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Abstract A simulation study was carried out to investigate the temporal evolution of H2S in the Huangcaoxia underground gas storage (UGS), which is converted from a depleted sulfur-containing gas field. Based on the rock and fluid properties of the Huangcaoxia gas field, a multilayered model was built. The upper layer Jia-2 contains a high concentration of H2S (27.2 g/m3), and the lower layer Jia-1 contains a low concentration of H2S (14.0 mg/m3). There is also a low-permeability interlayer between Jia-1 and Jia-2. The multi-component fluid characterizations for Jia-1 and Jia-2 were implemented separately using the Peng-Robinson equation of state in order to perform the compositional simulation. The H2S concentration gradually increased in a single cycle and peaked at the end of the production season. The peak H2S concentration in each cycle showed a decreasing trend when the recovery factor (RF) of the gas field was lower than 70%. When the RF was above 70%, the peak H2S concentration increased first and then decreased. A higher reservoir RF, a higher maximum working pressure, and a higher working gas ratio will lead to a higher H2S removal efficiency. Similar to developing multi-layered petroleum fields, the operation of multilayered gas storage can also be divided into multi-layer commingled operation and independent operation for different layers. When the two layers are combined to build the storage, the sweet gas produced from Jia-1 can spontaneously mix with the sour gas produced from Jia-2 within the wellbore, which can significantly reduce the overall H2S concentration in the wellstream. When the working gas volume is set constant, the allocation ratio between the two layers has little effect on the H2S removal. After nine cycles, the produced gas’s H2S concentration can be lowered to 20 mg/m3. Our study recommends combining the Jia-2 and Jia-1 layers to build the Huangcaoxia underground gas storage. This plan can quickly reduce the H2S concentration of the produced gas to 20 mg/m3, thus meeting the gas export standards as well as the HSE (Health, Safety, and Environment) requirements in the field. This study helps the engineers understand the H2S removal for sulfur-containing UGS as well as provides technical guidelines for converting other multilayered sour gas fields into underground storage sites.

A simulation study was carried out to investigate the temporal evolution of H2S in the Huangcaoxia underground gas storage (UGS), which is converted from a depleted sulfur-containing gas field. Based on the rock and fluid properties of the Huangcaoxia gas field, a multilayered model was built. The upper layer Jia-2 contains a high concentration of H2S (27.2 g/m3), and the lower layer Jia-1 contains a low concentration of H2S (14.0 mg/m3). There is also a low-permeability interlayer between Jia-1 and Jia-2. The multi-component fluid characterizations for Jia-1 and Jia-2 were implemented separately using the Peng-Robinson equation of state in order to perform the compositional simulation. The H2S concentration gradually increased in a single cycle and peaked at the end of the production season. The peak H2S concentration in each cycle showed a decreasing trend when the recovery factor (RF) of the gas field was lower than 70%. When the RF was above 70%, the peak H2S concentration increased first and then decreased. A higher reservoir RF, a higher maximum working pressure, and a higher working gas ratio will lead to a higher H2S removal efficiency. Similar to developing multi-layered petroleum fields, the operation of multilayered gas storage can also be divided into multi-layer commingled operation and independent operation for different layers. When the two layers are combined to build the storage, the sweet gas produced from Jia-1 can spontaneously mix with the sour gas produced from Jia-2 within the wellbore, which can significantly reduce the overall H2S concentration in the wellstream. When the working gas volume is set constant, the allocation ratio between the two layers has little effect on the H2S removal. After nine cycles, the produced gas's H2S concentration can be lowered to 20 mg/m3. Our study recommends combining the Jia-2 and Jia-1 layers to build the Huangcaoxia underground gas storage. This plan can quickly reduce the H2S concentration of the produced gas to 20 mg/m3, thus meeting the gas export standards as well as the HSE (Health, Safety, and Environment) requirements in the field. This study helps the engineers understand the H2S removal for sulfur-containing UGS as well as provides technical guidelines for converting other multilayered sour gas fields into underground storage sites. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

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The Yuanba Gasfield is a large gas field discovered by Sinopec in the Sichuan Basin in recent years, and another main exploration area for natural gas reserves and production increase after the Puguang Gasfield. The ultra-deep sour gas reservoir in the Yuanba Gasfield is characterized by complicated geologic structure, deep reservoirs and complex drilled formation, especially in the continental deep strata which are highly abrasive with low ROP (rate of penetration) and long drilling period. After many years of drilling practice and technical research, the following six key drilling and completion technologies for this type reservoir are established by introducing new tools and technologies, developing specialized drill bits and optimizing drilling design. They are: casing program optimization technology for ROP increasing and safe well completion; gas drilling technology for shallow continental strata and high-efficiency drilling technology for deep high-abrasion continental strata; drilling fluid support technologies of gas–liquid conversion, ultra-deep highly-deviated wells and horizontal-well lubrication and drag reduction, hole stability control and sour gas contamination prevention; well cementing technologies for gas medium, deep-well long cementing intervals and ultra-high pressure small space; horizontal-well trajectory control technologies for measuring instrument, downhole motor optimization and bottom hole assembly design; and liner completion modes and completion string optimization technologies suitable for this gas reservoir. Field application shows that these key technologies are contributive to ROP increase and efficiency improvement of 7000 m deep horizontal wells and to significant operational cycle shortening.

Located in the Sichuan Basin, the Yuanba Gasfield is the deepest marine sour gas field among those developed in China so far. Its biohermal gas reservoir of the Upper Permian Changxing Fm is characterized by ultra depth, high content of hydrogen sulfide, medium–low porosity and permeability, and small reservoir thickness. Economic evaluation on it shows that horizontal well drilling is the only way to develop this gas reservoir efficiently and to reduce the total development investment. At present, the petroleum engineering technology for this type of ultra-deep sour gas reservoir is less applied in the world, so an ultra-deep horizontal well is subject to a series of petroleum engineering technology difficulties, such as safe and fast well drilling and completion, mud logging, well logging, downhole operation, safety and environmental protection. Based on the successful development experience of the Puguang Gasfield, therefore, Sinopec Southwest Petroleum Engineering Co., Ltd. took the advantage of integrated engineering geology method to carry out specific technical research and perform practice diligently for 7 years. As a result, 18 key items of technologies for ultra-deep sour gas reservoirs were developed, including horizontal-well drilling speed increasing technology, horizontal-well mud logging and well logging technology, downhole operation technology, and safety and environmental protection technology. These technologies were applied in 40 wells during the first and second phases of productivity construction of the Yuanba Gasfield. All the 40 wells have been built into commercial gas wells, and the productivity construction goal of 3.4 billion m3 purified gas has also been achieved. These petroleum engineering technologies for ultra-deep sour gas fields play a reference role in exploring and developing similar gas reservoirs at home and abroad.

Elemental sulphur which is originally soluble in gas phase in the reservoir should precipitate from the gas phase after exceeding saturation state and deposit at pore spaces and throat sequentially resulting in porosity and permeability loss. Over several decades, modelling elemental sulphur deposition around the wellbore are mainly focused on the gas reservoir and were based on Darcy flow. Few recent studies have shown models that capable for predicting elemental sulphur deposition considered non-Darcy flow, variations in gas properties with pressure change as well as permeability reduction caused by compaction. It therefore follows that if compaction causes a reduction in the permeability of the reservoir as well as reduction in its porosity, then porosity damage function induced by compaction becomes a crucial factor needed to be incorporated into the existing models to adequately predict sulphur saturation. This study is concerned with developing an accurate model for predicting elemental sulphur saturation in the fractured reservoir by exploring the functional relationship between compaction and elemental sulphur deposition over time. The result obtained from newly improved model is at variance with that obtained from Guo et al. model. This variance may not be unconnected with the fact that the rate of sulphur deposition seemed to have been underestimated by Guo et al. model. The refined model is more accurate and practical in predicting sulphur deposition in fractured sour gas reservoir as it leads to a faster rate of sulphur deposition. [ABSTRACT FROM AUTHOR]

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The utilization of a horizontal well has a great significance in the development of sour gas reservoir. The accurate prediction of the productivity of horizontal well will become more and more important in developing sour gas reservoir. In this paper, the effect of sulfur deposition on permeability is considered and a productivity prediction formula of the horizontal well is established. The effects of the length of horizontal well, the effective thickness of the reservoir, elemental sulfur deposition, and reservoir heterogeneity on productivity are analyzed and calculated. The theoretical results show that elemental sulfur disposition and the heterogeneity are the most important factors. According to the field case, the calculating results of improved Joshi’s equation approaches the real productivity, which means that it could be used to predict the productivity of horizontal well at initial stage during sour gas reservoir development. The results can be used as a reference for the development of similar sour gas reservoir. [ABSTRACT FROM PUBLISHER]

Sulfur deposition in the near wellbore region is generally estimated using Roberts' model. However, the model cannot correctly predict sulfur deposition from its assumptions. In the present study, a modified sulfur saturation prediction model is established. The refined model, based on non-Darcy flow, takes into consideration the effects of reservoir compaction, variation in gas properties, and the dependence of sulfur solubility on pressure. In addition, the effect of sulfur deposition on gas well deliverability is also studied. The results showed that the following: (1) the rate of sulfur deposition was underestimated by Roberts' Model and that the new and comprehensive model is more accurate and practical in predicting sulfur deposition; (2) reservoir compaction is a common phenomenon, which should be considered in sulfur deposition prediction since it leads to a faster rate of sulfur deposition; (3)the effect of variation in the gas properties on sulfur deposition can be directly attributed to the influence of pressure change; thus, parameters in the model should be calculated according to the corresponding pressures; (4)the radius damage caused by sulfur deposition increases with increasing gas production rate and production time; furthermore, the gas production rate dramatically decreases as sulfur saturation increases. [ABSTRACT FROM AUTHOR]

The gas reservoir with high content of H2S is a special type of reservoir. With the decreasing of temperature and pressure, elemental sulfur may precipitate and block pore. The conventional material balance equation of common gas reservoir takes no account of the sulfur deposition. It is difficult to scientifically describe the performance of sour gas reservoir. Mol balance principle is used to establish material balance equation in sour gas reservoir. The modified material balance equation can be used to analyze the effects of deposited sulfur on original gas in place. For the different types of gas reservoir, such as constant-volume gas reservoir and water invasion gas reservoir, the material balance equation with high content of H2S is deduced and an example is presented to compare it with the conventional volume balance equation. This new model improves sour gas-engineering theory. [ABSTRACT FROM PUBLISHER]

Abstract: In order to scientifically and accurately predict the damage of sulfur deposition in a sour gas reservoir. Glomeration mechanism of precipitated sulfur in pores was analyzed, based on conventional black-oil reservoir simulator, given the effect of sulfur deposition and irreducible water, a reservoir damage model is established in the presence of non-Darcy flow, the model can be used to describe the change of pressure with deposited sulfur. The results show that when reservoir pressure is lower than critical pressure, higher saturation degree of irreducible water may lead to pressure drop more quickly and velocity of sulfur precipitation becomes faster, gas limited production time becomes shorter when non-Darcy flow is considered. [Copyright &y& Elsevier]

With the decreasing of temperature and pressure near the wellbore area, elemental sulfur may precipitate in a sour gas reservoir. In order to acquire prediction and management of sulfur deposition, a carbonate sour gas reservoir damage model was established in the presence of natural fracture. The effects of formation parameters to gas limited production time are analyzed. The results show that when pressure is lower than saturation pressure, gas limited production time goes up with fracture aperture and height increasing, because the reservoir can accommodate more precipitated sulfur. The bigger production rate is, the faster pressure drop is and the quicker sulfur precipitates. [ABSTRACT FROM PUBLISHER]

Abstract: With the decreasing of pressure and temperature near wellbore, elemental sulfur may precipitate and block sour gas reservoir pores. In order to analyze the effect of non-movable water on core permeability, depletion types of experiments were carried out to observe sulfur precipitation and plugging in carbonate rocks. During the experiment, reservoir carbonatite cores and supersaturated sour gas were adopted. Under a certain differential pressure, normal saline was used to establish non-movable water. The experimental pressure and temperature were set and maintained to simulate actual reservoir. The experimental results show that non-movable water can contribute to improve core permeability. The more non-movable water is, the more improvement would be. The reason is investigated that the acid environment which has been built when H2S dissolves in the water, reacted with reservoir carbonatite cores. As a result, core flow capacity is improved. Compared with the sulfur damage on dry reservoir core, the improvement arisen from this reaction lays more effect in this experiment, thus the core permeability is ultimately increased. [Copyright &y& Elsevier]