Produced Water Research Articles

Study of cellulose nanocrystals -enhanced natural gas foam performance and profile control & oil displacement mechanism

ABSTRACT To address the poor performance of conventional natural gas foam flooding in the tight conglomerate reservoirs of the Mahu region in Xinjiang, a high-activity green material, cellulose nanocrystals (CNC), was introduced to improve foam performance based on a conventional AOS+SDS foam system. However, the impact of CNC on the performance of the conventional foam system and the synergistic effects between CNC and surfactants are not yet clear. Therefore, this study evaluates the improvement effects of CNC on foam performance from both macroscopic and microscopic perspectives by analyzing the foam composite index and the synergistic effects between CNC and surfactants. The study also investigates the factors affecting foam performance and uses a planar visualization model to evaluate the enhanced gas foam flooding effects from a microscopic mechanism perspective. The results indicate that CNC increases the foam composite index by 26,850 mL·min on a macroscopic level. Microscopically, it makes the foam more compact, thickens the foam liquid film by 0.1 mm, improves the wettability reversal by 10%, and reduces the oil-water interfacial tension by 0.26 mN/m. After mixing 1 vol% crude oil, the foam volume and half-life decrease by 12% and 4%, respectively. At reservoir temperature and pressure, the foam volume decreases by 12.7% and 10.5%, but the half-life increases by 4 hours and 3.7 hours, respectively. At formation water mineralization conditions, the foam volume and half-life decrease by 6.6% and 1.7 hours, respectively. In summary, it still has good performance under reservoir conditions. The visualization model demonstrates from a microscopic perspective that the foam system has good gas shutoff capability. After foam flooding, the gas sweep efficiency increases by 54.12%, and the foam flooding and subsequent gas flooding improve the crude oil recovery by 20.32%.

Importance of Clay Swelling on the Efficacy of Cyclic Steam Stimulation in the East Moldabek Formation in Kazakhstan

Both steam and hot water flooding of high-viscosity oils in the presence of swelling clays are difficult methods for producing oil efficiently because of potential formation permeability reduction. This paper pertains to heavy oil recovery from the East Moldabek formation where the oil API gravity is about 22 and is inundated with swelling clays. To achieve this, we used the IntersectTM reservoir simulator to compare oil recovery economics using both hot water and steam injection as a function of steam cycle duration, temperature, and steam dryness. We also studied clay swelling in the East Moldabek formation where clay poses a significant challenge due to its impact on permeability reduction. In this research, we developed an equation based on experimental data to establish a relationship between water mineralization and permeability in the East Moldabek formation. The equation provides valuable insight on how to mitigate clay swelling which is crucial for enhancing oil recovery efficiency—especially in sandstone reservoirs. Our modeling studies provide the recovery efficiencies for salinities of the hot water EOR versus cyclic steam EOR methods in a formation containing swelling clays. Specifically, the reduction in formation permeability as a function of the distilled water fraction is the controlling parameter in hot water or steam flooding—when the formation water mixture becomes less saline, oil recovery decreases. Our research shows that clay swelling can significantly impact cyclic steam stimulation outcomes, potentially reducing its effectiveness, while hot water flooding may offer a more cost-effective and operationally feasible solution in formations where clay swelling is a concern. Economic analysis reveals the potential for achieving an optimal favorable condition for hot water injection. Therefore, this paper provides a guideline on how to conduct thermal oil recovery for heavy oils in fields with high clay content such as the East Moldabek deposit.

Long-Term Investigation of Nano-Silica Gel for Water Shut-Off in Fractured Reservoirs.

Silicate gels have long been utilized as water shut-off agents in petroleum fields to address excessive water production. In recent years, nano-silica gel has emerged as a promising alternative to traditional silicate gels, offering potentially improved plugging performance. However, the long-term effectiveness of these gels remains uncertain, posing challenges to sustained profitability. Therefore, a comprehensive study spanning 6 months was conducted on fractured and induced channel samples treated with nano-silica gel of 75/25 wt% (silica/activator) at 200 °F. A comparative analysis was performed with samples treated using polyacrylamide/polyethyleneimine PAM/PEI gel (9/1 wt%) to compare the performance of both systems. Throughout the aging period in formation water at 167 °F, endurance tests were conducted at regular intervals, complemented by computed tomography (CT) scans to monitor any potential degradation. The results revealed nano-silica gel's superior long-term performance in plugging fractures and channels compared to PAM/PEI gel. Even after 6 months, the nano-silica gel maintained a remarkable 100% plugging efficiency at 1000 psi, with a maximum leak-off rate of 0.088 cc/min in the mid-fractured sample and 0.027 in the induced channel sample. In comparison, PAM/PEI gel exhibited a reduction in efficiency to 99.15% in the fractured sample (5.5 cc/min maximum leak-off rate) and 99.99% in the induced channel sample (0.036 cc/min maximum leak-off rate). These findings highlight the potential of nano-silica gel as a more durable water shut-off agent for managing water production in fractures and channels.

Niger Delta Oilfields Produced Water Characteristics and Treatment Technologies: Challenges and Solutions

The Nigerian Niger Delta oilfields have high water-to-oil ratio ranging from 50% to 95% water content, due to its secondary and tertiary production phases. Oil and gas producers could shut-in such wells, or develop cost effective approach for Produced Water, PW handling to meet reinjection or environmental permissibility. Thus, the study investigated the compositions and treatment techniques of Niger Delta oil and gas fields PW, and proffered solutions for actualizing minimal hazardous contaminants in PW. Characterization of PW from a Flow Station, an Oil processing and a Gas processing facilities showed biogeochemical homogeneity in the PW compositions with high organic and inorganic constituents, which are above injection and disposal specifications. The results of treated PW from the extant PW treatment (PWT) techniques showed that the total dissolved solids (TDS) concentration (6105.9 mg/l) from the Flow Station PW treatment facility did not meet the required specifications for injection into depleted wells or disposal into the environment (2,000.00 mg/l for inland, and 5,000.00 mg/l for nearshore). The salinity contents in the treated PW from the three PWT configurations were 2411.0 mg/l, 2218.6 mg/l, and 2165.4 mg/l, respectively, which were slightly above Nigerian Upstream Petroleum Regulatory Commission (NUPRC) specification (2000.0 mg/l) for nearshore disposal. The chemical oxygen demand (COD) concentration in the treated PW from the three PWT configurations were 153.0 mg/l, 148.1 mg/l, and 141.2 mg/l, respectively, which were above the NUPRC standard (125.0 mg/l). The oil and grease (O&G) concentration in the treated PW were 84.7 mg/l, 51.5 mg/l, and 58.0 mg/l, respectively, which also were above regulatory stipulation (30.0 mg/l) for nearshore disposal. The modular Bio-Unit + Ultra/Nanofiltration achieved more than 95% removal of both organic and inorganic constituents in the PW. Therefore, this study suggests that reconfiguring the extant PW treatment equipment with this cost-effective innovation would be the solution to PW treatment challenges in the Niger Delta oil and gas operations.

Phenotypic and Genomic Characterization of a Sulfate-Reducing Bacterium Pseudodesulfovibrio methanolicus sp. nov. Isolated from a Petroleum Reservoir in Russia.

The search for the microorganisms responsible for sulfide formation and corrosion of steel equipment in the oil fields of Tatarstan (Russia) resulted in the isolation of a new halotolerant strictly anaerobic sulfate-reducing bacterium, strain 5S69T. The cells were motile curved Gram-negative rods. Optimal growth was observed in the presence of 2.0-4.0% (w/v) NaCl, at pH 6.5, and at 23-28 °C under sulfate-reducing conditions. The isolate was capable of chemoorganotrophic growth with sulfate and other sulfoxides as electron acceptors, resulting in sulfide formation; and of pyruvate fermentation resulting in formation of H2 and acetate. The strain utilized lactate, pyruvate, ethanol, methanol, fumarate, and fructose, as well as H2/CO2/acetate for sulfate reduction. The genome size of the type strain 5S69T was 4.16 Mb with a G + C content of 63.0 mol%. On the basis of unique physiological properties and results of the 16S rRNA gene-based phylogenetic analysis, phylogenomic analysis of the 120 conserved single copy proteins and genomic indexes (ANI, AAI, and dDDH), assigning the type strain 5S69T ((VKM B-3653T = KCTC 25499T) to a new species within the genus Pseudodesulfovibrio, is suggested, with the proposed name Pseudodesulfovibrio methanolicus sp. nov. Genome analysis of the new isolate showed several genes involved in sulfate reduction and its sulfide-producing potential in oil fields with high saline formation water.

New opportunities in produced water management: A market-based approach to produced water trading

Produced water (PW) is a byproduct of oil and gas (O&G) production. Obtained alongside the more valuable energy products, PW is usually characterized by high levels of salinity and often contains many contaminants (chemicals, soluble and insoluble oil, organics, etc.) making it unsuitable for release without substantial treatment. Couple this with the fact that PW is typically obtained at multiple times the rate of oil or gas, and the added transport, treatment, and disposal costs become a serious challenge for operators. These realities have led to ad-hoc practices including cooperation between industry competitors to recycle, share, or otherwise mitigate PW costs. The National Energy Technology Laboratory (NETL) in partnership with the Ground Water Protection Council (GWPC) is pursuing novel technology solutions to address PW issues that complement or improve ad-hoc practices adopted by operators. In this paper, we observe that well-established market management practices used in electrical power generation have natural analogues in the PW supply chain. These parallels open up a new line of research where we view PW management as a market equilibrium problem, and explore solutions that foster active and data-based collaboration among operators through market structures similar to power markets, with the ultimate objective of improving PW management costs and recycling rates. We make a case for our observations, present a PW market clearing optimization model that shows how such a market system could operate in the O&G space, and provide an illustrative case study for demonstration.

Study on the Percolation Law of Tight Gas in the Western Sulige Area based on the Lattice Boltzmann method

Abstract To address the problem of unable to determine the percolation law of tight sandstone gas reservoirs under laboratory conditions, especially when there are no water production measurements and no obvious edge and bottom water. In this study, takes the Western Sulige area as the research object, and based on the geological characteristics of the Western Sulige area and the lattice Boltzmann method, establishes a LB mechanism model for tight gsa in the Western Sulige area, identify Identify fluid distribution and percolation rules in the pore throat structure of Western Sulige area The results show that There are four types of bound water in the pore throats of the western Sulige area, including trapped water, bind pore water, dead pore water, and liquid film.. The remaining gas in the production process is mainly distributed in the pore throat structure, including bind pore gas, fine throat pore gas, and water seal gas. In the early stage of gas-water production, formation water mainly in the form of liquid film reduces the cross-section of natural gas flow. Subsequently, formation water mainly in the form of liquid droplets clogs the throat, thereby reducing the gas percolation capacity. Due to the capillary suction effect, liquid–solid viscous forces, and pore–throat structures, the reservoirs of Western Sulige Area is prone to water lock damage, resulting in reduced production and even production suspension of gas wells. Therefore hydraulic fracturing is a necessary measure for the development of tight gas, but the increase in the intensity of fracturing operations has increased the width of fractures and strengthened the water lock phenomenon, further worsening the percolation capacity of the matrix.

Mechanism of Water Control and Gas Augmentation by Fracturing Interface Modifier in Water-bearing Gas Reservoir

Abstract With the development of oil and gas reservoirs, water containing gas reservoirs have gradually received attention. However, problems such as water production during the production process have reduced gas permeability, leading to a decrease in gas well productivity underground. Phase permeability regulators improve productivity by changing the wettability of rocks and enhancing gas permeability. This article tests the interface performance of a phase permeability regulator and evaluates its temperature resistance, formation water salt resistance, and erosion resistance. The pore bound water saturation of the core before and after modification with the phase permeability regulator, as well as the relative permeability of gas and water phases, are tested. The experimental results show that the phase permeation regulator can reduce the surface tension of water to 22.2 mN/m, and the rock contact angle before and after soaking increases from 26.63 ° to 97.69 °, achieving the transition of rock from hydrophilic to hydrophobic. The surface tension of the phase permeation regulator changes significantly before and after aging at 80-120 °C, and its high-temperature resistance is poor. After mixing with formation water with a salinity of 60000 to 100000, the surface tension increases, and at a salinity of 60000, it increases by 5.1 mN/m. The use of phase permeability regulators for matrix core displacement resulted in a slight increase in displacement pressure, while the formation water remained unchanged after approximately 140 hours of erosion. After modification with phase permeability regulators, the irreducible water saturation of the core decreases by about 25%, and the relative permeability of the gas phase increases, resulting in a significant hydrophobic and gas conducting effect. Phase permeability regulators achieve hydrophobic gas conductivity by changing the wettability of rocks, which can alleviate the problem of water production in shallow and low salinity reservoirs.

Study on the Variation Rule of Solubility of Common Scaling under High Temperature and High Pressure Conditions

Abstract In view of the lack of equipment for direct detection of ion content in formation water under high temperature and high pressure conditions at domestic and overseas until now. In this paper, a static experiment was designed to test the solubility of each ion in the fluid under high temperature and high pressure conditions. The influence of different temperature and pressure on the solubility of scaling was tested by experiments, and the variation rule of the scaling solubility under high temperature and high pressure was comprehensively studied. The results show that: With the increase of temperature, the solubility of barium sulfate in pure water increases first and then decreases; the solubility of strontium sulfate decreases gradually; the solubility of magnesium carbonate increases first and then decreases; the solubility of magnesium carbonate increases first and then decreases; the solubility of calcium carbonate increases first, then decreases and then increases; at the same temperature and pressure, the solubility of four scalings that are barium sulfate, calcium carbonate, strontium sulfate and magnesium carbonate is in the size order of BaSO4<CaCO3<SrSO4<MgCO3.

Mechanism Research and Identification Method of Low Resistivity Gas Layers in the M block of Algeria

Abstract The M block in Algeria is located in the southern Sahara platform, with oil and gas reservoirs mainly composed of river-glacial marine facies, fluvial and shallow marine fine sandstones. The pore structure is complex, and the difference in resistivity logging between gas layers and water layers is not significant, resulting in difficulties in identifying and evaluating hydrocarbon zone and the occurrence of reservoir omission. Based on geological, mud logging, core experimental data, logging, formation water analysis and testing data together, the formation mechanism of low resistivity hydrocarbon zone and the response characteristics of logging curves were generalised. The research suggests that the main factors causing low resistivity in this area are strong heterogeneity, high formation water salinity, high shale content, etc. On this basis, in response to the difficulty of identifying low resistivity gas layers, three methods of assessment were constructed: resistivity reduction rate factor method, porosity curve differentiation technique method and double porosity overlap method, which can quickly identify low resistivity gas layers. The oil testing results have verified that this method significantly improves the interpretation accuracy, with a 17.2% increase in accuracy and good results. The test results show that the method can greatly improve the interpretation accuracy with current accuracy 89.1% and the method turns out to be effective. Based on the above methods, the distribution law of low resistivity oil and gas layers in the study area has been clarified, and favorable zones have been discovered, providing strong technical support for increasing reserves and production in the area.

The Flowback Proppant Scaling Mechanism in the Horizontal Shale Oil Wells of Qingcheng Oilfield

Abstract Proppant scaling in the horizontal shale oil wells is a common problem in the Qingcheng Oilfield, one of the largest shale oil producers in China. However, few studies have focused on the mechanism of the proppant scaling during the flowback stage of hydraulic fracturing. To elucidate the scaling mechanism, in this study we collected the samples of produced water and solid scales and analyzed their compositions. The experimental simulations of the static and dynamic scaling processes using fracturing fluids, formation water, and reservoir rocks were also performed. In these experiments, the scale was found to be mainly SiO2 combined with FeCO3 and/or CaCO3. FeCO3 was dominant at the initial stage of the flowback, and CaCO3 became dominant at later stages of the flowback and during the stable production stage. It is believed that the high percentage of ferrous minerals (e.g., 46.4% of ferrocalcite) in multiple formation rocks is an essential reason that the proppant scaling happened during the flowback stage. The Fe2+ and Ca2+ ions were believed to be released via reservoir rock reacting with the fracturing fluid under the reservoir temperature and pressure (e.g. 60 °C, 20MPa). In addition, the FeCO3 formed in the initial flowback stage of the fracturing has the greatest impact on production.

Research and Application of Chemical Water Plugging Technology with High Salt Resistant Gel and Immobile String

Abstract The salinity of formation water in Gasi N1-N2 reservoir is 18 × 104 mg/L, in which calcium and magnesium ions are 6300 mg/L. The conventional gel used for profile control and water plugging has poor salt resistance and is easy to dehydrate under the erosion of formation water; At the same time, the chemical water plugging of oil wells in the past needs to trip down the downhole string for many times, and the construction period is long. In order to solve the former problem, an anti-high salt organic gel suitable for Gasi N1-N21 reservoir is synthesized. The formula is 0.4 wt% SD-3000 + 0.1-0.2 wt% urotropine + 0.05 wt% resorcinol + 0.4 wt% additive. The viscosity of the gel is more than 6000 mPa.s after gelation, and no obvious dehydration phenomenon is found after aging for five months in the formation water environment of Gasi N1-N21 reservoir at 65 °C. The technology of chemical water plugging without moving the string has been innovatively developed, which does not require the operation of tubing and pump during construction. In Gasi N1-N21 reservoir, anti-high salt gel was used to carry out three well-times of chemical water plugging tests without pulling the string, which were all successful, saving 44% of the cost of measures and shortening 78% of the construction period. After water plugging, water production was obviously inhibited, and the average moisture content was reduced from 95% to 45%. The average daily oil increment of a single well was 1.8 tons, and the cumulative oil increment was 1700 tons. The results show that the chemical water plugging technology without pulling string has broad application prospects in Gasi N1-N21 reservoir in Qinghai Oilfield and similar reservoirs in China.

Fidelibacter multiformis gen. nov., sp. nov., isolated from a deep subsurface aquifer and proposal of Fidelibacterota phyl. nov., formerly called Marine Group A, SAR406 or Candidatus Marinimicrobia.

A Gram-negative, obligatory anaerobic, chemoheterotrophic bacterium, designated strain IA91T, was isolated from sediments and formation water from deep aquifers in Japan. IA91T derives its peptidoglycan, energy and carbon from exogenous cell wall fragments, namely muropeptides, released from actively reproducing bacteria, and is dependent on other bacteria for cell wall formation, growth and even cell shape: IA91T is irregular rod-shaped but coccoids when muropeptide is absent. IA91T grew in a temperature range of 25-45 °C with optimum growth at 40 °C. IA91T utilized limited substrates, yeast extract, muropeptides and d-lactate. The major end products from yeast extract degradation were acetate, hydrogen and carbon dioxide. Co-cultivation with a hydrogen-scavenging methanogenic archaeon promoted IA91T growth. No anaerobic respiration with nitrate, nitrite, sulphate or Fe(III) was observed. The major cellular fatty acids are C16 : 0, C18 : 1 trans9, C18 : 0 and C17 : 0. The G+C content of the genomic DNA was 45.6 mol%. Phylogenetic analysis based on 16S rRNA gene and conserved protein sequences involved in replication, transcription and translation indicated that IA91T belonged to the candidate phylum Marine Group A (MG-A, SAR406 or Ca. Marinimicrobia) with no cultivated representatives. Based on the phenotypic and phylogenomic characteristics, a new genus and species, Fidelibacter multiformis gen. nov., sp. nov., is proposed for IA91T (= JCM 39387T = KCTC 25736T). In addition, a new bacterial phylum named Fidelibacterota phyl. nov. is proposed for the candidate phylum MG-A represented by F. multiformis and Fidelibacteraceae fam. nov., Fidelibacterales ord. nov. and Fidelibacteria classis nov.

Analysis of Production Decline Type Curves Considering Water Influx in Naturally Fractured Gas Reservoirs

Abstract In the development of fractured gas reservoirs with edge and bottom water, water invasion is a pervasive issue. However, most production decline analysis models focus on primary depletion with closed boundaries rather than secondary depletion with water influx. Therefore, this paper aims to develop decline type curves for analyzing and interpreting production data from existing natural water influx in fractured gas reservoirs. Firstly, a transient dual porosity flow model is developed considering water influx in naturally fractured gas reservoirs, the functions of Blasingame decline type curves are derived and obtained. Subsequently, the Blasingame production decline type curves of a vertical well in naturally fractured reservoirs experiencing natural water influx are plotted. These new type curves can estimate water invasion and dual medium parameters, offering valuable insights for production decline analysis in fractured reservoirs with water influx. The Blasingame production decline curves are divided into six regimes based on characteristics. Then, the effects of various formation parameters and water invasion cases on the type curves are discussed and analyzed. Compared with Blasingame type curves without water influx at the external boundary, the behaviors of those presented in this paper are quite different at the boundary responses. Finally, through the analysis of a case well, it is found that theoretical type curves considering dual-medium and water invasion are more consistent with actual production data. This suggests that these new type curves provide more accurate estimation for understanding and managing issues related to water invasion in fractured gas reservoirs.

Analysis of Water Production Factors of Gas Wells in Sulige Gas Field

Abstract The Sulige gas field, characterized by its low porosity and poor permeability, faces challenges in managing the complex gas-water distribution, which has become a growing concern as the field develops. This complexity, coupled with the varied and intricate nature of water production, has impacted the field’s efficiency. To tackle this issue, a study was carried out on water-producing gas wells within the field, examining the production mechanisms, main factors, and distribution patterns. The study found that in the field’s central region, the gas-water ratio in water-producing wells is relatively stable, with some wells yielding over 0.8m3 of water per day. The water sources include formation water, pore water, and water from the wellbore edges and bottom, as well as industrial water usage. Understanding these factors helps mitigate the negative impact of water production on field development and provides guidance for managing similar gas fields effectively.

Geochemical modeling of diagenetic reactions between albitization of K-feldspar and plagioclase feldspar in sandstone reservoirs under the influence of CO2 partial pressure

Diagenetic albitization has been observed in sedimentary basins around the world. This process significantly changes the original composition of sandstones and the chemistry of the formation waters under the influence of partial pressure of CO2. The transformation of detrital feldspars into albite is considered a crucial diagenetic process in the Gulf Coast and North Sea reservoirs. Earlier studies suggest that plagioclase albitization typically happens before that of K-feldspar. In the Gulf Coast's Frio Sandstone, located in the Upper Oligocene at depths between 900 and 2400 m, detrital plagioclase is often dissolved and replaced by albite, while K-feldspar mostly dissolves without much substitution. Similarly, in the North Sea reservoirs, especially in the upper section of the Upper Triassic Lunde Formation at depths beyond 2900 m, plagioclase tends to undergo albitization, whereas K-feldspar remains largely unaffected or experiences minimal transformation. This research focuses on analyzing the differences in the albitization patterns of detrital and K-feldspar plagioclase through the KINDISP and Geochemist's Workbench (GWB) geochemical modeling tools, aiming to compare them. These diagenetic processes are crucial for reservoir geology, as they influence the concentration of silica in water, which, in turn, affects quartz cementation. This study aims to explore the variations in the albitization behavior of detrital and K-feldspar plagioclase using the KINDISP and Geochemist's Workbench (GWB) geochemical models and conduct a comparative analysis between them. Understanding these diagenetic reactions becomes relevant for reservoir geology analysis, as such phenomena control the aqueous silica concentration to some extent, which is consequently reflected in the quartz cementation. The dissolution of plagioclase and K-feldspar releases silica into the pore fluids. As the concentration of silica in the fluid increases, it leads to the precipitation of quartz as overgrowths on detrital quartz grains, a process known as quartz cementation. This was observed particularly in simulations involving temperature increases up to 150 °C, where the equilibrium between albite and anorthite was closely linked to the stability of quartz (Ben et al., 1993). The removal of feldspar through albitization reduces porosity and permeability but contributes silica to the system, which promotes quartz cementation. This, in turn, decreases the reservoir quality by filling pore spaces with secondary quartz, reducing the rock's ability to store and transmit fluids. Thus, the study highlights the importance of these diagenetic processes in reservoir evaluation, as the balance between feldspar dissolution and quartz cementation ultimately controls reservoir properties.

Research and Application of Compound Movable Gel Plugging Agent Suitable for Gasi Oilfield

Abstract In order to meet the water plugging requirements of high salinity reservoirs at different temperatures, we developed three kinds of movable gel plugging and regulating agent by using salt resistant polymer as the main agent, organic chromium and organic aldehyde as the cross-linking agent, supplemented by organic stabilizers and reinforcing agents. Namely, low, medium and high-temperature and high-salinity composite movable gel plugging and regulating agent, and the formulas are 0.4% YG-100 + 0.1% YG-107,0.4% YG-100 + 0.15% YG-107+0.8% YG-103,0.4% YG-100+0.15% YG-107+0.8% YG-103 respectively. The gelling performance, thermal stability and salt resistance of the composite movable gel are evaluated. The results showed the suitable temperature is 40~126 °C, and the salinity of formation water is 260000mg/L. Seven well groups were implemented on site, and the oil pressure in the water wells generally increased. Water channeling was controlled to a certain extent, and the comprehensive water content decreased from 90.5% to 85.1%, a decrease of 5.4%. The cumulative increase in oil production was 3164 tons, and a good oil increase effect was observed.

Application of Reservoir Blockage-relieving in Low Permeability Carbonate of Jingbian Gas-field

Abstract Jingbian gas-field is a low-permeability and lithological gas reservoir with strong reservoir heterogeneity and poorly physical properties. As the gas-field is getting older and older, its gas wells start to produce less, and have growing difficulties to lift water and finally fail to work normally and steadily. One inborn factor lies in the unstable liquid composition of Jingbian gas-field: salty formation water with easy-fouling ions and acidic gas such as CO2 and H2S. Living in the underground for a long time these active materials prone to make the forming of water blocking and the solid deposition, which will weaken gas flow ability and threaten the production. After a detailed study on the plugging, there are three kinds of blocking divided: abruptly impurity blocking, slowly water locking, and energy deficiency. To relieve these blocking, methods have been put forth and carried out in field with achievement. The successful application has brought blockage gas wells solutions in Jingbian gas-field.

The geothermal gradient shapes microbial diversity and processes in natural-gas-bearing sedimentary aquifers

Abstract. Deep subsurface microorganisms constitute over 80 % of Earth's prokaryotic biomass and play an important role in global biogeochemical cycles. Geochemical processes driven by geothermal heating are key factors influencing their biomass and activities, yet their full breadth remains uncaptured. Here, we investigated the microbial community composition and metabolism in microbial-natural-gas-bearing aquifers at temperatures ranging from 38 to 81 °C, situated above nonmicrobial-gas- and oil-bearing sediments at temperatures exceeding 90 °C. Cultivation-based and molecular gene analyses, including radiotracer measurements, of formation water indicated variations in predominant methanogenic pathways across different temperature regimes of upper aquifers: high potential for hydrogenotrophic–methylotrophic, hydrogenotrophic, and acetoclastic methanogenesis at temperatures of 38, 51–65, and 73–81 °C, respectively. The potential for acetoclastic methanogenesis correlated with elevated acetate concentrations with increasing depth, possibly due to the decomposition of sedimentary organic matter. In addition to acetoclastic methanogenesis, in aquifers at temperatures as high as or higher than 65 °C, acetate is potentially utilized by microorganisms responsible for the dissimilatory reduction of sulfur compounds other than sulfate because of their high relative abundance at greater depths. The stable sulfur isotopic analysis of sulfur compounds in water and oil samples suggested that hydrogen sulfide, generated through the thermal decomposition of sulfur compounds in oil, migrates upward and is subsequently oxidized with iron oxides present in sediments, yielding elemental sulfur and thiosulfate. These compounds are consumed by sulfur-reducing microorganisms, possibly reflecting elevated microbial populations in aquifers at temperatures as high as or higher than 73 °C. These findings reveal previously overlooked geothermal-heat-driven geochemical and microbiological processes involved in carbon and sulfur cycling in the deep sedimentary biosphere.

Helium enrichment theory and exploration ideas for helium-rich gas reservoirs

Using gas and rock samples from major petroliferous basins in the world, the helium content, composition, isotopic compositions and the U and Th contents in rocks are analyzed to clarify the helium enrichment mechanism and distribution pattern and the exploration ideas for helium-rich gas reservoirs. It is believed that the formation of helium-rich gas reservoirs depends on the amount of helium supplied to the reservoir and the degree of helium dilution by natural gas, and that the reservoir-forming process can be summarized as “multi-source helium supply, main-source helium enrichment, helium-nitrogen coupling, and homogeneous symbiosis”. Helium mainly comes from the radioactive decay of U and Th in rocks. All rocks contain trace amounts of U and Th, so they are effective helium sources. Especially, large-scale ancient basement dominated by granite or metamorphic rocks is the main helium source. The helium generated by the decay of U and Th in the ancient basement in a long geologic history, together with the nitrogen generated by the cracking of the inorganic nitrogenous compounds in the basement rocks, is dissolved in the water and preserved. With the tectonic uplift, the ground water is transported upward along the fracture to the gas reservoirs, with helium and nitrogen released. Thus, the reservoirs are enriched with both helium and nitrogen, which present a clear concomitant and coupling relationship. In tensional basins in eastern China, where tectonic activities are strong, a certain proportion of mantle-derived helium is mixed in the natural gas. The helium-rich gas reservoirs are mostly located in normal or low-pressure zones above ancient basement with fracture communication, which later experience substantial tectonic uplift and present relatively weak seal, low intensity of natural gas charging, and active groundwater. Helium exploration should focus on gas reservoirs with fractures connecting ancient basement, large tectonic uplift, relatively weak sealing capacity, insufficient natural gas charging intensity, and rich ancient formation water, depending on the characteristics of helium enrichment, beyond the traditional idea of searching for natural gas sweetspots and high-yield giant gas fields simultaneously.