This study aims at evaluating the mechanical integrity and the changes in the pore system of illitic sandstone formations being treated with HF acid generated in-situ and thermochemical fluids ( TCF ). Firstly, the acid-generating fluids were injected separately inside the core within a typical core flooding experiment. After that the core permeability, NMR porosity and rock static and dynamic parameters such as rock strength ( UCS ), dynamic Young's modulus, Poisson's ratio, shear modulus and bulk compressibility were evaluated before and after the treatment. Sand production prediction model was used to examine the potential of sand production problems for the cores treated with the in-situ generated acid ( ISGA ) and the TCF . Treating Scioto cores with the ISGA only led to permeability enhancement with final to initial permeability ratio K f i n a l K i n i t i a l of 1.2. In addition, treating the same cores with acid generating fluids and thermochemicals resulted in higher permeability enhancement with K f i n a l K i n i t i a l of 485. This higher enhancement in the formation permeability was attributed to the creation of some microfractures as was proved using the NMR scans. There was a reduction of the cores' static and dynamic parameters after being treated with the ISGA. This reduction was even higher after treating the core with thermochemical fluids. However, the sand production prediction model stated that the reduction in rock mechanical parameters would not lead to sand production problems.

Corrosion inhibitors currently used in the oil and gas industry are associated with environmental concerns and severe health risks. Recent advancements in corrosion inhibition technology had successfully tackled environmental concerns, but still faces issues with toxicity and performance at high temperatures. This work aims to develop environmentally friendly and non-toxic corrosion inhibitors that can overcome these limitations. Extracts of 14 common fruits were tested as sources of potential corrosion inhibitors. In order to determine the inhibition effectiveness of the different fruits, N-80 coupons were exposed to 15 wt.% HCl solutions at temperatures between 77-250 °F with 0.2-2 wt.% of dried ground fruit for 6 hours. In addition, a control solution containing no corrosion inhibitor was used to establish a corrosion rate for a base case. Upon identifying high performing dried ground fruits, extracts of these fruits were subsequently tested to save cost by minimizing quantity needed while achieving acceptable performance. At a concentration of 2 wt.%, fruits 1 and 2 were found to perform the best, exhibiting more than 98% corrosion inhibition efficiency at 77°F. Fruits 11 and 12 were observed to perform the worst, going so far as to enhance corrosion on the coupons. At 150°F, the corrosion rate of fruit extract 1 was 0.00436 lb/ft 2, while that of fruit extract 2 was 0.0277 lb/ft 2 . At 200°F, the addition of a corrosion inhibitor intensifier resulted in a corrosion rate of 0.00130 lb/ft 2 for fruit extract 1 and 0.0173 lb/ft 2 for fruit extract 2. At 250°F, a second corrosion inhibitor intensifier was used. The resulting corrosion rate was 0.0320 lb/ft2 for fruit extract 1 and 0.00963 lb/ft 2 for fruit extract 2. These results show that a naturally occurring, green, non-toxic corrosion inhibitor can be developed from these fruits and can comfortably pass the industry requirement of achieving corrosion rates below 0.05 lb/ft 2 for low carbon steel tubulars. Corrosion during acid treatments causes destruction to the tubulars and downhole equipment. Consequently, this leads to an increase in expenditure to maintain well production rates and well integrity. Therefore, corrosion inhibitors must be included in any acid treatment formulation. The results in this work share two new naturally occurring, green, non-toxic, high-temperature stable corrosion inhibitors that can be developed from fruits and can successfully protect the tubular during acid treatments.

Hydrocarbon production enhancement by means of acid stimulation in Kazakhstan requires application of a more effective approach to address challenges associated with acid placement and reservoir contact in long pay zones of high-temperature carbonate reservoirs, thereby improving return on investment. Several robust chemical product solutions, coupled with comprehensive modeling in a new advanced simulator, have been successfully implemented to tackle the challenges and successfully increase the efficiency of matrix acidizing. To improve the productivity of stimulated wells by improving the effectiveness of acid treatments, a detailed study of reservoir rock and its reaction to various acid and fluid systems has been made via laboratory testing and software modeling. Sensitivity analyses involving multiple treatment schedule scenarios incorporating various acid and diverter fluid systems are considered. Enhanced modeling of a novel retarded acid, viscoelastic diverting acid and particulate diverting systems demonstrated more uniform zone coverage, as well as deeper wormhole penetration. The above optimizations were field tested in several oil fields. Prior to any acid stimulation, the formation injectivity and damage profiles were calibrated based on the well pre-treatment production profile taken from production logs. As the first step, performance of the retarded acid was tested in several treatments. The bottomhole injection pressure decline behavior indicated that a slower reaction takes place during injection of the retarded acid compared to the stages of conventional hydrochloric acid, confirming the retarded nature of the acid as seen from the core tests. Secondly, viscoelastic self-diverting acid was added to the schedule for treatment of long intervals, replacing conventional gelled acid with shorter viscosity peak and lower retained permeability features. Better zone coverage, observed from injection pressure slope changes upon arrival of each diverter stage downhole, and improved post-acidizing formation cleanup were achieved as a result of this implementation. Third, field trials were made using combined application of the viscoelastic diverting acid and degradable particulate diverter pills. Full and uniform coverage of the entire zone of interest has been observed after pressure matching the actual treatments’ schedule and was validated by post-stimulation production logs. Field application of the approach supports the theoretical findings. Substantial improvement in well productivity was monitored after the application of each optimization step. The above approach demonstrates the value of thorough integration of laboratory testing, comprehensive software modeling and application of enhanced stimulation fluids. The efficiency of the approach is supported by multiple successful field case studies and is the recommended way forward for carbonate acidizing.

In acid fracturing treatments, the goal is to create enough fracture roughness through differential acid etching on fracture walls such that the acid fracture can keep open and sustain a high enough acid fracture conductivity under the closure stress. The viscous fingering phenomenon has been utilized in acid fracturing treatments to enhance the differential acid etching. For relatively homogeneous carbonate reservoirs, by injecting a low-viscosity acid into a high-viscosity pad fluid during acid fracturing, the acid tends to form viscous fingers and etch fracture surfaces non-uniformly. In order to accurately predict the acid- fracture conductivity, a detailed description of the rough acid-fracture surfaces is required. In this paper, we developed a 3D acid transport model to compute the geometry of acid fracture for acid fracturing treatments with viscous fingering. The developed model couples the acid fluid flow, reactive transport and rock dissolution in the fracture. Our simulation results reproduced the acid viscous fingering phenomenon ob-served from experiments in the literature. During the process of acid viscous fingering, high-conductivity channels developed in the fingering regions. We performed parametric studies to investigate the effects of pad fluid viscosities and acid injection rates on acid fracture conductivity. We found that a higher viscosity pad fluid and a higher acid injection rate help acid to penetrate deeper in the fracture and result in a longer etched channel.

This paper presents the first application of metal expandable frac packers for multistage acid fracturing (MSF) completions. This technology significantly reduces deployment risk commonly associated with openhole (OH) MSF completions with the ability to rotate while running in hole without any risk of premature expansion or compromising integrity of the sealing mechanism. Additionally, it improves efficiency of fracturing operations in tight gas reservoirs with the ability to expand to larger borehole diameters than is possible with current isolation packer technologies. The overall deployment method for this technology is similar to traditional openhole multistage fracturing completions that are industry standard. The main difference is that the isolation packer used is expanded by pressure to mechanically deform the metal sleeve to provide sealing against the open hole. The technology comprises an innovative material and design that can hold high differential pressure at high reservoir temperatures while maintaining permanent isolation in a relatively compact element length. The metal expandable frac packer completed an extended qualification process, including American Petroleum Institute (API) testing, to fulfil deployment and acid fracturing completion requirements. The outcome was an overall successful deployment and stimulation operation of multistage completion with the metal expandable frac packer. The metal expandable frac packer provided the ability to deploy the lower completion in difficult wellbore conditions with ability to rotate. The metal expandable frac packer is set with pressure; therefore, there is no waiting time to have full differential pressure capabilities for the fracturing operations. This technology provided a flexibility factor for packer placement as the metal expandable packer technology can hold its rated pressure at larger borehole diameters. Since the mechanism of the metal packer is expansion by inelastic deformation, the metal expandable sleeve conforms perfectly to the geometry of the borehole, providing a highly reliable seal for high pressure fracturing operations. Through a complete diagnostic process, it was confirmed that the metal expandable packers successfully isolated each stage of the stimulation treatment. Metal expandable frac packers unique testing was conducted in the laboratory and in field to qualify the technology with special focus on the chemical composition for the fluids encountered for the deployment, stimulation, and production environments including high concentration acid fracturing applications. The metal expandable sleeve technology utilizes a unique double-sleeve system for pressure compensation to enhance the sealing integrity of MSF stimulation operations and truly provide 10,000 psi under API 19OH V1.

A paper presents results of an industrial application of an innovative technology for oil and gas producing wells stimulation. Also, research results of a laboratory study of ESN (emulsion system with supercharged nanoparticles) physical and chemical properties under atmospheric and modeled reservoir conditions are briefly described in this paper. The technology is based on the use of an innovative emulsion system with supercharged nanoparticles (ESN) as a solution to solve two tasks at once: 1. to divert an active composition injected after; 2. to block water bearing most-permeable zones within a profile of productive interval for more than 12 months. The case studies considered in this paper focused on the technology application in two mature carbonate formations of Ural-Volga oil-gas province located in Russia. The formations have been under industrial development for almost 50 years and characterized by complicated geology and deteriorated reserves. A combination of effects of diverter and water-blocking agent, in one composition, provides significant competitive advantages, which resulted in two times increase in oil rates with a decrease in water cut of treated by the technology oil-gas producing wells. A duration of positive effect reached 14 months on average for ten treated wells, which is four times higher than a classical acidizing technology applied on the same formations. The main competitive advantages of the technology are enlarged surface charge (alteration of wettability of rock), high thermal stability (150 °C), predictable rheology (Herschel-Balkly model), reversible blocking effect and absence of negative impact on geological formation, downhole equipment and oil and gas collecting system (environmental friendly).

In carbonate matrix acidizing, the critical design parameters are interstitial velocity and pore volume to breakthrough for wormhole propagation at the optimal condition (v i,opt and PV BT,opt ). These two parameters are determined by the formation rock properties including permeability, porosity, temperature, pressure, and mineralogy, and the acid system that will be used. HCl has been the most commonly used acid in carbonate acidizing. However, the efficiency of wormhole creation using strong HCl solutions is sometimes low because the injection rate needed for optimal wormhole propagation is not attainable, especially when applied to long completion intervals and/or low permeability carbonates. High concentration HCl solutions also raise safety and environmental concerns. When retarded acid systems are used to overcome these challenges, the efficiency of acid stimulation often suffers from low reaction rate and low dissolving power. This study presents testing results of a modified acid system that has controlled reaction rate with favorable wormhole propagation characteristics, especially at low interstitial velocities. Due to the increased activation energy barriers utilized in these modified-acid systems, it is possible to control the reaction rate of the hydrogen proton and optimize the wormholing effect based on the completion method and formation specifications. Single phase modified acid systems are applicable and can be tailored for limestone and chalk formations. Laboratory linear core flooding experiments and acid jetting experiments were conducted to study the wormhole efficiency with the new acid systems. Core flood tests were designed to generate the wormhole efficiency curves and compare the results from the tests with HCl under the same conditions. Jetting experiments were conducted to evaluate the structure of cavity and wormhole development, and the results were also compared with HCl injection at similar conditions. Results from the experimental study were then used to compare the acid systems through wormhole efficiency curves and CT scans of acid dissolution structures. The experimental results showed clear advantages of the modified acid systems. The modified acids have similar or better wormhole efficiency parameters compared with HCl having comparable dissolving power. When combined with acid jetting, further improvement in wormhole growth in low permeability limestone is achieved. In addition to minimizing the hazardous exposure levels, corrosion rates, and negative HS&E properties compared with hydrochloric acid, the new acid system provides the positive aspects of solubilizing ability and reaction rates thus improving optimal wormhole conditions (lower v i,opt and PV BT,opt ). This potentially allows for better stimulation results with less fluid required.

This paper presents a detailed study on the effects of evolved CO 2 due to carbonate mineral dissolution, and its ensuing activity, during the preflush phase in matrix acidizing of sandstone reservoirs. Sandstone acidizing in the presence of different rock saturations conditions is seldom investigated. The presence of oil during preflush may change the perception of acid with carbonate minerals. The cores were acidized via coreflood experiments and validated through simulation studies using three-phase numerical model. The acid was injected into 100% brine saturated rock with 15 wt% hydrochloric acid (HCl) at a temperature of 150 F and at a back-pressure of 1200 psi. This was done to calibrate and initially test the numerical model. The numerical model was able to match the performed coreflood experiments at different saturation conditions to a good level of accuracy. The HCl-calcite and HCl-dolomite chemical reaction parameters were fixed in all cases to ensure consistency in analyses. Oil production was observed, with an average of 25% recovery of the residual oil in place at pore pressures of 1,200 psi. The swelling of oil by the soluble CO 2 was inferred as the main mechanism for additional oil production during the 15 wt% HCl injection. A direct symmetry was observed between the oil recovery and average CO 2 moles in the oil phase based on the numerical model prediction of the conducted experiments. The recovery curve flattened once surrounding oil reached its full-saturation level with CO 2 . The successful capability of the numerical model to effectively mimic the preflush stage sets a new bar in the area of sandstone acidizing. The potential of CO 2 , a by-product of acidizing, towards its contribution in swelling the surrounding oil, and thus mobilizing the trapped oil has been depicted in this study.

Acid-tunneling is an acid jetting method for stimulating carbonate reservoirs. Several case histories from around the world were presented in the past showing optimistic post-stimulation production increases in open-hole wells, comparing to conventional coiled tubing (CT) acid jetting, matrix acidizing, and acid fracturing. However, many questions about the actual tunnel creation and tunneling efficiency are still not answered. In this paper, the results of an innovative full-scale research program involving water and acid jetting are reported for the first time. The tunnels are constructed through chemical reaction and mechanical erosion by pumping hydrochloric (HCl) acid through conventional CT and a bottom-hole assembly (BHA) with jetting nozzles and two pressure-activated bending joints that control the tunnel initiation directions. If the jetting speed is too high and the acid is not consumed in front of the BHA during the main tunneling process, then unspent acid flows toward the back of the BHA and creates main wellbore and tunnel enlargement with potential wormholes as fluid leaks off, lowering the tunneling length efficiency. Full-scale water and acid jetting tests were performed on Indiana limestone cores with 2-4 mD permeability and 12-14% porosity. Many field-realistic combinations of nozzle sizes, jetting speeds, and back pressures were included in the testing program. The cores were 3.75-in. in diameter by 6-in. in length for the water tests, and 12-in. in diameter by 18-in. in length for the tests with 15-wt% HCl acid. The jetting BHA was moved as the tunnels were constructed, at constant force on the nozzle mole, to minimize the nozzle stand-off distance. Six acid tests were performed at the ambient temperature of 46F and two at 97F. The results from the acid tests show that the acid tunneling efficiency can be optimized by reducing the nozzle size and pump rate. The results from the water and acid tests with exactly the same parameters to match the actual CT operations in the field show that the tunnels are constructed mostly by chemical reaction and not by mechanical erosion. The acid tunneling efficiencies obtained from the full-scale acid tests are superior to the average tunneling efficiency of more than 500 actual tunnels constructed during more than 100 acid tunneling operations performed to date worldwide. The paper describes the full-scale water and acid jetting tests on Indiana limestone cores. The major novelty of this test program consists of performing all measurements with back pressure, unlike all previous water and acid jetting studies reported in literature, to more accurately mimic the downhole well conditions. The novel understanding of the combined effect of the nozzle size, pump rate, and back pressure significantly improves the actual acid-tunneling efficiency.

Viscoelastic surfactants (VES) have been introduced as acid divergent agents for easier cleaning and mixing advantage over in-situ gelled acid systems. Thermal stability and compatibility with the other additives, such as corrosion inhibitors, are the main problems with conventional VES. This work introduces five VES-based acid systems for diversion in matrix acidizing. A series of VES samples were developed, hereinafter named samples A, A1, B, C and C1 according to their chemical composition, and evaluated for various applications. The initial screening was conducted by viscosity measurements of the spent acid system at 150°F and shear rates of 10 and 100 s −1 . The effects of different corrosion inhibitors on the viscosity of the selected VES were then examined. The viscosity of the VES system was then measured as a function of temperature (77 to 300°F) and shear rate (10 and 100 s −1 ) to evaluate thermal stability. The diversion characteristic of the VES systems was evaluated with single core flood experiments on Indiana limestone cores with a permeability range of 10-200 md. CT-scan imaging of the cores after the acid treatment was used to evaluate the structure and the propagation of the wormhole. Dual coreflood experiments were conducted on Indiana limestone cores with permeability contrast of 1.5-50 to examine the ability of the VES to divert the acid system on heterogeneous limestone formations. Phase separation was observed during the preparation of the systems with a samples C and C1 VES samples. High viscosity was found in the case of A and B VES systems with the viscosity of 2,500, and 350 cP at 10 and 100 s −1 , respectively, at 150°F. The viscosity of the Sample A1 and B VES systems were not affected by the tested corrosion inhibitor. The single coreflood experiments revealed the ability of the VES to divert the acid system. The breakthrough injected acid volumes were 0.7 and 0.6 in the case of Sample A1 and Sample B, respectively. The wormhole tortuosity was 1.8 in sample A, compared to 1.4 in Sample B. This work introduces VES systems with superior divergent ability and viscosity measurements at high temperature even when in contact with the other acid additives, which leads to less acid spending and better wormhole structure.

A comprehensive study on wormholing has been conducted to improve the understanding of matrix acidizing in carbonate reservoirs. This work is a continuation of previous work ( Furui et al. 2012a , 2012b ). An analysis of additional experimental results as well as field measurements is provided to reinforce and extend the wormhole penetration model and productivity benefits provided by Furui et al. (2012b ). A series of small block tests and one large block test under geomechanical stresses has been conducted to characterize wormholing in outcrop chalk samples. In addition, field data including acid pumping data as well as post-stimulation pressure falloff data has been collected and analyzed to evaluate stimulation effectiveness. Pressure buildup data from stimulated wells has also been analyzed to evaluate the sustainability of the acid induced skin benefits. Production logging data has been used to investigate whether created wormhole networks have remained stable or have collapsed under production stresses. To statistically analyze the data more comprehensively, the new data was also compared to the data from other field data available in the literature. The following conclusions are drawn from an analysis of the laboratory data and field data: 1) a skin value of −4 is achievable in carbonate reservoirs by matrix acidizing, 2) the negative acid skin is relatively stable under production stresses, 3) the wormhole penetration model is proven to successfully simulate matrix acidizing processes in both laboratory scale and field scale work, 4) the small and large block laboratory tests re-confirmed wormholing efficiency which was discussed as a scale effect in previous studies, 5) an understanding of the possible range of wormhole penetration has allowed us to improve field acid treatments and reduce the risk of connecting to water. This comprehensive study includes acid linear core flooding tests, small block tests, large block tests and field measurements to thoroughly analyze acid wormholing in carbonate rock. The database can be very useful information for understanding, benchmarking and optimizing future completion/stimulation design.

Foam diversion has industry recognition as a proven approach to diversion in remedial sandstone acidizing in deep-water environments. With long intervals and large displacement volumes it is critical that a stable diverter reach the perforations with sufficient viscosity to sustain diversion effectiveness. Industry publications and laboratory testing indicate that non-stabilized foam systems tend to breakdown over time. A novel sandstone acidizing diverter (SSAD) system was recently developed and applied successfully in the field. The new SSAD system is comprised of a surfactant based gelling agent prepared in an ammonium chloride base fluid. The formulation of the SSAD system can be altered as needed to obtain desired rheology and break profile. In order to demonstrate the viscosity potential of this system, formulations without breaker were prepared in the laboratory for each specific well application at bottom-hole temperature. For instance, a formulation designed for 240 °F bottom-hole temperature, provided a stable viscosity slug of 300 cp at 100s -1 for six hour duration. The system maintained viscosity above 100 cp at 40s -1 after six hours with internal breaker. In 2015, two wells in deep water Gulf of Mexico with 200°F bottom-hole temperatures and an average perforated interval of 114 ft were treated with an organic mud acid treatment with no diverter. These zones were then re-stimulated in late 2016 with the same organic mud acid system and the new SSAD system. The initial production of the two wells treated in 2015 versus the re-stimulation treatment in 2016 showed a twofold production increase. Diversion pressure response was observed to be as high as 285 psi. The SSAD system can be applied in wells with low and elevated bottomhole temperatures up to 300°F. The SSAD system is non-damaging to the formation and will break in presence of hydrocarbons, or an internal breaker can be added for enhanced clean-up. Other features include extended fluid stability and no additional mixing equipment or personnel requirements compared to foam. The case study of the two wells in deep water Gulf of Mexico demonstrates the effectiveness of the new SSAD treatment compared to the conventional treatments without diversion being previously pumped in the Gulf of Mexico. Not only do SSAD treatments provide enhanced diversion compared to foam, on average, the cost of an SSAD system is 25% less than a treatment using foam diversion.

A new in-situ generated HCl acid was developed to overcome the fast reaction rate and high corrosion rates of 15 wt% regular HCl acidizing system. The objectives of this work are to: (1) examine the reaction rate of the new in-situ generated HCl with calcite at 100, 150, and 200℉, and (2) compare the reaction rate of 15 wt% regular HCl with the new in-situ generated HCl. The rate of the reaction of 15 wt% HCl and the new in-situ generated HCl was measured using the rotating disk apparatus (RDA). Calcite disks were used with the specifications of 1.5 in. the diameter and 0.65 in. thickness. The effects of disk-rotational speed (200-1,200 rpm) and temperature (100-200℉) were investigated. Calcium concentrations were measured in the samples collected from the RDA, which were used to calculate the rate of dissolution. The disk surface after the tests was analyzed using Scanning-Electron-Microscope–Energy-Dispersive Spectroscopy (SEM-EDS). Experimental results showed that the rate of dissolution at 100 and 150°F was controlled mainly by the rate of mass transfer of the acid to the surface. By increasing the temperature to 200℉, the overall rate of reaction for the in-situ generated HCl was mass transfer limited up to 800 rpm and surface limited above 800 rpm. Based on the dissolution rate results, the diffusion coefficient, the activation energy, and the reaction rate constant at 100, 150, and 200°F were determined for the new developed in-situ generated HCl and were compared to 15 wt% regular HCl. This study will assist in developing a more cost-effective and efficient design of acid treatments through a slower reaction rate of the in-situ generated HCl. This new in-situ generated acid system reacts slower and more efficient compared to regular HCl in carbonate and sandstone reservoirs.

Modeling of wormholing phenomenon is one of the challenging research problems due to the complexity of the process which requires coupling of multi-phase fluid flow, species transport, geochemistry, and geomechanics. There is not a single model that captures all of these aspects of the wormholing phenomenon which requires further development of more accurate 3D multiphase/multiphysics models. This challenge is the principal motive for this work. The objective of this paper is to model carbonate acidizing more accurately from a geochemical point of view. All previous numerical models consider only the acid/rock reaction and the transport of hydrogen ions only. In this work, we also account for chemical reactions between the aqueous species, including the dissolved CO2, under full-speciation transportation. This is done by solving the Reaction-Advection-Diffusion (RAD) equation not only for the Hydrogen ions, but also for all other primary species. Coupling of transport and reaction equations is done using a Sequential Non-Iterative Approach (SNIA). Aqueous kinetics are assumed at equilibrium, while rock/acid reaction is kinetically constrained. Single-phase 2D & 3D simulations of HCl injection in limestone rock are performed under a linear flow geometry. Results of the full speciation simulations are validated with previous experimental work, and compared with results from previous numerical models. This has been accomplished with special focus on the treatment design parameters; optimum injection rate, volume of acid injected to achieve breakthrough. The simulations show that; 1) the full-speciation model captures the different dissolution patterns reported experimentally, 2) confirms the existence of an optimum injection rate that corresponds to minimum volume of acid injected, 3) aqueous kinetics affect the treatment design parameters. We have performed a more geochemically accurate simulation of carbonate acidizing with HCl that takes in to account aqueous kinetics and effect of other species other than hydrogen ions. We believe that this is another step forward towards fully capturing the complex wormholing phenomenon.

Numerous carbonate matrix acidizing models have been developed to study the flow and reaction of Hydrochloric acid (HCl) in calcite, but there is a significant gap in the literature for models built to investigate wormhole propagation by alternative acidizing fluids such as organic acids and chelants. In this work, a model is developed to study wormhole propagation by these alternative fluids, using the two-scale carbonate acidizing model approach with Navier-Stokes formulation for fluid-flow description. The reaction kinetics used for acetic acid (HAc) in the model is modified to account for the slight dissociation of the weak acid in aqueous solution and a fractional order of reaction. The output from the model is compared with available experimental data in the literature for qualitative and quantitative validation. This study extends the linear first-order reaction kinetics used for HCl in previous two-scale models for the chelating agents ethylenediaminetetraacetic acid (EDTA) and diethylenetriaminepentaacetic acid (DTPA), with updated dissolution rate constants and dispersion coefficients, and the output compared with experimental data for qualitative validation. The acid efficiency curves generated from the model for acetic acid compares qualitatively and quantitatively with reported experimental data, and the numerical simulations show that a higher amount of acid will be required to reach breakthrough for acetic acid than for HCl, as expected. The model output for the chelating agents does not match quantitatively with experimental data, but the qualitative trend can be observed from the numerical simulation results. The updated reaction kinetics for acetic acid is extendable to formic acid, which is the other commonly used organic acid in carbonate matrix acidizing, to obtain an equally dependable model output. However, a more complex reaction kinetics will be required to model the multi-step chemistry that occurs in the dissolution of carbonate by chelating agents. The model developed in this study accurately captures the wormholing phenomena by acetic acid, and it can also be used to predict optimum injection rates for organic acids. The simulation results also show that the model, based on Navier-Stokes momemtum formulation, is computationally less expensive than previous models with the Darcy-Brinkman formulation, and simulations at very high injection rates with this model require less computational time than models developed with the Darcy formulation.

Carbonate acidizing restores and enhances production by dissolving a fraction of the rock to create highly conductive channels or wormholes. Most experimental acidizing studies are focused on acid injection at Constant Volumetric Rate (CVR) rather than at Constant Injection Pressure (CIP). A recent study highlighted the benefits of each injection technique for 15% wt. HCl acid. Formations with high injectivity should be treated at CVR as efficient wormholes can be propagated with less acid volume. Aditionally, the increasing injection rate characteristic of CIP can be beneficial in formations with initial low injectivity where wormhole dissolution can change from face and conical to dominant pattern. The injection rate and injection pressure for acid and chemical diverters are important variables because they affect wormholing, treatment distribution, and therefore the overall skin reduction. The primary objective of the present work is to investigate the effect of chemical diversion when acid treatments are injected at CVR and CIP. This study focused on the behavior of a Viscoelastic Surfactant (VES) based acid diverter inside the porous media and its effect on the treatment and wormhole distribution for low and high injectivity formations. A core-flood study was conducted using Pink Desert Limestone cores with similar permeability to assess the pressure response of the diverter at CIP. Additionally, a 2-D wormhole model was used to describe the acidizing phenomena. This model captures the acid reaction and chemical diversion coupled with Darcy flow. Synthetic scenarios were created to evaluate the effect of each acid injection technique (CVR and CIP) and diversion staging on the post-treatment skin and wormhole length. The results of these simulations showed that proper staging of a the chemical diverter aided to improve the treatment placement injected at CVR in a long, highly permeable and homogenous zone as shown by smoother wormhole and skin profiles. CIP delivered nearly uniform treatment placement without chemical diverter when applied at the highest rate below fracture pressure in a long, homogenous and low permeable zone. For a synthetic case of a long and heterogeneous treatment zone, this study confirmed that CIP generated branched wormholing in the high-permeability zones in the early stages of a treatment sequence and did not significantly reduce the skin in the low injectivity layers. Fluid placement turned less efficient as the injection rate increased over the course of the treatment. Based on these results, the simulation outputs suggest that CIP is not an effective diversion technique in long treatment intervals with significant injectivity contrast. Additionally, it was observed that the inclusion of diverter stages can improve the treatment distribution.

Carbonate rocks have complex heterogeneities that result from syn- and post-depositional stressors. These heterogeneities invariably affect the movement of fluid through the formation. When considering an acid treatment procedure, care must be taken to optimize the acid concentration and pumping schedule to encourage the formation of wormholes. Despite the abundance of carbonate formations (60% of conventional reserves), there is little consensus on the effect of physical formation properties related to acidizing efficiency. This study characterizes the pore-size distribution for different carbonates and evaluates how the optimum pore volume to breakthrough, PV bt,opt , and the optimal interstitial flux, v i,opt , are related to various physical properties of the rock. The pore-size distributions evaluated in this study are constructed with micro-computer tomography (micro-CT) imaging, a non-invasive X-Ray imaging technique pioneered in the medical field. Micro-CT is improved over medical CT because it can scan at higher energies and higher resolution. In this work, resolution for scanned samples range from 5-8 μm/voxel and sample sizes are approximately 1cm 3 . Image processing is applied to the raw CT data to segment pore space from the surrounding matrix. Object counter software is used to identify and measure individual pores, which can then be organized into a pore-size distribution. Statistical parameters are calculated by fitting a lognormal distribution function to each sample's pore-size distribution. We find that the shape of the pore-size distribution is influenced by the type of carbonate rock and that fitting the distribution yields better correlations to optimum acidizing parameters than permeability or porosity alone.

An accurate description of reactive transport phenomenon in porous media has major applications for many processes such as, contamination in groundwater resources, carbon capture and storage, enhanced oil recovery, and acid stimulation. These processes, involve surface reaction coupled with flow that result in dynamic alteration of the porous media structure. More particularly, in well acidizing, an accurate understanding and control of the stimulation operations outcomes still represents a major challenge in heterogeneous carbonates. The objective of this paper is to describe how an integrated experimental and numerical approach is adopted to develop a core-scale reactive transport simulator that could be used to investigate acidizing efficiency in carbonates. A series of core flooding experiments were performed on Richemont carbonate blocks from queries at reservoir temperature. A back pressure valve system is used to eliminate the effect of free gaseous CO 2 on the flow dynamics of acid. Moreover, mathematically, a continuum-scale model was used to describe the reactive transport phenomenon. This model consists of fluid transport, continuity, species balance, and porosity evolution equations at a continuum scale. The porous media characteristics such as permeability and pore radius are obtained as a function of local porosity using closure relations. The rock properties required as input to the model come from numerous experimental techniques such as computed tomography (CT), Mercury injection capillary pressure (MICP), and X-ray diffraction (XRD) The numerical results obtained using the model, show a close match with the experimental observations, in terms of pore volume to breakthrough (PV BT ). Additionally, the developed model was able to reproduce the different dissolution regimes along with the transient pressure response, as observed experimentally.

The complex pore structure and porosity in carbonate rocks have a strong influence on the stimulation efficiency of the acid. Recently, it was shown that nondestructive tracers can be used to predict pore volume of acid to breakthrough (PVBT) for both plain and emulsified acids [ 1 , 2 ]. The present study explores the use of digital rock technology to simulate tracer injection in carbonate rocks. The accuracy of the digital rock method is compared to the laboratory measured values for five carbonate rocks of different porosity types and heterogeneity scales. The digital rock simulations are performed by an industry-unique direct hydrodynamic pore flow simulator that operates on pore geometries from digital rock models obtained from 3D scanning electron microscope images. The pressure-volume-temperature and rheological models used in the simulator represent real treatment and reservoir fluids. Fluid-solid interactions are introduced using distributed microscale wetting properties. The simulator uses the density functional approach applied to the hydrodynamics of complex systems. The simulations are used to calculate a measure of the accessible rock volume which is then used to predict the acid response. Conventional laboratory testing methods require large volumes of formation rocks for optimization of acid type and volume and it often prohibitively expensive. The digital rock methodology has the potential of significantly reducing the required volume of formation cores, which could be an enabler for more frequent carbonate porosity specific stimulation optimization. The present study explores the limits of its applicability.

Acidizing of carbonate reservoirs is a common technique used to restore and enhance production by dissolving a small fraction of the rock to create highly conductive channels. Literature review reveals that most acidizing studies are focused on acid injection at a constant volumetric rate (CVR) instead of at a constant injection pressure (CIP). Therefore, the primary objective of the present work is to investigate the benefits and recommended applications of each technique. The study analyzes dissolution patterns, and wormhole propagation rate. A coreflood study was conducted using different Indiana limestone cores to assess both techniques. Additionally, a 2-D wormhole model was used to mathematically describe the acidizing phenomena. This model describes the reactive transport of acid as a coupling between Darcy scale flows. The algorithm captures the essential physics and chemistry of the acid reaction in a carbonate porous medium. The study confirmed that all types of acid dissolution patterns (i.e. face, conical, wormhole, and branched) exist for both techniques (CVR or CIP). Unlike in the CVR technique, dissolution patterns during the CIP technique can change, tending toward a branched dissolution regime. The CIP technique required a lower acid volume to achieve breakthrough in the conical dissolution regime and a higher acid volume to achieve breakthrough the branched dissolution regime compared to the CVR technique. In a dominant wormhole pattern, both techniques required nearly the same acid volume for breakthrough. A CT scan confirmed that the CIP technique develops a uniform wormhole at a low initial injection rate. For the CIP technique, the acid injection rate increased exponentially with the volume of the acid injected.