Summary Hydrates are ice-like solids composed of a water-based lattice “encaging” gas molecules. They form under conditions of high pressure and low temperature. In the oil and gas industry, where these conditions are easily met, hydrate formation may cause pipe blockages and severe financial implications, making its prevention (and remediation) one of the main flow-assurance concerns. Desired hydrate inhibition may come from electrolytes naturally dissolved in the water that is produced in conjunction with the hydrocarbon stream, or alcohols can be deliberately injected for such a purpose. When trying to predict hydrate conditions in real-world production systems, computer simulation should ideally integrate hydrate and multiphase-flow calculations. Failing to do so [by performing a decoupled analysis with a flow simulator and a separate pressure/volume/temperature (PVT) package for example] may generate misleading results under certain flow conditions. This paper presents an integrated wellbore simulator to deal with this issue. A hydrate model is added to verify hydrate formation for specific pressure, temperature, and composition of each gridblock. Integration with a geochemical package allows consideration of electrolyte inhibition coming from the associated brine. After successfully comparing results with the available simulators and the experimental data, it is demonstrated that when flowing gas/water ratios (GWRs) exceed 10 5 scf/STB, water condensation throughout the flow may dilute the beneficial effect arising from the brine composition, thus reducing electrolyte inhibition. Conversely, mineral precipitation along the flow path has shown a nearly negligible impact on this effect.

Summary Scale inhibitor (SI) squeeze treatments are one of the most common techniques to prevent downhole scale formation. In this paper, we present the optimization of treatment design for multiple wells included in offshore campaigns. Two offshore fields with 8 and 12 production wells in west Africa were considered that are separately treated via yearly squeeze campaigns. The wells included in each campaign are treated in a single trip of the supply vessel. Based on the storage capacity of the vessel, the available volume of SI onboard should be optimally allocated to each of the wells (having different properties and water production rates), so that they are all protected from scaling for 1 year until the next campaign is carried out. A hybrid optimization methodology was applied to optimize the squeeze campaign design. The gradient descent (GD) algorithm was first applied to derive the squeeze “isolifetime proxies” related to each well. Each proxy includes all the possible squeeze designs that result in 365 days of squeeze lifetime in the well. Using these proxies, any combination of wells’ squeeze designs could be nominated as the campaign design, because that would result in treating all wells until the next campaign. The multiobjective particle swarm optimization (MOPSO) technique was implemented to optimize the campaign design by simultaneously minimizing the total SI volume and the total injection time for the whole campaign. Minimizing the total pumping time would consequently minimize the deferred oil volume and the total cost of squeezes in the field. Finally, the Pareto Front was identified for each field, showing the most optimum campaign designs. The Pareto Front was shown to be a valuable tool for the operator to make a trade-off between the size of the vessel and the injection time; that is, to use a bigger vessel to transport more inhibitor to the wells or to use a smaller one but for a longer time to inject more water during the squeeze treatments in the field. A cost analysis was performed to identify the most optimum deployment plan providing the most optimum inhibitor allocation strategy, including the optimum inhibitor volume and the optimum injection time for each campaign.

Summary Uncertainties regarding the factors that influence asphaltene deposition in porous media (e.g., those resulting from oil composition, rock properties, and rock/fluid interaction) strongly affect the prediction of important variables, such as oil production. Besides, some aspects of these predictions are stochastic processes, such as the aggregation phenomenon of asphaltene precipitates. For this reason, a well-defined output from an asphaltene-deposition model might not be feasible. Instead of this, obtaining the probability distribution of important outputs (e.g., permeability reduction and oil production) should be the objective of rigorous modeling of this phenomenon. This probability distribution would support the design of a risk-based policy for the prevention and mitigation of asphaltene deposition. In this paper we aim to present a new approach to assessing the risk of formation damage caused by asphaltene deposition using Monte Carlo simulations. Using this approach, the probability-distribution function of the permeability reduction was obtained. To connect this information to a parameter more related to economic concepts, the probability distribution of the damage ratio (DR) was also calculated, which is the fraction of production loss caused by formation damage. A hypothetical scenario involving a decision in the asphaltene-prevention policy is presented as an application of the method. A novel approach to model the prevention of asphaltene aggregation using inhibitors has been proposed and successfully applied in this scenario.

Summary What do you do after plunger lifting? What if lift gas is not readily available or your liquid level is around a bend? What can you do with a well that has low reservoir pressure, liquid-loading trouble, and fragile economics? Do you give up on the remaining reserves and advance to plugging and abandonment? These questions were considered, and the answers were found to be unsatisfactory. This paper will describe the development and testing of a novel wireline-deployed positive-displacement pump (WLPDP) that was invented to address these challenges. Artificial-lift (AL) pumps have historically been developed with high-producing oil wells in mind. Pumps for late-life wells have mostly been repurposed from these applications and optimized for reduced liquids production. The WLPDP development began with the constraints of late-life wells with the goal of addressing reserves that conventional AL methods would struggle to produce profitably. Internal and industry-wide data were first reviewed to determine what WLPDP specifications would address the majority of late-life wells. The primary target was gas wells, although “stripper” oil wells were also considered. The resulting goal was a pump that could deliver 30 BFPD from 10,000-ft true vertical depth (TVD). The pumping system must be cost-effective to be a viable solution, which led to several design boundaries. Pumps fail and replacement costs can drive economics, so the system must be deployable/retrievable through tubing. The majority of new onshore wells have tortuous geometries, so the system must be able to function at the desired depth despite them—without damaging associated downhole components. The system should use as many off-the-shelf components and known technologies as possible to reduce development costs and encourage integration. Finally, the pump should be able to handle a variety of wellbore liquids, produced gases, and limited solids. The WLPDP was designed to meet the established specifications and boundary conditions. The 2.25-in.-outer-diameter (OD) pump is deployed through tubing. and powered with a standard wireline (WL) logging cable. The cable powers a direct-current (DC) motor that drives an axial piston pump. The piston pump circulates a dielectric oil between two bladders by means of a switching valve. When each bladder expands, it pressurizes inlet-wellbore liquids, pushing them out of the well. Produced gas flows in the annulus between the tubing and production casing. The intake/discharge check valves and bladders are the only internal pump components that contact the wellbore fluids. The WLPDP system was able to meet the design-volume/pressure specifications in all orientations, as confirmed through laboratory and integration testing. Targeted studies were conducted to verify/improve check-valve reliability, gas handling, elastomer suitability, and cable-corrosion resistance. The results of these and related studies will be discussed in the paper.

Summary The use of chemical demulsifiers in the treatment of crude oil emulsions is an essential step in processing facilities worldwide. Each production facility requires specific demulsifier reformulations as the crude characteristics change. The assessment of candidate demulsifiers before online field trials is currently done with bottle tests. Such tests are manual, based on water dropout visually measured by operators. The development of a method that can automatically determine the speed and amount of water dropout without the laborious need to manually record water separation would significantly decrease human error. Pulsed field gradient nuclear magnetic resonance (PFG-NMR) is used as a classification tool to qualitatively rank the efficiency of different demulsifiers in breaking Arabian Light emulsions. This imaging method can evaluate demulsifier action based on the emulsion characteristics; for example, rate of sedimentation and coalescence and formation of a dense packed zone (rag layer). The results are validated against field trials performed in gas-oil separation plants (GOSPs) at two Saudi Arabian facilities. There was good agreement between the PFG-NMR method and field trials. The results were found to correspond to the water dropout in the first stage of crude oil treatment in processing plants (production traps).

Summary The development of concentrated and highly stable oil-in-water (O/W) emulsion is considered to be a cost-effective alternative for the transportation of produced heavy crude oils. However, the demulsification of a transported O/W emulsion is necessary once it reaches the destination. This article experimentally investigates the performance of four low-cost chemicals of varying water solubility as potential demulsifiers, independently and in combinations, for demulsifying two Indian heavy crude O/W emulsions prepared for pipeline transportation. The chemical demulsifiers used, in order of their higher water solubility, are: polyethylene glycol 400 (PEG) > polyoxyethylene (20) sorbitan monooleate (Tween-80) > linear alkylbenzene sulfonic acid (LABSA) > n -octylamine (OA). For this study, stable O/W emulsions (in the 60:40 ratio) of two Indian heavy crude oils were prepared using high-frequency ultrasonic waves in the presence of Triton X-100 as a surfactant. Both crude oils were characterized at first based on their physicochemical properties, infrared (IR) spectrum, and rheological properties. Prepared O/W emulsions were characterized based on rheological properties and droplet size. A bottle test method with heating (using a water bath) and enhanced gravity (by centrifuge) has been used to study the demulsification efficiency of used chemicals. Complete demulsification of both emulsions was achieved as desired. The synergetic effect of the interaction between two suitable demulsifiers provided remarkably better performance than that of independent returns, leading to minimization of the amount of demulsifier and the energy requirement for complete demulsification of both emulsions.

Summary An experimental and theoretical investigation of surfactant - stabilized oil/water emulsion characteristics was carried out under water sweep (WS) and oil sweep (OS) conditions. Both hydrophilic and hydrophobic surfactants were used, with concentrations less than and more than the critical micelle concentration (CMC). Experimental data were acquired for detection of the phase - inversion region, which was measured simultaneously by several independent methods. These include a circular differential dielectric sensor (C-DDS), a rectangular differential dielectric sensor (R-DDS) (both sensors accurately detect the phase - inversion region), a pressure transducer, and a mass flowmeter. The addition of an emulsifier surfactant to an oil/water mixture generated a stable emulsion, which resulted in a phase - inversion delay. For water-continuous to oil-continuous flow, a hydrophilic surfactant was a better emulsifier, while for oil-continuous to water-continuous flow, a hydrophobic surfactant was a better emulsifier for creating more stable emulsions. The surfactant/oil/water emulsion resulted in an increase of the dispersed-phase volume fraction required for phase inversion, as compared to the case of oil/water dispersions without surfactant. For emulsions with surfactant concentrations above CMC, the presence of micelles contributed to further delay of the phase inversion, as compared to those with surfactant concentrations below CMC. The phase - inversion region exhibits a hysteresis between the OS and WS runs, below CMC and above CMC, which was due to the difference in droplet sizes caused by different breakup and coalescence processes for oil-continuous and water-continuous flow. This research shows that the DDS is an efficient instrumentation that can be used to detect the region where the emulsion phase inversion is expected to occur. Moreover, the experimental results and the pertinent analysis and discussion provide useful insights for a more informed design of surface facilities (including emulsion separators) in oil and gas production operations.

Summary Injection of low-sulfate seawater (LSSW) instead of untreated full-sulfate seawater (FSSW) is widely used to mitigate barium sulfate scaling risk at the production wells. LSSW injection may no longer be required when the barium concentrations in the produced water drop below a certain threshold. Such a trigger value could be estimated from the barium sulfate precipitation tendency. Relaxation of requirements for the sulfate reduction plant (SRP) can significantly reduce operational costs. This study investigates the impact of several parameters on the timing and degree of relaxation of the output sulfate concentration by the SRP. Finally, the optimal switching strategy is proposed for a field case. The strategy for switching from LSSW to FSSW (e.g., time and method; direct or gradual increase in the sulfate concentration) was initially investigated using generic 2D areal and vertical models. The sensitivity study included the impact of reservoir heterogeneity and the initial barium and sulfate ion concentrations. Findings were later applied on a full-field reservoir simulation model followed by a mineral scale prediction software to investigate the specific switching strategy for a field that has multiple wells and significantly more complex heterogeneity. The results show that barium concentrations in the formation brine affect the choice of switching time more than the output sulfate concentration produced by the SRP. The degree of heterogeneity around the producers also has a significant impact on the switching time. Another parameter is the contrast in the permeability between layers; higher contrast allows a longer period of coproduction of the scaling ions and thus delays the switching time. In the field case, switching to FSSW at early times allows higher consumption of barium ions because of its in-situ precipitation. Barium is no longer a limiting ion, and so a higher degree of deep reservoir precipitation reduces the requirement for prolonged LSSW injection. Another strategy is a gradual relaxation of LSSW output, which allows even earlier buildup of the injected sulfate concentration compared with the direct FSSW switch. The study investigates the reservoir parameters that affect sulfate relaxation of LSSW injection for a field. After the proposed workflow, the optimal relaxation strategy can be designed for other field cases.

Summary A gel-plug system for temporary blocking technology is proposed in this paper to address the prevalent leakage of killing fluid in low-pressure wells; the low technical strength of existing gel plugs for temporary blocking in well killing; difficult-to-control crosslinking time; and gel embrittlement and the difficulty of breaking certain gel plugs. A mixture of etherified galactomannan plant gum, isooctanol polyoxyethylene ether surfactant, and oil phase was used as a thickener. An inorganic salt complex containing long-chain polyhydroxy alcohol was used as a crosslinker and the concentration of long-chain polyhydroxy alcohol far exceeds the theoretical amount required to complex the metal ion. A mixture of polyhydroxy alcohol with a small amount of weak acid was used as a crosslinking regulator. Finally, a mixture of sodium thiosulfate and long-chain quaternary ammonium salt surfactant was used as a stabilizer. Laboratory evaluations showed that this gel-plug system can be directly pumped into the wellbore after being mixed homogeneously, and the viscosity of the system on the surface can be controlled by the amount of crosslinking regulator. The viscosity of the gel-plug system after gelling was high (viscoelastic solid colloid); the initial viscosity reached 30 000 mPa·s at 120°C and retained a semisolid gel shape after aging for 72 hours. Right-angle thickening occurred when the gel warmed to target-zone temperature. The acidic liquid breaker acted quickly, and the viscosity of the broken fluid was lower than 5 mPa·s after 1 to 4 hours. This gel plug for temporary blocking and well-killing technology was successfully applied in a low-pressure, leakage-prone gas well. No gas, pressure, or liquid remained in the open well after killing, the wellhead was successfully replaced, and the tubing was successfully removed. The gel plug also exhibited self-healing: The hole formed by the tubing could be filled and sealed automatically by the gel plug in the annulus. The static friction (outer wall) of 73-mm tubing in the gel plug was 39.6 t/km; the dynamic friction (outer wall) after tubing removal was 7.2 t/km. This gel plug thus shows promise as a temporary blocking technology in workover operations of low-pressure, leakage-prone gas wells.

Summary For decades, increasingly severe downhole conditions call for superior and less-expensive corrosion inhibitors (CIs) for acidizing in petroleum production. Inhibitors that exhibit satisfactory protective ability at relatively low concentration are of great interest to most scholars in this area. In this work, two newly obtained dimer indolizine derivatives that were derived from the conventional quaternary quinolinium salts were introduced as potential highly efficient acidizing CIs. The indolizine derivatives could perform well alone, even without any synergistic component, in concentrated hydrochloric acid (HCl). Two quinoline ammonium salts, ethyl acetate quinolinium chloride (EAQC) and n -butyl quinolinium chloride (BuQC), were synthesized in advance by means of the quaternarization process. Afterward, in the presence of alkali, the ammonium salts could then get converted into the corresponding novel dimer indolizine derivatives easily by means of a 1,3-dipolar cycloaddition reaction in a relatively high yield. The derivatives were purified and their accurate chemical structures were confirmed by elementary analysis, nuclear magnetic resonance (NMR), and mass spectrometry (MS). Dimer derivatives of two quinoline salts were prepared successfully and characterized separately as C 26 H 23 N 2 O 4 Cl and C 26 H 27 N 2 Cl. Corrosion-inhibition performance of the quaternary quinoline salts as well as the related dimer indolizine derivatives in concentrated HCl for N80 steel was investigated by gravimetric research, electrochemical method, and scanning electron microscopy (SEM) energy dispersive X-ray analysis. The thermodynamic aspect of the inhibition was also discussed. The structure of EAQC and BuQC are very close to the quinolinium salt inhibitors that are commonly used as key components in commercially accessible acid CI products. However, under alkaline condition, EAQC and BuQC would easily be transformed to dimer indolizine derivatives that possess a general “indolizine” structure. That is the reason why the targeted molecules are recognized as “dimer indolizine derivatives.” Both the derivatives have good thermal stability at approximately 248°F and are easily soluble in acid solution. The surprising difference in the anticorrosion effect between the original quinoline salts and their dimer derivatives was proved by weight-loss experiments in 15 wt% HCl at 194 and 248°F with dosage ranges from 0.01 to 0.5 wt%. The derivatives could retard the corrosion of steel considerably at a much lower concentration compared with their precursors. A 0.1-wt% dosage of indolizine derivatives could increase the inhibition efficiency (IE) of N80 steel remarkably, to approximately 99.0% in 15 wt% HCl at 194°F. Results obtained from gravimetric tests and electrochemical methods are in good agreement and confirmed the well-behaved inhibition of the derivatives. We predict that the inhibition will be enhanced apparently when similar quinoline or pyridine ammonium salt are converted via the similar 1,3-dipolar cycloaddition mechanism. We have determined that the use of dimer indolizine derivatives provides a creative new choice for low-cost corrosion prevention, and the protective compounds can be applied as main component of acidizing CIs in the coming years.

Summary Polymer flooding is being pilot tested for the first time in the Schrader Bluff viscous oil reservoir at the Milne Point Field on Alaska North Slope (ANS). One of the major concerns of the operator is the impact of polymer on the oil production system after polymer breakthrough, especially the polymer-induced fouling issues in the heat exchanger. This study investigates the propensity of polymer fouling on the heater tubes as a function of different variables, with the ultimate goal of determining safe and efficient operating conditions. A unique experimental setup was designed and developed in-house to simulate the fouling process on the heating tube. The influence of heating tube skin temperature, tube material, and polymer concentration on fouling tendency was investigated. Each test was run five times with the same tube, and in each run, the freshly prepared synthetic brine and polymer solution was heated from 77°F to 122°F to mimic field-operating conditions. The heating time and fouling amount were recorded for each run. Cloud point measurement has also been conducted to find the critical temperature at which the polymer in solution becomes unstable and precipitates out. The morphology and composition of the deposit samples were analyzed by environmental scanning electron microscopy (ESEM) and X-ray diffraction (XRD), respectively. It was found that the presence of polymer in produced fluids would aggravate the fouling issues on both carbon steel and stainless steel surfaces at all tested skin temperatures. Only higher skin temperatures of 250°F and 350°F could cause polymer-induced fouling issues on the copper tube surface, and the fouling tendency increased with polymer concentration. At the lower skin temperatures of 165°F, no polymer-induced fouling was identified on the copper tube. A critical temperature that is related to the cloud point of the polymer solution was believed to exist, below which polymer-induced fouling would not occur and only mineral scale was deposited but above which the polymer would aggravate the fouling issue. The cloud point of the tested polymer solution was determined to be between 220°F and 230°F. From a practical safer design standpoint, we recommend a value of 220°F for operational purposes on the pilot site. The heating efficiency of the tube would be decreased gradually as more fouling material accumulates on its surface. If polymer precipitated and deposited on the surface, it would bond to the mineral crystals to form a robust three-dimensional network structure, resulting in a rigid polymer-induced fouling. The study results have provided practical guidance to the field operator for the ongoing polymer flooding pilot test on ANS.

Summary In hydrocarbon production and processing, choke and control valves mix and emulsify petroleum phases. The consequence is often that the efficiency of separation processes is affected and finally that the quality of oil and water phases is degraded. Over the last few years, low-shear valves targeting petroleum processes have emerged on the market. This paper presents four separate live-fluid experiences from low-shear valve installations, each surveyed and documented by an independent third party. Three of the installations refer to choke valves, whereas the fourth installation refers to a control valve. For each installation, standard choke and control valves were used as reference valves. In terms of downstream separation efficiency, the low-shear choke valves reduced oil-in-water concentrations respectively by 70, 45, and 60%, by total average. In the control valve application, the low-shear valve, which was located between the hydrocyclones and a compact flotation unit, reduced the oil-in-water concentration by 23%. In sum, the field installations have demonstrated that low-shear valves significantly and consistently reduce oil-in-water concentrations and thus improve the produced water quality. The results signify that low-shear valves may be used in debottlenecking separation and produced water treatment processes, reducing the environmental influence from produced water discharges. Because the low-shear technology enables processing of petroleum phases with less effort, energy, and chemicals, it also reduces emissions to air.

Summary Iron sulfide scale causes major losses in both upstream and downstream sectors of the hydrocarbon industry. Pyrite is one of the most-difficult forms of iron sulfide scale from a removal point of view. Inorganic acids such as hydrochloric acid (HCl) are not recommended for removing pyrite scales because they have many drawbacks, including low pyrite solubility, high corrosivity to the tubular system, and generation of toxic hydrogen sulfide (H 2 S). In this work, pyrite-scale dissolution is studied using an ecofriendly formulation of glutamic diacetic acid [L-glutamic acid, N, N-diacetic acid (GLDA)] as an alternative to HCl. Although GLDA has shown potential for removing iron sulfide in general and pyrite scale in particular, still GLDA/pyrite kinetics have not been well-understood. Both experimental and theoretical techniques have been used. The reaction kinetics has been investigated in a rotating-disk apparatus (RDA) at typical reservoir conditions of 150°C and 1,000 psi (Conway et al. 1999). Characterization techniques, including X-ray photoelectron spectroscopy (XPS) and scanning electron microscope (SEM), have been used to study the surface chemistry before and after treatment with GLDA, and the results support pyrite removal. Furthermore, density-functional-theory (DFT) calculations have been performed to understand the ability of GLDA to dissolve iron sulfide scale at the atomistic level. From the laboratory results, the reaction rate using 20-wt% GLDA (pH of 3.8) was 5.378×10 −8 mol/cm 2 ·s. The measured rate outperformed other proposed formulations according to the tetrakis(hydroxymethyl)phosphonium sulfate (THPS) formulation by 15 times. In addition, GLDA surpassed the most recent results on diethylenetriamine penta-acetic acid (DTPA) by nearly an order of magnitude. Moreover, pyrite dissolution in GLDA increases as the disk rotational speed increased, which indicates mass-transfer control with a diffusion coefficient of 1.338×10 −7 cm 2 /s. Furthermore, from molecular modeling using DFT, the binding energy between GLDA and Fe 2+ is calculated as –105.97 kcal/mol. The negative value observed correlates with the stability constant and indicates the strong binding affinity to Fe 2+ . Finally, GLDA could be recommended for pyrite-scale removal because it is biodegradable, less corrosive, free of H 2 S, and achieved solubility that outperformed THPS- and DTPA-basedformulations.

Summary A successful rigless subsea stimulation was executed during 2018, with the intervention performed on three target wells offshore of Sabah Malaysia, at a water depth of approximately 1400 m (4,593 ft). Significant changes in reservoir performance prompted an acid‐stimulation and scale‐squeeze treatment, designed to remedy fines migration and scaling issues within the well and production system. Treatment fluids were delivered subsea by an open‐water hydraulic access system, using a hybrid coiled tubing downline (HCTD). Access to the subsea trees was enabled by a novel choke‐access technology, allowing for a flexible, cost-efficient, and low‐risk intervention. The intervention system was installed on a multiservice vessel, with the downline deployed via the vessel moonpool. A second support vessel was used as required to provide additional fluid capacity without disturbing primary intervention operations. This enhanced the flexibility of the operation, accommodating potential changes in the treatment plan without impact to critical path‐stimulation activities. The full intervention was delivered as an integrated service, with all elements supplied by a single provider, via one contract. An established network of in‐house equipment, expertise, test laboratories, and operational bases supported the planning and execution of the project. This was complemented by select external providers for vessels, remotely operated vehicle services, and other specialist contractors. The challenges faced during execution included completion of a comprehensive treatment fluid test program, importation and logistics of equipment from around the globe, and managing operational risks, all within a condensed timeline to satisfy a brief intervention window. A collaborative solution was developed that combined the resources of the service provider, inclusion of performance-based elements within the contract, and delivery of an efficient and flexible well-access technology that supported rapid mobilization and alleviated operational risk. Post‐stimulation well testing confirmed an average increase in oil productivity of 86%, with a corresponding productivity‐index factor gain of 3.4. These results confirm the appropriateness of open‐water hydraulic access using coiled tubing (CT) for performing cost‐effective stimulations on complex subsea wells.

Summary Hydrochloric acid (HCl) is the acid of choice for acidizing operations in most carbonate formations, and is the base acid that is commonly paired with hydrofluoric acid (HF) in most sandstone applications. However, high dissolving power, high corrosion rate, lack of penetration, and sludging tendency coupled with high temperature (HT) can make HCl a poor choice. Alternatively, weaker and less-corrosive chemicals, such as organic acids, can be used instead of HCl to avoid these issues. The objective of this paper is to provide an intensive review on recent advancements, technology, and problems associated with organic acids. The paper focuses on formic, acetic, citric, and lactic acids. This review includes various laboratory evaluation tests and field cases that outline the use of organic acids for formation-damage removal and dissolution. Rotating-disk-apparatus (RDA) results were reviewed to determine the kinetics for acid dissolution of different minerals. Additional results were collected from solubility, corrosion, coreflooding, inductively coupled plasma, X-ray diffraction, and scanning-electron-microscope (SEM) diffraction tests. Because of their retardation performance, organic acids have been used along with mineral acids, mainly a formic/HCl mixture, or as a standalone solution for HT applications. However, the main drawback of these acids is the solubility of reaction-product salts. This challenge has been a limiting factor of using citric acid with calcium-rich formations because of the low solubility of calcium citrate. However, the solubility of the salts associated with formic, acetic, and lactic acid can be increased when these acids are mixed with gluconic acid because of the ability of gluconate ion to chelate calcium-based precipitation. In terms of formation-failure response, organic acids are in lower risk of causing a failure compared with HCl, specifically at deep formation treatments. Organic acids have also been used in other applications. For instance, formic acid is used in HT operations as an intensifier to reduce the corrosion rate caused by HCl. Formic, acetic, and lactic acids can be used to dissolve drilling-mud filter cakes. Citric acid is commonly used as an iron-sequestering agent. This paper shows organic acid advances, limitations, and applications in oil and gas operations, specifically in acidizing jobs. The paper differentiates and closes the gap between various organic acid applications along with providing researchers an intensive guide for present and future research.

Summary This paper presents a data‐driven methodology to predict calcium carbonate (CaCO 3 )‐scale formation and design its inhibition program in petroleum wells. The proposed methodology integrates and adds to the existing principles of production surveillance, chemistry, machine learning (ML), and probability theory in a comprehensive decision workflow to achieve its purpose. The proposed model was applied on a large and representative field sample to verify its results. The method starts by collecting data such as ionic composition, pH, sample‐collection/inspection dates, and scale‐formation event. Then, collected data are classified or grouped according to production conditions. Calculation of chemical‐scale indices is then made using techniques such as water‐saturation level, Langelier saturation index (LSI), Ryznar saturation index (RSI), and Puckorius scaling index (PSI). The ML part of the method starts by dividing the data into training and test sets (80 and 20%, respectively). Classification models such as support‐vector machine (SVM), K ‐nearest neighbors (KNN), gradient boosting, gradient‐boosting classifier, and decision‐tree classifier are all applied on collected data. Prediction results are then classified into a confusion matrix to be used as inputs for the probabilistic inhibition‐design model. Finally, a functional‐network (FN) tool is used to predict the formation of scale. The scale‐inhibition program design uses a probabilistic model that quantifies the uncertainty associated with each ML method. The scale‐prediction capability compared with actual inspection is presented into probability equations that are used in the cost model. The expected financial impact associated with applying any of the ML methods is obtained from defining costs for scale removal and scale inhibition. These costs are factored into the probability equations in a manner that presents incurred costs and saved or avoided expenses expected from field application of any given ML model. The forecasted cost model is built on a base‐case method (i.e., current situation) to be used as a benchmark and foundation for the new scale‐inhibition program. As will be presented in the paper, the results of applying the preceding techniques resulted in a scale‐prediction accuracy of 95% and realized threefold cost‐savings figures compared with existing programs.

Summary Iron sulfide scale deposition can be a significant flow‐assurance issue in sour‐gas production systems. It can deposit along the water‐flowing path from the near‐wellbore reservoir region to the surface equipment, which results in formation damage, causes tubing blockage, interferes with well intervention, and reduces hydrocarbon production. The main objectives of this paper are to review the new advancements and remaining challenges concerning iron sulfide management in sour‐gas wells, covering the mechanisms of iron sulfide formation, the mechanical and chemical removal techniques, and the prevention strategies. In this paper we give a special emphasis to the different mechanisms of iron sulfide formation during well‐completion and production stages, especially the sources of ferrous iron (Fe 2+ ) for scale deposition. It is essential to understand the root cause to identify and develop suitable technologies to manage the scale problem. We also summarize the latest developments in mechanical methods and chemical dissolvers for the removal of iron sulfide deposited on downhole tubing. The capabilities of the current chemical dissolvers are discussed, and the criteria for effective dissolvers are provided to serve as guides for future development. Then, we provide an overview of recent developments on iron sulfide prevention technologies and treatment strategies. We differentiate the treatment approaches for corrosion byproduct and scale precipitation and scale‐inhibitor deployment through continuous‐injection and squeeze treatments. Finally, we outline the technical gaps and areas for further research‐and‐development (R&D) efforts. We provide the latest review on iron sulfide formation and mitigation, with an attempt to integrate viable solutions and showcase workable practices.

Summary The first-ever field pilot on Alaska North Slope (ANS) to validate using polymer floods for heavy-oil enhanced oil recovery is currently ongoing. One of the major concerns of the operator is the effect of polymer on oil/water‐separation efficiency after polymer breakthrough. This work investigates the influence of polymer on the separation behavior of heavy-oil emulsions and evaluates the performance of emulsion breakers (EBs). In this study, two types of heavy-oil emulsions were prepared and tested at 20 and 50% water cut (WC), respectively. The bottle test method was used in the experiments, in which the separated water volume with time, the separated water quality, and the volume fraction of phases were recorded. Results showed that polymer accelerated the oil/water separation acting as an emulsion inhibitor at 20% WC but tended to impede the water separation at 50% WC. Regardless of WC, polymer resulted in poor water quality and the formation of a stable intermediate oil in water (o/w) emulsion, because of the increased viscosity of the water phase. The performance of EBs showed a complex dependency on the WC, the type of demulsifier and dosage, and the polymer concentration. Despite the varied conditions encountered in the heavy-oil/water/polymer/demulsifier system, a compound EB achieved satisfactory demulsification performance, showing the highest potential for deployment in the current ANS polymer flooding pilot. In this paper, we systematically studied the potential influence of polymer breakthrough on the separation behavior of heavy-oil emulsion on ANS for the first time. The findings of this study will provide practical guidance in advance for produced fluid treatment of the ongoing first-ever polymer flooding pilot on ANS.

Summary Hydraulic‐fracturing treatments in shale infill wells are often impacted by existing parent‐well depletion and asymmetrical fracture growth. These phenomena can result in excessive load‐water production, deposition of proppant and deformation of casing in the parent well, and unbalanced stimulation of infill wells. This study determines the effectiveness of particulate materials (i.e., far‐field diverting agents) for mitigating the above negative outcomes by bridging near the extremities of dominant fracture wings. Fracture propagation was modeled to characterize the width profile at fracture extremities in a depleted‐stress environment. A slotted‐disk device was used to evaluate and optimize particulate blends for bridging slots representative of width near the fracture tip. Rheological tests replicating the downhole environment were used to formulate a system for transporting the diverting materials. Statistical analysis of 511 fracture hits at 30 parent wells was performed on key treatment indicators by the category of diverter type and post‐hit parent‐well condition. Production trends of the influenced wells were compared to area‐specific type curves and offset wells without diverter trials. On the basis of the simulation and testing results, two types of high‐graded far‐field diverter systems were field‐tested in a shale play: dissolvable, extremely fine particulate mixed with a 100‐mesh sand, and mixtures of a nominal 325‐mesh silica flour and a 100‐mesh sand. Proppant dust collected at the fracturing site was also evaluated for replacing commercial silica flour. High‐graded blends of the above diverting systems demonstrated superior fracture‐hit and productivity metrics as compared to the base case of not applying far‐field diverters. The silica flour and 100‐mesh‐sand mixture performed on a par with the significantly more expensive blend of dissolvable fine particulate and 100‐mesh sand. Borate‐crosslinked‐guar gel was an effective carrying fluid for transporting diverting materials to the fracture extremities. Statistical analysis of fracture‐hit events shows that the application of far‐field diverters did not reduce the magnitude of pressure buildups during fracture hits; however, it significantly increases the post‐hit pressure‐falloff rate at the parent wells. On the basis of the area‐specific type curves, pumping far‐field diverters increased the P50 estimated ultimate recovery (EUR) by approximately 6% compared with the base cases of not applying diverters. For all the wells impacted by far‐field diverters, the infill wells saw larger benefits with an increment of P50 EUR by approximately 7% compared with the parent wells.

Summary An onshore oil well in Japan, referred to as Well M‐1 in this paper, experienced a serious emulsion problem soon after the introduction of artificial lift using a hydraulic jet pump. Even though the problem was resolved after switching to a new demulsifier, it is possible that the operator could experience another emulsion problem as the production condition changes in the future and accordingly, the new demulsifier becomes less effective. Therefore, a laboratory case study was conducted to understand not only the cause of the emulsion problem encountered, but also the relative magnitude of several factors affecting emulsion stability. Knowing the conditions that lead to the emulsion problem helps in understanding how to remove the emulsion and in designing intervention treatments to restore long‐term well productivity. At first, the oil and brine samples from Well M‐1 were mixed and agitated to form emulsion, and subsequently emulsion stability was evaluated. Subsequently, the mixing conditions were altered to investigate the individual impact on the emulsion stability: (1a) replace Well M‐1 oil with another field's oil, (1b) replace Well M‐1 brine with another field's brine, (2) change concentrations of asphaltene, (3) change concentrations of wax, (4) change concentrations of toluene insolubles, (5) vary temperature between 20 and 70°C, (6) vary shear stress (rotational speed between 3,500 and 15,000 rev/min), and (7) vary water cut between zero and 100%. The result of the emulsion stability in every test was different. All the above factors showed some impact on emulsion stability, except for brine composition and toluene insolubles, which had little impact on emulsion stability in this study. Operationally speaking, because it was found that the emulsion was stabilized by multiple factors, multiple preventative approaches are required to sustain stable production, free of emulsion.