Problem In Oil Fields Research Articles

Visualization of Casing Stress Characteristics under Non-Uniform In-situ Stress and Non-uniform Cement Sheath

Casing damage is a common problem in oil and gas fields due to the complicated stress state of casing. Especially in the horizontal well section, the casing is difficult to be centered, and the eccentric casing is prone to failure under non-uniform in-situ stress. In order to study the influence of non-uniform in-situ stress and non-uniform cement sheath on the stress state of casing, a numerical model of the coupling of casing, cement sheath and formation is established. The stress distribution characteristics of casing under four conditions of uniform in-situ stress uniform cement sheath, uniform in-situ stress non-uniform cement sheath, non-uniform in-situ stress uniform cement sheath and non-uniform in-situ stress non-uniform cement sheath are compared. The results show that the non-uniform cement sheath will cause the stress distribution of casing to be uneven, and the maximum stress on the casing is proportional to the amount of eccentricity. The non-uniform in-situ stress will cause the casing stress to be uneven and affect the extreme value of the stress on the casing inner wall. The results will provide the theoretical basis for the casing damage prediction effectively.

MATERNAL AND PATERNAL EFFECTS ON OFFSPRING INTERNALISING PROBLEMS: FINDINGS FROM FAMILY DATA AND EXTENDED GCTA ANALYSES

Barium sulfate deposition on the inner surface of a tube is one of the most serious oil field problems affecting oil field water injection systems. The effects of tube length, liquid volume, deposition time, the profile of the Ba2+ concentration in the outlet and the pressure drop in the tubing were evaluated using a graphite furnace atomic absorption spectrometer (GFAAS) and pressure transducer methods. The deposition model of BaSO4 in the tube is presented using coupled mass balance and fluid flow equations. The deposition model contains two governing parameters, the kinetic coefficient and the deposition coefficient, which can be estimated from experimental data. The predictions from the simplified model for barium sulfate scale were in good agreement with experimental data and laboratory observations. In addition, it was proved that many factors are important for deposition kinetics, including the accumulated barium ion amount, the initial flow rate, the initial barium concentration and the deposition time. Scanning electron microscopy (SEM) images of the inlet and outlet of the tube reveal the deposition thickness and morphology.

Factors affecting phosphonate measurement by inductively coupled plasma optical emission spectroscopy (ICP-OES) in oilfield produced waters

ABSTRACT Phosphonate scale inhibitors are commonly used to mitigate scaling problems in oilfields. Continuous measurement of phosphonate in the produced waters in the levels of few mgL−1 using ICP-OES is usually conducted to monitor and assess phosphonate treatments, and to qualify the discharged produced waters. These measurements of phosphonates in high salt producedwaters suffer from severe matrix effects, contamination, samples preservation and dilution issues. The results in this study showed that conducting measurements when the sample total dissolved solids (TDS) was higher than the calibration standards TDS that leads to lower phosphonate results, while higher results obtained when the sample TDS was lower than the calibration standards TDS. The matrix elements Na, Mg, and Ca were found to depress the emission lines intensity of phosphorus and their effect was in the order of: Ca > Na > Mg for the lines 213.617 nm, 253.561 nm, and in the order of Mg > Ca> Na for the line 214.914 nm. Besides, it was found that diluting the samples of low phosphonate content leads to lower phosphonate results; therefore, phosphonate measurements are better be conducted on undiluted samples. The instrument robust operating conditions at low nebulizer and pump uptake rates, high RF power and with the use of baffled cyclonic spray chamber showed better sensitivity, LOD and LOQ compared to the plasma non-robust conditions. The use of internal standard and quality control QC program along with the instrument setup at robust plasma conditions allowed direct measurement of phosphonate down to 1 mgL−1 without dilution, desalination, preconcentration or matrix matching. It was also found that Ca and Fe affect phosphonate measurements due to the high phosphonate precipitation/adsorption potential on their compounds, and acid preservation methods using HCl were found to be the best method to avoid phosphonate precipitation or adsorption.

Waterborne Polyurethanes as a New and Promising Class of Kinetic Inhibitors for Methane Hydrate Formation

A facile, new and promising technique based on waterborne polymers for designing and synthesizing kinetic hydrate inhibitors (KHIs) has been proposed to prevent methane hydrate formation. This topic is challenging subject in flow assurance problems in gas and oilfields. Proposed technique helps to get KHIs with required number and distance of hydrophilic and hydrophobic groups in molecule and good solubility in water. The performance of these new KHIs was investigated by high pressure micro-differential scanning calorimeter (HP-μDSC) and high-pressure autoclave cell. The results demonstrated the high performance of these inhibitors in delay the induction time (10–20 times) and reduce the hydrate growth rate (3 times). Also they did not increase hydrate dissociation temperature in comparison with pure water and show thermodynamic inhibition as well. Inhibition effect of synthesized polymers is improved with the increase of concentration significantly. Since this is the first report of the use of waterborne polymers as kinetic hydrate inhibitor, we expect that KHIs based on waterborne-based polymers can be a prospective option for preventing methane hydrate formation.

Applying Selected Lost Circulation Materials to Study Lost Circulation of Azkand Formation in Khabaz Oil Field

Managing lost circulation during drilling is a great challenge issue in naturally fractured or vugy formations. This situation becomes further complicated if there are gas or oil returns at the same formation or at a formation above it. The lost circulation problem happens in some of the northern Iraqi oil fields such as Khabaz oil field. Particulate lost circulation materials (LCM) have been used for many years to control lost circulation. However, these traditional LCMs are not efficiently applicable to cure sever to total losses, such as highly fractured formations and formation with large vugs. In this work, an experimental attempt was done to solve such problem in Khabaz oil field. The experiments were carried out using a closed loop circulation system that simulates the drilling fluid loss into formations. Five core plugs from Azkand formation of Khabaz oil field from different depths were used. The experiments were grouped into three, the first was done with the fresh-water-based drilling fluid to measure the severity of losses. The second, fresh-water-based drilling fluid was treated with traditional LCM (cotton seeds) to investigate how the severity of losses is affected by these materials. Adding polymer lost circulation material were the last sets to modify the drilling fluid rheological properties which prepare a medium within the lost circulation zone that increases the friction inside the losses paths to increase the LCMs (the polymer itself) sealing efficiency.

الإشكاليات القانونية المتعلقة بأستغلال الحقول النفطية المشتركة بين العراق وإقليم كوردستان وتسوية منازعاتها

يقصد بالحقول النفطية المشتركة، تلك الحقول التي يكون لها امتداد عبر حدود دولتين او اكثر، فالحقل النفطي يمتد في حدود دولتين او اكثر، فيبدأ من دولة معينة، و يمر عبر دولة اخرى، و قد يكون متمركزاً في إحدى الدولتين و مخترقاً في جانب منه لحدود دولة او دول اخرى. و يتطلب تنظيم هذا الأمر ابرام اتفاقيات ثنائية بين الأطراف المستغلة لإدارة الحقل. وعليه تظل مشكلة الحقول النفطية المشتركة بين دول الجوار تثير أكثر من سؤال وإشكال حول عائدية هذه الحقول ومدى أحقية كل طرف بإستغلالها. لاشك أن تداخل الحقول النفطية بين البلدان المتجاورة يفرض واقعا جغرافيا ونفطيا، ويُلزمها بإبرام إتفاقيات ثنائية وعقود الاستغلال المشترك بحصص تتناسب وحجم النفط المتواجد في باطن الحقول المتمددة خلف الحدود. وهذا الواقع النفطي المتداخل واسع الانتشار بين دول العالم، أما آلية ضبط واحتساب الحصص وأحجامها وكمياتها فهي من أهم وظائف الهيئات الدولية المحايدة المتخصصة في هذا المضمار، ولكن إثارة هذه المواضيع والمطالبة بالحقوق والمستحقات تثير في دول الشرق الأوسط بعض النعرات السياسية، وتتسبب في تجديد الصراعات. وقد توصل البحث الى العديد من الاستنتاجات والتوصيات، و من اهمها، أن انفراد كل دولة في استغلال حصتها من حقول النفط المشتركة لا يخدم المصالح الإقتصادية لهذه الدول إلا إذا وجد تعاون وثيق وتنسيق بينها في عمليات الاستغلال و الإنتاج، كالأتفاق على حصص متساوية من انتاج الحقل المشترك، وتحمل نفقات تطوير الحقل بحسب حصة كل طرف. وقدم البحث توصية لحكومة إقليم كوردستان ببذل جهود مضنية من اجل التوصل مع الأطراف المعنية إلى اتفاقيات ثنائية في إستغلال و إدارة الآبار والمصادر النفطية المشتركة، وأن تبادر الوزارات المؤسسات والجهات المعنية إلى إجراء المسوحات الدقيقة، وانجاز الدراسات المعمقة حول هذه الحقول المتمددة وراء الحدود الداخلية والدولية. وكما نوصي بإيجاد قواعد قانونية ومبادىء، بحيث يمكن تقنين تلك القواعد و المبادىء من خلال اتفاقية دولية شارعة لتكون بمثابة بداية لإعداد مشروع لقانون نفطي دولي، بحيث يعتد بقواعد هذا القانون في الإتفاقيات الدولية، وتعتمد عليها المحاكم الدولية ومراكز التحكيم الدولية في حسم ما يعرض عليها من منازعات النفطية عموماً والمنازعات التي تنشأ بين أطراف استغلال و إدارة الحقول النفطية المشتركة خصوصاَ.

Production Allocation on Commingled Two Layer Well Using Fingerprint Method

Production proportion ratio study of commingled well two layers reservoir has been developed by geochemistry approaching, with oil reservoir fingerpint methode by using Gas Chromatography then processed by Chemstation software. The study is developed to solve the commingled well production alocation problem in oil field. There are 4 oil samples will be analyzed to represent each layer and commingle production oil sample in 2009 and 2015.Result of study, figures out that oil fingerprint from commingle production has a difference as long as production time. Oil sample that taken from different commingle production time is predicted to produce a different ratio contribution form each layer of reservoir. Every layer reservoir has a different contribution from 2009 to 2015. Result of production proportion ratio study can be applied to decisionmaking of reservoir developement in an oil field, especially for well completion and enhanced oil recovery. This methode is proven to be a solution of commingle production problem of two layers reservoir. Fingerprint methode to determine production proportion ratio of commingled well production is the first in Indonesia.

Analysis of Stuck Pipe Incidents in Khabaz Field

There are many events which causes nonproductive time (NPT) in the drilling industry. The mostly effective in this NPT is pipe sticking event. A considerable amount of time and resources can be spent in efforts to free a stuck pipe. In addition, Unsuccessful fishing operations results in costly alternatives including side-tracking. The drilling in Khabaz oil field poses many operational challenges among of them stuck pipe , lost circulation, flow of salt water during drilling, and hole caving. Stuck pipe can be considered the quite difficult problem in Khabaz oil field due to associated incidents which lead to NPT activities.Well Khabaz -34 was selected to study the problem of stuck pipe in this field. An analysis of stuck pipe events was made by using the graphical analysis software Easy View. The results were then discussed to identify the causes of stuck pipe. Finally, recommendation to select proper type /drilling fluid rheology properties, optimize casing seat design to reduce probability of stuck pipe.

Analysis and Evaluation of Oil Well Riser with Different Exit Geometries Using Computational Fluid Dynamics (CFDs)

The exploration of large oil fields or wells in deep waters for crude oil and gas has generated immense challenges within the oil and gas industry that has caused remarkable developments in methods of optimizing production of oil and gas. This research work presents the analysis and evaluation of the flow dynamics of an exit riser configurations using computational fluid dynamics (CFDs). STAR-CCM+ computational fluid dynamics (CFD) tool was employed in this research work. To model the flow in the exit configuration, the geometry of the exit configuration was created using CATIA. The CATIA model saves as IGES format were imported into the STAR CCM+ as regions with the one boundary per face setting, the one region per body setting was also selected and the sewing tolerance was set to 0.001. Four different exit configurations were analyzed for the single phase flow. The results obtained show that the flow in the exit configuration 3 converges faster. Also, from the pressure plot it is discovered that the pressure remained steady until it reaches the junction where a division of the flow occurs. The total pressure and the static pressure are low for exit 3 and lowest for exit 4. For companies where the computational cost is of paramount importance, exit 4 should be considered if oil-field problems and monitoring are done via CFD tools.

Evaluation of Soy Lecithin as Eco‐Friendly Biosurfactant Clathrate Hydrate Antiagglomerant Additive

AbstractHydrate plug formation is one of the most challenging problems in upstream oilfields. The most preferred option to prevent hydrate plug formation is the use of antiagglomerants in the oil/gas flowlines and in drilling fluids. Antiagglomerants do not prevent hydrate formation but restrict the hydrate crystals from agglomerating. In this study, experiments were conducted on of soy lecithin (biosurfactant) at different concentrations to measure its effectiveness as an antiagglomerant additive. In all the experiments, tetrahydrofuran (THF) hydrate was used, and to study the antiagglomerant efficiency of the additive, visual observation was utilized. Soy lecithin was compared with cetyltrimethylammonium bromide (CTAB), and the former was found as a good environmentally friendly antiagglomerant additive. Soy lecithin at 0.1 wt% in the experimental solution increased the agglomeration time of hydrate crystals by more than 1440 min and showed agglomeration state III at 1 °C. Soy lecithin at 0.01 wt% increased the agglomeration time of hydrate crystals to 1000 min. The effect of soy lecithin on the rheological characteristics and filtration properties of drilling fluid was also studied. Even at the highest concentration of 1.0 wt% soy lecithin and at a temperature of 1 °C, the rheological parameters of the drilling fluid remained within permissible limits. Soy lecithin was thus found to effectively restrict the agglomeration of hydrate crystals.

Adding the Human Touch to Oilfield Apps

As time goes by, an increasing number of new processes that oil and gas companies want to push to their workforce will come in the form of an app. This is true for field technicians as well as production engineers. But just as with anytime change is introduced, the improvements these apps are intended to deliver may not be lasting—or realized at all—without strong internal acceptance. ChaiOne is a Houston-based app developer that has built its business around this conundrum. In its 9 years, the company has worked for several of the upstream industry’s most recognizable names including ExxonMobil and Schlumberger. Chief Executive Officer Gaurav Khandelwal said the company’s success lies in its bottoms-up strategy, which begins with the end user and “understanding their problems, stresses, frustrations, and emotions.” This work relies on teams of behavioral psychologists, anthropologists, and software interaction engineers who are tasked with figuring out new ways for workers to save time and money for their companies. Like others who promise efficiency improvements to the oil and gas business, a lot of ChaiOne’s efforts are centered around reducing how much time is spent on regular working hours and overtime. “When we take the user-experience-driven approach, and send people into the field to study a process, often we find tremendous amounts of waste in the way things are being done,” explained Khandelwal, adding that, “In 4 to 6 weeks, we can find millions of dollars in savings in these companies.” Smarter Field Repair Many of the software products that ChaiOne has created cannot be discussed thanks to the industry’s penchant for nondisclosure agreements. But among those that it can speak freely about is CygNet, which was developed for inter-national service company Weatherford. This iPhone app connects with oilfield SCADA systems to show engineers production trends or to relay important alarms. Khandelwal said operators who use the app—12 of which supplied input to steer its development—are now using fewer field technicians to deal with routine oilfield problems. When a worker is on his way back from a repair job, it is not unusual for another problem to arise at a wellsite just 10 minutes away. In the past, Khandelwal said that the technician would likely be unaware of a nearby failure, and because dispatch did not know they were close by, an additional crew would be sent out. With the CygNet app, the reverse is now true for its users. When a repair team is out on location and a nearby well sets off an alarm, CygNet sends a geo-targeted notification. And just as important, the app can also help them decide if the issue needs to be attended to at all.

Simulation of asphaltene precipitation during gas injection using PC-SAFT EOS

Oilfield problems owing to asphaltene precipitation are well known. Asphaltenes can block pore throats or change the formation wettability and thereby reduce the hydrocarbon mobility. Simulation of asphaltene precipitation during gas injection requires a comprehensive thermodynamic model, which accounts for the complex phase behavior of asphaltenes. In this paper, PC-SAFT EOS is implemented for the first time in a compositional reservoir simulator to model asphaltene precipitation. The additional computational time of PC-SAFT compared to the cubic equations-of-state such as Pen-Robinson (PR EOS) is decreased by improving its root finding algorithm. A deposition and wettability alteration model is then integrated with the thermodynamic model to simulate the dynamics of precipitated asphaltenes. Different gas injection scenarios are modeled to show the effect of gas injection on apshaltene precipitation and deposition.Simulation results show that the profile of the damaged area by asphaltene deposition is governed by the shape of the asphaltene precipitation envelope for the reservoir fluid. The damage caused by asphaltene deposition, through plugging and wettability alteration, was revealed as a decline in productivity index curves. Results indicate that a reservoir fluid can have precipitation risk during gas injection even if it does not exhibit precipitation in the primary recovery life of a field. The computational time of the simulations using PC-SAFT EOS were compared to those using PR EOS for different number of components. Results of these comparisons show the feasibility of using PC-SAFT in compositional simulations.

Determination of asphaltene precipitation using a CPA equation of state

ABSTRACTAsphaltene precipitation during natural depletion and miscible gas injection is a common problem in oilfields throughout the world. Therefore, predicting asphaltene phase behavior through thermodynamic modeling may help to control its precipitation and reduce the associated problems. In this work, a new modified CPA equation of state (EoS) was used to model asphaltene precipitation. This equation is based on a combination of a new physical part and the Wertheim association term.The results of the new model were compared with the experimental data of five oil samples. The results showed that this modified CPA EoS can predict asphaltene precipitation with good accuracy.

Uncertainty quantification for cuttings transport process monitoring while drilling by ensemble Kalman filtering

The aim in this work was to develop a method to draw our conclusions for the uncertain quantities of interest in a real problem in oilfield, namely the cuttings transport problem, given the limited data available. The cuttings transport process is subject to disturbances and is influenced by various factors in a stochastic and uncertain manner. In addition, the drilling environment is very complex to understand fully, and to model efficiently and accurately. An experiment was conducted to monitor the process in real-time via time-series measurements of distributed pressure transducers along the drillstring. A mathematical model describing the dynamic process of cuttings transport is developed, which aims to capture the dominant characteristics of the process, without attempting to model reality perfectly; modeling and measurement errors are represented by uncertainties in model inputs, parameters, and states. The proposed model is described in detail, and is incorporated in the Bayesian framework (via ensemble Kalman filtering) to make our best estimate about the location and amount of cuttings transported along the wellbore in real time, given the available data. The estimations of the uncertain process parameters are described.

Determination of asphaltene precipitation using a new CPA-based equation of state

ABSTRACTAsphaltene precipitation during natural depletion and miscible gas injection is a common problem in oilfields throughout the world. Therefore, predicting asphaltene phase behavior through thermodynamic modeling may help to control its precipitation and reduce the associated problems. In this work, a new modified cubic-plus-association (CPA) equation of state (EoS) was used to model asphaltene precipitation. This equation is based on a combination of a new physical part and an association term.The new physical part has an evolved cubic equation of state with a new attractive term in this work. The results of the new modification of CPA EoS were compared with the experimental data of two oil samples (oil samples 1 and 2) that belonged to Moradi et al. The results showed that this modified CPA EoS can predict asphaltene precipitation with good accuracy.

Screening Cation and Anion of Ionic Liquid for Dissolution of Silicon Dioxide using COSMO-RS

Objectives:Silicon dioxide (SiO2) is one of the common oilfield scales which is hardest scale to dissolve and there is no specific commercial chemical scale removal to dissolve SiO2. The purpose of this study to screens Ionic Liquids (ILs) that will be used in dissolution of SiO2due toscale problem in oilfield. Methods/StatisticalAnalysis:COSMO-RS since then has become a widely used and fast method for the prediction and screening of ionic liquid properties, is used for sigma profile, sigma potential and solvent capacity for metal dissolution. The best cation and anion have been chosen based on sigma profile, sigma potential and the high solvent capacity from COSMO-RS findings. Findings: Ammoniumcation and sulfate anion is the best combination with highest amount of SiO2 capacity is 7.832x1010. Ammonium sulfate is the possible ionic liquid to dissolve SiO2 scale in oilfield.

Development of anionic-cationic inhibitors for mitigating silicate scales during ASP flooding

Silicate scaling is often induced by alkaline surfactant polymer (ASP) flooding in sandstone reservoirs. The formation of silicate scale is complicated by its dependence on multiple factors including pH, silica concentration, and magnesium concentration, which vary as the flood progresses. These factors affect silicate scaling tendency, and consequently, severity of the problem. Silicate scale is a very serious problem in the oil and gas production system. Therefore, silicate scale inhibitors have been suggested to mitigate problems in oilfields. In this study, some of the dendrimers inhibitors with enhanced functionality used in the water industry were reviewed and assessed for possible application in oilfields scales. It was found that the NH2-terminated dendrimers exhibited excellent inhibitory silica polymerization efficiency compared with the control. It is now certain that effective silica scale inhibition is dependent on the cationic charge on the polymer backbone. However, these dendrimer inhibitors suffered from a serious disadvantage when the silicates that had not been inhibited entrapped the dendrimers. Visual observations showed that these particles appeared as white flocculant precipitates at the bottom of the test vessels. Previously, it had been found that silica scale inhibition could be achieved by using of scale inhibitors in combination with anionic polymer additives. It is believed that an effective silica inhibition should be based on a delicate balance structure of cationic–anionic charges. Therefore, in the present study pteroyl-L-glutamic acid (PGLU) compound is used in synergistic action with cationic dendrimer polymer. PGLU was proven to be an effective scale inhibitor at high temperature in aqueous solution of synthetic produced water. Furthermore, it was found that PGLU assisted the inhibitory action of dendrimers by alleviating formation of insoluble SiO2-PAMAM precipitates to operate more effectively.

An efficient geometry-based optimization approach for well placement in oil fields

This study aims at introducing a problem-specific modified Genetic Algorithm (GA) approach for optimal well placement in oil fields. The evolution method used in this algorithm includes a novel genetic operator named “Similarity Operator” alongside the standard operators (i.e. Mutation and Crossover). The role of the proposed operator is to find promising solutions that share similar features with the current elite solution in the population. For the well placement problem in oil fields, these features include the new well location with respect to pre-located wells and the porosity value at the proposed location. The presented approach highlights the importance of the interaction between the nominated location and the pre-located wells in the reservoir. In addition, it enables systematic improvements on the solution while preserving the exploration and exploitation properties of the stochastic search algorithm. The robustness of Genetic Similarity Algorithm (GSA) is assessed on both the PUNQ-S3 and the Brugge field data sets.

Using high- and low-salinity seawater injection to maintain the oil reservoir pressure without damage

The oil reservoir pressure declines due to oil production, and this decline will lead to reduction in the oil productivity. The reservoir pressure maintenance is a practice in the oil industry in which seawater is injected into the aquifer zone below the oil zone to support the reservoir pressure. Calcium sulfate scale is one of the most serious oilfield problems that could be formed in sandstone and carbonate reservoirs. Calcium sulfate may precipitate during the injection of seawater with high sulfate content into formation brine with high calcium content. Mixing seawater and formation water may cause precipitation of calcium sulfate, barium sulfate, and/or strontium sulfate. Seawater treatment does not remove the entire sulfate ions from the injected water. Low sulfate concentrations may cause damage. Enhanced oil recovery processes such as smart water injection, which originally is diluted seawater, may cause calcium sulfate precipitation as the reduction of water salinity will increase the sulfate precipitation and decrease its solubility. This study was conducted to investigate the damage caused by the deposition of calcium sulfate precipitation. A solution is proposed to prevent the damage due to calcium sulfate by using chelating agents. Several coreflooding experiments were conducted using Berea sandstone and Indiana limestone cores at reservoir conditions of pressure and temperature using seawater (high and low salinity) and formation water. Chelating agents used in this study are: EDTA (ethylenediaminetetraacetic acid), HEDTA (hydroxyethylenediaminetriacetic acid), and HEIDA (hydroxyethyliminodiacetic acid). HEDTA and HEIDA chelating gents are environmentally friendly and can be used in marine environment. High-salinity water injection caused severe formation damage, and the injectivity will decline faster compared to the low-salinity water injection. HEDTA and EDTA chelating agents at low concentrations performed better than HEIDA chelating agents in both Berea sandstone and Indiana limestone cores. HEDTA and EDTA chelating agents were able to prevent the damage due to calcium sulfate precipitation and enhanced the core permeability.

Simulation for estimation of hydrogen sulfide scavenger injection dose rate for treatment of crude oil

The presence of hydrogen sulfide in the hydrocarbon fluids is a well known problem in many oil and gas fields. Hydrogen sulfide is an undesirable contaminant which presents many environmental and safety hazards. It is corrosive, malodorous, and toxic. Accordingly, a need has been long left in the industry to develop a process which can successfully remove hydrogen sulfide from the hydrocarbons or at least reduce its level during the production, storage or processing to a level that satisfies safety and product specification requirements. The common method used to remove or reduce the concentration of hydrogen sulfide in the hydrocarbon production fluids is to inject the hydrogen sulfide scavenger into the hydrocarbon stream. One of the chemicals produced by the Egyptian Petroleum Research Institute (EPRI) is EPRI H2S scavenger. It is used in some of the Egyptian petroleum producing companies. The injection dose rate of H2S scavenger is usually determined by experimental lab tests and field trials. In this work, this injection dose rate is mathematically estimated by modeling and simulation of an oil producing field belonging to Petrobel Company in Egypt which uses EPRI H2S scavenger. Comparison between the calculated and practical values of injection dose rate emphasizes the real ability of the proposed equation.