Sour Reservoirs Research Articles

Fe2NiSe4 Nanowires Array for Highly Efficient Electrochemical H2S Splitting and Simultaneous Energy-Saving H2 Production

The electrochemical removal of abundant and toxic H2S from highly sour reservoirs has emerged as a promising method for hydrogen production and desulfurization. Nevertheless, the ineffectiveness and instability of current electrocatalysts have impeded further utilization of H2S. In this communication, we introduce a robust array of Fe2NiSe4 nanowires synthesized in situ on a FeNi3 foam (Fe2NiSe4/FeNi3) via hydrothermal treatment. This array acts as an active electrocatalyst for ambient H2S splitting. It offers numerous exposed active sites and a rapid electron transport channel, significantly enhancing charge transport rates. As an electrode material, Fe2NiSe4/FeNi3 displays remarkable electrocatalytic efficiency for both sulfide oxidation and hydrogen evolution reactions. This bifunctional electrode achieves efficient electrochemical H2S splitting at a low potential of 440 mV to reach a current density of 100 mA∙cm−2, with a faradaic efficiency for hydrogen production of approximately 98%. These findings highlight its significant potential for desulfurization and energy-efficient hydrogen generation.

Review on the Mechanism of CO2 Storage and Enhanced Gas Recovery in Carbonate Sour Gas Reservoir

Carbonate gas reservoirs in the Sichuan Basin have many complex characteristics, such as wide distribution, strong heterogeneity, high temperature, high pressure, high H2S and CO2 content and an active edge or bottom water. In the late stage of exploitation of carbonate sour gas reservoirs, the underground depleted reservoirs can provide a broad and favorable space for CO2 storage. If CO2 is injected into the depleted carbonate sour reservoirs for storage, it will help to achieve the goal of carbon neutrality, and the CO2 stored underground can perform as “cushion gas” to prevent the advance of edge or bottom water, to achieve the purpose of enhanced natural gas recovery. Injecting CO2 into low permeability reservoirs for oil displacement has become an important means to enhance oil recovery (EOR). However, the mechanism of EOR by injecting CO2 into carbonate sour gas reservoirs is not clear and the related fundamental research and field application technology are still in the exploration stage. This paper reviews the main scientific and technical perspectives in the process of injecting CO2 into carbonate sour gas reservoirs for storage and enhancing gas recovery.

Investigating the souring mechanism in two giant carbonate oil reservoirs, southwestern Iran

In general, a hydrocarbon reservoir with a produced gas stream having more than three parts per million by volume (ppmv) of hydrogen sulfide is considered a sour reservoir. This study aims to present novel ideas on the main souring mechanisms in Bangestan Group, a well-known Mid-Cretaceous hydrocarbon hosting carbonate in Iran, including Ilam, Sarvak, and Kazhdumi formations. Especially, several scenarios are discussed on potential source of H2S in Sarvak Formation and controversial sweetness of the Upper Ilam Reservoir. At first, both of the bacterial or microbial sulfate Reduction (BSR or MSR) and thermochemical sulfate reduction (TSR) mechanisms were rejected based on the reported bottom-hole temperature and lack of anhydrite in rock matrix, respectively. Moreover, the possibility of souring due to migration was disregarded mainly due to the reported constant concentration of H2S over time and among the target oilfield. At the end, thermal decomposition of organic sulfur compounds within the kerogen or crude oil was introduced as the only potential souring mechanism that was further proven through sulfur isotopic analysis. Furthermore, the possibility of H2S absorption in lower horizons of Ilam Formation, and so sweetness of this formation, due to the presence of ferrous minerals was evidenced through detailed petrographic analysis.

NEW CORRELATIONS FOR THE PSEUDOCRITICAL PARAMETERS AND THE ACENTRIC FACTOR S OF THE HYDROCARBON COMPONENT OF THE DNIEPER-DONETS PETROLEUM BASIN’S NATURAL GAS

NEW CORRELATIONS FOR THE PSEUDOCRITICAL PARAMETERS AND THE ACENTRIC FACTOR S OF THE HYDROCARBON COMPONENT OF THE DNIEPER-DONETS PETROLEUM BASIN’S NATURAL GAS

Study of thermochemical sulfate reduction of different organic matter: Insight from systematic TSR simulation experiments

Abstract A series of thermochemical sulfate reduction (TSR) simulation experiments were carried out involving different organic matter (crude oil, solid bitumen, type II kerogen, type III kerogen) and different sulfate species (anhydrite and MgSO4) to address the chemical and carbon isotopic variations of the hydrocarbon, H2S and CO2. The increase of main peak carbons of residual saturated hydrocarbon and the decrease of gaseous hydrocarbons from control treatment to corresponding sulfate treatments suggest that TSR promote the consumption of both liquid and gaseous hydrocarbons. The δ13C1-3 values generally shift positively from control treatment to sulfate treatments and the (δ13Cethane-δ13Cmethane) values in sulfate treatments are higher than that in control treatments. The variation of δ13C1-3 in TSR is controlled by the isotope fractionation during the generation and consumption of C1-3 in TSR. MgSO4 is more reactive than anhydrite in TSR. A certain amount of H2S is incorporated into solid bitumen as the result of secondary alteration. We believe that the reactivity order of different organic matter in TSR is crude oil > solid bitumen > type II kerogen > type III kerogen. The reactivity of organic matter in TSR depends on the hydrocarbon generation kinetics of each organic matter. The dissolution/decomposition and precipitation of carbonate control the yield of CO2 in sour reservoirs. The negative shift of δ13CO2 with increasing TSR extent is mainly due to the inheritance effect of carbon isotope from hydrocarbons. Inorganic CO2 sourced from the thermal decomposition or acid dissolution of carbonate mineral impose significant influence on δ13CO2. The H2S yields decrease with CH4 yields and increase with δ13CH4 value, the δ13CH4 values increase with residual amount of gaseous alkane (1- H2S/(residual alkane + H2S)), suggesting that methane acted as reactant in TSR. The (δ13CO2-δ13CH4) values decrease significantly with increasing temperature, and the δ13CO2 is even more negative than δ13CH4 in 450 °C MgSO4 treatments involving type II and type Ⅲ kerogen. Accordingly, methane acted as a predominant reactant in 450 °C sulfate treatments in our experiment. It is possible for natural gas with high gas dryness to experience methane-dominated TSR in geological reservoirs.

Investigations on corrosion behaviors of super-strength sucker rod FG20 steel in high SO42− environment

In some sour reservoirs and tertiary oil recovery blocks, SO42− in the well fluid can cause the corrosion and corrosion fatigue of the sucker rods. In this paper, the corrosion behaviors of super-strength sucker rod FG20 (16Mn2SiCrMoVTiA) steel in the well fluid are investigated by electrochemical measurements, and electron probe micro-analyzer (EPMA) analysis. The results show that FG20 steel has a favorable corrosion resistance in neutral solution. When the hydrogen ions increase, the hydrolysis of SO42− greatly accelerates the corrosion of FG20 steel. The energy dispersive X-ray (EDX) results demonstrate that the corrosion process of FG20 steel in neutral well fluid is an oxygen concentration process, and the protective FeCO3 and Fe2O3 on the surface of the samples can prevent the further corrosion. With the increase of the acidity in the well fluid, the corrosion process converts into a sulphide concentration process, and the sloppy FeS and mackinawite film cannot provide effective protection for the specimens, resulting in the increase of corrosion rate.

Corrosion Behavior of P110 Tubing Steel in the CO2-saturated Simulated Oilfield Formation Water with Element Sulfur Addition

With continuously growing oil and gas demand, exploitation of highly sour reservoirs brings large corrosion risks due to the coupling effects of corrosive factors including elemental sulfur, CO2, and formation water. In the present work, corrosion behavior of P110 tubing steel in simulated oilfield formation water containing elemental sulfur and CO2 was investigated by immersion tests and electrochemical measurements. The results indicate that increasing temperature accelerates the corrosion rate of P110 tubing steel, promotes the formation of iron sulfide, and causes serious pitting corrosion. However, influence of temperature varies in different temperature range mainly due to the different corrosion-controlling species like CO2 at low temperatures and elemental sulfur at high temperatures. Based on the results, the coupling effects of elemental sulfur and carbon dioxide were discussed.

Deposition of Inorganic Carbonate, Sulfate, and Sulfide Scales on Antifouling Surfaces in Multiphase Flow

Impairment of flow by way of mineral scale formation is a major complication affecting production in the oil and gas industry. Soured reservoirs contain hydrogen sulfide (H2S) that can prompt the formation of exotic metal sulfide scales, leading to detrimental fouling that can negatively impact production. The contrast in the mode of precipitation (solid formation from liquid solution) and deposition of both sulfide scale and conventional inorganic carbonate and sulfate scales is herein examined. Design of an experimental rig allowing diffusion of H2S gas into the brine phase of a sealed reaction vessel resulted in a realistic representation of scaling processes occurring within sour reservoirs. Multiphase conditions, induced by introduction of a light oil phase to scaling brine within a turbulent regime, aimed to study the effect of oil and water wetting on pipeline fouling. Performance of a range of antifouling surfaces was determined through measurement of scale deposition by gravimetry and microscopy techniques. Under conditions modeled to reflect a typical H2S-containing reservoir, the contrasting scaling mechanisms of conventional calcium carbonate (CaCO3) and barium sulfate (BaSO4) scales when compared to lead sulfide (PbS) scale highlighted the critical role of the light oil phase on deposition. While conventional scales showed deposition by both crystallization and adhesion onto surfaces, the thermodynamic driving force for PbS prompted rapid bulk nucleation, with adhesion acting as the overwhelmingly dominant mechanism for deposition. The results showed that the addition of a 5% v/v light oil phase had a profound effect on scale particle behavior and deposition onto antifouling surfaces of varying wettability as a result of two processes. Primarily, the oil wetting of hydrophobic surfaces acted as a barrier to deposition, and second, adsorption of scale crystals at the oil/water interface of oil droplets within a turbulent oil-in-water emulsion resulted in adhesion to hydrophilic surfaces after impaction. It is therefore proposed that sulfide scale, typically deposited in the upper regions of production tubing, is driven by adhesion after formation of a PbS solid-stabilized Pickering emulsion. This contrasts with the commonly held view that metal sulfides precipitate and deposit similarly to conventional scales, whereby salts crystallize both directly upon surfaces and in the aqueous bulk phase as solubility decreases toward the wellhead.

Effects of H2O in the Feed of Sulfur Recovery Unit on Sulfur Production and Aromatics Emission from Claus Furnace

An increase in the exploitation of sour reservoirs with a high content of acid gas (mainly H2S and CO2) and the enforcement of stringent emission standards have triggered demand for high sulfur recovery efficiency in sulfur recovery units (SRUs). The high amount of H2O that is present in feed gases to the SRU can act as a diluent in the thermal section of the SRU and can also pose operational difficulties and have substantial chemical effect on the equilibrium-limited reactions of sulfur production and the destruction of impurities. This paper explores the role of H2O (0–12% in the furnace feed) in sulfur recovery and in the fate of undesirable aromatics, COS, and CS2 in the thermal section using a detailed reaction mechanism and industrial SRU operating parameters. An increasing H2O concentration in the feed decreased the sulfur recovery efficiency in the thermal section significantly, as the equilibrium conversion of H2S to sulfur was affected. The higher H2O concentrations increased the concentrations ...

Effect of sulphur deposition on well performance in a sour gas reservoir

AbstractSulphur deposition has been the centre of attention in sour gas reservoir development. While Roberts's solubility model is widely used in sour reservoir damage to describe elemental sulphur precipitation and deposition in a near‐wellbore area, this model cannot accurately predict a change in sulphur solubility. A productivity prediction model, with consideration of sulphur deposition, is also not complete, particularly for modelling sulphur deposition and fractured horizontal wells. In this study, based on the unsteady percolation mechanics theory and superposition principle, we develop a new numerical model to quantify fractured horizontal well production by combining various sulphur solubility models. We examine the effects of sulphur deposition on permeability, porosity, and production performance. The results show that sulphur deposition damages reservoirs and thus decreases well production in later stages. These results also show that the permeability and porosity reduction using Roberts's sulphur solubility model is greater than that using Hu et al.'s sulphur solubility model. The damage degree is relatively smaller when using Hu et al.'s sulphur solubility model, and the effect of sulphur deposition on a production performance curve is negligible. Moreover, Hu et al.'s model is closer to actual production data. The results can guide reservoir engineers to optimize development plans in sour gas reservoirs.

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.

Antiagglomerant Hydrate Inhibitors: The Link between Hydrate-Philic Surfactant Behavior and Inhibition Performance

The application of antiagglomerant hydrate inhibitors (AAs) is becoming more important as advancing technology allows access to petroleum reserves with extreme conditions including high pressures, high temperatures, sour reservoirs, and arctic climates. Application of thermodynamic hydrate inhibitors (THIs) is becoming cumbersome and outdated due to high volumes required, especially in offshore applications. High subcooling scenarios and capital costs preclude the use of kinetic hydrate inhibitors (KHIs) and THIs. Even though AAs are industrially recognized surfactants, they have not been extensively studied with regard to their surfactant properties as related to performance. In this paper, selected AAs have been examined in terms of their surfactant properties. These findings were then related to hydrate inhibition performance in a crude oil system. It is widely known that AAs perform better with increased salinities and decreased water-cuts. This study provides data that shines light on the plausible r...

Challenges of Tight and Shale-Gas Production in China

This article, written by Dennis Denney, contains highlights of paper IPTC 17096, ’Production-Technology Challenges of Tight and Shale-Gas Production in China,’ by Hon Chung Lau, SPE, Shell (China) Projects and Technology, and Meng Yu, SPE, Shell International Exploration and Production, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed. Natural-gas production from tight and shale-gas reservoirs will be increasingly important in China as the country shifts from coal-based energy to cleaner energy sources. Recent Chinese sources have estimated that the gas-in-place resources from tight and shale-gas reservoirs in China are at least 12×1012 m3 and 31×1012 m3, respectively. In 2008, annual production from tight gas reservoirs reached 20×109 m3, approximately 23% of the natural-gas production in China. Commercial production from shale-gas reservoirs has not begun but is expected to grow rapidly. Introduction Since 2010, the consumption of natural gas in China has far exceeded domestic production. To bridge this gap, domestic production of natural gas, especially from unconventional resources [e.g., coalbed methane (CBM) and tight and shale-gas reservoirs], must be increased significantly. From a review of published literature and their own observations, the authors identified several relevant production technologies that could have a significant effect on tight and shale-gas production in China. Unconventional Gas Resources The US Energy Information Administration estimated that China had 0.289×1012 m3of proved CBM reserves in 2011, although other recent estimates of recoverable reserves are 9.9×1012 m3. Fig. 1 shows most of China’s gas-producing basins. CBM resources are in the north and northeast, the Sichuan basin in the southwest, and the Junggar and Tarim basins in the west. In China, tight gas resources total approximately 12×1012 m3. The Sichuan basin is one of the largest tight gas basins in China and is reported to have approximately 1.8×1012 to 2.25×1012 m3of natural gas. The Sulige gas field in the Ordos basin is the largest tight gas field in China. Most of China’s proved shale-gas resources are in the Sichuan, Tarim, and Ordos basins. Estimates of China’s total tight and shale-gas resources range from 36×1012 to 100×1012 m3. Although there was no commercial shale-gas production as of 2012, the Chinese Ministry of Land Resources has set aggressive targets of 6.5×109 m3/a by 2015 and at least 59.5×109 m3/a by 2020. Management of Hydrogen Sulfide (H2S) Risks Most of China’s sour-natural-gas fields are in the northeastern and western parts of the Sichuan basin (mostly conventional gas fields). An evaluation of shale-gas potential in the Weiyuan area showed significant shale-gas reserves. Therefore, it is important to determine the likelihood of penetrating sour reservoirs and to manage H2S risks. In general, a rigorous H2S safety-management plan will be needed if tight or shale-gas development will require drilling through or near zones containing H2S.

Prediction of sour gas compressibility factor using an intelligent approach

Compressibility factor (z-factor) values of natural gasses are essential in most petroleum and chemical engineering calculations. The most common sources of z-factor values are laboratory experiments, empirical correlations and equations of state methods. Necessity arises when there is no available experimental data for the required composition, pressure and temperature conditions. Introduced here is a technique to predict z-factor values of natural gasses, sour reservoir gasses and pure substances. In this communication, a novel mathematical-based approach was proposed to develop reliable model for prediction of compressibility factor of sour and natural gas. A robust soft computing approach namely least square support vector machine (LSSVM) modeling optimized with coupled simulated annealing (CSA) optimization tool was proposed. To evaluate the performance and accuracy of this model, statistical and graphical error analyses have been used simultaneously. Moreover, comparative studies have been conducted between this model and nine empirical correlations and equations of state. The obtained results demonstrated that the proposed CSA-LSSVM model is more robust, reliable and efficient than the existing correlations and equations of state for prediction of z-factor of sour and natural gasses.

TSR versus non-TSR processes and their impact on gas geochemistry and carbon stable isotopes in Carboniferous, Permian and Lower Triassic marine carbonate gas reservoirs in the Eastern Sichuan Basin, China

The Palaeozoic and lowermost Mesozoic marine carbonate reservoirs of the Sichuan Basin in China contain variably sour and very dry gas. The source of the gas in the Carboniferous, Permian and Lower Triassic reservoirs is not known for certain and it has proved difficult to discriminate and differentiate the effects of thermal cracking- and TSR-related processes for these gases. Sixty-three gas samples were collected and analysed for their composition and carbon stable isotope values. The gases are all typically very dry (alkane gases being >97.5% methane), with low (<1%) nitrogen and highly variable H2S and CO2. Carboniferous gas is negligibly sour while the Lower Triassic gas tends to be most sour. The elevated H2S (up to 62%) is due to thermochemical sulphate reduction with the most sour Triassic and Permian reservoirs being deeper than 4800m. The non-TSR affected Carboniferous gas is a secondary gas that was derived from the cracking of sapropelic kerogen-derived oil and primary gas and is highly mature. Carboniferous (and non-sour Triassic and Permian) gas has unusual carbon isotopes with methane and propane being isotopically heavier than ethane (a reversal of typical low- to moderate-maturity patterns). The gas in the non-sour Triassic and Permian reservoirs has the same geochemical and isotopic characteristics (and therefore the same source) as the Carboniferous gas. TSR in the deepest Triassic reservoirs altered the gas composition reaching 100% dryness in the deepest, most sour reservoirs showing that ethane and propane react faster than methane during TSR. Ethane evolves to heavier carbon isotope values than methane during TSR leading to removal of the reversed alkane gas isotope trend found in the Carboniferous and non-sour Triassic and Permian reservoirs. However, methane was directly involved in TSR as shown by the progressive increase in its carbon isotope ratio as gas souring proceeded. CO2 increased in concentration as gas souring proceeded, but typical CO2 carbon isotope ratios in sour gases remained about −4‰ V-PDB showing that it was not solely derived from the oxidation of alkanes. Instead CO2 may partly result from reaction of sour gas with carbonate reservoir minerals, such as Fe-rich dolomite or calcite, resulting in pyrite growth as well as CO2-generation.

Sr evolution in the Upper Permian and Lower Triassic carbonates, northeast Sichuan basin, China: Constraints from chemistry, isotope and fluid inclusions

Abstract Petrographic features, C, O and Sr isotopes, rare earth and trace elements were determined, and fluid inclusions were analyzed on various stages of interparticle cements and vug-fillings from the Upper Permian and Lower Triassic sour reservoirs in northeastern Sichuan basin. The aim was to assess the origin and evolution of palaeo-waters in the carbonates. The original water was contemporary seawater, from which marine cements precipitated with slightly high Sr contents (mean 1911 ppm), 87 Sr/ 86 Sr ratios from 0.7067 to 0.7082 and nonluminescent CL. The palaeo-seawater was diluted by meteoric water, as indicated by bright cathodoluminescence (CL) and Sr-depletion (0–516 ppm) in low-temperature calcite. When buried to temperatures of about 60–90 °C during Middle to Late Triassic, the palaeo-water was enriched in Sr released from the transformation of precursor aragonite and calcite to dolomite, resulting in precipitation of substantial pre-bitumen Sr-rich minerals (SrSO 4 and SrCO 3 ). For un-dolomitized limestone sections, aragonite neomorphism may have contributed Sr to the precipitation of small amounts of Sr-bearing minerals and calcite crystals with elevated homogenization temperatures (HTs, mainly from 90 to 130 °C) and wide Sr contents (from 34 to 3825 ppm), as recorded in stage III calcite. Since the Middle Jurassic, almost all of the early stage celestite and significant amounts of solid CaSO 4 have been consumed by reactions with hydrocarbons (i.e., TSR), resulting in water enriched in isotopically light CO 2 and HCO 3 - , Sr 2 + , Ba 2 + and Eu 2+ , as recorded in calcite with low δ 13 C values (down to −18.9‰), 87 Sr/ 86 Sr ratios from 0.7072 to 0.7076, high HTs (mainly 110–198 °C), positive Eu anomalies and high Sr and Ba contents. Subsequently, the water was uplifted and cooled down to about 115 °C, celestite and strontianite were precipitated with the occurrence of natural elemental S immiscible inclusions. TSR may have produced significant amounts of freshwater, which brought down Sr concentrations and salinities of the palaeo-waters to not more than about 6.0 wt.% NaCl equivalent.

Diagenetic Alteration of Wingate Formation: Possible Indications of Hydrocarbon Microseepage, Lisbon Valley, Utah: ABSTRACT

The bulk mineralogy and character of the Wingate formation is uniform, but substantial differences occur in the spatial distribution of authigenic kaolinite and hematite to permit differentiation of three areas: northern bleached, central unbleached, and southern bleached. Bleached rocks are gray/white due to a lack of hematite/clay coatings as constituent grains, most of which have overgrowths. These coatings are present in unbleached rocks, making them red. Compared to the other areas, the northern bleached rocks have 3 to 5 times more authigenic kaolinite, half the porosity, twice as many altered feldspars, and one-third as much mixed-layer clay. Bleached rocks contain hematite pseudomorphs after pyrite, and the northern rocks also contain hematite after siderite. In general, the southern bleached rocks are more similar to unbleached rocks than to northern bleached rocks. Stratigraphy, primary depositional features, and sedimentary petrography demonstrate that bleached rocks were initially the same as the unbleached rocks and that differences are due to postdepositional authigenic processes. Bleaching was driven by acidic/reducing fluids that entered the strata soon after burial, resulting in precipitation of kaolinite and dissolution and local replacement of hematite by pyrite and siderite. An area between the two bleached zones remained unaltered. Fluids either remained inmore » the southern area for a shorter period of time or were weaker, resulting in less alteration than in the north. The prime candidate for a source of these fluids is leakage from the geographically associated sour petroleum reservoir at Lisbon Valley oil field.« less

Sour Gas Well Completion Practices in the Foothills, Western Canada

Summary Shell Canada Resources Ltd. Currently completes and stimulates sour natural gas wells up to 20,000 ft (6000 m) deep in the foothills region of Alberta, western Canada. In addition, sour gas wells recently were recompleted as dual tubing string producers in the foothills, Limestone field. This paper reviews completions and stimulation practices used in these wells. Introduction Shell Canada's active exploration and development well program in the foothills region of Alberta has been directed primarily at the sour natural gas reservoirs found in the porous carbonate formations of the region. Fig. 1 illustrates the geographical location and extent of the foothills play, which extends approximately 400 miles (600 km) northward from the U.S. border and runs along the eastern edge of the Rocky Mountains, Shell currently produces from Waterton, Jumping Pound, Burnt Timber, and Limestone sour gas fields. The primary zones of interest in the foothills produce sour natural gas and condensate with a hydrogen sulfide (H2S) content between 5 and 30% (50 and 300 mol/kmol), and a carbon dioxide (CO2) content between 5 and 15% (50 and 150 mol/kmol). The sour reservoir fluids are found mostly in formations of Mississippian and Devonian age, such as the Mississippian Turner Valley (Mt), Mississippian Pekisko (Mp), Devonian Nisku (Dn), Devonian Reef (Dr), and Devonian Wabamun (Dwa). In general, the productive formation rocks are dolomites [CaMg(CaCO3)2] or partially dolomitic limestones (CaCO3). Porosity normally is less than 10%, and permeability ranges from about 0.1 to 10 md, with an average of 2 md. Reservoir pressures are slightly less than hydrostatic, and bottomhole temperatures (BHT's) are typically 160 to 250°F (70 to 120°C), depending on depth. Exploration targets have increased in depth over the past 2 years, and wells up to 20,000 ft (6000 m) deep currently are completed. Completion practices and stimulation techniques used in these deep sour gas wells are reviewed in this paper. Another area of recent activity has been the development of sour gas production from the Limestone field. This field came on stream in Nov. 1980, shortly after six wells had been recompleted as dual tubing string producers on segregated Mississippian and Devonian intervals. (There are a total of 10 production wells tied into the Limestone gathering system; four are as originally completed with single production tubing strings.) The average depth of completion intervals in Limestone range from 10,000 to 13,800 (3050 to 4050 m). The recompletion of the Limestone wells as dual tubing string, sour gas producers also is addressed, including description of the completion techniques and stimulation methods. Completion Techniques Deep Sour Gas Wells. In general, the deep sour gas wells are cased with 7-in. (178-mm) API long thread and coupling (LT&amp;C) production casing from surface to total depth (TD). However, in completions deeper than about 18,000 ft (5500 m), 7-in. (178-mm) production casing is set at about 16,500 ft (5000 m), with a 5-in. (127-mm) flushjoing production liner from above the 7-in. (178-mm) casing shoe to TD. Casing grades used for the sour gas conditions include K55, L80, and S0090. Grades K55 and L80 are modified in accordance with Shell Canada's material specifications for sour gas service. These specifications are additional to API Specs. 5A1 and 5AC2 for Grades K55/J55 and L80, respectively, and entail modification to the heat treatment, process of manufacture, and physical properties as outlined in Table 1. Deep Sour Gas Wells. In general, the deep sour gas wells are cased with 7-in. (178-mm) API long thread and coupling (LT&amp;C) production casing from surface to total depth (TD). However, in completions deeper than about 18,000 ft (5500 m), 7-in. (178-mm) production casing is set at about 16,500 ft (5000 m), with a 5-in. (127-mm) flushjoing production liner from above the 7-in. (178-mm) casing shoe to TD. Casing grades used for the sour gas conditions include K55, L80, and S0090. Grades K55 and L80 are modified in accordance with Shell Canada's material specifications for sour gas service. These specifications are additional to API Specs. 5A1 and 5AC2 for Grades K55/J55 and L80, respectively, and entail modification to the heat treatment, process of manufacture, and physical properties as outlined in Table 1.