The sophisticated molecular imaging methods, atomic force microscopy (AFM) and scanning tunneling microscopy (STM), have been utilized to image individual asphaltene molecules, both their atoms and bonds, and their electronic structure. The stunning images have confirmed previous results and have all but resolved the long-standing uncertainties regarding asphaltene molecular architecture. Asphaltenes are also known to have a strong propensity to aggregate. The dominante asphaltene molecular structure and hierarchical nanocolloidal structures have been resolved and codified in the Yen-Mullins model. Use of this model in a simple polymer solution theory has given the first equation of state (EoS) for asphaltene gradients in oilfield reservoirs, the Flory-Huggins-Zuo EoS. With this EoS it is now possible to address reservoir connectivity in new ways; equilibrated asphaltenes imply reservoir connectivity. For reservoirs with disequilibrium of contained fluids, there is often a fluid process occurring in geologic time that precludes equilibrium. The collection of processes leading to equilibrium and those that preclude equilibrium constitute a new technical discipline, reservoir fluid geodynamics (RFG). Several reservoirs are reviewed employing RFG evaluation of connectivity via asphaltene thermodynamics. RFG processes in reservoris often include diffusion, RFG models incorporating simple solution to the diffusion equation coupled with quasi-equilibrium with the FHZ EoS are shown to apply for timelines up to 50 million years, the age of charge in a reservoir. When gas (or condensates) diffuse into oil, the asphaltenes are destabilized and can convect to the base of the reservoir. Increasing asphaltene onset pressure as well as viscous oil and tar mats can be consequences. Depending on specifics of the process, either gooey tar or coal-like asphaltene deposits can form. In addition, the asphaltene structures illuminated by AFM are now being used to account for interfacial properties using simple thermodynamics. At long last, asphaltenes are no longer the enigmatic component of crude oil, instead the resolution of asphaltene structures and dynamics has led to new thermodynamic applications in reservoirs, the new discipline RFG, and a new understanding of tar mats.

Paraffin represents one of the main case of failures and production losses which facing the entire oil industry. Prevention of paraffin deposition on the subsurface/surface equipment can be achieved by keeping the paraffin dissolved in crude oil or minimizing the adhesion or aggregation process of wax crystals. The paraffin problems which occur, conduct to gradual reduction of the tubular and pipelines internal diameter, restriction or valves blockages, and reduce the equipment capacity until the production is stop. Problems due to paraffin deposition varies and is different according with each commercial field, sometime the difference is from a well to well which producing from the same reservoir with different consistency. How we shall proceed? Before or after paraffin is field on the equipment? How could be avoid the future paraffin deposition? How long the selected method is proper for well ? The decision represents a combination based on oil's chemical & physical characteristics, well's behavior, method selected for prevention or elimination and combined with economic analysis and field experience. The paraffin inhibition applying is a common practice in OMV Petrom, which cover majority of the production wells. For the special wells, which the paraffin inhibition didn't provided satisfying results (multiple intervention due to paraffin deposition) was selected the Down Hole Heating technology (DHH) which was successfully tested in our company since 2014 thanks according with the yearly New Technology Program. The operating principle consists in heating the fluid volume from tubing using the heating cable which can be installed inside tubing, for NF and ESP wells or outside tubing for SRP or PCP wells. The cable is designed and located at the interval of wax crystallization appearance and heats the fluid to the temperature higher than the wax crystallization point (WAT). Since then, the DHH technology had an upward course, proven by high run life (highest value 2500 days / average 813 days) of the technology at the total 47 wells equipped, until this moment. Based on the successful results, recorded of 64% of old production wells equipped, it was decided to apply the technology at first completion of the new wells (36%), thus ensuring the protection of the new equipment. The paper offers an overview of DHH technology implementation, achievements, benefits and online monitoring of technology implementation starting with 2014 until today. The total impact shown a decreasing of no.of failures with 73,8%, the cost of intervention with 76,5%. The production losses decreased only with 5%, which certifies the fact that the technology helping production maintaining during the exploitation in comparison with production losses due paraffin issues recorded at wells without equipped with DHH technology. During 6 years of down hole heating technology application were developed candidate selection decision tree, monitoring the electrical efficiency, using the adaptability capacity of the technology from one well to another and integrate the temperature parameters in online monitoring system as part of digitalization concept of OMV Petrom, aspects which will be present in this article.

Pigging of Once Through Steam Generators (OTSGs) indicated various types of scales, the most predominant of these being silicates of hardness causing ions. It was noted that scaling propensity can potentially go up with higher Steam Quality (SQ) as the reject stream gets concentrated with ions. However, models suggested that there are benefits of higher SQ in enhancing fuel savings (8%) and electricity savings (2%) when SQ was increased by 20%. The challenges of higher SQ were noted in terms of increased scaling tendency and therefore the need for improved softening. In Field D, the service cycle, the backwash cycle, and the brining cycle were optimized leading to a gain in throughput and reduction in salt consumption. Service cycle improvement gained 30 % to 130 % in throughput between two regenerations, backwash cycle improvement by fluidizing the bed to nearly 35% helped gain 10% in throughput, and reduction of brining cycle from 75 minutes to 48 minutes helped reduce salt consumption by 56% without impacting the throughput. In Field B, a six month pilot revealed that shallow shell resins where ion-exchange is more efficient due to inert core (better intra particle diffusion control) can enhance the throughput by 30% - 80% and simultaneously reduce the number of regenerations by 15 – 30%. Resin fouling is still a major challenge to contend with as oil can foul the resin and throughput can decline by 0.5 – 3 folds. In a plant operation, where there are multiple softener and brine vessels, there is a need to optimize them as a system. Reliability, Availability, and Maintainability (RAM) Models are used in Field C to a) Address equipment configuration optimization with impact on capital capacity expansion project scope b) Understand how net softwater delivery capacity was affected by increases in inlet hardness and c) Assess through a comparison scenario, if the large cost of addressing the valve issue in an upstream nutshell filter was worth the lost production opportunity related to unplanned downtime.

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.

Pickering emulsions are stabilized by solid particles that occupy the fluid-fluid interface, physically preventing coalescence. Their stability in brine, where interparticle electrostatic repulsion is negligible and van der Waals (vdW) attraction dominates, makes them attractive for applications in porous media. Recent studies postulate that inter-droplet particle networks assemble in brine and aid Pickering emulsion stability to coalescence. This work experimentally assesses the effect of increasing interparticle vdW attraction on particle network strength and emulsion stability. We grafted 6 nm, 12 nm, and 20 nm silica nanoparticles with varying densities of polyethylene glycol (PEG) to prevent aggregation and dispersed them in either brine or deionized water (DI). We characterized the PEG-coated nanoparticles with thermogravimetric analysis and dynamic light scattering to determine PEG grafting density, diameter, and zeta potential. To generate oil-in-water emulsions, we sonicated dispersions of variable nanoparticle concentration and decane in equal volumes. We imaged the emulsions with microscopy and centrifuged them for 15 minutes at 5000 g of acceleration, using the volume of decane released after centrifugation as a measurement of emulsion coalescence to the applied force. Nanoparticle characterization confirmed successful grafting of PEG to the silica surface. We compared trends in emulsion stability as a function of salinity and particle diameter to changes in the relevant interparticle forces described by extended Derjaguin-Landau-Verwey-Overbeek (DLVO) theory. Analysis of microscopy images showed an increase in emulsion droplet diameter with decreasing nanoparticle concentration, salinity, and increasing nanoparticle diameter. Through centrifugation we observed that lower PEG grafting densities tended to produce more stable emulsions, suggesting that particles with high grafting densities and consequently high steric repulsion tended to repel and prevent formation of strong particle networks. Emulsions generated in DI coalesced more easily, indicating that electrostatic repulsion dominated relative to vdW attraction and that particle networks did not form. In brine, where electrostatic forces were screened out by counterions, the emulsions better resisted coalescence, consistent with the formation of a particle network. The strength of the network was inferred from the difference in emulsion stability to coalescence in DI and in brine. We measured a greater brine-DI stability difference of 3.7× for the larger 20 nm PEG-coated nanoparticles, compared with 3.3× and 2.2× for the 12 nm and 6 nm PEG-coated particles, respectively, further supporting the role of particle networks on emulsion stability.

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

The harsh conditions presented in Brazilian presalt, summed up with the complexity of its reservoir, generate a series of challenges to improve reservoir recovery. Routinely, we have used intelligent completion systems to address the major part of the challenges; however, with the new production rates new problems have arrived and the usual ones have turned more aggressive, generating risks even to the intelligent completion systems. Inorganic scale is a critical challenge in presalt reservoirs production. Future plans for presalt production include more robust flow conditions and the use of an all-electrical completion system. Higher flow rates are likely to increase the risk of scale deposition and an optimum design is required. To address the new challenges arising from the new perspective of exploration in the presalt fields, we developed the presented workflow to mitigate the scale deposition on completion valves. The method enables the optimization of choke geometry to reduce scale deposition on inflow control valves. The proposed workflow generates a criticalness parameter for geometry classification according to a scenario of mechanical failure (due to sleeve incapacity to move) or deviation of production design point. A computational fluid dynamics (CFD) simulation was developed and benchmarked by experimental data, thus CFD results for different scenarios and various choke geometries were used to build a risk analysis matrix, which allows the definition of the optimal choke design to mitigate scale on ICVs. The extracted criticalness parameter may be used as an evaluator to estimate the time to valve stuck due to scale deposition in a commercial 1D transient flow simulator, optimizing then valve cycling time.

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.

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.

Carbonate reservoirs are challenging for chemical EOR, particularly in selecting fine-tuned chemical formulations which combine high performance, stable behavior, and trouble-free operations. The design of suitable formulations requires substantial laboratory work and a solid methodology. In this paper, a systematic all-inclusive laboratory workflow to design a surfactant-polymer (SP) formulation for a carbonate reservoir is presented. In this work, a complete process for development and evaluation of an SP formulation for high-salinity high-temperature conditions is proposed and adopted. For which, a high throughput robotic platform is used for efficient and robust formulation design. The process is illustrated on an actual case with harsh reservoir conditions (i.e. a high temperature of 100℃ and high connate salinity of 213,000 mg/L). The SP design methodology consisted of five steps: surfactant design, polymer selection, surfactant/polymer verification, topside assessment, and oil-displacement evaluation. The surfactant formulation design consisted of four substeps: solubility scans, phase-behavior scans (salinity scans), IFT measurements, and static adsorption tests. The sourced polymers were screened based on three key performance indicators: viscosity, filter ratio, and thermal stability. The selected surfactant formulations and polymers were then assessed as sloppy slugs in terms of compatibility and injectivity. Then, the unique topside assessment was conducted where it consisted of two components focusing on: separation kinetics and separated water quality. Finally, an oil displacement study was performed using a preserved composite plug, in which the SP formulation developed through the outlined process was used. The results demonstrate the potential of a mixture of Olefin Sulfonate (OS) and Alkyl Glyceryl Ether Sulfonate (AGES). The results also illustrate couple of polymers with stabilities suitable for high temperature conditions: an associative polymer, and an AM/AMPS copolymer. In addition, injectivity corefloods supported the SP slug transportability across the porous media. Corefloods also demonstrated the SP slug capacity to recover around 62% ROIC (remaining oil in core). Finally, SP in produced brines improved the separation kinetics but lead to a slight deterioration in separated water quality. A key novelty of the adopted workflow is the integration of topside assessment. In addition, the experimental steps were clearly delineated including the preparation of representative oils. Beside a clear layout of the methodology, the work demonstrates that a surfactant-polymer formulation can successfully be designed for high temperature carbonate reservoirs and provide encouraging guidelines with respect to SP impact on topside facilities.

Even though the influence of wettability alteration on imbibition is well-documented, its synergy with Interfacial-Tension (IFT) for Alkali/Nanoparticles/Polymer flooding requires additional investigation. Particularly, when the oil Total Acid Number (TAN) may determine the wetting-state of the reservoir and influences IFT. Therefore, a laboratory evaluation workflow is presented that combines complementary assessments such as spontaneous imbibition tests, IFT and contact angles measurements. This workflow aims at evaluating wettability alteration and IFT changes when injecting Alkali, Nanoparticles and Polymers or a combination of them. Dynamics and mechanism of imbibition was tracked by analyzing the recovery change with the inverse Bond number. Three sandstone types (outcrops) were used that mainly differ in clay content and permeability. Oils with low and high-TAN were used, the latter from the potential field pilot 16TH reservoir in the Matzen field (Austria). We have identified the conditions leading to an increase of recovery rates as well as ultimate recovery by imbibition of Alkali/Nanoparticles/Polymer aqueous phases. Data obtained demonstrate how oil TAN number (low and high), chemical agent and reservoir mineralogy influence fluid-fluid and rock-fluid interactions. Application of alkali with high-TAN oil resulted in a low-equilibrium IFT. Alkali-alone fall short to mobilize trapped low-TAN oil. Alkali-polymer is efficient in wettability alteration of oil-wet core plugs towards water-wet state for high-TAN oil. The investigated nanofluids manage to restore a water-wet state in cores with high clay content along with improving gravity driven flow. IFT reduction between oil and surface-modified nanoparticles is unaffected by the acidity of the oil. Furthermore, contact angle in high-TAN oil remained similar even after 1000 min of observation for 2.5% clay cores in synthetic brine, but increases significantly when in contact with alkali/polymer. Comparing porosity and permeability before and after imbibition, a slight reduction was observed after imbibition with brine and nanofluids. We preliminary conclude that permeability reduction is not associated to the tested nanoparticles present in solution. We observed evidence of change in the imbibition mechanism from counter-current (capillary driven/high inverse Bond number) to co-current (gravity driven/low inverse Bond number) for nanoparticles/alkali. The calculated inverse Bond number correlates with the ultimate recovery, larger inverse Bond number leading to lower ultimate recovery. This work presents novel data on the synergy of IFT, contact angles and Amott imbibition for the chemical processes studied. We leverage from complementary laboratory techniques to define a comprehensive workflow that allows understanding wettability-alteration when injecting Alkali, Nanoparticles and Polymers or a combination of them. Obtained results show that the workflow can be used as an efficient screening tool to determine the effectiveness of various substances to increase oil recovery rate and ultimate recovery.

This work presents a numerical assessment of chemical inhibitor injection to mitigate wax deposition in unconventional wells. The goal of this study is to simulate the deposition of wax under several operational conditions and later optimize the chemical inhibitor injection position, using two different types of numerical simulations. A transient one-dimensional multiphase flow simulator - ALFAsim, with a dedicated wax model, was used to predict flow conditions such pressure, temperature, holdup and flow pattern profiles, as well the position and rates that wax accumulates. The results from the 1D simulation were then used as boundary conditions in a 3D CFD simulator, which aimed to assess how long it would take to a satisfactory homogenization of the inhibitor with the flow and what would be the minimum depth for the injector should be installed. In this work, a 1D multiphase flow simulator with wax deposition model was used to identify on which operational conditions (flow rates and environmental temperatures) an unconventional well would start to present wax deposition on its tubing walls. After defining the susceptible region where the paraffin could deposit, it was important to verify if the inhibitor would be well homogenized with the stream when reaching this region. For that, a 3D CFD simulation was performed, using information obtained directly from the 1D simulator as boundary conditions. The CFD model was capable to show the mixing evolution of the inhibitor with the stream and it was possible to determine the minimum distance where the injector should be placed to guarantee such homogeneity. A real well was selected to provide comparisons between field observations and simulated data, in order to validate the model assumptions and accuracy.

Asphaltene deposition is a notorious flow assurance problem faced by oil companies that causes production loss and large expenses for operators. The complex nature of asphaltenes and limited data available makes it challenging to develop a full field implementation strategy that is economically viable as well. Conducting asphaltene clean-up operations whenever wells get plugged up are the reactive approach to deal with asphaltene issues. However these approaches often result in prolonged well downtime, production losses and high well intervention costs. As part of proactive measures, chemical inhibitors were screened for formation squeeze and field trials conducted to assess their performance. Results from these trials helped to frame the full-field implementation strategy that is promising from a technical-economic standpoint. This paper describes the asphaltene mitigation journey of a major Abu Dhabi oil operator that resulted in multi-million dollar savings.

Gas hydrate inhibition through the use of chemicals has been ongoing over the years and these chemicals are toxic, synthetic and expensive, adding to the cost of doing oil and gas business, and also leads to environmental degradation. The call for greener environment has necessitated the search for more eco-friendly gas hydrate inhibitors. This paper takes a look at the use of a bio-extract in its unmodified state to inhibit gas hydrate using a locally made mini flow loop for gas hydrate studies. The bio extract was compared to a conventional gas hydrate inhibitor 2-Di(methylaminoethyl)methacrylate (2-DMAEM). For all the weight percentages considered (0.01-0.05wt%), the bio-extract had better pressure profiles. At the end of the experiment which lasted for 120 minutes, this is attributed to the fact that the pressures in the system were more regulated which prevented rapid gas dissolution in water. The Bio-extract is plant based, locally available in the commercial quantity and is eco-friendly so it should be harnessed as gas hydrate inhibitors in lieu of the expensive and imported conventional hydrate inhibitor 2-DMAEM which non-eco-friendly.

In offshore production, the type of field development scheme is crucial aspect due to its associated flow assurance risks, which affect project economic, safety, and sustainability. The objective of this study is to simulate and evaluate two offshore field development schemes, namely subsea and platform in offshore Kuwait. Further objective is to carry out detailed transient simulation study on the subsea scheme to investigate flow assurance risks related to terrain slugging, and hydrates formation during shut-in and re-start transient events. The evaluation of the two schemes is based on the associated flow assurance risks, and project economics. Steady state simulations are used to identify the feasible production scheme, which is further simulated under transient shut-in/restart events to investigate flow assurance risks related to terrain slugging and hydrates formation. The steady state simulation results of this study showed that flow assurance risks such as hydrates and pipeline corrosion are significant in both production schemes. To mitigate these risks, sixteen different field development designs of both production schemes were simulated and economically evaluated. Results revealed that the subsea multiphase development scheme with 10-in. ID carbon steel multiphase flowline and 0.3-in. thick polypropylene thermal insulation is the optimum design. Consequently, the optimum design is further analyzed under transient conditions, resulting in appreciable risk of terrain slugging due to hilly-terrain pipeline configuration, especially for the low production rate cases. The transient shut-in/restart simulation results revealed a risk of hydrates formation due to cooling effect during shut-in, which is mitigated by MEG injection. In conclusion, the subsea multiphase flow scheme is selected over platform scheme due to manageable flow assurance risks, low capital investment cost, and minimum environmental impact. This study would enable Kuwait Oil Company to evaluate different offshore development schemes to ensure sustainable production with safe operation and protected environment.

This work aims to develop a fracturing nanofluid with a dual purpose: i) to increase heavy crude oil mobility and ii) to reduce formation damage caused by the remaining fluid. Three commercial nanoparticles were evaluated: two fumed silica of different sizes and one type of alumina. They were acidified and basified, obtaining nine nanoparticles (NPs) by the surface modification, characterized by TEM, DLS, Z Potential and Total Acidity. The effect of adding nanoparticles at different concentrations onto the linear gel and heavy crude oil was determined by their rheological behavior. Also, there was assessed the alteration of the rock wettability by contact angle for all NPs and concentrations. Based on these results, the nanoparticle with better performance was the neutral fumed silica of 7 nm at 1000 mg/L. These were used to make a fracturing nanofluid from a commercial fracturing fluid (FF). Both of them were evaluated through their rheological behavior overtime at high pressure following the API RP39 test and quantitative measurements of the rock sample wettability changes. Displacement tests also were performed on proppant and rock samples at reservoir conditions: pressure and temperature. Finally, there was evaluated the rheological behavior of the crude oil recovered in the displacement test. It was possible to conclude that the inclusion of nanoparticles allowed obtaining a reduction of 10 and 20% in the two breakers used in the commercial fracture fluid formulation. An alteration of the rock wettability was achieved, where the rock sample became up to 50% more wettable to water. Moreover, there was a diminution of 53% in the damage caused by the remaining fracturing fluid to the oil effective permeability in the proppant medium. In the rock sample, a decrease of 31% of this kind of damage was observed. Increases of 28 and 18 % in the crude oil recovery were noticed in the proppant and the rock sample, respectively. Finally, there was a reduction of 40% in the crude oil viscosity, showing the effectiveness of adding nanoparticles to fracturing fluids for increasing oil mobility and reducing the formation damage.

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.

Accurate and in-time monitoring of corrosion inhibitor (CI) residual concentration is a key factor in asset integrity management for oil and gas operations. However, the natural variability of CI residual due to field conditions is usually convoluted with the error introduced by sampling and analytical techniques. In traditional analytical techniques, it is typical to encounter error of over 100%. Recently, a novel nanoscale technique (TrueDetect™, TD) was developed to accurately measure CI in the field. This technique is based on a proprietary spectrometry technique and allows quick and accurate analysis of CI residual at the ppm level. The portable instrument allows field samples to be analyzed on-site without the need for shipping them to a centralized laboratory. In the current study, the TD technique was applied to analyze field samples from various fields. Moreover, the TD technique was capable of analyzing CIs at low dosages and could be used as a method to qualify CI products in the lab and in the field.

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.