High Pressure Sour Research Articles

Simulation of high-pressure sour natural gas adsorption equilibrium on NaX and NaY zeolites using the multicomponent potential theory of adsorption

Simulation of high-pressure sour natural gas adsorption equilibrium on NaX and NaY zeolites using the multicomponent potential theory of adsorption

Experiment on Gas–Liquid Sulfur Relative Permeability under High-Temperature High-Pressure Sour Gas Reservoir Condition

In the development of high temperature sour gas reservoirs, gas–liquid sulfur two phase percolations exist, which have a significant impact on the gas permeability and gas well productivity. There are currently few reports on experimental studies on gas–liquid sulfur relative permeability. This study improves the experimental equipment and process, and it proposes an experimental method for measuring the gas–liquid sulfur relative permeability curve. Several typical core samples from a sour gas reservoir in Sichuan Basin, China were selected for experimental study, and the gas–liquid sulfur relative permeability under high temperature and high pressure (HTHP) was measured. The results show that, first, the critical flowing saturation of liquid sulfur was 40%, and the gas–liquid sulfur co-flow zone was narrow. With the increase in the liquid sulfur saturation, the gas relative permeability decreased rapidly. Second, the better the physical properties of the core, the greater the damage of liquid sulfur to the core properties. The residual liquid sulfur saturation of the fractured core was higher than matrix core, and as liquid sulfur saturation increased, so did the damage to gas permeability. Third, temperature had an effect on the gas–liquid sulfur relative permeability. Gas relative permeability decreased as the temperature rose, while the liquid sulfur relative permeability remained essentially constant. Fourth, the rock effective stress had a significant impact on the gas–liquid sulfur relative permeability. The relative permeability of gas and liquid sulfur decreased as the effective stress increased, and the fractured core was more sensitive to stress.

Coiled Tubing Program Succeeds in Harsh-Environment Tight Gas Wells

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209032, “Successfully Adapting and Overcoming Challenges for Coiled Tubing Applications in High-Pressure Sour Environments and Horizontal Unconventional Tight Gas Wells in UAE,” by Ole Sorensen, Yang Wu, and Didier Caillon, SPE, TotalEnergies, et al. The paper has not been peer reviewed. During the completion phase of four unconventional wells in the United Arab Emirates, a detailed engineering approach overcame challenges presented by extreme conditions of pressure, temperature, and a sour environment across long horizontal sections to carry out cleanout activities successfully. This operation, the first of its kind in the country for the operator, yielded lessons for design considerations and the execution process and recommendations for coiled tubing (CT) intervention in similar working environments. It also confirmed that 110,000-psi-yield-strength quench-and-tempered (Q&T) CT strings can be deployed safely in a high-pressure sour environment by implementing proper risk-mitigation strategies. Introduction The unconventional gas play (referred to as “A” in the complete paper) featured a reservoir pressure of nearly 13,000 psi and a bottomhole temperature of approximately 325°F. The environment was sour, with 5 mol% of hydrogen sulfide (H2S) and 5% carbon dioxide (CO2). The well’s architecture consisted of a 5½-in. monobore completion with cemented casing and horizontal sections ranging from 5,000 to 8,200 ft. The selected completion methodology was plug-and-perf, including up to 35 fracturing stages in a single well. Overview of CT Intervention Challenges The true vertical depth of the play was 12,600 ft on average, representing a maximum anticipated surface pressure (MASP) of 8,000 psi with the wellbore full of working fluid (8.34-lbm/gal slickwater) and a maximum potential wellhead pressure (MPWHP) of 11,300 psi with the wellbore full of gas. Also, partial pressures of H2S and CO2 exceeded 600 psi at bottomhole conditions, confirming that sour- and corrosive-service programs had to be implemented fully in this project. Convergence of MASP above 7,500 psi, CT dynamic pressure of greater than 11,000 psi, lateral length of up to 8,200 ft, and the sour and corrosive environment required a highly engineered approach on the design and selection of the CT string and configuration of the surface equipment.

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.

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.

High-Pressure Sour Gas and Water Adsorption on Zeolite 13X

The design and optimization of natural gas conditioning with adsorbents requires self-consistent data up to pressures relevant to gathering and transportation pipelines. Adsorption isotherms for me...

Test Conditions for Pipeline Materials Selection with High Pressure Sour Gas

Acid gases, such as CO2, H2S, and/or sulfur in oil industry’s production fluids, can be responsible for both general and localized corrosion, acting with different mechanisms, which depend on chemical and physical properties of the produced fluids. Materials selection for handling such fluids is performed by combining experience with suggestions from standards and regulations. A good deal of knowledge is available to predict corrosion rates for CO2-containing hydrocarbons, but the effect of high H2S pressure is less understood, mainly due to the difficulty of performing laboratory tests in such challenging conditions. For instance, the so-called NACE solution to assess SSC (Sulfide Stress Cracking) susceptibility of steels is a water-based solution simulating production fluids in equilibrium with one bar bubbling H2S gas. This solution does not represent environments where high gas pressure is present. Moreover, it does not take into account the corrosive properties of sulfur and its compounds that may deposit in such conditions. Besides, properties of high pressure gases are intermediate between those of a gas and those of a liquid: high pressure gases have superior wetting properties and better penetration in small pores, with respect to liquids. These features could enhance and accelerate damage, and nowadays such conditions are likely to be present in many production fields. This paper is aimed to point out a few challenges in dealing with high pressure gases and to suggest that, for materials selection in sour service, a better correspondence of test conditions with the actual field conditions shall be pursued.

Environmental Cracking Susceptibility of Low-Alloy Steels Under a High H2S Pressure and High-Temperature Sour Environment

Environmental cracking (EC) susceptibility of low-alloy steels with a specified minimum yield strength of 655 MPa (95 ksi) and 758 MPa (110 ksi) manufactured by quenching and tempering heat treatments was investigated in high H2S partial pressures (more than 1.0 MPa) using four-point bend tests in autoclaves. The H2S partial pressures and testing temperatures varied from 1.0 MPa to 10 MPa and 24°C to 150°C, respectively. Materials of grades 95 ksi and 110 ksi containing high Cr and Mo showed no macrocracking under all tested conditions. Localized corrosion occurred at several locations after exposure for 1 month under high H2S pressure and high-temperature conditions. It was concluded that the localized corrosion did not form macrocracking even after long-term (3 months) immersion tests. On the other hand, 110 ksi grade material containing low Cr and Mo suffered from sulfide stress cracking at low temperatures (below 66°C) and at an H2S pressure of 1.0 MPa. The material also showed EC at an H2S pressure of 10 MPa and temperature from 107°C to 150°C. The difference of EC susceptibility among the materials is discussed based on corrosion reactions, hydrogen absorption, and morphologies of the corrosion products on the steel surface.

High-pressure sour gas adsorption on zeolite 4A

In an effort to measure self-consistent adsorption isotherms for sour gas species on zeolite 4A, two high-pressure manometric adsorption instruments have been built for measurement up to p = 225 bar. A comparison of CO2 adsorption up to p = 200 bar on Fitrasorb F400 activated carbon shows the reliability of these instruments. For the purpose of this work, high purity zeolite 4A was synthesized and characterized by SEM/EDX, XRD, FTIR, and DLS. High-pressure adsorption isotherms (absolute and excess) for CO2, COS, CH4 and H2S adsorption on zeolite 4A have been reported for T = 0, 25, and 50 °C along with corresponding parameters for the modified Toth isotherm. The adsorption of COS on zeolite 4A showed some unexpected results, where (i) lower temperature isotherms were dominated by size effects, (ii) the adsorption capacity was half that of CO2 or H2S, and (iii) computational calculations for HOMO bond orientation indicate that COS should be excluded from zeolite 4A, despite the experimental results.

Selection and Application of Sulfide Oxidizing Microorganisms Able to Withstand Thiols in Gas Biodesulfurization Systems.

After the first commercial applications of a new biological process for the removal of hydrogen sulfide (H2S) from low pressure biogas, the need arose to broaden the operating window to also enable the removal of organosulfur compounds from high pressure sour gases. In this study we have selected microorganisms from a full-scale biodesulfurization system that are capable of withstanding the presence of thiols. This full-scale unit has been in stable operation for more than 10 years. We investigated the microbial community by using high-throughput sequencing of 16S rRNA gene amplicons which showed that methanethiol gave a competitive advantage to bacteria belonging to the genera Thioalkalibacter (Halothiobacillaceae family) and Alkalilimnicola (Ectothiorhosdospiraceae family). The sulfide-oxidizing potential of the acclimatized population was investigated under elevated thiol loading rates (4.5-9.1 mM d-1), consisting of a mix of methanethiol, ethanethiol, and propanethiol. With this biomass, it was possible to achieve a stable bioreactor operation at which 80% of the supplied H2S (61 mM d-1) was biologically oxidized to elemental sulfur. The remainder was chemically produced thiosulfate. Moreover, we found that a conventionally applied method for controlling the oxygen supply to the bioreactor, that is, by maintaining a redox potential set-point value, appeared to be ineffective in the presence of thiols.

A new approach to risk control of gas kick in high-pressure sour gas wells

During drilling in high-pressure sour gas well, the occurrence of gas kick may cause serious consequences. Generally, in order to prevent gas kick, higher density of drilling fluid is adopted to keep adequate positive pressure difference in hole bottom. The requirement of positive pressure difference in China is 5 MPa. However, due to the narrow mud weight window in most high-pressure sour gas well, this method could not keep both equivalent static density and equivalent circulation density within the safe window. The lower density of drilling fluid could not ensure hydrostatic pressure higher than a pore pressure of 5 MPa; while higher density may cause leakage and therefore trigger blowout. In this paper, an improved approach is proposed to solve this problem, which involves bottom-hole pressure control methods and necessary equipment. A case study shows that the conventional method cannot develop a reasonable mud density while the improved method can ensure a bottom-hole pressure within the narrow pressure window. The results show that the improved method not only solves the problem of circulation loss that occurs in conventional drilling, but also meets the Chinese standards of well control in high-pressure sour gas wells, providing a new technique for the risk control of gas kick.

An individual risk assessment framework for high-pressure natural gas wells with hydrogen sulphide, applied to a case study in China

Accidents of high-pressure sour gas wells at the well drilling and completion stages may cause serious consequences when poisonous H2S gas diffuses with the diversity of terrain and wind etc., especially in China, where most of sour gas wells are located in mountainous areas with complicated geological conditions. This paper focuses on an assessment framework to explicitly calculate the individual risk of high-pressure sour gas wells at the well drilling and completion stages. The method is based on accident probability analysis by fault tree simulation as well as accident consequence analysis through building reasonable accident scenarios for H2S gas diffusion related to death probability within a given distance. The death probability curves of different wind directions and corresponding minimum proximity distances to the surrounding buildings could be provided by probabilistic risk analysis. Finally the individual risk contours could be mapped by concentration interpolation, and be compared with acceptable risk level. The case study in Chinese Sichuan–Chongqing region shows that the minimum proximity distances of different directions range from 600 to 1200m locating between individual risk values of 10−4 and 10−6. The zones within 1.2-km radius and northwest area deserve more attentions in the design and deployment of the protective measures.

Design of Test Parameters during Assessment of Material Safety Fitness for Purpose in High Temperature High Pressure Sour Gas Field

The design or assessment method to identify the safety of all the materials or components in accordance with the specific service environment is called design or assessment method for applicability. The assessment method for material applicability is set forth in Standard API 579.The most important step in applicability design is to simulate the practical conditions on the site as close as possible. However, limited by material, manufacturing level and cost, etc., it is hard to simulate the real environment in the laboratory test. Therefore, the testing condition and method should be designed scientifically to allow the testing result to close to the practical condition as much as possible. At present, as for the design of the gas component, the content of each component during the test is designed based on the principle of partial pressure equalization of corrosive component according to the actual pressure and the gas components on the site. But the author assumes that the principle of dissolved amount equalization for the corrosive components in the solution shall be adhered to in the process of applicability assessment. The paper mainly introduces the method to calculate the partial pressure of each component, the model to calculate the solubility of the corrosive components in the solution, and finally gives the example of calculation and points out the problem existing in the partial pressure equalization principle.

XPS study of fluorinated diamond-like carbon films prepared by reactive magnetron sputtering

Fluorinated diamond_like carbon(F_DLC) films were prepared by radio frequency(RF) reactive magnetron sputtering with trifluoromethane (CHF3) and argon as source gases, and pure graphite as a targ et. The influence of source gas flow rate ratio on the film bonding configuration, sp2/sp3 hybrid ratios and optical band gap were investigated by Raman, Infrared transmission spectra, UV_visible spectra and XPS spectra. The results show that F-DLC films with high fluorine content, wide optical band gap and ultra-low diel ectric constant can be prepared by RF reactive magnetron sputtering technique in low input RF power (60W), high pressure (2.0Pa) and proper sour ce gas flow ratio (Ar/CHF3=2∶1).

アブダビ海域におけるサワーガス圧入について

Abu Dhabi Oil Co., Ltd. (Japan) operates three offshore oil fields, namely Mubarraz, Umm Al-Anbar (hereafter referred to as AR) and Neewat Al-Ghalan (hereafter referred to as GA) Fields, in Abu Dhabi, United Arab Emirates.AR and GA Fields are oil fields containing high concentration of H2S and CO2 within the associated gas, which are highly corrosive to metal and extremely toxic to humans. The highest levels of precaution for safety were taken in the development policy as well as in the design of the facilities. Meanwhile, gas injection into oil reservoirs had been planned for EOR from the commencement of production, which in turn met the gas conservation policy of Abu Dhabi Government.Given that high-pressure sour gas injection technology was not available in the mid-1980's, H2S and CO2 in produced sour gas had to be extracted by a gas sweetening unit and the sweet gas was then injected into the reservoirs. The sour gas fed from low-pressure separators and acid gas fed from the gas sweetening unit were flared at the artificial island located at the center of the AR Field, namely AR Site Terminal. Since then, various methods to resolve this flaring issue, such as sulfur recovery, production of fertilizer or plaster and disposal of liquid sulfur into underground formations, etc. have been investigated and studied as a priority. However, none of them were economically and/or technically feasible.After a site survey in Calgary, Canada, and in-house extensive studies, it was concluded that sour gas injection was technically and economically feasible. The basic engineering study was commenced in November 1997, and the detail engineering was started in March 1998. The facilities for the sour gas injection were constructed between July 1999 and May 2000 in AR Site Terminal, comprising of two units of low and high-pressure sour gas compressors and one sour gas dehydrator. At the initial stage of the commissioning of the facilities, problems such as vibration of the low-pressure compressors and scale plugging at the strainer were encountered, which caused the delay in the completion of the project.After resolving these difficulties in November 2000, the sour gas injection has been working successfully. The sour gas injection is the first challenge in the Arabian Gulf region, achieving gas conservation, environmental protection and enhanced oil recovery, simultaneously.

Coil Tubing Plug Retrieval/Fishing Operations On Deep, High Pressure Sour Wells

Abstract This paper discusses coil tubing operations performed on three sour gas wells in which coil tubing was used to retrieve plugs where conventional wireline methods proved ineffective. All three wells are located in the Obed Field of Alberta, which produces high pressure sour gas. The field was suspended in March 1992 with wireline plugs set to isolate the down-hole formation. All of the wells had severe corrosion problems prior to suspension, making plug setting and retrieval difficult. Coil tubing offered the versatility of jetting and circulating, allowing access to the down-hole plugs in a sloughing scale environment. On the first two reactivations, coil tubing was used for descaling tubing and washing onto plugs. During the third reactivation, the coil tubing was parted, leaving 3,000 m of 31.8 mm coil tubing (CT) down-hole. The 31.8 mm CT was successfully retrieved using 50.8 mm CT in conjunction with wireline chemical cutters. Introduction The Obed Field is located near Hinton, Alberta. The field was purchased and reactivated by Chevron Canada Resources in August 1992. The field is comprised of five producing wells, three of which are completed in the Nisku formation and two in the Leduc formation. The wells are approximately 4,000 m deep and produce gas with 26–33% H2S and 6–9% CO2. Bottom-hole static pressures for the wells range from 35 to 38 MPa. The tubing in all of the wells is 114.3 mm, L-80 VAM ACE with 88.9 mm VAM ACE corrosion resistant alloy (lncoloy/Hasteloy) tailpipe. Figures 1, 2, and 3 are schematics of the wells. All of the wells have a history of severe scale and corrosion problems. Prior to being suspended in March 1992, the wells had been on a Diaryl Disulfide (DADS) batch treatment program for sulphur deposition prevention. In August 1992, attempts were made to retrieve the down-hole wireline set plugs from three wells. All three plugs were leaking and could not be pulled by conventional wireline methods due to scale buildup. Some sulphur buildup was encountered down to 1,000 m, with a mix of carbonate and iron sulphide scale existing from 2,000 m to bottom. Options Available to Retrieve Plugs When Chevron reactivated the Obed Field, it was assumed that the plugs could be retrieved using conventional wire line methods. Normally, plug retrieval using wireline is quite effective in vertical wells wiLh up to 60 ° deviation. The following options were available for scale control, plug retrieval and fishing operations:Wireline prong/plug retrieval.Wireline bailing for scale removal.Wireline fishing.Coil tubing jetting/acid washing for descaling tubing.Coil tubing used for washing over fish.Coil tubing used to clean out sloughed scale and pull prongs/plugs. Initially, pulling the prongs and plugs with wireline techniques was selected, since it was the most economical and, historically, had been successful in the Obed field. Initial runs were unsuccessful due to sloughed scale which made it impossible to reach the prongs/plugs. Consequently, an attempt was made to bail out the fill, but this also proved to be ineffective.

Estimation and measurements of pH in high temperature and high pressure sour environments.

A new technique for estimating the pH of concentrated aqueous solutions in equilibrium with high pressure H2S and CO2 at elevated temperature was proposed. Based on the thermodynamic investigation for solution properties, the following equation was obtained.pH=-logγH+{(K1, H, KH, H, PH2S/γ2±H2S)1/2+(K1, C, KH, C, PCO2/γ2±CO2)1/2}The physico-chemical parameters in the equation were calculated by PBILC (Principle of Balance of Identical-Like Charges) proposed by Cobble et al. or assumed to be identical with those for HCl+NaCl aqueous solutions. The calculation of the pH of high temperature and high pressure sour environments was facilitated by the of this equation.A Nb-doped TiO2 semiconductor electrode of n-type was found to be suitable for the measurement of the pH of the environments; no interference from NaCl, H2S and CO2 occurred. The measured pH values agreed well with those estimated by the newly proposed technique at the temperatures up to 473 K and at partial pressures of H2S and CO2 up to 4 MPa. It was ascertained by pH measurements for HCl+NaCl aqueous solutions at elevated temperatures that the assumption made for physico-chemical parameters in the pH estimation was valid.

高温高圧サワー環境のpH推定および測定

高温高圧サワー環境のpH推定および測定

Development of High-Pressure Sour Gas Technology

Summary High-pressure sour gas has been produced continuously and safely since 1972 from three fields about 15 miles southeast of Jackson, MS. The wells in these fields are completed in the Smackover formation between 19,700 and 22,250 ft, and the initial bottomhole pressures (BHP's) ranged from 17,500 to more than 22,000 psi. Bottomhole temperatures (BHT's) range from 365 to 385°F. The well fluids consist of 28 to 46% H2S, 3 to 8% CO2, 51 to 69% methane, and no condensate. Water production is about 6 to 8 bbl/Mcf of gas. The bottomhole conditions and fluid composition of these wells from a hostile environment that has required development of new technology at great cost to safely produce these reserves. This paper reviews the major problem areas encountered and discusses the solutions used during the past 10 years since high-pressure sour gas was discovered. Metallurgical problems, well design, corrosion control, quality control, and safety are discussed. Introduction Before the late 1960's, drilling and production experience with high-pressure (>15,000-psi BHP) sour gas was very limited. Probably the most notable experience in the U.S. before that time was the Phillips-Josephine A-1 well in southeast Mississippi. That well was drilled to 20,138 ft, where it encountered a BHP of 13,830 psi and a BHT of 385°F.1 In 1969, Shell Oil Co. discovered higher-pressured (17,500-psi) sour gas near Thomasville, about 15 miles southeast of Jackson, MS. Since that time, Shell has continued to drill in this area and now has three fields (Thomasville, Piney Woods, and Southwest Piney Woods) that produce to a 100-MMscf/D sulfur recovery and gas-processing plant. The CO2 and H2S content of the produced fluids, coupled with high pressure and high temperature, constitute a very corrosive environment that few materials can withstand. Further, because of toxicity of the H2S and the danger of metal failure as a result of stress corrosion cracking, extreme caution must be taken in selecting materials to drill and produce this type of reserve safely. A temporary completion was made in the Thomasville discovery well to permit production testing (Fig. 1). The well tested at rates up to 10 MMcf/D of sour gas before completion-equipment failures resulted in temporary abandonment. Analysis of the failures indicated many technical problems in wellhead and well design, selection of materials, elastomer seals, quality control, and other design considerations. As a result, a task force was established to develop the necessary technology to produce high-pressure sour gas safely. The task force consisted of a group of engineers from production operations, closely backed by a counterpart research and development staff. The group's initial efforts were directed toward (1) designing a well completion that would overcome the deficiencies noted in the discovery well test and (2) development of contingency plans in the event of a sour gas release. Over the years, problems were resolved and new problems were identified as producing operations began. In general, for purposes of discussion, they can be grouped in general problem areas of (1) metallurgy, (2) well design, (3) corrosion control, (4) quality control, and (5) safety and contingency planning.

Exclusion area for safety from high-pressure sour gas leaks.

A discussion of considerations necessary to the preparation of a safety program which can save lives when hydrogen sulfide leaks occur during the transportation of sour oil and gas covers hydrogen sulfide toxicity; conditions such as pressure and exit velocity of gas containing hydrogen sulfide and leaking from a split in a pipe or connection; calculation of the maximum dilution factor for the case in which the leak permits free expansion; calculation of the adiabatic cooling of the expanding gas stream; hazard increase through formation of a fog, which forms if the temperature of the leaked gas mixture falls below the dew-point temperature; density; calculation of maximum concentration downwind of a ground-level source; calculation of a safety exclusion radius for any desired hazard level; calculation of the area with a time-concentration exposure greater than that specified for safety; determination of the probability that any point within the exposure distance of a leak will receive the maximum calculated exposure value; other considerations such as terrain and weather; and other related work, including rule 36 of the Texas Railroad Commission regulations on sour gas.