Predicting accurate erosion rate due to sand particles in oil and gas production is important for maintaining safe and reliable operations while maximizing output efficiency. Computational Fluid Dynamic (CFD) is a powerful tool for erosion prediction as it provides detailed erosion pattern in complex geometry. In an effort to improve accuracy of erosion prediction, this paper proposes an algorithm to accurately represent particle shape in CFD erosion simulation through coupling with Discrete Element Method (DEM) for non-spherical shape particles. The fluid motions are predicted by CFD and the particle movements (including particle-particle and particle-wall collisions) and fluid-particle interaction are calculated using DEM. It is widely known that sand particles are of finite volume with a non-spherical shape, accurate representation of sand particles is important in CFD modelling for accurate prediction of erosion rate. Traditional CFD approach usages lagrangian tracking of sand particles through Discrete Phase Model (DPM), where a particle is assumed as a point mass for the calculation of trajectory and particle-wall interaction. Particle impact velocity and impact angle are important parameter in determining erosion. Assumption of point mass in DPM approach, will not capture particle-wall interaction accurately especially when particles are of non-spherical in shape. In additional, DPM approach ignores particle-particle interactions. This can adversary affect the accuracy of erosion predictions. Integrating non-spherical DEM collision algorithm with CFD erosion simulation, will overcome these limitations and improve erosion predictions. Benefits of this CFD-DEM erosion modelling was demonstrated for gas-solid flow in a 2" pipework which consists of out-of-plane elbows in series and blind-tees. Experimental dataset [ 1 ] for erosion pattern on each elbow was used to validate CFD predictions. Three different erosion CFD simulations were performed, traditional DPM based CFD simulation, CFD-DEM simulation for spherical shape particles and CFD-DEM simulation for non-spherical shape particles. CFD-DEM coupled simulations clearly show an improvement on erosion predictions compared to DPM based CFD simulation. Effect of non-spherical shape on rebound angle during particle-wall collision is captured accurately in CFD-DEM simulation. CFD-DEM simulation using non-spherical particle, was able to predict erosion pattern closer to experimental observations. This paper will demonstrate an increase in accuracy of sand erosion prediction by integrating DEM collision algorithm in CFD modelling. The prediction results of elbow erosion subject to a condition of dilute gas-particle flow are validated against experimental data. Improved prediction of erosion risk will increase the safety and reliability of oil & gas operations, while maximizing output efficiency.

Oklahoma is known for having ample sources of CO 2 , pipelines and sinks where for many decades, oil and gas operators were injecting CO 2 into geological formations for EOR purposes. We utilized SimCCS, an economic-engineering software tool (DOE-NETL), to integrate infrastructure related to CO 2 sources, pipeline, and geological formations. The approved tax incentive program by IRS (45Q) has motivated many oil and gas operators to participate in reducing CO 2 concentration and minimizing global warming effect by collecting CO 2 from various sources, select the best pipeline route and the safest location to inject into geological formation for EOR purpose or deep saline aquifer for sequestration. This paper presents an economic evaluation of CO 2 capture, utilization, storage (CCUS) into geological formation in the state of Oklahoma. Under this comprehensive approach, the process of capturing, transporting, and storing CO 2 into geological or saline formations has been economically evaluated for different sites and routes utilizing an ad hoc simulation software (SimCCS) for integrated modeling of CCUS. The outcome of this paper determines the most optimal scenario using optimization algorithms embedded in SimCCS. This case study will mitigate the CO 2 sequestration approval process when operator apply for tax credit under 45Q program. Our work will assist oil and gas operators by comparing different scenarios based on utilizing existing infrastructure, making decision in building new transportation system or new injection well to benefit the approved tax incentive program at its maximum capacity. Moreover, the outcome of this work will shed lights into future legislation demands (locally and nation-wide) to maintain CCUS momentum after its initial implementation phase is concluded.

Well abandonment under a corrosive environment is often unpredictable and challenging, especially if the zone exhibits irregular wellbore geometry due to severe corrosion. These situations not only increase associated risks, but also greatly increase the abandonment cost for workover operation. This paper presents a successful application of a mechanical aid to replace a firm base using bridge plug or viscous pill base to abandon a well in the province of Basra in Southern Iraq. Numerous wells in Southern Iraq have compromised casing integrity due to sulphureous water flow from Umm Er-Radhuma / Tayarat formations, making their abandonment imperative. Due to unpredictable corrosion inside the casing, setting any type of mechanical bridge plug was a laborious operation, because the operator must run multiple logs to confirm the casing integrity and might not get the required casing integrity at the desired abandonment depth. Setting up a viscous pill was a challenge in the well environment, and in absence of a firm base it was highly probable that the cement plug would slump. Looking at multiple options to ensure the successful plug setting operation on the first attempt, it was decided to use a suitable mechanical aid, as a firm base to prevent the slumping motion of the fluids that were pumped to isolate sensitive zones. The unique foldable and adjustable parasol construction of the tool enabled it to be pumped through small diameter tubing avoiding any sticking, and it was a critical parameter for tool selection process. This paper summarizes the first-successful well abandonment using such a tool in the province of Basra in 7-in. casing and 9 5/8-in. casing. The logging tool was not able to detect one section of 9 5/8-in casing, which was presumably completely corroded. The first attempt to isolate it using a polymer system was not successful, since the fluid flowed to different leaks in the outer casing. The parted 7-in. casing made it impossible to identify the depth of lower leaks. Then a plan to utilize the mechanical aid was presented and subsequently approved. Tool was dropped and set above the top of 7-in. casing and gave support to the first cement plug to abandon the well, significantly reducing the time and cost of abandonment of the well by reducing repeated plug jobs. The use of the mechanical aid as a primary option to set plugs for abandonment purposes in corrosive environments has resulted in a great success by reducing non-productive time and enhancing zonal isolation results. Similar usages around the world will help in reducing workover operation economics where integrity of the casings is questionable.

Objective/Scope Integrity of the wells and facilities is planned right from the reservoir development phase. In the pilot phase all the contributing parameters are collected and considered in the design of the production facilities. As the corrosion/erosion is very important aspect to determine the operating condition and the metallurgy of the facilities/completion, due consideration must be given to the technologies helping the infrastructure planning. However, once the production begins, the real time corrosion monitoring is essential as the reservoir produces from multiple zones along with solids during the complete lifecycle. The sand erosion aggravates the corrosion and can cause leaks around the wellheads and areas with changes in cross section. There are several processes such as inhibitor dosage, chemical treatment are performed from the startup and continued throughout the pilot. The paper covers integrated technologies to minimize the risk of corrosion damages by providing predictive analytics for corrosion and erosion impact. This includes chemical injection system, trace detector, non-intrusive corrosion monitoring, sand detector technologies as a holistic solution and best practice for ensuring asset integrity. Methods, Procedures, Process With the given information on the fluid corrosivity, the corrosion inhibitor and its dosing rate gets identified. Continous injection leads to the formation of a thin film on the entire system which need to be protected. However, many times the dosage is not optimized often leading to over injection or under injection of the chemicals. The injection rate is important to be monitored and optimized with a Realtime corrosion monitoring and gauging the impact on the asset integrity. The non-intrusive easy to install Realtime corrosion monitoring probe can provide real time monitoring for all the above requirements and in remote locations inaccessible during inspection A tracer is added to the chemicals to identify the residual through the tracer meter, which is hooked up with the chemical injection system, to optimize the set dosing rate. The corrosion monitoring system is in a corrosion prone location where the highest corrosion rate is expected to optimize the dosage. The sand detector can be considered in case we are producing from unconsolidated sand reservoir. This helps to identify erosion and where more sand is expected. Results, Observations, Conclusions Integrating all these technologies helps optimize the chemical used by around 20% and maximize the lifetime for the integrity by 70%. Also, it predicts potential failures in the system. As the data is stored and accessed from different locations, the organization will have a better control on the full integrity which lead to better design and alternating the corrosion inhibitor without any risk on the integrity. However, the combined technologies will be high CAPEX, but it will save a lot of OPEX on the long run which is demonstrated in the paper and will provide a good historical data for the field development and overall production enhancement

An improved flow assurance solution based on a new additive with robust performance, low treat rate and versatile handling properties was developed successfully. It was applied in a waxy crude oil from West Africa with high pour point and a wax content of about 24%. Crucial for the project success was a close collaboration among all involved stakeholders from operator, service company and chemical supplier. In the initial lab screening by the chemical supplier, tests focused on pour point, viscosity and yield stress. This approach allowed to identify the most efficient type of additive chemistry for the specific crude oil and to meet target performance requirements. Crude oil viscosity and yield stress under pipeline operation conditions could be reduced by more than 95% while reducing the required amount of additive by more than 75% compared to the incumbent solution. This resulted in significant cost savings for the operator and in a reduction of the Health, Safety and Environmental (HSE) exposure.

Objectives/Scope A 60-year-old well exhibited a leak at the surface and sustained annuli pressure (SAP) in all three annuli - A, B and C. The age of the well coupled with the symptoms suggested a complex multi-barrier failure scenario that needed to be diagnosed quickly and accurately so that the well could be secured safely. The paper shows how the comprehensive set of downhole diagnostics, including metal and cement barriers integrity assessment, aided in planning and execution of well intervention to secure the indicated failures. The well intervention team selected an approach to investigate the barriers status prior the rig came to the location. Surface diagnostics included evaluation of pressure trends, completion design, leak fluid composition and drilling records analysis which guided the selection of downhole survey. The input parameters for downhole through barrier diagnostics were: – SAP observed in all annuli; – Questionable cementing of downhole tubulars; – Poor material selection to withstand H 2 S and CO2 concentrations; Downhole through barrier diagnostics targeted the evaluation of leak paths and failures in well barriers and included: – Casings metal wall thickness profiling by Electro-Magnetic(EM) pulse logging tools; – Seal evaluation of metal and integrity of cement barriers evaluation by passive acoustic logging tools;-Tracking of the fluid migration within the well system by high precision temperature. EM pulse survey was conducted after the tubing retrieval. This paper explores the concept, planning, execution and achieved results of the downhole diagnostics performed and how the results were implemented by Operator.

The main objective of this study is to develop and evaluate a nanotechnology-based material in combination with a commercial corrosion inhibitor (CI) as an alternative to reduce the corrosion rate in oil and gas facilities. The corrosion rate (CR) of surface facilities coupons was estimated using weight loss analysis as the response variable in the following study, showing that in absence of CI treatments, carbon steel (CS) coupon displays corrosion rates over 2.1 mm·y −1 . Four commercial CI were evaluated at concentrations ranging between 35-50 mg·L −1 to select the most suitable treatment at surface facilities conditions, showing CR reductions of around 12.2 and 22.5% in both dosages for the best CI treatment. SiO 2 and Carbon Quantum Dots (CQDs) nanomaterials were added to the selected CI at nanoparticle dosages from 50 to 500 mg·L −1 to improve the behavior of the selected treatment in presence of production brine. The effectiveness of the proposed nanomaterials is strongly dependent on the nanoparticle concentration, and hence, its dispersion degree onto the metallic surface, whereas low dosages in SiO 2 lead to an increase in the CR, however, low dosages in CQD lead to a reduction of the CR. The proposed NanoIC was evaluated using 1M HCl solutions to study the role of the nanoparticles in strong acid media. The corrosion rates for CS outcrops in the presence of production brine with 1M HCl was 8.6 mm·y −1 , which suggests an important role of mineral acids in the corrosion phenomena. In the presence of CI at a dosage of 35 mg·L −1 , the corrosion rate was reduced by 10.7%. The CR of CS surfaces treated with brine and strong acid solutions in presence of NanoCI containing CQD nanomaterials at 50 mg·L −1 shows reductions of 28.6 and 74.2%, respectively. It can be concluded, the nanoparticles act as a corrosion inhibitor agent, reducing the interaction between the acid molecules and the steel surface by the formation of a thin film. This work opens the landscape into the incorporation of carbon-based nanomaterials in surface oil and gas operations for the reduction of the corrosion rate in the facilities during the production stage in the wells by the synergistic behavior between commercial corrosion inhibitor and nanoparticles.

An advanced high-resolution acoustic imaging technology was deployed for well integrity and deformation assessments in both vertical and horizontal wells. This high frequency acoustic tool collected three-dimensional data quantifying deformation and wall thickness with resolution unobtainable by existing multi-finger caliper, magnetic flux leakage, and rotating single element ultrasonic systems. Several novel imaging methods are enabled by the high number of transducers (up to 512) on the imaging probe. These methods, including beam forming, beam steering and semi-stochastic multipulse imaging, are outlined and discussed in this paper. In addition, multiple types of standardized visualizations enabled by this high-resolution 3D data capture tool are introduced and examples of each are shown. Lab qualification and imagery generated by the high-resolution solid-state imaging technology, when applied to various precision machined geometric anomalies, are presented. In addition to lab validation results, several field studies are showcased including assessments of ovalized casing, complex downhole corrosion, and isolated minor pitting. Leak paths, splits, and damaged regions within threaded casing collars were also identified, imaged, and quantified using the acoustic technology. Until now, these collar regions have been very difficult to image using legacy downhole tools due to fundamental limitations at the threaded connection geometry. Lastly, various downhole completion equipment case studies are presented showcasing several applications of acoustic imaging used to validate the set-position or condition of specialty downhole equipment. This paper outlines the usage of the solid-state acoustic technology to generate three dimensional geometry and wall thickness datasets with sub-millimetric resolution, providing operators with a holistic and actionable assessment of their well integrity.

Customers in Ecuador inject the byproduct formation water from production wells into injector wells. A limited injection rate bottlenecks production, which is economically undesirable. Two major contributors limit injection capacity: reservoir injectivity and flowline pressure losses. In the latter case, paraffins, asphaltenes, and scale, collectively referred to as "schmoo," progressively build in the flowline and reduce the internal diameter, limiting flow rate capacity. One cost-effective method to remediate flowlines with significant deposits is coiled tubing (CT) cleanouts. This unconventional method, which calls for optimized planning, execution, and performance evaluation, has been implemented in five flowlines. An economic analysis shows that remediating flowlines using CT cleanout yields significant savings as compared with replacement. After a candidate is identified, job planning takes into consideration flowline length and deviation (to identify maximum reach of CT), schmoo analysis (to design an optimal bottomhole assembly and fluid treatment), and execution logistics (to ensure a viable, reliable, and safe operation). After the cleanout, the flowline is put back into service, and the effectiveness of the treatment is estimated based on system flow rates and pressure losses. The equivalent internal diameter (ID) for the flowlines was improved by over 49% in each of the remediated flowlines, achieving an effectiveness of over 89% of nominal ID and increasing flow rates without a detrimental effect on system pressure. The cleanouts re-established nominal capacity in over 50k ft of flowline that no longer needed replacement. Lessons learned include the ability to complete the cleanout with water alone. The chemical analysis in planning stages showed the absence of carbonates, which enabled a mechanical cleanout with a high-pressure nozzle. Nonetheless, a chemical treatment was designed as a contingency. Another learning was that whereas tubing force models helped predict the reach of the CT, other factors created limitations. For example, the weld bead on the flowline limited the reach of the CT and required re-evaluating where to create cuts along the flowline. Finally, deploying the CT in a flowline required configuring the injector head horizontally, which required a customized base for safe rig up and operation of the injector head and pressure-control equipment. CT successfully cleaned out five flowlines with IDs ranging from 6-in. to 8-in. and re-established 89% to 98% of their nominal ID. As a result, the operator saved upwards of USD 14 million in flowline replacement costs, increased asset utilization, and decreased deferred injection. Historically, there is limited documented experience with flowline cleanouts using CT. The paper documents a repeatable methodology for candidate selection, planning, execution, and performance evaluation. It also provides basic building blocks to meet treatment design, rig-up, and execution requirements that are unique to this application.

Previous efforts to promote hydrogen as an energy carrier described a Utopian world in which renewable resources provided all energy for heating, electricity, transportation, and industrial needs. The elegance of this vision overlooked the cost and the footprint represented by the renewable energy resources required to generate so much electricity, and the additional cost required to employ electrolysis to generate hydrogen for energy storage not possible for electricity. Today an abundance of natural gas offers an option for hydrogen generation from methane that can include capturing and storing CO2 produced from the generation process. This results in blue hydrogen, effectively as ecologically attractive as the green hydrogen from electrolysis, and considerably less expensive. This paper evaluates a New Hydrogen Economy employing blue hydrogen as a bridge to net zero greenhouse gas emissions. Of particular interest is the observation that depleted natural gas reservoirs offer pore space sufficient to store about 1.5 times the CO2 coming from hydrogen generation from the produced natural gas. The implication of this observation is that blue hydrogen generation need not rely on saline aquifer storage or on CO2 Enhanced Oil Recovery. We find that blue hydrogen cost is comparable to the cost of current crude oil-based transportation fuels. Further, electricity generated using blue hydrogen is less expensive than decarbonized electricity generated from natural gas with post combustion CO2 capture and storage. The infrastructure required for this energy transition can leverage existing natural gas transport and storage and existing petroleum industry skills. Energy companies committed to net zero emissions need not rely only on renewable energy sources or nuclear power. Further, switching to blue hydrogen reduces or eliminates combustion related pollution including nitrogen and sulfur oxides. Finally, the Blue Hydrogen Economy makes efficient and cost effective use of petroleum engineering core skills, as well as the core skills championed by the petroleum industry.

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.

Components and tubulars in down-hole applications for oil and gas production must withstand severe wear (e.g. erosion, abrasion, rod wear) and corrosion environments. These challenges can be addressed through boronizing of steels achieved employing chemical vapour deposition-based process. This process permits protection of the entire working surfaces of production tubulars up to 12m in length, as well as various sizes of complex shaped components. The performance of these tubulars and components have been evaluated in abrasion, erosion, and corrosion conditions simulating the environment and service conditions experienced in down-hole oil and gas production. Harsh service conditions are very common in the oil industry and the combination of abrasion, friction-induced wear, erosion, and corrosion environments can be quite normal in wells producing with the assistance of artificial lift methods. The boronized steel products demonstrated significantly higher performance in terms of material loss when exposed to harsh operating conditions granting a significant extension of the component service life in wear and corrosion environments. As opposed to many coating technologies, the boronizing process provides high integrity finished products without spalling or delamination on the working surface and minimal dimensional changes. Successful application of tubulars and components with the iron boride protective layer in oil and gas production will be discussed and presented.

As the most potential Carbon Capture, Utilization, and Storage (CCUS) technology, CO2-enhanced oil recovery (CO 2 -EOR) can both improve oil recovery and relieve the pressure of reducing CO 2 emission. However, CO 2 -EOR projects have not been substantially deployed in China due to the significant investment and high uncertainties of technology, market, and policy. Therefore, identifying potential bottlenecks, and developing effective investment strategies are of great necessity at present. In this work, a real option approach combined with reservoir simulation technologies is proposed, which can investigate the optimal deployment timing and the investment value of the CO 2 -EOR projects. Meanwhile, a sensitivity analysis is conducted to examine the effects of different uncertainties. The results show that real option approach is suitable for the evaluation of CO 2 -EOR projects because it can fully take the flexibility of investment time into account. And it is found that under the current investment environment, it is difficult for China to deploy CO 2 -EOR projects on a large scale before 2030. High oil prices, low CO 2 purchase prices, and transportation of CO 2 by pipeline can bring forward the investment time and increase the investment value. Besides, government subsidies and technological progress are also favorable for the deployment of the project. Compared with technological progress, the effect of subsidies is more obvious, while it should be noted that huge subsidies will bring a financial burden to the government. In a word to launch CO 2 -EOR projects earlier and make it play a more important role in China's carbon emission reduction, a compound strategy should be made based on consideration of all these influencing factors.

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.

The everlasting emphasis on abiding by the forecasted plans and targets in Greater Birba while limiting operating expenditure exhaustion has paved the way for additional analysis and monitoring of current well performance trends in complex reservoir configurations such as Al Noor. Buried at deep depths underneath a high-pressure overburden, the Ara Salt depositional features in the southern basin of Oman present unique yet extremely challenging characteristics with respect to hydrocarbon extraction and subsequent production. Situated below the four primary carbonate layers of A1C-A4C, Al Noor Field's Athel-type formation poses one of the most challenging reservoir configurations across the region. Recent efforts to sustain free-flowing production in this field were initiated through applying the cyclic huff and puff process to spark the necessary pressure difference between the tubing head and the flowline pressures, allowing the well to remain active. With projected additional constraints bound to augment the producing capacity, efforts to sustain a high yield from what remains to be a considerable extent of unrecovered hydrocarbons has called for a more thorough case study; one that is aimed at maximizing the capital gain as well as minimizing the environmental footprint and existing time constrains on the field operators. The goal of this work is to present a thorough study of Al Noor field's huff and puff plan as well as highlight underlying subsurface and surface issues. Based on initial deductions, the task is to then analyze a wide selection of parameters on PI and energy component, both of which are primary production programming interfaces that are consulted to correlate existent depressurization patterns with respect to the tubing head pressure (THP) before and after kick-off procedures, lowest flowline pressure (FLP) readings, average choke opening sizes in order to contrive an updated categorization of the field's active or temporarily closed/quit wells; one based on the tested net production rate of each well against the duration of its quitting cycle in days/month. Consequently, preliminary observations of a few wells unravelled startling revelations in terms of the potential for prolonging time elapse until quit. In addition to minimizing the operator's load and reducing quantities of gas flared, large capital gains were generated in proportion to the feasibility of reducing inefficient disparities, some even stretching to an excess of a $142,000 in relatively low producers and over a considerably small batch of tested wells. Following that, an implementation proposal comprised of a case-by-case strategy for three selected wells was relayed to the on-site operations team. The selection process was based on their optimization viability with regards to examined parameters as well as their productivity profile. Instructions included following the standard procedure in ALNR 21 but depressurizing the FLP to below 4 bars instead of 40, aiming therein to maximize the THP after kick-off and stretch out the cycle. The choke size was adjusted from 50% to 20% opening in ALNR 20 to observe effects on rates as well as pressure maintenance and last but not least, apply the innovative pressure build-up theory in a quantitatively low producing ALNR 24. The effects of this strategy presented an overwhelming degree of success in augmenting post kick THP levels, steadying production rates and perpetuate the wells’ activity. Finally, case study focussed and general recommendations were outlaid for short to long-term future performance improvements.

The production and transportation of high viscosity liquid/gas two-phase along petroleum production system is a challenging operation due to the lack of understanding the flow behavior and characteristics. In particular, accurate prediction of two-phase slug length in pipes is crucial to efficiently operate and safely design oil well and separation facilities. The objective of this study is to develop a mechanistic model to predict high viscosity liquid slug length in pipelines and to optimize the proper set of closure relationships required to ensure high accuracy prediction. A large high viscosity liquid slug length database is collected and presented in this study, against which the proposed model is validated and compared with other models. A mechanistic slug length model is derived based on the first principles of mass and momentum balances over a two-phase slug unit, which requires a set of closure relationships of other slug characteristics. To select the proper set of closure relationships, a numerical optimization is carried out using a large slug length dataset to minimize the prediction error. Thousands of combinations of various slug flow closure relationships were evaluated to identify the most appropriate relationships for the proposed slug length model under high viscosity slug length condition. Results show that the proposed slug length mechanistic model is applicable for a wide range of liquid viscosities and is sensitive to the selected closure relationships. Results revealed that the optimum closure relationships combination is Archibong-Eso et al. (2018) for slug frequency, Malnes (1983) for slug liquid holdup, Jeyachandra et al. (2012) for drift velocity, and Nicklin et al. (1962) for the distribution coefficient. Using the above set of closure relationships, model validation yields 37.8% absolute average percent error, outperforming all existing slug length models.

In an effort to increase oil production over the past twenty years, the oil industry has moved into deep water for new field developments. During this time, progressively deeper wells containing geopressured reservoirs require the use of high density completion brines. Many of these reservoirs require the use of completion brines above 14.7 ppg. Historically, zinc bromide solutions have been used to provide the required density and true crystallization temperature (TCT) for these reservoirs. However, health, safety, and environmental concerns around zinc bromide have caused operators to seek alternative solutions. The oil and gas industry uses a large amount of heavy brines in the completion of high pressure-low temperature (HPLT) wells, and there are currently very limited options for high density (>14.7 ppg), low TCT fluids that do not contain zinc. One option, cesium formate, is prohibitively expensive, and the other, based on existing halide technology, has a lower density limitation than this new class of clear brine fluid. This paper describes a novel, zinc-free, high-density, low true crystallization temperature brine fluid developed by Albemarle Corporation. We will discuss the testing performed to characterize this new fluid. This new class of brine fluid fills a gap in fluids technology for a fluid suitable for high pressure, low temperature applications at higher densities than previously available. Further, this is accomplished in an environmentally friendly heavy brine fluid that contains no Environmental Protection Agency (EPA) listed materials.

High strength steel pipes internally clad with Ni superalloys are components widely used in the oil and gas industry, with distinguished application in the production of rigid steel risers. The joining of clad pipes is carried out through a girth welding process, in which the joint is totally filled with a filler material similar to the internal clad. However, depending on mechanical strength of the pipe substrate, an undermatching condition is created. Thus, a critical weaker region results in the welded joint, where loads and plastic deformations will occur preferentially. In view of this problematic, this work aims to apply an alternative approach as a method of joining clad steel pipes, whereby an overmatching condition is achieved in the joint. This technique is carried out through a double-sided weld, which enables the use of steel filler wire in the joint filling externally, preserving the internal cladding through an inside diameter weld with a CRA filler wire. A C-Mn API X-65 steel pipe, metallurgically cladded with Inconel 625 was used in the study. For joining the pipes, modern welding techniques as GMAW CCC (Controlled Short-Circuit) and GTAW with dynamic wire feeding were applied. The developments showcased weld beads with excellent surface appearance and without welding defects, fact verified by internal videoscopy and cross section macrography. Energy Dispersive X-ray Spectometry (EDS) indicated low iron dilutions, around 2,7% in weight, on the internal weld bead surface. The double-sided welding methodology produces favorable conditions to reach joint properties equalization, enabling the employment of steel filler wire in joint filling, in addition to preserving the internal clad and its corrosion properties.

Predicting CO 2 corrosion in fluid transmission pipelines is crucial for oil/gas company in upstream applications. This paper applies Light Gradient Boosting Machine (LightGBM) and Multiple Layer Perceptron Neural Network (MLPNN) models for the prediction of CO 2 corrosion in aqueous pipelines with different pipe bending angles. To build the predictive models, a data set with total of 77,745 data points was generated parametrically by a computational fluid dynamics (CFD) model. Since different environmental conditions and geometries of the pipeline may cause non-uniform corrosion, a total of seven variables, including flow velocity, pH value, CO 2 concentration, pipe inner diameter, pipe bend angle, radius and temperature are taken as the input features with the corrosion rate as the target variable. The CFD model was then used to compute the electrochemical processes occurring at the metal surfaces to predict the corrosion rate. Knowing that these features have nonlinear relationship with the target, tree based LightGBM, and neural network based MLPNN were chosen. LightGBM can control the overfitting issues, deal with comparative scales of the features and learn non-linear decision boundaries via boosting. The most significant findings are that these two types of machine learning (ML) algorithms have higher efficiency and can predict new results in microseconds in contrast to hours or even days using CFD. The R square of the LightGBM model is 0.9985, which is slightly higher than that of the MLPNN model at 0.9931. The k-fold cross validation results also show the stability of the two models. These ML models are 5 to 6 orders of magnitude faster than CFD models with similar accuracy therefore significantly saving time and cost. We further built a web application based on these predictive models as a tool for pipeline design and monitoring applications.

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.