High Pressure Sour Gas Research Articles

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.

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.

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.

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.

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.

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.

Computer Control of High-Pressure Sour Gas Wells, Kaybob South BHL Gas Unit No: 3

Abstract This paper describes the computer- controlled supervisory and control system which was installed to measure and control production tram and injection into the gas wells of the Kaybob South Beaverhill Lake Gas Unit No. 3. Items to be covered include: reasons for installation of an automation, scheme in this field, initial configuration of the system, field installation and start-up, changes that have been made and an assessment of the systems performance after one year of operation. Introduction THE KAYBOB SOUTH BEAVERHILL LAKE GAS UNIT No. 3 is located approximately 130 miles west of Edmonton. The plant, which is one of the largest gas plants in North America, is located centrally in the 12- by 6-mile field. The terrain in this area is heavily wooded and has high relief, with ground elevations ranging from 2600 to 4150 feet above sea level. Temperatures at the Kaybob plant range from -50 °F in the inter to +80 °F in the summer. Precipitation averages 75 inches of snow in the winter and 30 inches of rain in the summer. The plant was designed for an inlet rate of 445 MMcf/D of very rich, sour gas, yielding a daily output of 3,065 long tons of elemental sulphur, 32,720 barrels of pentanes plus, 17,950 barrels of LPG's and 284 MMcf of dry residue gas. Of the residue gas, 54 MMcf is sold and the remaining 230 MMcf is re-injected into the formation in a recycling scheme designed to enhance the recovery of pentanes plus and sulphur. Prior to plant start-up, the well count was 37 producing wells, 11 injection wells and one well that could be used as either an injector or a producer. The effluent from the producing wells is carried as two-phase flow through lateralpipelines to one of the three-trunk lines feeding the plant. These gathering lines operate at pressures of 1200 to 1500 psig and temperatures of 90 °F to 150 °F. At these conditions, the liquid hydrocarbon ratio is as high as 150 barrels per MMcf of gas. The residue gas from the plant to the reinjection wells is carried in a three-trunk line to lateral sy.3terns operating- at a maximum discharge pressure of 4700 psig at the plant. Reasons for Automation At Kaybob South Operating problems within the gas plant make frequent cuts in plant inlet rate necessary. This could be accomplished by reducing the producing flow rates or diverting part of the inlet gas to flare. If consideration is given to pollution of the environment and conservation of energy resources, it is obvious that flaring of inlet gas is not acceptable. A method of reducing well flow rates that is used by many gas plants is to increase the, back pressure that the plant exerts on the gathering system. Two-phase flow in pipelines installed in hilly terrain produces liquid heads wherever the flow is uphill. The amount of liquid build-up increases as the flow rate is reduced, up to the point at which the liquid starts to move as a slug.

Explosive Termination of a Wild Well Evaluation of a Concept

A concept to terminate a wild well by detonating a subsurface explosive charge placed in a relief well near the wild well has been investigated and found to be feasible. The study described in this paper dealt with the application of conventional chemical explosives; however, the concept is equally valid for nuclear explosives. Introduction In March, 1970, the Shell Cox No. 1 well near Jackson, Miss., blew out during drilling, caught fire, and eventually cratered and extinguished itself. The well was a 22,000-ft high-pressure sour-gas well. Flow rates while the well was blowing out were estimated to range from 20 to 100 MMcf/D. Data gathered on site indicated that the crater had plugged at a relatively shallow depth, causing an underground blowout. Plans were developed to drill a relief well to total depth. Drilling time of this well was estimated to be 12 to 18 months. The great depth, the directional drilling problems, the presence of sour gas, and the tightness of the formation were severe conditions that dictated the development of a novel concept to kill the well quickly. Two such concepts were developed. The first consisted of (1) drilling an intercept well to a depth of approximately 10,000 ft in such a way that the casing in the intercepting well was in contact with the casing in the Cox No. 1 well, (2) cementing the two strings together, (3) perforating the strings to create communication, and (4) pumping cement into the wild well to kill it. This is the technique that was eventually used. The second concept consisted of (1) drilling a 10,000-ft intercept well converging to within 15 ft of the wild well, (2) washing a large cavity at the bottom of the hole, (3) pumping conventional explosives into the cavity, and (4) detonating on command. The explosion would create a larger cavity, crush and rubble the rock, collapse and shatter the casing in the wild well, and stem the flow of gas at that depth. The purpose of this paper is to discuss the program that was carried out to evaluate this concept. Calculations, using finite-difference programs, were made to evaluate the effect of explosive properties and rock properties on the cratering and ground motion associated with the detonation so that the shot could be properly designed. In addition, an explosive formulation was developed that met the requirements for safe handling and pumping on the surface and detonation in a high-pressure and high-temperature environment. From the study it has been concluded that the concept of using explosives to terminate a wild well is feasible. Although the concept is untried to date in this country, the Russians have demonstrated the soundness of it by killing two wild gas wells using nuclear explosives. Project Planning Project Planning After the explosive kill concept was conceived, the following program was developed to evaluate it and to bring it to completion, if necessary. Phase 1 Determine the feasibility of explosively terminating Cox No. 1 and develop specific proposals to accomplish the job. JPT P. 1084

Contingency Planning for Drilling and Producing High-Pressure Sour-Gas Wells

A blowout of a sour-gas well near a populated area can expose local residents to hazards that are not normally associated with a blowout of an oil or gas well. Without detailed plans made well in advance and kept current, such an accident can have serious consequences for a company that is not prepared. Introduction Field experience in developing the sour-gas reserves discovered in Western Canada in the early 1950's showed that metals often failed quickly when exposed to sour gas because of its hydrogen sulfide (H2S) content. For a time there was considerable concern about the industry's ability to provide facilities that could safely handle this gas, but research by both industry and universities developed the necessary technology, and today sour-gas production and processing in this area is a safe, routine operation. This achievement can be attributed, for the most part, to the careful selection, quality control, and inspection of materials scheduled for use in sour-gas service. Now once again the industry is faced with a new challenge for producing sour gas. Drilling for and producing from deep, high-pressured reservoirs of producing from deep, high-pressured reservoirs of high H2S content present a hazard not normally associated with the production of sour gas from moderately pressured reservoirs. This is the threat of blowouts caused by the often rapid failure of high-strength steels when they are exposed to hydrogen sulfide. When H2S is Present, the yield strength of steel must be limited to about 90 to 100 ksi and stringent quality control and inspection procedures must be set up to insure that higher strength materials are not used to drill or complete the well. In spite of all possible precautions, there will always exist the possibility that failure of some component during the possibility that failure of some component during the lifetime of a well may lead to a blowout with disastrous results. When a blowout occurs in an ultra-deep well, much time may be required to control it if relief wells must be drilled. Thus if the well does not bridge or the reservoir does not deplete quickly, the operator will be faced with protecting the lives and property of nearby residents for an extended period. This is particularly serious when the period. This is particularly serious when the blowout occurs near a heavily populated area. We shall discuss here various elements that Shell considered in developing contingency plans for its deep Smackover drilling program in Mississippi. The actual plans are quite detailed and outline the responsibilities and duties of all concerned, from top management to the field operations personnel. They are divided into two parts, one dealing with procedures for protecting the operating personnel, and the other outlining means for protecting nearby residents and their property. The execution of the latter is primarily the responsibility of the staff organization; primarily the responsibility of the staff organization; however, the field operating personnel are responsible for the production of any endangered residents until the staff group relieves them of this function. The plans are principally designed to cope with the period of shock that immediately follows an accident, when there is the greatest danger of losing control of the situation. General Considerations Contingency plans must be specific in assigning duties and areas of responsibility, so that each man knows what is expected of him during an emergency. JPT P. 347