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Fracture conductivity is a measure of the fracture ability to transfer fluids from a hydrocarbon-bearing zone to a well. Proppant embedment in soft formations and rock weakening due to the acid/rock reaction limit the stimulation success resulting in sharp fracture conductivity decline. The focus of this study is to increase the rock strength by mineralogical alteration aimed at sustaining long-term fracture conductivity. To achieve these, several standard cylindrical Indian limestone plugs with diameters of 1.5 and 2.5 in and length of 3 in were treated with different types of zinc solutions to substitute calcium with zinc in calcite crystals. The goal of these mineral alterations is to change the principal component of limestone rocks surface, calcite (CaCO 3), into smithsonite (ZnCO 3). Smithsonite is harder than calcite and its lattice system is similar to calcite. The treatment was carried out by full immersion of samples into zinc solutions at a predetermined time intervals. The rock strength was measured from samples surface (Young's modulus) before and after the treatment by a non-destructive technique using an impulse hammer. Zinc sulfate solution was found to enhance the rock hardness by values ranging from 25% to 35% via the formation of a layer of smithsonite on the sample's surface. SEM, XRF, XPS and FIB-SEM experiments were conducted to understand the exchange mechanism that eventually led to the hardening. Also, effective porosity and permeability were measured before and after the chemical treatment to investigate its impact. A field-scale modeling study of rock hardness impact on productivity is provided as a preliminary proof of concept. • Improving hydraulic fracture conductivity in carbonate minerals by forming harder ones was proved to be possible. • Rock surface Young's modulus improved significantly when calcite minerals were replaced with smithsonite. • Hi-Res XPS, XRF, SEM, and FIB-SEM experiments were conducted to understand the exchange mechanism. • Automated impulse hammer measurements were taken to prove the increase in rock hardness. • Numerical simulations proved that enhancing the rock hardness could improve the fractured well productivity. [ABSTRACT FROM AUTHOR]

Fracture conductivity is a fracture's capacity to deliver fluids from the hydrocarbon reservoir to the wellbore. Sustaining long-term fracture conductivity results in better well productivity and reserve recovery. Harder rocks tend to sustain conductivity better than do weak and ductile rocks because they are less likely to suffer from proppant embedment and the crushing and creeping of asperities. This study shows that the hardness of carbonate rocks can be improved significantly when they are treated with carbonate-consolidating chemicals. Ideally, this should be done without damaging the matrix permeability. This research tested the capacity of microemulsion, calcium hydroxide (Ca(OH) 2) nanoparticles, and tetraethyl orthosilicate (TEOS) to consolidate carbonate rocks. These are all believed to improve rock hardness by enhancing carbonate grain attachment. The treatments were applied to cores and slabs of Mississippian Indiana limestone and permo-carboniferous Khuff carbonate rocks. These chemicals were tested by either impregnation or complete immersion of the rock sample in a solution. SEM, X-ray fluorescence, porosity, permeability, and rock hardness were all measured before after the treatment. It was observed that the rock surface Young's modulus could be improved by 10%–38%. Matrix permeability was reduced by 50% when Ca(OH) 2 nanoparticles were tested. Nevertheless, the TEOS improved the carbonate rock's hardness and permeability 18% and 44%, respectively. A modeling study has also been provided to explain the impact of fractured rock strengthening on productivity improvement. • TEOS is an efficient chemical for strengthening of carbonates. • Ca(OH) 2 nanocrystals consolidate carbonates. • Treatments lead to an increase in Youngs modulus of up to 38%. • Permeability is improved in the case of TEOS treatments. [ABSTRACT FROM AUTHOR]

Sandstone acidizing treatments are conducted to remove the damage in the near-wellbore area and restore the well productivity. Clays and feldspars are abundant in sandstone formations and they have very large surface area compared to quartz and this will deplete the injected HF acid and prevent its deep penetration to remove the damage. There are several environmental and formation damage concerns with the existing retarders such as aluminum chloride, boric acid, and phosphonic acids. In this study, a newly synthesized cationic gemini surfactant was investigated as a new retarder during sandstone acidizing using HF/HCl mud acid system. The new surfactant adsorbed on clays and feldspars surfaces and prevent their reaction with the HF/HCl mud acid. This will allow for more reaction with silicate and the acid can penetrate deeper and remove the damage. Coreflooding experiments were conducted using 12-inch long Scioto sandstone cores with very high clay contents. This work also included a numerical modeling study of the mud acid reactive transport in sandstone. The calibrated model was then implemented to predict the new surfactant impacts on the mud acid penetration and permeability enhancement at field-scale. Numerical simulation was done on the core and field scales. Coreflooding experiments showed that, flushing the rock sample with a 0.5 wt% solution of the new surfactant before the acid treatment minimized the interactions between both HCl and HF with clays and feldspars. This was confirmed by the pressure drop profile during the treatment, ICP cation analysis, and HF concentration collected from the coreflooding effluent. The numerical study showed that the new surfactant could reduce the minerals' surface area exposed to the mud acid by five times. The field-scale simulations showed that the new system would result in an important increase in the acid penetration length and permeability improvement. • Synthesis of new cationic gemini surfactant for acid stimulation. • A new acid retarder system for deep penetration of HF/HCl mud acid system. • New retarded acid system can penetrate twice the distance penetrated by the conventional mud acid. • Numerical modeling study of the mud acid reactive transport in sandstone. • The numerical model could capture the full concentration profile of the new system. [ABSTRACT FROM AUTHOR]

Acid reactivity with dolomite is more sensitive to temperature as compared to calcite formations, resulting in different dissolution profile. Acid fracture fluids are heated inside the fracture, as it flows away from the wellbore, due to the reservoir heat flux. This causes a sharp increase in dolomite reactivity, resulting in a bell-shaped conductivity profile along the fracture half-length. The productivity of such conductivity distributions will be wrongly estimated if a single average conductivity value is used. In the present research, a reservoir simulator that includes variable fracture conductivity was coupled with an integrated acid fracture model. Also, design guidelines for acid fractures in dolomite formations have been proposed. Case studies are presented, showing that in conventional acid fracture designs, the maximum dissolution in dolomite usually occurs away from the wellbore. This negatively affects productivity, as maximum conductivity is desired near the wellbore. This effect is especially significant for fracturing candidate wells in higher permeability reservoirs. This study shows that in good permeability formations, productivity can be improved by acid fractures designed at a lower injection rate. In cases where the desired injection rate is not sufficient to propagate the fracture, good productivity can be obtained by using two acid stages with different injection rates. A higher injection rate is employed to create the desired fracture dimensions, and a smaller rate used to obtain good conductivity in the near-wellbore region. In low permeability reservoirs, it is desirable to alternate injections of retarded acid systems with pad fluid to create longer acid penetration distances. The results show that, in certain conditions, designs following the proposed guidelines can result in substantial productivity improvement compared to the conventional approach. • Temperature-dependent reactivity is important when acid fracturing dolomites. • High injection rates result in small near-wellbore conductivity in cold dolomites. • Lower injection rates are preferable, especially if the permeability is high. • Using two injection rates (high/low) can improve the outcome of these operations. • Retarded acid systems are important in low permeability formations. [ABSTRACT FROM AUTHOR]

Acid fracture is a widely applied stimulation technique in carbonate formations; however, it has yet to be fully engineered. A holistic approach was taken in this study to improve the general understating of acid fracture from the field, laboratory, and modeling perspectives. Fully integrating these three elements is imperative to enhancing the performance of acid-fractured wells. The comprehensive review provided in this study will reduce the gap between job execution outcomes and acid fracture model predictions, a goal that is unattainable without knowledge of acid fracture fluid properties, potentials, and limitations. Such an understanding can be obtained from laboratory studies, as well as from job execution results. Obtaining accurate descriptions of the fluid and rock properties encountered during operation is essential. For instance, an experimental approach is applied to obtain the reaction kinetics, diffusion coefficients, and acid fracture conductivity. These, along with the fluid loss coefficient and pressure data obtained from field operations, are valuable modeling inputs. This study sheds light on improvements in acid fracture modeling capabilities made during the past several decades, as well as limitations in terms of capturing some of the fundamental physical phenomena occurring during the process of acid fracture. Essentially, a model that can predict stimulation outcomes can be used to improve the design. • Review of the fluids used in acid fracturing. • Review of the laboratory experiments to evaluate acid fracturing. • Review of the simulation models. • Review of field techniques and practices. • Recent advances in acid fracturing were reviewed. [ABSTRACT FROM AUTHOR]

Foam has many applications in the oil and gas industry, either in hydraulic fracturing, enhanced oil recovery, or drilling operations. The success of these operations depends largely on understanding the behavior of foam rheology, which is complex. The literature contains many models used to estimate the effective bulk foam viscosity; most were based on fitting parameters estimated from limited-experimental data. Nevertheless, the fitting parameters are not valid at different operating conditions such as temperature, pressure, and shear rate. This results in models with limited applicability as the laboratory conditions are hardly replicated. In this study, we generated 360 data points of effective bulk foam viscosity using the high pressure high temperature (HPHT) foam rheometer device. A wide range of conditions was examined, such as temperature, pressure, shear rate, foam quality, and composition. The gas-phase consisted of either CO 2 or N 2 , while four types of water representing different salinities were used in the liquid phase. The foam was generated using seven different commercial surfactants at different concentrations. Also, low pH chelating agent and corrosion inhibitor were added in some experiments. The data pool was analyzed using four machine learning techniques: Artificial Neural Network (ANN), Decision Trees (DT), Random Forest Regressor (RFR), and K-Nearest Neighbor (KNN). ANN showed the highest accuracy with R2 of 0.972 and 0.985 on the training and testing datasets, respectively. Also, the relative importance of features was examined using Pearson, Spearman, and Kendall correlation coefficients. The most significant parameters in reducing foam viscosity were temperature, corrosion inhibitor, and shear rate, respectively. On the contrary, foam quality positively impacted the foam viscosity, where 80% foam quality was the maximum tested condition. The impact of pressure, surfactant concentration, water type, and chelating agents were complex. This paper provides a simplified ANN-based model which can be used on the fly to predict the effective bulk foam viscosity in both laboratory and field conditions. • This research generated 360 data points of effective foam viscosity utilizing the HPHT foam rheometer. • The data pool was analyzed using four machine learning techniques. • The performance of ANN was much better than the other three techniques. • The sensitivity analysis with the proposed ANN model showed that it can predict the physics-based behavior. • An empirical model was provided in this study to predict the effective foam viscosity. [ABSTRACT FROM AUTHOR]

Foamed acid is usually an HCl acid-based stimulation fluid applied to carbonate reservoirs. However, this study investigates the rheology of a CO 2 foamed chelating agent, L-glutamic acid-N, N-diacetic acid (GLDA), that acts as less corrosive, environmentally friendly, and more stable foamed acid. Foam rheometer and analyzer were used to study the foam rheology, quality, size and structure, and half-life. Five different commercial surfactants with different chemical structures were investigated. The study was conducted at 100 °C, 1000 psi, 3.5 pH level, and various water salinity, resembling harsh reservoir conditions. The general trend showed that the higher the water salinity, the higher the effective viscosity. It also showed that the chelating agent improved the effective viscosity of the high total dissolved solids (TDS) water samples. The highest viscosity (76 mPa⋅s) was attained by mixing GLDA with a cationic alkyl diamine derivative surfactant in formation water at a 100 1/s shear rate. The prolonged constant shear rate experiments revealed that some formulations are stable for more than 8 h. The study revealed that higher surfactant concentrations did not result in improved performance. For the first time, the study reveals that chelating agents could be used as a stable stimulation foamed fluid at harsh reservoir conditions. • The rheology of chelating-based acid prepared in a different water medium, various surfactants, and at HPHT was investigated. • The study proves that a chelating agent (GLDA) can be used to create a stable and high viscosity foamed acid. • The use of GLDA improved the surfactants' viscosity values when prepared in synthetic seawater and formation water. • Adding the chelating agent in DI water decreased the viscosity values of most of the tested surfactants. [ABSTRACT FROM AUTHOR]

Matrix acidizing is a well stimulation method that is applied to enhance productivity. The success of a stimulation job depends mainly on the efficiency of the acid systems that are employed. This study investigated a new and efficient acid system that is biodegradable, not corrosive, and safe to handle. The system efficiency was compared to that of HCl and chelating agents. Acid coreflooding has been applied to chalk, dolomite, and limestone carbonate rock samples to measure the efficiency in terms of injected pore volume to breakthrough (PVBT). The rock samples were characterized in terms of porosity, permeability, composition using X-ray diffraction (XRD), and pore distribution using nuclear magnetic resonance (NMR). The effluent was collected at different times and analyzed using induced coupled plasma (ICP). Medical computed tomography (MCT) was used to visualize the interior of the rock samples after acidizing. The new acid system was more efficient in terms of acid spending than straight HCl acid and chelating agents in Indiana limestone. At the optimum injection rate, chelating agents had an optimum PVBT value of about 15 compared to 0.85 for plain HCl acid. Using the new acid system resulted in an optimum PVBT value of only 0.41, which is less than half of HCl acid. A numerical wormhole simulator was implemented to match the experimental PVBT and assess the reactivity of the acid system. • A novel acid system has been identified to be better than aqueous HCl. • A modelling approach reproduces the wormholing. • Different lithologies react (systematically) different. [ABSTRACT FROM AUTHOR]

Nuclear Magnetic Resonance (NMR) is being widely deployed as a powerful tool for estimating petrophysical properties. Compared to conventional carbonate reservoirs, sandstone reservoirs contain a high amount of paramagnetic ions (such as iron, nickel, or manganese) usually found in clays. The interpretation of NMR-derived petrophysical properties for sandstone formation can be complicated due to the paramagnetic ions which cause inhomogeneity in the magnetic field called internal gradient. Earlier studies focused on investigating the impact of clays and field strength on internal gradient, but implications for estimating NMR-derived petrophysical properties are not well understood yet. This study aims to investigate the impact of the internal gradient and magnetic field strength on the T 2 relaxation times and the NMR-derived porosity, T 2 logarithmic mean value (T 2,LM), and permeability. NMR T 2 measurements at several echo times were performed to evaluate the internal gradient for six sandstone samples characterized by variable porosity, permeability, and clay contents/mineralogy. The analysis was executed at two different operating Larmor frequencies (2 and 12 MHz), which are the most common frequencies for rock core analysis. The results show that the internal gradient magnitude increases with the increase of the paramagnetic-rich clays (Chlorite and Illite in the studied samples) while no correlation is observed with Kaolinite content. Furthermore, the internal gradient's magnitude and effect are consistently more pronounced at the 12 MHz measurements than those performed at 2 MHz. Porosity estimates from NMR are found to be independent of the internal gradient and the magnetic field strength as long as sufficiently low echo time (0.2 ms) is used. Unlike porosity, noticeable discrepancies in T 2,LM were reported between 2 MHz and 12 MHz measurements, with the later showing consistently lower T 2,LM values. The discrepancies in T 2,LM values result in significant differences (up to 300%) when calculating NMR-derived permeability using the same formulations for both 2 and 12 MHz data. That is, calibration done using the T 2 data from 12 MHz equipment cannot be applied for permeability estimation from lower field NMR data (like logging NMR). The discrepancies between 2 and 12 MHz in terms of T 2,LM and derived-permeability increase exponentially as the internal gradient increases but such discrepancies diminish for tight rocks (permeability < 1 mD). This behavior of the tight sandstone samples is attributed to the relaxation regime, which is impacted by pore sizes. If pores are small enough, such as the case occasionally for shale or tight sandstone, relaxations move from a short time regime to the motionally averaged. In such a regime, the internal gradient is averaged by diffusion over the length scale, meaning that relaxation time has no dependence on echo time. • Relationship between clay, internal gradient, magnetic field strength, and NMR-derived properties has been investigated. • Internal gradient magnitude increases with the increase of paramagnetic-rich clays. • Porosity estimates from NMR are found to be independent of the internal gradient and magnetic field strength. • Significant discrepancies in T 2,LM and permeability were reported between 2 MHz and 12 MHz measurements. • T 2,LM discrepancies (between 2 and 12 MHz) diminish for tight rocks (permeability < 1 mD). [ABSTRACT FROM AUTHOR]