fundamental information about the imbibition mechanisms. Retention of oil droplets at the outer core surface and initial production delay are the two key artifacts of the classic Amott experiment. This retention, referred to here as the “external-surface oil holdup effect” or simply “oil holdup effect”, often results in stepwise recovery curves that obscure the true dynamics of spontaneous imbibition. To address these holdup drawbacks of the classic Amott method, we modified the Amott cell and experimental procedure. For the first time, using water-wet Indiana limestone cores saturated with brine and mineral oil, we showed that our improvements of the Amott method enabled accurate and reproducible measurements of oil recovery dynamics. Also for the first time, we used the generalized extreme value (GEV) statistics to describe oil production histories from water-wet heterogeneous limestone cores with finite initial water saturations. We demonstrated that our four-parameter GEV model accurately described the recovery dynamics, and that optimal GEV parameter values systematically reflected the key characteristics of the oil–rock system, such as oil viscosity and rock permeability. These findings gave us a more fundamental understanding of spontaneous, counter-current imbibition mechanisms and insights into what constitutes a predictive model of counter-current water imbibition into oil-saturated rocks with finite initial water saturation.

Investigation of the Effect of Residual Oil and Wettability on Sulfonated Polymer Retention in Carbonate under High-Salinity Conditions

Summary Polymer flooding in carbonate reservoirs is greatly affected by polymer retention, which is mainly due to adsorption by polymer-rock surface interactions. Consequently, this leads to a delay in polymer front propagation and related oil recovery response. This work investigates the effects of residual oil (Sor) and wettability on sulfonated-based (ATBS) polymer retention under the conditions of high salinity and moderate temperature. Polymer single- and two-phase dynamic adsorption tests as well as bulk and in-situ rheological experiments were conducted on outcrop carbonate cores in the presence of a high-salinity brine of 243,000 ppm at a temperature of 50°C. A total of four corefloods were conducted on Indiana limestone core samples with similar petrophysical properties. Overall, polymer adsorption was found to be low and within the acceptable range for application in carbonate reservoirs in the absence and presence of Sor. Furthermore, the polymer adsorption and in-situ rheology tests highlighted the significance of oil presence in the core samples, where retention was found to be around 40–50 µg/g-rock and 25–30 µg/g-rock in the absence and at Sor, respectively. An additional 50% reduction in retention was observed on the aged core sample that is more oil-wet. Polymer retention/adsorption was measured by double slug and mass balance techniques, and the results from both methods were in agreement with less than 7% difference. Inaccessible pore volume (IPV) was also calculated based on the double slug method and was found to be in the range of 23% to 28%, which was qualitatively supported by in-situ saturation monitoring obtained from an X-ray computed tomography (CT) scanner. The ATBS-based polymer showed excellent results for applications in carbonate without considerable polymer loss or plugging. This paper provides valuable insights into the impacts of residual oil and wettability on polymer adsorption, supported by CT in-situ saturation monitoring, which is necessary to avoid unrepresentative and inflated polymer retentions in oil reservoirs.

In-situ fines migration and grains redistribution induced by mineral reactions – Implications for clogging during water injection in carbonate aquifers

Water injection into an aquifer is generally motivated by one of three objectives: disposal, managed aquifer recharge (MAR), or aquifer storage and recovery (ASR). Any of these would be undermined if an injection well were to become clogged. This paper investigates whether mineral reactions can cause mobilization of fines and rock grains, and if so, how this would affect clogging. Injection experiments are performed on Edwards Brown (dolomite) and Indiana limestone core samples. X-ray Powder Diffraction analysis of the rocks shows that no clays are present. Filtered-deaired deionized water and pure salts are used to prepare the injection fluids. The core samples are subjected to four sequential injections of fluids: at salinities 44,580 mg/L (referred to as “seawater”), 14,860 mg/L, 7,430 mg/L, and 0 mg/L (deionized water). These salinities are selected to represent disposal, and less saline fluids to represent MAR and ASR projects. Pressure difference is recorded across the core sample at each stage and is used to calculate permeability. The effluent samples are collected to characterize produced fines and elements. The increase in the pH of the effluent samples suggest mineral reactions, which is supported by an increase in the concentration of chemical elements in the effluent samples. Scanning Electron Microscopy (SEM) images show pore enlargement due to dissolution and depict pore blockage due to fines migration, grains redistribution, and mineral precipitation. Mineral reactions dissolved the grain's surface and intergranular cement, releasing silicate fines and rock grains, which in turn reduce the permeability of the rock by 68 % to 99.9 %.

Rock-Wettability Impact on CO2-Carbonate Rock Interaction and the Attendant Effects on CO2Storage in Carbonate Reservoirs

Deep saline aquifers and depleted carbonate reservoirs are generally considered promising locations for subsurface CO2 storage. However, carbonate minerals particularly calcite can react with CO2-saturated brine, resulting in dissolution of carbonate and potentially mechanical compaction. Thus, it is crucial to understand the extent of this reaction in both water-wet and oil-wet scenarios, and subsequently its consequences on CO2 storage in depleted carbonate reservoirs. In this study, medical X-ray computed tomography (CT) was used to image water-wet and oil-wet Indiana limestone core samples before and after CO2 flooding. Changes in the rock matrix and pore structure were further assessed from the porosity and permeability data computed from the CT images. In both cases, imaging shows a significant amount of dissolution resulting in an increase in pore volume after core flooding with live brine and subsequently CO2. This increase in porosity is 46.7% and 19% for the water-wet and oil-wet core, respectively. Likewise, the brine permeability for the water-wet core increased from 9.2 mD (before CO2 flooding) to 108 mD (after CO2 flooding), whereas the permeability for the oil-wet core increased modestly from 9.0 mD to 20.1 mD. These results suggests that the reactivity is less pronounced in the oil-wet rock compared to the water-wet rock. Therefore, the wettability state of a target carbonate reservoir and the subsequent potential for the wettability state to be modified should be considered when assessing the CO2 storage capacity and integrity.

Low retention surfactant-polymer process for a HTHS carbonate reservoir

Development of surfactant formulations for high temperature (100 °C), high salinity (>50,000 ppm) and especially high hardness (>2000 ppm) reservoirs is challenging. Alkali-surfactant-polymer processes have been developed in the past, but requires soft injection brine. The objective of this work is to develop a surfactant-polymer (SP) process for a high temperature, high salinity (HTHS) reservoir that can be injected with available hard brines (such as sea water) to achieve ultra-low IFT, low residual oil saturation, and low surfactant retention in carbonate rocks. Phase behavior experiments were performed to identify a combination of anionic and zwitterionic surfactants. Four tertiary chemical corefloods were conducted in Indiana Limestone cores to test oil recovery and surfactant retention. A copolymer containing acrylamido-tertiary-butyl sulfonate, SAV10xv was identified to be stable at this HTHS condition. Sodium polyacrylate (NaPA) was identified as a sacrificial chemical to reduce surfactant adsorption. The chemical floods were successful in reducing the residual oil saturation to 8–11%. A preflush of NaPA reduced the surfactant retention from 0.133 mg/g to 0.017–0.038 mg/g of rock. Including the NaPA in the chemical slug was not as effective. The use of this surfactant formulation with a preflush of sodium polyacrylate can enhance the oil recovery in high temperature, high salinity carbonate reservoirs with very low surfactant retention.

Adsorption Study of Novel Gemini Cationic Surfactant in Carbonate Reservoir Cores-Influence of Critical Parameters.

Surfactant flooding is an enhanced oil recovery method that recovers residual and capillary trapped oil by improving pore-scale displacement efficiency. Low retention of injected chemicals is desired to ensure an economic and cost-effective recovery process. This paper examines the adsorption behavior of a novel gemini cationic surfactant on carbonate cores. The rock cores were characterized using an X-ray diffraction (XRD) spectroscope. In addition, the influence of critical parameters on the dynamic adsorption of the cationic gemini surfactant was studied by injecting the surfactant solution through carbonate cores in a core flooding apparatus until an equilibrium state was achieved. The concentration of surfactant was observed using high performance liquid chromatography. Experimental results showed that an increasing surfactant concentration causes higher retention of the surfactant. Moreover, increasing the flow rate to 0.2 mL/min results in lowering the surfactant retention percentage to 17%. At typical high salinity and high temperature conditions, the cationic gemini surfactant demonstrated low retention (0.42 mg/g-rock) on an Indiana limestone core. This study extends the frontier of knowledge in gemini surfactant applications for enhanced oil recovery.

Inorganic Acid Optimizes Remediation of Formation Damage in Carbonate Producer

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 208185, “Single-Phase Retarded Inorganic Acid Optimizes Remediation of Drilling Formation Damage in High-Temperature Openhole Horizontal Carbonate Producer,” by Ahmed Mohamed Fawzy, Noor Nazri Talib, SPE, and Ruslan Makhiyanov, SPE, ADNOC, et al. The paper has not been peer reviewed. Emulsified acid is one of the preferred choices among retarded-acid options used in Middle East high-temperature carbonate producers. However, it also brings operational complexities. The recent introduction of a single-phase retarded inorganic acid system (SPRIAS) has enabled stimulation with the same benefits as those of emulsified acids while eliminating its drawbacks. A newly drilled oil producer in one of the largest carbonate fields onshore Middle East was selected for pilot implementation of the SPRIAS. The experience gained with this pilot well confirmed the SPRIAS as a reliable option to replace emulsified acids in the region. SPRIAS The SPRIAS has the dissolution capacity of hydrochloric acids (HCl) of similar concentration. It also has a retardation factor equivalent to that of emulsified acid, which allows the creation of wormholes just as deep into the formation. Such a retardation effect was demonstrated through numerous pore-volume-to-breakthrough (PVBT) coreflow experiments at downhole conditions. Fig. 1 shows such a PVBT experiment with 15% HCl, emulsified acid, and a SPRIAS of similar HCl acid concentration on a 1-in.-diameter×6-in.-long, 8-md Indiana limestone core at 250°F. The PVBT of the emulsified acid and SPRIAS are significantly smaller than that of HCl and are statistically similar. Because it is not an emulsion but a single-phase aqueous fluid, the SPRIAS also has a viscosity within the same order of magnitude as HCl. This allows the SPRIAS to be pumped at higher rates than retarded emulsified acid. For the application discussed in this study, the SPRIAS was selected to improve the stimulation of the tighter part of the wellbore because the retarded-acid system can develop deep wormholes at low injection rates.

Chemical Compositions in Modified Salinity Waterflooding of Calcium Carbonate Reservoirs: Experiment

Modified or low-salinity waterflooding of carbonate oil reservoirs is of considerable economic interest because of potentially inexpensive incremental oil production. The injected modified brine changes the surface chemistry of the carbonate rock and crude oil interfaces and detaches some of adhered crude oil. Composition design of brine modified to enhance oil recovery is determined by labor-intensive trial-and-error laboratory corefloods. Unfortunately, limestone, which predominantly consists of aqueous-reactive calcium carbonate, alters injected brine composition by mineral dissolution/precipitation. Accordingly, the rock reactivity hinders rational design of brines tailored to improve oil recovery. Previously, we presented a theoretical analysis of 1D, single-phase brine injection into calcium carbonate-rock that accounts for mineral dissolution, ion exchange, and dispersion (Yutkin et al. in SPE J 23(01):084–101, 2018. https://doi.org/10.2118/182829-PA). Here, we present the results of single-phase waterflood-brine experiments that verify the theoretical framework. We show that concentration histories eluted from Indiana limestone cores possess features characteristic of fast calcium carbonate dissolution, 2:1 ion exchange, and high dispersion. The injected brine reaches chemical equilibrium inside the porous rock even at injection rates higher than 3.5 times 10^{-3} m s^{-1} (1000 ft/day). Ion exchange results in salinity waves observed experimentally, while high dispersion is responsible for long concentration history tails. Using the verified theoretical framework, we briefly explore how these processes modify aqueous-phase composition during the injection of designer brines into a calcium-carbonate reservoir. Because of high salinity of the initial and injected brines, ion exchange affects injected concentrations only in high surface area carbonates/limestones, such as chalks. Calcium-carbonate dissolution only affects aqueous solution pH. The rock surface composition is affected by all processes.

Injectivity and Potential Wettability Alteration of Low-Salinity Polymer in Carbonates: Role of Salinity, Polymer Molecular Weight and Concentration, and Mineral Dissolution

Summary Coupling polymer with low-salinity water (LSW) to promote enhanced oil recovery (EOR) in carbonate reservoirs has attracted significant interest in the petroleum industry. However, low-salinity polymer (LSP) application to improve oil extraction from such rocks remains a challenge because of the complex synergism between these two EOR agents. Thus, this paper highlights the main factors that govern the LSP displacement process in carbonate reservoirs in terms of wettability alteration and mobility control. A series of experiments including contact angle, spontaneous imbibition, injectivity, adsorption, and oil displacement tests were performed. The impact of mineral dissolution on the polymer/brine and polymer/rock surface interactions and its possible connection to the efficiency of the LSP in carbonates was also investigated using ζ potential analysis following an elaborative procedure. All experiments were executed at elevated temperature (75°C) using two polymers (SAV10) of different molecular weights (MWs) prepared at varying concentrations and salinities. Contact angle measurements showed that increasing the polymer concentration and MW and, at the same time, decreasing the solution salinity could effectively rend homogeneous oil-wet calcite surfaces strongly water-wet. Conversely, spontaneous imbibition tests using heterogonous oil-wet Indiana limestone cores showed that the polymer viscosity and its molecular size hinder the performance of the polymer to modify the wettability of the core samples at high concentration and MW because they could limit its penetration into the porous medium. On the other hand, the results obtained from polymer injectivities showed that LSP had better propagation with lower filtration effects in comparison with high-salinity polymer (HSP). However, polymer adsorption and inaccessible pore volume (IPV) increased with the decrease of salinity. Calcite mineral dissolution triggered by LSP, which is associated with an increase in pH and [Ca2+], considerably influenced the polymer viscosity. In addition, ζ potential measurements showed that the LSP altered the rock surface charge from positive toward negative and at the same time, the Ca2+ released due to mineral dissolution could modify the polymer molecule charge toward positive. This confirms that mineral dissolution impressively results in better wettability alteration performance; however, it could lead to undesirable high polymer adsorption at low salinity. These findings provide new insight into the influence of mineral dissolution on polymer performance in carbonates. Finally, forced oil displacement tests revealed that both HSP and LSP extracted approximatively the same amount of oil. The HSP could enhance the oil recovery through mobility control. By contrast, wettability alteration could take part in the improvement of oil recovery at LSP, as proved by spontaneous imbibition tests, along with mobility control. Despite possessing high wettability alteration potential, LSP could not yield very high recovery because of its low accessibility into the porous medium. Shearing of the LSP was found effective in improving oil recovery through enhancing the polymer accessibility. This will lead us to simply say that polymer accessibility into carbonates is crucial for the success of the wettability alteration and mobility control processes, which is remarkably important not only for this specific study but also for other various polymer EOR applications.

Enhanced oil recovery with anionic and zwitterionic surfactants in carbonate rocks: A CT-aided investigation

Surfactant-polymer enhanced oil recovery (EOR) in carbonates is challenging at high salinity/hardness and high temperature conditions due to poor aqueous stability at these conditions. This work finds that a surfactant blend of zwitterionic surfactant (lauryl betaine) and anionic surfactants (carboxylate & internal olefin sulfonate – IOS) that is aqueous stable at 4–6 wt% salinity and 100 °C and has ultralow water/oil interfacial tension (IFT) to allow near-miscible water/oil displacement to enhance oil recovery. The surfactant-polymer aqueous stability is greatly improved after mixing 2 wt% oil to create a homogeneous oil-in-water microemulsion. Flow experiments are conducted at 100 °C in Indiana limestone cores with vugs and microporosity. The zwitterionic-anionic surfactant blend reduces oil saturation to 10% and drains oil in pores ≥200 nm. In comparison, the anionic blend (carboxylate + IOS) reduces oil saturation to 23% and drains oil in pores ≥1 μm. The adsorption of both surfactant blends on carbonate is less than 0.4 mg/g. Particularly, the X-ray computed tomography (CT) images show a negative correlation between pixel-wise oil saturation and porosity during oil displacements by water and by surfactant/polymer. This correlation is likely due to capillary pressure and the mixed wettability of the Indiana limestone. These results provide new surfactant formulations for EOR at extreme conditions and insights for modeling EOR in rocks with porosity heterogeneity and mixed-wettability.

Enhanced oil recovery by spontaneous imbibition of imidazolium based ionic liquids on the carbonate reservoir

Wettability alteration plays an important role in the enhanced oil recovery (EOR), particularly for the oil-wet carbonate reservoir in harsh environments. It is essential to alter the native oil-wet characteristics of the rock matrix into water-wet or intermediate-wet in an attempt to achieve the favorable EOR process. The rate of water imbibition can be greatly improved by altering the rock wettability and by reducing oil–water interfacial tension. This can be achieved by using smart water, surfactants, oilfield chemicals, functionalized nanoparticles, or a combination of these to enhance water imbibition and oil displacement. In this study, a suite of spontaneous imbibition tests was run and investigated the efficacy of eco-friendly imidazolium-based ionic liquids (ILs) on the oil-wet carbonate sample and evaluated their effectiveness for the enhanced oil recovery with the minimal concentration of ILs (≤500 ppm). In this, we have studied the various affecting parameters including; type of ILs, ILs concentration (0–500 ppm), aging time (0–8 weeks), and rock permeability (45 and 250 mD). Subsequently, two conventionally used surfactants (SDS and CTAB) were also screened for the same study in order to set the reference case. All these experiments were performed on the Indiana limestone core samples, and experimental condition was set as high temperature (100 °C) and high brine salinity (TDS: 240, 000 ppm) in order to represent the typical Saudi Arabian reservoir condition. Overall, it was observed that a maximum of 34% increment of oil recovery was recorded for IL case over the seawater. Whereas only 11% of increased recovery was achieved with the use of conventional surfactants than the seawater. It is also noted that the longer chain containing ILs had shown better recovery (34%) than the shorter chain containing ILs (27%). Furthermore, NMR T2 relaxation distribution and NMR T2D responses were acquired for the same study. This helps to estimate the rate of water invasion and oil recovery both qualitatively and quantitatively. NMR measurements confirm that seawater was ineffective in all the pores, however a very little recovery was contributed from the macropores. At the same time, ILs showed almost double the recovery compared to seawater, and all types of pores (micro-, meso, and macropores) contributed to the recovery. This suggests that ILs diffused in all type of pores due to their greater diffusiophoresis tendency than the seawater case. NMR T2D measurements correlated well with the gravimetric Amott cell imbibition test results in regards to oil and brine saturations and recovery at different stages of the imbibition process. Overall, this can be concluded that ILs are potentially strong EOR agent, which has the capability to increase the oil recovery at harsh reservoir conditions and it is cost-effective and more economically viable when compared to other conventional chemicals.

A novel retarded HCl acid system for HPHT carbonate acidizing applications: Experimental study

AbstractRetarded acid systems for high‐pressure and high‐temperature (HPHT) carbonate reservoirs are the key to provide a deep acid penetration and higher acid efficiency. The current study experimentally evaluates a new retarded HCl acid for HPHT carbonate acidizing applications. The acid retardation mechanism is attained by using a polymeric resin‐based composition that restricts the proton mobility of the acid species. Ten Indiana limestone cores were used with the dimensions of 6 in (0.15 m) length and 1.5 in (0.038 m) diameter and average permeability of 9 mD (0.009 ). Two sets of experiments were conducted, one at 250°F (394 K) and another at 300°F (422 K), with acid injection rates from 0.5–10 cm3/min (8.3E−9 to 1.67E−7 m3/s). The pore volume of acid required to breakthrough (PVBT) was monitored. Effluent samples were collected to track the pH and the dissolved material. Computed tomography (CT) was used to scan the core before and after the experiment to determine the wormhole propagation along with the core. The optimum injection rate at 250 and 300°F (394 and 422 K) were found to be 2.5 and 6 cm3/min (1.67E−8 and 1.25E−7 m3/s) with PVBT of 0.41 and 0.43 PV, respectively. The 3D CT scan showed an effective wormhole profile featuring a single dominant trajectory with few branches. These results are confirmed by calcium ion concentration profiles through inductively coupled plasma (ICP) analysis. The use of the new acid system will provide deep penetration with low injected acid volume. As a result, the stimulation job efficiency will improve.

Quantifying the Effect of Multiphase Flow on Matrix Acidizing in Oil-Bearing Carbonate Formations

Summary It is common to inject acidic stimulation fluids into oil-bearing carbonate formations to enhance well productivity. This process of matrix acidizing is designed to maximize the propagation of wormholes into the formation by optimizing the injection parameters, including acid-injection rate and volume. Previous studies have suggested that saturation conditions, permeability, heterogeneity, temperature, and pressure can significantly affect the design of matrix-acidizing treatments. However, laboratory studies’ results are inconsistent in their conclusions and are mostly limited to water-saturated cores. In this work, we designed a systematic experimental study to evaluate the impact of multiphase flow on the acidizing process when injecting 15 wt% hydrochloric acid (HCl) into crude-oil-saturated Indiana Limestone cores. The results reveal the following: Contrary to published literature for water-saturated cores, acidizing in partially oil-saturated high-permeability cores at high pressure requires less acid volume than in low-permeability cores; lower-pressure acid injection results in more efficient wormhole propagation in low-permeability cores compared to high-pressure acid injection; acidizing in low- and high-permeability cores at low pressure leads to similar efficiency; and wormholing is more effective in partially oil-saturated cores, resulting in multiple parallel branches as compared to inefficient leakoff in water-saturated cores.

A methodology for chemical formulation for wettability alteration induced water imbibition in carbonate reservoirs

Oil recovery tests are performed to evaluate the performance of different single and mixed-surfactant systems. Contact angle and O/W IFT measurements are first used to derive the capillary driving forces necessary for spontaneous imbibition. Surfactant mediated imbibition in oil-wet Indiana limestone cores resulted in additional oil recoveries over brine and the extent of oil recovery was determined by the surfactant type, initial water saturation, and brine salinity. A maximum oil recovery of 47% at 50 °C was observed for the best single surfactant system while a maximum oil recovery of 27% at 90 °C was observed for the best mixed surfactant system. It was found that the highest oil recovery occurs at intermediate water saturations. The positive effect of SO42− ions on wettability alteration is also noted with an approximately 10% incremental oil recovery observed at 1% sulfate concentration. Universal recovery curves corresponding to gravity-driven imbibition process are obtained. To obtain predictive tools for oil recovery, the ultimate oil recoveries are scaled with the capillary pressure to generate a universal oil recovery curve as a function of the cloud point temperature difference as a thermodynamic descriptor.

Propagation characteristics of optimum wormhole in carbonate matrix acidizing using micro X-ray CT imaging

This study aims to investigate the propagation characteristics of an optimum wormhole to make an efficient acid treatment in carbonate matrix acidizing based on wormhole visualization using micro X-ray computerized tomography (CT) with high resolution. Five cases comprising 25 core-flood experiments under different experimental conditions using Indiana limestone cores were carried out at various injection rates to obtain the optimum injection rates. From the results, the optimum injection rates tended to increase with permeability but was not related to acid concentrations. The pore volume to breakthrough (PVBT), the amount of acid consumption required to breakthrough, was lower at higher permeability and acid concentration. This means that less amount of acid is consumed to generate the wormholes. Wormhole visualization with X-ray CT imaging showed that the wormhole diameters were gradually reduced along with the wormhole propagation axis in all cases. In addition, the mean of wormhole diameter tended to increase according to the higher permeability and acid concentration. The tortuosity, which is the ratio of actual wormhole length to core length, was exceeded at least 1.35 in each case. This implies that the actual flow length of the optimum wormhole is much longer than the core length. However, previous studies of wormhole propagation regarding the configuration of optimum wormhole are sparse, more intensive research would be required. Therefore, these propagation characteristics of optimum wormholes should be considered to improve the wormhole prediction model, and the wormhole prediction results would be more accurate and realistic than those of the existing models. Further study is needed to develop a new wormhole prediction model considering the propagation characteristics, such as diameter reduction and actual flow length.

Direct Visualization of Ultrasonication Induced Asphaltenes Removal in Carbonate Rock Using Confocal Imaging

Asphaltenes deposition is a major issue in the petroleum industry as it can have a detrimental impact on hydrocarbon recovery efficiency. Therefore, it is imperative to study the fundamental mechanisms controlling the asphaltenes flocculation and deposition in reservoirs allowing us to prevent and possibly eliminate such problem. Hitherto many studies have highlighted ultrasonication as a potential remediation technique but no investigation has been able to provide direct visual evidence of the phenomena. The primary objective of this study is to visualize the deposition of asphaltenes and their subsequent removal by ultrasonication in Indiana Limestone using state of the art confocal microscopy. To do so, we performed a comprehensive series of experiments by flooding Indiana Limestone core samples with crude oil and later passing ultrasonic waves through the flooded sample. Four core samples of Indiana Limestone each displaying different permeability were used, these are referred to as A2, B2, C4, and D4. At each stage of experiment series of images were captured by confocal microscopy depicting asphaltenes deposition and it’s post-sonication distribution. The images were further segmented allowing us to compute changes in the asphaltenes content before and after sonication. The comparison of confocal scans reveals that the ultrasonic irradiation is highly efficient in removing asphaltenes from the low permeability core samples, whereas in the case of highly permeable cores, rather than preventing it promoted the asphaltenes flocculation. Surprisingly, an increase in asphaltenes content was observed after ultrasonication in high permeability core samples.

Experimental Study of Blending CO2 with Triethyl Citrate for Mitigating Gravity Override During Reservoir Flooding

Challenges during CO2 flooding of oil reservoirs are mobility control and gravity override caused, respectively, by lower viscosity and density of CO2 compared with reservoir fluids. Blocking agents such as foam, cross-linked polymers and gels have been tested. However, such techniques are more effective in preventing fingering and blocking thief zones than reducing gravity override. Moreover, no foaming agent has been identified to withstand the high temperatures and salinities of some reservoirs. This experimental study investigates the use of triethyl citrate (TEC) as a densifying agent to blend with supercritical CO2 (scCO2) to minimize gravity override. High-permeability, Indiana limestone core samples saturated with either dead or live light crude oils at irreducible water saturations were flooded vertically upward at 24.132 MPa and 100 °C with about one pore volume of either pure scCO2 or a scCO2–TEC blend of 0.15 mol fraction (0.525 mass fraction) TEC. At breakthrough, scCO2 flooding of dead oil recovered 14.82% of the initial oil in place, while the blend flood recovered 31.99%. At 1 PV, the scCO2 flood recovered 60.14%, while the blend flood recovered 72.67%. The live-oil-saturated core samples produced similar results but with generally lower oil recoveries. At 1 PV of fluid injected, all floods reduced the oil saturation to levels lower than the residual oil saturation achieved with water flooding. With TEC’s low solubility in both crude oil and water, blending scCO2 with TEC is, thus, a technically viable method to mitigate gravity override in CO2–EOR process.

Transport of Associative Polymers in Low-Permeability Carbonates

Carbonate reservoirs are heterogeneous from pore scale to field scale. Waterflood in carbonate reservoirs often leaves behind a substantial amount of oil due to pore-scale and large-scale bypassing. Polymer flooding can improve sweep efficiency and oil production. Most EOR polymers cannot be transported through low-permeability (< 30 mD) rocks. Hydrophobically modified associative polymers (APs) associate with each other during passage through pore throats and give a larger flow resistance than conventional polymers (Flopaam) of the same molecular weight. The goal of this work is to investigate the transport of associative polymers in low-permeability carbonate reservoirs (less than 50 md). An associative polymer similar in molecular weight to Flopaam 3330 was investigated in this study. Polymer rheology and the effect of salinity were studied at 60 °C. Mechanical shearing and aggressive filtration were used to modify the particle size distribution in polymeric solutions and improve transport through tight cores. Single-phase polymer transport experiments were performed in outcrop Edwards Yellow and Indiana limestone cores. Mechanical shear degradation reduced the particle size and improved the transport of the associative polymer in low-permeability carbonate cores. The permeability reduction factor and the residual resistance factor were higher for the sheared AP polymers than those for the sheared Flopaam polymer. The resistance factors for the associative polymer were higher than those for Flopaam for a given shear viscosity. Coreflood experiments with AP showed the evidence of two propagation fronts: polymer concentration front and pressure gradient stabilization front due to polymer network formation and polymer adsorption. As AP polymer concentration increased, permeability reduction factor, resistance factor, residual resistance factor and polymer adsorption increased. All the coreflood experiments suggest successful polymer transport in low-permeability carbonate cores even at significantly high polymer concentrations with pre-shearing.