Sour Gas Wells Research Articles

Optimization of Velocity String Drainage and Gas Recovery Process for Sour Gas Wells in Jingbian Gas Field

Abstract In view of the gradual attenuation of gas well energy during the development of Jingbian gas field, the liquid carrying effect of some gas wells with small gas production becomes worse, the drainage effect of 60 % gas wells is not ideal, and the H2S content of the lower paleo-sulfur gas wells is high, the salinity is high, there is a certain corrosion, and most of the drainage measures cannot be implemented. The optimization of sulfur-resistant velocity string was carried out from the aspects of velocity string size and pipe material, and the appropriate pipe diameter and pipe material were selected. A new type of broken disc speed string plug was developed, which successfully solved the problem that the existing plug could not be broken or returned after construction. The field application results show that compared with the 27/8 “ string, the liquid carrying flow rate is reduced by 82 %. After 2.5 years of service, the anti-corrosion performance of the pipe is good. The cumulative increase of the well is 445.4 thousand cubic meters, and the effective rate of the measures is 97.45 %. The stable and continuous liquid carrying of the gas well is realized, which has a good application effect. It has certain reference significance for the implementation of the drainage gas recovery technology of the velocity string in the lower ancient sulfur gas well.

Corrosion law of cement paste under hydrogen sulfide conditions in natural gas wells

Downhole anticorrosion in sour gas (H2S or CO2) wells is one of the technical problems in petroleum engineering, and the corrosion law of cement paste, which is the “first barrier of the wellbore,” needs to be focused on. Aiming at the problems existing in the current research on the corrosion of underground cement paste, a curing method for interfacial corrosion is proposed. X-ray diffraction and scanning electron microscopy are used to investigate the corrosion mechanism of cement paste cured under hydrogen sulfide (H2S) conditions in natural gas wells. Experimental results showed that the corrosion depth of cement paste is proportional to the partial pressure of H2S and the corrosion time, and the compressive strength of cement paste after corrosion is inversely proportional to the H2S partial pressure value and the corrosion time. Due to the gradual enrichment, accumulation, and migration of products after the cement paste is corroded by H2S, the cement paste forms a relatively stable dense layer or corrosion transition zone. The porosity and permeability of cement paste after corrosion increased with corrosion time, showing the characteristics of first increasing and then decreasing and finally making it more difficult for the corrosive medium to enter the interior of the cement paste. It is an important method stable corrosion transition zone forms as soon as possible, which is important to maintain the long-term sealing and chemical integrity of the cement sheaths in natural gas wells containing H2S.

Polymeric Membranes for H2S and CO2 Removal from Natural Gas for Hydrogen Production: A Review

Natural gas, an important source of hydrogen, is expected to be crucial in the transition to a hydrogen-based economy. The landscape of the gas processing industry is set to change in the near future with the development of highly acidic sour gas wells. Natural gas purification constitutes a major share of the gas separation membrane market, and the shift to low-quality sour gas wells has been mirrored in the trends of membrane material research. Purification also constitutes the major portion of the cost of natural gas, posing implications for the cost of hydrogen production. This review provides an update on the current state of research regarding polymeric membranes for H2S removal, along with CO2 separation, from natural gas that is used for hydrogen production via steam methane reforming. The challenges of adapting polymeric membranes to ternary H2S/CO2/CH4 separations are discussed in detail. Key polymeric materials are highlighted, and the prospects for their application in H2S removal from natural gas are evaluated. Finally, the growing interest in H2 production from H2S is discussed. Advances in the membrane industry and the emergence of new membrane materials may significantly improve the commercial viability of such processes.

TUBING HANGER INVESTIGATION OF LOADING

In this article, the failures of tube hangers made from UNS N07718 are discussed. An arrangement known as a tubing hanger may be found in wells that produce either oil or gas. It is positioned in the upper tubing head’s bowl after it has been installed. The tubing is held in place by this, and a main annulus seal is created between tubing also the production casing. This holds the tubing in place, and at the same time, it creates a primary annulus seal between tubing also production casing. When compared to odd component in wellhead system, tubing hangers are available in a broader range of styles and sizes than any other option. Tubing hangers made of UNS N07718 are often used in the installation process of sour service oil and gas wells that operate under high pressure and also high temperatures. Afterwards more than 10 years of service, it was only recently found that the tubing hanger made of UNS N07718 had failed in sour wells. Failures of the tubing hanger will inference in substantial production delays as well as high workover expenses. The purpose of this research is to demonstrate the failure mechanism of tubing hanger furthermore its ramifications on existing wells that were erected with material that is comparable to what was used here. In order to establish what caused the failure, each and every exposure that was brought on by well intervention efforts was evaluated. The manner of failure of stringer head suspension was researched, as was its influence on already existing wells that had been erected with materials that were comparable. Keywords: tubing head, tubing hanger, tubing thread, back pressure valve profile, landing shoulder, snap ring, running thread,

Design of Multifunctional and Efficient Water-Based Annulus Protection Fluid for HTHP Sour Gas Wells

In order to solve the corrosion problem of production string in the process of acidizing for the purpose of production, a new water-based annular protective fluid suitable for HTHP acid gas, including H2S-CO2 wells, was developed. Firstly, an appropriate deoxidizer, bactericide, and corrosion inhibitor shall be selected according to the production string of acid gas. In addition, the synergism between additives is evaluated. Then, by designing the additive ratio, the optimal formulation of the water-based annular protective fluid is determined. Finally, a high-temperature autoclave was used to evaluate the protective performance of the water-based annular protective liquid. The results showed that it is recommended to use water-based annular protective liquids prepared with clear water that comes easily from nature (rivers, etc.), which consist of a corrosion inhibitor, CT2-19C (30,000 ppm), BN-45 bactericide (2 g/L), and anhydrous sodium sulfite (3 g/L). The density of the water-based annulus protection liquid is 1.02 g/cm3, and the freezing point is −2.01 °C. The dissolved oxygen content of water-based annulus protection fluids prepared with clear water in formation water shall be controlled within 0.3 ppm. The corrosion inhibition rate of water-based annular protective fluid in the liquid phase is higher than 90%, and the corrosion rate of P110SS steel in the gas–liquid phase is lower than the oilfield corrosion control index (0.076 mm/y).

Application of anticorrosive materials in cement slurry: Progress and prospect

During gas well cementing operation, the erosion of acidic formation corrosive medium will destroy the cementation between the cement slurry and the sidewall in the well sealing section, reduce the mechanical properties of the cement paste, cause problems such as sidewall collapse and casing damage, seriously endanger the normal exploitation of oil and gas resources, and cause major safety accidents. Therefore, improving the corrosion resistance of cement paste is the key to ensuring long-term stable cementing of high-temperature sour gas wells. This paper summarizes the influencing factors, corrosion mechanism, corrosion test methods and research status of anti-corrosion oil well cement additives, discusses the advantages and disadvantages of each anti-corrosion additive, summarizes the latest progress and challenges of anti-corrosion oil well cement, and aims to provide some reference for researchers in related fields.

Research and Application of Surface Throttling Technology for Ultra-High-Pressure Sour Natural Gas Wells in Northwestern Sichuan Basin

The gas reservoirs in the Northwestern Sichuan Basin have great development potential. However, their production efficiency is seriously reduced by the complex surface multistage throttling process and frequent hydrate plugging caused by the ultra-high-pressure sour gas. Considering the prevention and control of hydrates, properly designing the throttling temperature and pressure to optimize the surface production process is the key to solving this problem. First, this work presents a method for predicting the hydrate formation conditions of ultra-high-pressure sour natural gas based on the vdW-P (van der Waals–Platteeuw) model and the CPA (cubic-plus-association) equation of state (EoS) and considering the association between acid gases (H2S, CO2) and H2O. Secondly, the throttling temperature prediction method was developed by coupling the isenthalpic throttling model and the modified Lee–Kesler EoS mixing rule; the maximum throttling pressure difference calculation method was constructed based on the critical flow principle. Finally, field cases are given to illustrate the distribution process of assigning the maximum throttling pressure differences. The results show that the proposed model can accurately predict the hydrate formation conditions and throttling temperature of ultra-high-pressure sour natural gas, and reveal their changing laws. The surface throttling technology of the ultra-high-pressure sour gas wells Long 004-X1 and Long 016-H1 was optimized from five-stage to three-stage, and the application of the fixed throttle valve in the field is successfully demonstrated.

Numerical Simulation of Sulfur Deposition in Wellbore of Sour-Gas Reservoir

Sulfur deposition has an important effect on the productivity of sour-gas wells. Accurately predicting the occurrence of sulfur deposition and the location and amount of sulfur deposition in wellbore can effectively guide the production of gas wells. In this paper, the wellbore sulfur deposition model, pressure model, and transient temperature model are established for various well types. Then, numerical simulations of sulfur deposition in the sour-gas well were conducted by coupling these models. Examples show that the proposed methodology has high accuracy, and the average relative error of the calculated results is 3.61%. Based on the model, a sensitivity analysis was performed on the factors affecting sulfur deposition. The results show that with the increase of wellbore inclination angle, the critical sulfur carrying velocity first increased and then decreased, and the maximum critical velocity is about 30% larger than that of the vertical section. The amount of wellbore sulfur deposition increases with increased production time and decreased wellbore pressure, and the amount of wellbore sulfur deposition decreases with increased gas production rate, H2S content, and inclination angle. The results suggest that the sour-gas reservoir should be developed with the horizontal or deviated well, timely adjust the production system, and keep the gas-well production higher than the critical flow rate as much as possible. At the same time, wellbore heating and insulation, pre-cleaning technology, and the closely implemented sulfur deposition prevention technology in the middle and late stage of development can be adopted to reduce the occurrence of sulfur deposition to ensure the safe and efficient development of high-sulfur gas wells.

Densities for Sulfur in Benzene and Densities with Solubilities for a Eutectic Mixture of Biphenyl plus Diphenyl Ether: A General Solubility Equation for the Treatment of Aromatic Physical Sulfur Solvents

Physical sulfur solvents are utilized in (i) the mitigation of sulfur deposition in sour gas wells and gathering lines and (ii) as a process medium for small-scale sulfur recovery. Non-aqueous aromatic solvents have two distinct advantages, where they are less reactive with elemental sulfur and provide for relatively large sulfur solubilities. Understanding the solubilities and physical properties within aromatic sulfur solvents over a wide range of temperature and pressure is important for both the previous applications. In this study, high-pressure densities for sulfur in benzene and a eutectic mixture of biphenyl and diphenyl ether were measured for T = (298.15–373.15) K and p < 100 MPa, where the densities were used to calculate the molar volume change upon dissolution. New sulfur solubility measurements are reported for sulfur in the eutectic mixture of biphenyl and diphenyl from T = (298.15–403.15) K and compared to benzene, toluene, and xylenes (BTX). The calculated volumetric changes and measured solubilities at atmospheric pressure were used to determine the enthalpy of dissolution, ΔX→slH°, and the change in heat capacity, ΔX→slCp°, for the α-sulfur, β-sulfur, and the liquid-sulfur phase dissolution using a van’t Hoff model. The eutectic solvent showed a higher solubility when compared to BTX at higher temperatures (β-sulfur and the liquid-sulfur regions) and both solubilities calculated to have a very small pressure dependence.

Technology Focus: Drilling and Completion Fluids (November 2021)

Design and development of optimal drilling-fluid systems, as well as their proper maintenance while drilling, are essential components of any successful drilling campaign. As the oil and gas industry is drilling in more-challenging areas (e.g., unconventional shale oil/gas wells, deepwater offshore wells, and deep high-pressure/high-temperature sour gas wells), the demand for more-accurate real-time assessment of the downhole state of the drilling fluids during drilling operations increases. Recent developments in drilling systems automation provide a multitude of opportunities to have real-time monitoring of drilling-fluid properties and early diagnosis of drilling-fluid-related complications that might arise while drilling. Coupled with closed-loop control of surface and downhole drilling-fluid properties, automated monitoring of fluid properties would allow rig personnel to make timely corrections to the drilling-fluid program, which eventually would lead to more-cost-efficient and safer drilling operations. This feature provides examples of such new technologies that can be used as part of the automated drilling-fluid monitoring system, allowing real-time control of drilling-fluid rheological properties (i.e., density and viscosity) and management of solids content with potential benefits of real-time management of equivalent circulating density, effective hole cleaning/cuttings transport, increasing drilling rate, and reducing nonproductive time, resulting in safer wells drilled at minimum costs. Recommended additional reading at OnePetro: www.onepetro.org. SPE 199101 - Field Results of a Real-Time Drilling-Fluid Monitoring System by Sérgio Magalhães, Universidade Federal Rural do Rio de Janeiro, et al. SPE 200990 - Intelligent Pressure-Control System for Managed-Pressure Drilling by Zhao Hui Song, Engineering Technology Research Institute of XDEC, et al. SPE 203389 - Real-Time Measurement of Drilling-Fluid Rheology and Density Using Acoustics by Paul Ofoche, Texas A&amp;M University, et al.

Failure analysis on aluminum alloy drill pipe with pits and parallel transverse cracks

In recent years, aluminum alloy drill pipe are used more and more frequently in the exploration and development of the deep wells, ultra-deep wells and sour gas wells due to the high strength, light weight and corrosion resistance to H2S and CO2. However, the pitting and fracture failure sometimes occurred, resulting in giant economic losses and fatal disaster. In this study, the failure analysis of aluminum alloy drill pipe was addressed and the formation cause of the pits and parallel transvers cracks was investigated. Results show that the chemical composition and the regular mechanical properties (including tensile and impact properties) meet ISO 15546:2011 standard requirements. But the tensile strength of samples immersed in the mud environment is lower than that of ISO 15546:2011 standard requirements. Metallographic analysis results show intermittent ribbon Al6(MnFe) solid solution, S (CuMgAl2) phase and AlFeSi phase distributed on α solid solution. The failure cause of aluminum alloy drill pipe is mainly attributed to the brittleness sensitivity of intermittent banded second phase and inclusions to corrosive media from mud environment. Cracks and pits are prone to generate here. XRD and EDS analysis results of corrosion products and the pits bottom show that the main corrosion products are Al2O3, Al2S3, AlPO4, BaSO4 and CaCl5. S and Cl are from environment media. The microscopic morphology analysis results of the tensile and impact specimens fracture show that the fracture is the brittle fracture caused by the environmental medium.

The Venting System for Ultrahigh Pressure Sulfur Gas Wells in the Northwestern Sichuan Basin

Due to the high pressure, large gas handling capacity and high acid medium content in the development and construction of high-pressure sour gas fields, the conventional venting system cannot meet the demand of production. By investigating the relevant standards and specifications of natural gas venting system at home and abroad, the main methods and principles that should be followed in the design process of the venting system of ultra-high pressure sour gas wells are summarized. Combined with the technological characteristics of venting and venting of ultra-high pressure sour gas wells, the two technological processes are integrated, and the integrated venting/venting process of ultra-high pressure sour gas wells is obtained.

A blockage removal technology for natural gas hydrates in the wellbore of an ultra-high pressure sour gas well

In order to safely, efficiently and economically remove the blockages of natural gas hydrate (NGH) in the wellbores of ultra-high pressure gas wells, this paper utilized the heat released from an independently developed autogenetic heat based solid blockage remover through chemical reaction in the wellbore to dissolve NGH and prevent it from forming again. In addition, adjustable heat generation time and heat generation amount was realized by regulating the dosage of the blockage remover. Finally, the chemically autogenetic heat based blockage removal technology was applied to remove the blockages in ultra-high pressure sour gas wells in the Sichuan Basin. And the following research results were obtained. First, when the independently developed chemically autogenetic heat based solid blockage remover is adopted, the peak temperature (34.2–88.5 °C) and time (24.2–884.0 min) of heat generation can be adjusted by its dosage. What's more, there is NGH inhibitor in the reaction product, which can inhibit the regeneration of NGH. Second, as the concentration of the blockage remover increases, the heat transfer speed increases, leading to an increase of NGH dissociation rate around the blockage remover. Third, blockage removal time increases with the increase of wellbore ID. In addition, the increasing rate of the blockage removal time as the wellbore ID increases from 64 mm to 76 mm is lower than that from 76 mm to 102 mm. Fourth, the coincidence rate between the simulation calculation result of heat diffusion and the on-site actual consumption is more than 85%, which indicates that the proposed model for the heat diffusion of chemically autogenetic heat based blockage remover is reliable and can be used to calculate the dosage of blockage remover. Fifth, solid reagent adding device with resistance to sulfur and pressure of 140 MPa is used to add autogenetic heat based solid blockage remover. This blockage remover has been applied in the ultra-high pressure sour gas wells in the Sichuan Basin three well times. Thanks to its application, NGH blockages in these wells are removed successfully and their production is resumed smoothly. In conclusion, this blockage removal technology has such advantages as effective blockage removal, safe and simple on-site operation and low cost, and a promising application prospect.

Recent Development and Remaining Challenges of Iron Sulfide Scale Mitigation in Sour-Gas Wells

Summary Iron sulfide scale deposition can be a significant flow-assurance issue in sour-gas production systems. It can deposit along the water-flowing path from the near-wellbore reservoir region to the surface equipment, which results in formation damage, causes tubing blockage, interferes with well intervention, and reduces hydrocarbon production. The main objectives of this paper are to review the new advancements and remaining challenges concerning iron sulfide management in sour-gas wells, covering the mechanisms of iron sulfide formation, the mechanical and chemical removal techniques, and the prevention strategies. In this paper we give a special emphasis to the different mechanisms of iron sulfide formation during well-completion and production stages, especially the sources of ferrous iron (Fe2+) for scale deposition. It is essential to understand the root cause to identify and develop suitable technologies to manage the scale problem. We also summarize the latest developments in mechanical methods and chemical dissolvers for the removal of iron sulfide deposited on downhole tubing. The capabilities of the current chemical dissolvers are discussed, and the criteria for effective dissolvers are provided to serve as guides for future development. Then, we provide an overview of recent developments on iron sulfide prevention technologies and treatment strategies. We differentiate the treatment approaches for corrosion byproduct and scale precipitation and scale-inhibitor deployment through continuous-injection and squeeze treatments. Finally, we outline the technical gaps and areas for further research-and-development (R&amp;D) efforts. We provide the latest review on iron sulfide formation and mitigation, with an attempt to integrate viable solutions and showcase workable practices.

Dynamic risk analysis of hydrogen sulfide leakage for offshore natural gas wells in MPD phases

Leakage of high-pressure sour gas wells is one of many challenges for offshore drilling operations, which may cause serious consequences due to poisonous H2S gas diffusion in the platform with limited working space. This study presents a new method for dynamic risk analysis of H2S leakage in such sour gas fields during managed pressure drilling phases. This method can model the influence of uncertainty from accident probability and consequences, being reflected in failure rates and unmodeled factors. The accident cause-consequence analysis via BT modeling for H2S release is conducted, integrating dynamic characteristics with probability estimation based on the inference of dynamic Bayesian networks (DBNs). The individual risk under different consequence scenarios is performed by the DBN modeling as well as death probability prediction at key monitoring points dynamically. A case study focused on specific Chinese offshore wells is analyzed to demonstrate the feasibility of the proposed method. The results show that the vulnerable factors with higher values are worth being addressed for prevention. In addition, the tolerable duration in total risk with the upper bound is approximated from 4.5 to 15 min between individual risk values of 1.0E − 4 and 1.0E − 6, as well as the exposure time after 15 min deserves more attention in risk emergency management.

Finite service life evaluation method of production casing for sour-gas wells

The material selection and design for oil and gas wells containing hydrogen sulfide and carbon dioxide is very difficult due to the uncertainties such as the changeable production capacity, partial pressure of corrosive medium (like CO2 and H2S). For oil and gas wells, there is a high production rate in the initial stage while the production rate is very low in the rest of stage. Meanwhile, some wells may have water outflow in the very early period but they even become flooded in the following process. According to relevant standards, Nickel-based alloys must be used in these conditions. However, using Nickel-based alloys could greatly increase construction cost. In this paper, we propose an evaluation method for those types of wells based on a finite life design theory, which utilizes a high pressure high temperature (HPHT) flow corrosion test. Furthermore, phase state and transformation kinetics are introduced into the evaluation. The simulation covers the formation of water corrosion in three periods, which include the condensate water gas production period, the water-carrying gas production period and the water accumulation period. Corroded casing strength was derived according to API Specification 5CT, and the residual strength including residual tensile strength, residual internal pressure, and the residual collapsing strength of the casing. Finally, residual strength data was used for the finite life theory based on the resistance safety method, and compared with the Offshore Drilling Manual, the finite service life can be predicted.

Environmentally assisted cracking performance research on casing for sour gas wells

Flowage in rock salt may induce extrusion deformation on casing pipes; this hinders performance in the production process in injection wells and also challenges security in oilfields. The typical treatment for this problem is to grind or expand the deformed sections of the casing, which itself may cause additional damage (cold hardening) in the casing. Cold hardening may degrade the performance of casing materials, especially when the materials are exposed to a high-sulfur environment. Since it is common for casing pipes materials exposure in the H2S/CO2 environment like Puguang gas field, the cracking sensitivity of C110 after cold hardening is very important.To investigate the environmentally assisted cracking performance of C110, a series of tests were conducted, including the basic mechanical property test, the electrochemical corrosion test, the Double Cantilever Beam test (DCB), and the four-point bending test. The results indicate that cold hardening increases the yield strength, reduces the impact toughness, and degrades sulfur-resistance which greatly increases the potential risk to the integrity of the wellbore.

Drilling Technology for Deep and HPHT Containing Sour Gas well in the ChuanDongBei Field of China

ChuanDongBei Field of Sichuan Basin is a HPHT deep gas reservoir with multiple pressure systems, with maximum formation temperature up to 156 oC and pressure gradient of 1.86 at the depth of 6500m. Part of the well section contains more than 5% CO2 and near to 10% H2S, so drilling operation is extremely challenged. Firstly, this paper introduces drilling challenges such as lost circulation, severe caving-in, pipe sticking in upper section, sour gas corrosion problems, low penetration rate in the middle and deep section. Secondly, a lot of available key drilling technologies are innovated and provided, including casing program optimization, air and nitrogen drilling to improve ROP, combination drilling with anti-HT motor and fit for purpose PDC bits, anti-HT mud along with losses prevention technologies such as MPD, anti-gas channeling and big temperature difference cementing slurry in the long interval, BOP and H2S sour gas monitoring system with emergency plan and some management advices for deep HTHP containing sour gas wells. Finally, some unexpectable application results regarding these techniques to solve a series of drilling difficulties have been mentioned according to 40 wells cases. Take well LG01-XY as an example, which was improved average ROP to 6.4m/h, extended the footage to 1713m in one specialized bit with air hammer, reduced drilling period to 145days, reached “zero pollution, zero harm, zero accident” achievement during H2S interval, got premium cementing result and well bore qualify. So it could be used as a technical reference while drilling in deep HTHP containing sour gas wells in similar geologically complicated gas fields.

Completion difficulties of HTHP and high-flowrate sour gas wells in the Longwangmiao Fm gas reservoir, Sichuan Basin, and corresponding countermeasures

For safe and efficient development of the sour gas reservoirs of the Cambrian Longwangmiao Fm in the Anyue Gas Field, the Sichuan Basin, and reduction of safety barrier failures and annulus abnormal pressure which are caused by erosion, corrosion, thread leakage and improper well completion operations, a series of studies and field tests were mainly carried out, including optimization of well completion modes, experimental evaluation and optimization of string materials, sealing performance evaluation of string threads, structural optimization design of downhole pipe strings and erosion resistance evaluation of pipe strings, after the technical difficulties related with the well completion in this reservoir were analyzed. And consequently, a set of complete well completion technologies suitable for HTHP (high temperature and high pressure) and high-flowrate gas wells with acidic media was developed as follows. First, optimize well completion modes, pipe string materials and thread types. Second, prepare optimized string structures for different production allocation conditions. And third, formulate well completion process and quality control measures for vertical and inclined wells. Field application results show that the erosion of high-flowrate production on pipe strings and downhole tools and the effect of perforation on the sealing performance of production packers were reduced effectively, well completion quality was improved, and annulus abnormal pressure during the late production was reduced. This research provides a reference for the development of similar gasfields.

Safe Practices in Drilling and Completion of Sour Gas Wells

This paper examines the current status of the global market of sour fields. In particular, it clarifies on the existing methods, standards, and technologies applied for drilling, cementing, and completing a well with high H2S concentration, with view of recommending the minimum health, environmental, and safety (HSE) protocols or standards required when dealing with sour environments. The overall approach for this study was literature review. This will involve exploration of various exploitation case studies from the region and the globe meant for improving the economics of developing sour reservoirs in this cost sensitive time for the industry. Literature on current status of methods and technologies applied for drilling, cementing and completing high H2S concentration wells will be reviewed. Standards and recommendations set by the American Petroleum Institute (API) and National Association of Corrosion Engineers (NACE) on the minimum Health, Environmental, and Safety (HSE) for use in sour environments will also be reviewed. The findings of this study informed of the fact that there is very small even any room for error when it comes with exploiting high H2S concentration well reservoirs. The results of the study established that dealing with sour fields is a challenge the industry will face more often, and in increasing magnitudes over time. In particular, it was established that the best approach for meeting this challenge is for companies in the industry to acquire knowledgeable personnel, an element that dictates for consulted investing in the proper training of employees. In order to ensure proper training of personnel, core areas of the training should encompass best practices on the selection of materials, planning operations, and the swift planning and executing of operation plans and incidents. This study will have implication for unlocking the full potential of the sour environments frontier for the region. The findings of this study will provide drilling and completions engineers with insightful knowledge on best practices in dealing with sour fields.