A case study and methodology is presented to shed the light on the different processes followed during the placement of a non-damaging isolation barrier in a group of highly naturally-fractured and vugular gas wells. The temporary isolation aims at isolating the wellbore from the troublesome formation and allow the removal of the original completion string and install a new redesigned one. The process helped putting the wells back on production with-out the need to stimulate any of them. This helped client to reduce the overall workover cost by 40% and proved to be successful and efficient to complete the required operation in a time-efficient. The operator had 4 wells with OH sections ranging from 40-80m which were completed in the late 1990's with no production packer. To preserve wellbore integrity the completion string needed to be pulled and replaced by a string with production packer and DH gauges. Visco-Elastic Surfactant (VES) and calcium CaCO 3 (carbonate) used ubiquitously in field operations were tested for optimal design to fill highly fractured OH without damaging formation. Caliper logs were not available, and the presence of natural fractures posed a challenge to calculate the actual OH volume. A system was developed to carry the CaCO 3 into the wellbore in stages and slickline was employed to measure fill after each stage. Once the OH was filled with CaCO 3 and well would support a fluid column coil tubing was used to place an acid-soluble cement plug in the short interval between casing shoe and end of tubing (6-9m). The paper describes the optimization process followed to tune the CaCO 3 pads composition, gel composition, mixing and placement technique. The first well in the campaign required more than 10 times the theoretical volume of CaCO 3 to fill the open hole with multiple settling issues at surface. It was concluded the surfactant gel was likely carrying the CaCO 3 into the fractures. The procedure was modified to tie in a line of breaker solution to the well head allowing sufficient viscosity of the fluid to carry the CaCO 3 from surface but immediately lose viscosity and allow the CaCO 3 to settle in the open hole without being carried into the formation. Specific coil tubing procedures were employed to allow the setting of ultra-short acid soluble cement plugs (<6m). All wells were successfully isolated to allow the safe workover of the completion string and returned to production with no loss of gas flow, with-out the need to stimulate after the work over. The campaign exhibited a new method of employing existing technologies to achieve the objective in a highly challenging and relatively new oilfield of Kurdistan. The campaign also demonstrated the benefit, in terms of saving time and cost because of extensive pre-execution planning.

A case study is presented detailing the methodology used to perform the clean-out operation in a water disposal well of Khurmala Field, Kurdistan Region of Iraq. Untreated disposed water caused scaling and plugging in perforated liner and in the open hole that eventually ceased injection. Multiple attempts and investments were made in recent years to resume access to the injection zone using high-pressure hydro-jetting tools coupled with acid treatments. However, these attempts yielded futile efforts. Before proceeding with the decision of workover, it was decided to go for one final attempt to regain wellbore access using Fluidic Oscillator (SFO). Fluidic Oscillator (SFO) having pulsing, cavitation and helix jetting action was used in combination with a train of fluids consisting of diesel, 28% HCl and gel. The clean out was performed in stages of 10m, to clean the fill from 1091m to 1170m. Since the well bore was initially isolated from the injection zone, the cleanout was conducted with non-nitrified fluids. As the cleanout progressed and access to the liner and open hole was regained, the circulation of insoluble fill to surface required a lighter carrying fluid. Nitrification, volume of the fluids, batch cycling, and ROP were designed considering the downhole dynamic changes expected during each stage of the operation. The combination of SFO, the thorough selection of treatment fluids and the accurate downhole hydraulics simulations pertaining to different stages of the operation offered an effective solution and regained the connectivity between the wellbore and the injection zone. The injection rate of water increased from 0 bpm at 700 psi to 15 bpm at 200 psi. Throughout this operation, the SFO helix, cavitation, and acoustic pulse (alike) jetting proved to be more effective than other single acting rotating jetting tools. Also, Environmental impact was reduced by eliminating the need for a rig workover operation. The matching of the injection pressure when the well was first completed and the post job value indicated that the complete zone was exposed and scale deposits were removed from the critical matrix or bypassed. SFO has an effective jetting near wellbore region, while the kinetic energy transferred via fluid makes the impact stronger in the deeper region. Internal mechanism of the tool allows it to handle high pumping rate and pressures, external finishing offer multi-port orientation of outflow that allows targeting the fill in desired directions. Presently the SFO used in the case study is the only technology that has pulse, cavitation, and helix jetting structure. Also, since the tool does not require redressing, it proves to be an efficient, safe and cost effective alternative

Rock heterogeneities, such as variations in pore distribution, pore throat diameter, and initial permeability, significantly affect the outcome of carbonate matrix stimulation treatments. A better understanding of the influence of these parameters on stimulation and diversion, especially for the performance of self-diverting acids, is needed for efficient stimulation designs. Carbonate rock samples from six outcrop formations, with permeability ranging from 2 to 150 md, were used in the study. Large blocks were acquired for each outcrop, and several 1.5×6-in. core plugs were drilled from these blocks. Pore structure in each outcrop was characterized by high-pressure mercury injection (HPMI) porosimetry and flowing fraction measured with nondestructive tracer tests. Pore volume to breakthrough (PV bt ) for a viscoelastic self-diverting (VES) acid was determined at 150°F for injection rates ranging from 1 to 10 cm 3 /min. The diversion ability for the VES acid was evaluated by (1) the increase in pressure during VES acid injection and (2) the pore volumes this higher pressure was maintained. The results show that flowing fractions measured by injection of either KCl (potassium chloride) tracer in deionized water or a dilute polymer solution is an effective means for characterizing the pore structure and for predicting the pore volume to breakthrough and diversion performance of VES acids. High-permeability grainstones such as Indiana Limestone, where most of the rock porosity is accessible to aqueous fluids (high flowing fraction), have the largest pore volume to breakthrough and the largest relative pressure buildup during injection of VES acids. Low-permeability rocks with heterogeneous porosity (low flowing fraction) have lower pore volume to breakthrough and had a relatively low-pressure build-up. The results are summarized in a master-curve, which facilitates prediction of pore volume to breakthrough of VES acids from rock properties that can be measured by non-destructive techniques. Correlations for PV bt and the diversion ability of the VES acid are presented, so that the performance of these acid systems can be estimated for formation rocks where direct measuremets of PV bt or diversion are not be practical.

The Mishrif formation in west Kuwait is a tight carbonate reservoir having low oil mobility. It is fractured and heterogeneous with wide variation in porosity ranging from 10 to 25%, matrix permeability of about 0.1 to 10 md, and 20°API oil. Production tests and geomechanical study results have revealed that productivity is mostly from the high-permeability matrix and critically stressed fracture networks. Recently, the Mishrif development has been dominated by horizontal wells to maximize reservoir contact and enhance productivity. However, a challenge in such openhole completion is the stimulation strategy requiring effective diversion technology due to the uneven acid distribution along the lateral section. To address those challenges, a novel engineered workflow has been implemented relying on distributed temperature sensing (DTS) to assess the fluid coverage across the openhole section. Results enable identifying high- and low-intake zones, segmenting the uncased section into intervals requiring different levels of stimulation, and making informed decisions regarding diversion requirements. The intervention was conducted in two stages. Coiled tubing (CT) was the selected fluid conveyance method on the first stage given its capacity for more controlled fluid placement, and high-rate bullheading stimulation was selected for the second stage. During the treatment, multiple challenges were faced, mainly driven by a high-permeability streak identified by the DTS near the heel of the lateral. The CT stimulation procedures were modified on the spot, and measures were taken to minimize the impact on the thief zone, which included a combination of diversion techniques, such as high-pressure jetting, dual injection, and pumping of a near-wellbore nonreactive diverter, which is composed of a customized blend of multimodal particles and degradable fibers to minimize fluid leakoff into the high-intake zone. Likewise, real-time downhole telemetry was crucial throughout the CT stimulation because it allowed the highest injection rate possible below the preset pressure limits, continuous monitoring of downhole dynamics along the intervention, and optimal actuation of the high-pressure jetting tool. Upon completion of the CT stimulation, a second DTS log was carried out to evaluate the fluid coverage and effectiveness of the diversion strategy, enabling further adjustment of the bullhead stimulation program. This stimulation workflow implemented in west Kuwait represents a cost-effective alternative to stimulate openhole tight carbonates. This study brings new perspectives for treating complex reservoirs in the region, and shares lessons learned for future interventions.

With the expanding offshore rig activity in United Arab Emirates leading to an increased number of horizontal wells and longer drains, coupled with changing rock fabrics, it became imperative to diverge from the existing stimulation methods to deliver more consistent and reliable results. These results were achieved via the introduction of single-phase retarded acid (SPRA) and viscoelastic diverting acid (VEDA) to both active and shut-in wells offshore. The introduction of SPRA and VEDA was possible after extensive laboratory testing including core flow tests, solubility tests, emulsion tendency testing, and corrosion inhibition tests to evaluate and benchmark the performance of these blends in comparison to the existing acid recipes such as plain HCl and polymer-based diverted acid. These tests showed that a combination of SPRA and VEDA would allow maximizing lateral coverage and enhance acid penetration due to the reduced rate of reaction and chemical diversion capabilities from thief zones. Combining the introduction of SPRA and VEDA with a shift to bullheading and higher pumping rates enabled the delivery of previously unachievable production results at sustainable wellhead pressures or even well revival of shut-in wells. In addition, reduction of acid content for dolomite stimulation was possible due to the implementation of acid retardation, which also allowed protecting wellheads from exposure to higher acid concentrations while bullheading. Treatment parameters such as volumes, rates, and acid/diverter sequence and ratio were then adjusted for optimal wormhole penetration across all zones using a new carbonate matrix acidizing modeling software. Post-treatment evaluation for the cases of previously shut-in wells has proven the success of the SPRA and VEDA combination. Shut-in wells that were unable to produce sustainably at the required tubing-head pressure (production flowline pressure), were able to produce sustainably with a 100% increase in production compared to prestimulation testing. Similarly, for gas wells, the combination of SPRA and VEDA resulted in a 50% increase in production at a similar bottomhole pressure. In addition, water injectors have also exhibited sustainably increased levels of injectivity compared to prestimulation levels, leading to better sweepage. The novelty of this paper is the comparison between historical carbonate stimulation results in UAE using plain HCl acid with polymer-based diverted acid and using SPRA with VEDA. It also sheds light on the game-changing solutions that suit the ever-increasing challenges observed in offshore oil and gas wells including well placement, lithology, permeability contrast, and type of hydrocarbon within the various target sublayers.

The present paper is concerned with improving matrix acidizing in carbonate formation. For this purpose, ultrasonic waves were added to conventional matrix acid stimulation to increase the acid reach inside the rock. This concept is based on a phonophoresis effect of the acid, applying a similar concept in pushing the stimulation acid deeper in the formation during matrix acidizing. This effect will have a great benefit in reaching larger stimulated areas and increasing the overall well productivity. Extensive laboratory experiments have shown that the rate of penetration of the acid when exposed simultaneously to ultrasonic wave irradiation reached almost 90% more than the acid only. This phenomena has been investigated through the use of CT scan analysis on the core samples. The penetration was instantaneous and rapid in reaching deeper length of the plug sample.

Matrix acidizing with fluoroboric acid (HBF 4 ) has gained special attention as not only it provides deeper penetration of in – situ generated hydrofluoric acid, but also stabilizes formation fines by binding them to the pore surface. While numerous mathematical models exist in literature for design and evaluation of conventional mud acid treatments, fewer attempts have been made in developing a lab validated model that can do so for fluoroboric acid treatments. This paper presents a novel mathematical model that has been developed taking into account the chemical kinetics and equilibrium aspects of important reactions and fluid flow inside the reservoir rock. The solution to the governing equations has been obtained through tools of computational fluid dynamics (CFD). The model has been validated rigorously through use of state-of-the-art core flooding and ion chromatography setups. The resulting simulator can be used to design an optimum fluoroboric acid treatment by analysing the effects of all the important factors including reservoir temperature, formation mineralogy and job execution details like initial acid concentration, pumping rate, job volume and shut-in time post treatment. Simulation results with the developed model indicate that although penetration of fluoroboric acid is much larger compared to mud acid, its overall effect on skin factor is inferior for temperatures less than 90 °C. Stimulation in such wells should be preferred with mud acid which can be followed by fluoroboric acid for fines stabilization. For temperatures more than 120 °C, stimulation effects of fluoroboric acid become comparable to that of mud acid. Under these conditions, it can be used as an alternate fluid to mud acid to prevent issues of secondary and tertiary precipitation. It is found that major stimulation benefits with fluoroboric acid are realized during pumping and subsequent shutting of well, which is a common practice with fluoroboric acid, has relatively smaller effect on skin factor. Apart from design and evaluation of fluoroboric acid treatments, the simulator can also be used for analyzing mud acid and mud acid followed by fluoroboric acid treatments thus enabling the user to select and design the best suited treatment for a given well.

As known, fracture's capacity and penetration are two key factors for fulfillment of the fracturing jobs including conventional and acid fracturing process. Penetration of acid into existing fractures can improve fracture capacity by etching of fracture surface. Increasing temperature of reservoir rock results in reduction of breakdown pressure. Thermo-gas-chemical technology by in-situ releasing of extra hot gases (N 2 and steam) and acid provides a series of network with long fractures and permanent conductivity. A series of experiments in high-pressure and high-temperature (HPHT) reactor were designed to understand the performance and effectiveness of thermo-gas-chemical reaction and determine the optimum binary composition in order to release maximum temperature, pressure and acid generation to provide long conductive fractures. In parallel, dependence of breakdown pressure and temperature was modeled. Moreover, to understand the geometry and propagation of fractures, the effect of thermo-gas-chemical method was studied on core samples in core holder and then cores were scanned by 4D tomography. The preliminary results showed that during the thermo-gas-chemical reaction temperature in reaction zone reaches 207 ℃ and pressure 893 psi due to reaction products. It was found that reaction initiates just after the injection of activator and temperature and pressure increased instantly. This phenomenon acts as a strong impact to break formation rock. The pH of aqueous solutions during the reaction decreased from 8 to 1 and below which provides etching the surface of existing and new fractures. Observed that thermobaric parameters of reaction closely depend on the concentration and reaction activator. Experimental results show that the application of thermo-gas-chemical fluid instead of ordinary fracturing fluid, results in reduction of breakdown pressure from 3400 psi to 121 psi, due to induced thermobaric shock. Experiments on core samples and 4D tomography confirmed the formation of new fractures and expansion of existing ones. Thermo-gas-chemical technology by generation of in-situ hot gases and acid can provide a new high efficiency, cost-effective and eco-friendly method of EOR method for tight low permeability reservoirs and even depleted reservoirs without increasing water cut.

Different applications of fracture bridging and diversion are used regularly in carbonate acid fracturing without an in-depth understanding of the physical phenomena that dominate the processes involved in the bridging and diversion process. The extension of modeling capabilities in conjunction with yard-scale and field-scale experiences will increase our understanding of these processes. A robust multimodal diversion pill and polylactic acid fiber-laden viscous acid were utilized for near-wellbore and far-field bridging, respectively. Numerous field treatments demonstrated the uncertainty of achieving effective diversion. An existing multiphysics model was extended to develop functionalities to model diversions at different scale. Extensive laboratory testing was conducted to understand the scale of bridging and diversion mechanisms. Finally, a bridging yard test was designed, and field case studies were used to integrate all the branches. Field cases showed a diversion pressure up to 4,000 psi depending on perforation strategy, pill volume, and pill seating rate. Correlations showed the interdependence of multiple parameters in diversion processes. The field studies motivated modeling capabilities to simulate the critical diversion processes at high resolution and quality. The model simulates diverting agents that reduce leakoff in the fracture area and their effects on fracture geometry. The approach considers the acid reaction kinetics coupled with geomechanics and fluid transport. Different diverting agent concentrations required for bridging can be modeled effectively. A yard test was designed to confirm the integrity of the pill material through completion valves (minimum inside diameter 9.5 mm) and analyzed with high-resolution imaging. All the theoretical, mathematical, and numerical findings from modeling were integrated with laboratory- and yard-scale experimentation results to develop and validate near-wellbore and far-field diversion modeling. Analytical correlations were formulated from injection rate, particulate material concentration, pill volumes, fracture width, etc., to incorporate and validate the model. This study enhances understanding of the different diversion mechanisms from high-fidelity theoretical modeling approach integrated with a practical experimental view at laboratory and field scale. Current comprehensive research has significant potential to make the modeling approach a reliable method to develop tight carbonate formations around the globe.

Matrix acidizing is a common but complex stimulation treatment that could significantly improve production/injection rate, particularly in carbonate reservoirs. However, the desired improvement in all zones of the well by such operation may not be achieved due to existing and/or developing reservoir heterogeneity. This paper describes how a new flow control device (FCD) previously used to control water injection in long horizontal wells can also be used to improve the conformance of acid stimulation in carbonate reservoirs. Acid stimulation of a carbonate reservoir is a positive feedback process. Acid preferentially takes the least resistant path, an area with higher permeability or low skin. Once acid reacts with the formation, the injectivity in that zone increases, resulting in further preferential injection in the stimulated zone. Over-treating a high permeability zone results in poor distribution of acid to low permeability zones. Mechanical, chemical or foam diversions have been used to improve stimulation conformance along the wellbore, however, they may fail in carbonate reservoirs with natural fractures where fracture injectivity dominates the stimulation process. A new FCD has been developed to autonomously control flow and provide mechanical diversion during matrix stimulation. Once a predefined upper limit flowrate is reached at a zone, the valve autonomously closes. This eliminates the impact of thief zone on acid injection conformance and maintains a prescribed acid distribution. Like other FCDs, this device is installed in several compartments in the wells. The device has two operating conditions, one, as a passive outflow control valve, and two, as a barrier when the flow rate through the valve exceeds a designed limit, analogous to an electrical circuit breaker. Once a zone has been sufficiently stimulated by the acid and the injection rate in that zone exceeds the device trip point, the device in that zone closes and restricts further stimulation. Acid can then flow to and stimulate other zones This process can be repeated later in well life to re-stimulate zones. This performance enables the operators to minimise the impacts of high permeability zones on the acid conformance and to autonomously react to a dynamic change in reservoirs properties, specifically the growth of wormholes. The device can be installed as part of lower completions in both injection and production wells. It can be retrofitted in existing completions or be used in a retrievable completion. This technology allows repeat stimulation of carbonate reservoirs, providing mechanical diversion without the need for coiled tubing or other complex intervention. This paper will briefly present an overview of the device performance, flow loop testing and some results from numerical modelling. The paper also discusses the completion design workflow in carbonates reservoirs.

Acid fracturing is a preferred method of stimulating low permeability limestone formations throughout the world. The treatment consists of pumping alternating cycles of viscous pad and acid to promote differential etching, thereby creating a conductive acid-etched fracture. Acid-type, pad and acid volumes, and the injection rates in the designed pump schedule are based on treatment objectives, rock-types and in-situ conditions such as temperatures, in-situ stress, proximity to water-bearing layers, and others. During the acid fracturing treatment, the acid-rock interaction is often marked by signature pressure responses, that are a combined outcome of acid reaction kinetics, responses to changes in fluid viscosity and densities, fluid-frictional drop in narrow hydraulic fractures, and other such parameters. This paper focuses on interpretation of bottomhole pressures during acid fracturing treatment to separate these individual effects and determine the effectiveness of the treatment. Unlike propped fracturing treatments where most fracturing treatments result in net pressure gain, acid fracturing treatments seldom result in net pressure increase at the end of the treatment because the in-situ stresses are generally relieved during the rock-dissolution and fracture width creation process that results from acid-mineral reactions. Not only is the extent of stress relief evident from the difference in the start and the end of the treatment instantaneous shut-in pressures, the loss of stresses is also apparent during the treatment itself, especially in jobs where the treatment data is constantly monitored and evaluated in real-time. The study reveals that the changes in pressure responses with the onset of acid in the formation can be successfully used to determine the effectiveness of treatment design and can aid in carrying out informed changes during the treatment. Better understanding of these responses can also lead to more effective treatment designs for future jobs. The interpretation developed in the study can be applied to most of the acid fracturing treatments that are pumped worldwide.

Acid jobs with conventional acid systems like hydrochloric acid in high temperature conditions is challenging on various fronts. Enhanced reactivity of strong acids results in poor penetration and severe face dissolution. Also, it aggravates the issue of corrosion of downhole equipment and may also result in sludge formation/asphaltene deposition. Worldwide, chelating agents has emerged as a standalone stimulation fluid for high temperature acidizing. Their unique attributes and properties have been proved very useful for acid jobs at elevated temperatures. However, the chelating agents-based formulations need to be carefully evaluated on various acidization parameters for a fruitful stimulation. Mumbai Offshore field has been encountering the above-mentioned problems in acidizing of its high temperature (>275°F) limestone reservoirs. The paper presents innovative solutions devised for high temperature matrix acidizing. Two chelating agents viz., EDTA (Ethylenediaminetetraceticacid) and GLDA (L-Glutamic Acid N, N-diacetic acid) were explored and evaluated with meticulous laboratory studies. The performance of the chelating agent-based stimulation fluid was compared with acetic acid. Slurry tests were performed to quantify the dissolving power of each acid. Consequently, core flooding tests were carried out to to find the optimum pH of the chelating agents from stimulation point of view. Core flooding studies were performed at anticipated injection rates on representative core samples from a payzone A, with BHT 275-290° F, from Mumbai Offshore. pH optimized formulations were tested against N-80 metallurgy coupons at reservoir temperature for corrosion potential estimation. Also, sludge, asphaltene and emulsion formation tendencies were analyzed with representative oil samples. The results convey that both EDTA and GLDA were able to mitigate the challenges encountered at elevated temperatures. EDTA and GLDA were found to stimulate the cores with wormholes formed at wide pH range with no face dissolution observed. Chelating agents enjoyed good dissolving power with negligible corrosion rates, absence of sludge and asphaltene deposition, compatibility with formation fluid and excellent iron control properties.

This paper presents the successful stimulation workflow case for a carbonate acidizing pilot project performed in Gigante field in the Matambo block of the Upper Magdalena Valley basin in Colombia. An adecuate diagnostic, laboratory testing, treatment fluid selection, on-site QAQC and placement technique selection was fundamental to obtain a successful design and an optimized application. Gigante field production is mainly coming from Tetuan and Caballos units producing 32-degree API crude oil during several years. Specifically, in Gigante-2 ST well, oil production has declined until its commercial limit. During a candidate wells review, it was identified a previous acid stimulation treatment performed in Tobo-Monserrate formation in Gigante-1 with very poor results in oil production –short production time in natural flow– giving to this zone a low potential as oil producer and it was not considered as a primary target zone. The well was completed in its main target at Tetuan formation leaving Tobo-Monserrate behind an intermediate 7 in casing with no future expectatives to produce. After a reservoir evaluation of Tobo-Monserrate formation done in Gigante-2 ST well, it was selected as a candidate for an intermedia matrix stimulation job to evaluate the real potential of this formation in Matambo block. During this phase, reservoir samples were tested against different acid treatments in the laboratory. A gelled HCL based acid was selected based on their laboratory testing performance to delay acid reaction –improving acid penetration– and having fluid loss control to enhance reservoir coverage. The complete chemical formula was customized to match the oil-treatment compatibility. An organic solvents treatment was added to dissolve organic scale prior to the acidizing. Acid was deployed directly through a TCP string to optimatize the operational time and managing treatment rate according to the pressure behavior. During the acid pumping, a pressure drop is observed and treatment rate was increased to generate rate diversion. Gigante-2 ST well came in production at natural flow reaching 502 BOPD and 105 MSCFD evaluated after 35 days of the stimulation job proving and adding important hydrocarbon reserves from Tobo-Monserrate formation. A post job evaluation using a specialized chemical stimulation simulator shows a significant skin removal. Measured treatment pressure and rate were matched with the simulated parameters resulting in −3.24 of skin value post acid stimulation having a productivity improvement factor of 4.35 and an average wormhole penetration estimated from 60 to 75 in into the reservoir. A correct diagnostic, reservoir understanding, design, laboratory testing, execution and post job evaluation was the right route to obtain a successful stimulation job in operational terms and production results. This paper is intended as a guideline for stimulation jobs in future interventions where the exact reservoir mineralogy is unknown. It shows a step-by-step methodology, a customized acid formula and finally, stimulation results as well as recommendations and learned lessons.

Most lab-scale acidizing experiments are performed in core samples with 100% water saturation conditions and at pore pressures around 1100 psi. However, this is seldom the case on the field, where different saturation conditions exist with high temperature and pressure conditions. Carbon-di-Oxide (CO 2 ), a by-product evolved during the acidizing process, is long thought to behave inertly during the acidizing process. Recent investigations reveal that the presence of CO 2 dynamically changes the behavior of wormhole patterns and acid efficiency. A compositional simulation technique was adopted to understand the process thoroughly. A validated compositional numerical model capable of replicating acidizing experiments at the core-scale level, in fully aqueous environments described in published literature was utilized in this study. The numerical model was extended to a three-phase environment and applied at the field scale level to monitor and evaluate the impacts of evolved CO 2 during the carbonate acidizing processes. Lessons learned from the lab-scale were tested at the field-scale scenario via a numerical model with radial coordinates. Contrary to popular belief, high pore pressures of 1,000 psi and above are not sufficient to keep all the evolved CO 2 in solution. The presence of CO 2 as a separate phase hinders acid efficiency. The reach or extent of the evolved CO 2 is shown to exist only near the damage zone and seldom penetrates the reservoir matrix. Based on the field scale model's predictions, this study warrants conducting acidizing experiments at the laboratory level, at precisely similar pressure, temperature, and salinity conditions faced in the near-wellbore region, and urges the application of compositional modeling techniques to account for CO 2 evolution, while studying and predicting matrix acidizing jobs.

The success of stimulation fluid placement in openhole extended reach wells (ERWs) through coiled tubing (CT) is highly dependent on the depth achieved. Friction forces and helical buckling typically cause early CT lockup, which limits the reach. Organic deposits in the wellbore increases frictional forces causing premature lockup or in some cases even complete blockage. Efficient removal of organic deposits enables CT to reach maximum depth to perform the matrix stimulation. Analysis of these organic deposits was conducted and following a thorough comparative test, a new solvent-external phase emulsion inhibitor was selected to treat the wellbore prior to matrix stimulation. Optimum cleanout methodology was identified for the CT run with a high-pressure jetting nozzle (HPJN) combined with a chemical dissolution effect of the chosen solvent. Focused, high-energy fluid streams loosen any compacted deposits, while the high rate of fluid passing through the tool allows for an efficient cleanout. A matrix stimulation treatment with CT was then executed in the openhole section of the ERW with a TD of 18,773-ft (9800-ft horizontal lateral section) with HCl and emulsified acid systems. By using a solvent-external phase emulsion, only the external phase of the emulsion containing the dissolver is in contact with organic deposits; the remaining internal phase fluid is not. This therefore allows a reduction in total solvent volume. The proposed wellbore cleanout treatment with HPJN reduced the friction coefficient between CT and the completion by 10%. In turn, it was verified that during the operation, an additional 3,320 ft of reach was achieved in the openhole section. Combined with other extended-reach techniques (i.e., mechanical agitator tools, friction reducers), it allowed the 2.0-in CT pipe to reach the TD of the well (18,773 ft). These efforts together maximized the reservoir contact during the matrix stimulation in the openhole section with HCl and emulsified acid systems. Distributed temperature sensing (DTS) methodology was used with the aid of fiber optic installed CT, and the intake profile of the openhole section was mapped. Analysis of the data was applied to optimize the pumping schedule to obtain uniform production contribution across the openhole section. The systematic engineering workflow presented includes the organic deposit diagnostic procedure, laboratory testing, chemical selection, and treatment application. This yields a wellbore treatment that minimizes friction for the remainder of the operation and enables maximum CT reach. This provides more insights of integrated matrix stimulation treatment with CT to overcome the serious challenges present in extended reach openhole wells.

Controlling the reactivity of HCl is the most viable approach to successfully stimulate a high-temperature carbonate reservoir. It is essential to retard the HCl-carbonate rock reaction to achieve the optimum balance between total fluid used and enhancing well production. However, drawbacks intrinsic to the technology architectures have prevented the industry-wide adoption of these inventions. For instance, the conventional emulsified acid is well documented to exhibit high friction pressure, is cumbersome to prepare, and performance is sensitive to a multitude of parameters. The recently developed singleaqueous-phase retarded acid (SAPRA) represents one big step toward the right direction, but there is certainly ample room for improvement. This paper presents the next generation of SAPRA system and its laboratory findings. In this system, the HCl reactivity is regulated and retarded by a single, potent low-dosage additive, which is compatible with selected acid corrosion inhibitors, non-emulsifiers, H2S scavengers, and other commonly used additives, and if necessary, friction reducers as well.

Chelating agents are used to stimulate high-temperature carbonate reservoirs and remove mineral scales. For field applications, commercial chelates—EDTA, DTPA, GLDA, etc.—are commonly supplied as 3550 wt% (1.2-1.7 M) solutions and diluted two times in water. However, the dependence of the reaction rate on the concentration of chelate in solution has never been quantified. This paper focuses on determining the kinetics of calcite dissolution as a function of the dilution factor of commonly used chelates at acidic pH. Using a rotating disk apparatus, the kinetics of calcite marble dissolution in 0.10.25 M EDTA (pH=4.9-5.0), 0.1-0.25 M DTPA (pH=3.5-5.0), and 0.28-0.85 M GLDA (pH=3.7-5.0) solutions has been investigated. The dissolution of calcite in all chelates has a negative fractional-order that increases with temperature in the range -0.6 < n < -1.9. Thus, less concentrated chelate solutions react faster with calcite, and the effect of chelate dilution becomes less pronounced with a temperature increase. For example, three times dilution of pH=3.7 commercial GLDA solution—from commonly used 50 vol% (0.85 M) to 16.7 vol% (0.28 M)—increases calcite dissolution rate 8.4, 4.9, 2.7, and 2.0 times at 98.6, 116.6, 134.6, and 188.6°F, respectively. Dilution of pH=5.0 EDTA and pH=3.5 DTPA from 0.25 M to 0.1 M increases the dissolution rate of calcite 1.4-3.1 times at 98.6-188.6°F. Probable reasons for such an unusual reaction behavior are discussed in the paper. Presented results are integral for designing the stimulation operations in carbonate reservoir rocks and the removal of carbonate scales.

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.