Major Gas Fields Research Articles

Research And Application Of 3D Collaborative Design in Oil and Gas Field Surface Engineering

With the constant development of major oil and gas fields at home and abroad towards the direction of digitalization and intelligent technologies, the traditional surface engineering process has encountered the challenges of limited professional collaborative design and poor data connection, etc. The advanced 3D collaborative design has gradually become the mainstream platform of oil and gas field surface engineering design due to its features of a higher degree of model reduction and its advantages of cross-discipline, cross-platform, and cross-region collaborative design. However, in the course of current station modeling and designing, due to the complexity of engineering and the limits of design software, etc., the problems of mutual transmission failure amongst models and the loss of attribute information are prone to occur, causing a bad impact on the work efficiency of 3D collaborative design. In this paper, the commonly used 3D collaborative design software in oil and gas fields has been systematically discussed along with the common issues and their solutions in aspects of 3D design analyzed. Moreover, the effective application of collaborative design in the stage of procurement and construction, and the stage of the operation and maintenance of the digital station shall be separately discussed. While improving the efficiency of 3D collaborative design, it also plays the role of guidance in strengthening the digital and intelligent construction foundation of oil and gas fields.

A New Calculation Method of Well Leakage in Gas Well with Annular Pressure

The gradual promotion of the concept of gas well integrity has made major oil and gas fields pay more and more attention to the integrity management and evaluation of gas wells with annular pressure. Annular leakage rate is one of the key parameters for gas well integrity evaluation. However, the leakage rate measurement of high-temperature, high-pressure, and acid-containing gas wells has high risks and costs, which are often difficult to obtain in field operations. In order to obtain the bottom hole leakage rate parameters of the gas well to assist the integrity evaluation, this article is based on the safety valve leakage model and the small hole leakage model, combined with the characteristics of the gas well with annulus pressure, the idea of applying the annulus leakage rate calculation from the perspective of model mechanism is analysed, and the model parameters are clarified as well. The application of the two leak models is compared by case wells calculation, which verifies their rationality and feasibility. The research of this paper provides a theoretical basis for the leakage evaluation of gas well with annular pressure, and promotes development of gas well integrity management research.

Treated water from oil and gas extraction as an unconventional water resource for agriculture in the Anadarko Basin

The energy industry generates large volumes of produced water (PW) as a byproduct of oil and gas extraction. In the central United States, PW disposal occurs through deep well injection, which can increase seismic activity. The treatment of PW for use in agriculture is an alternative to current disposal practices that can also provide supplemental water in regions where limited freshwater sources can affect agricultural production. This paper assesses the potential for developing PW as a water source for agriculture in the Anadarko basin, a major oil and gas field spanning parts of Kansas, Oklahoma, Colorado, and Texas. From 2011 to 2019, assessment of state oil and gas databases indicated that PW generation in the Anadarko Basin averaged 428 million m3/yr. A techno-economic analysis of PW treatment was combined with geographical information on PW availability and composition to assess the costs and energy requirements to recover this PW as a non-conventional water resource for agriculture. The volume of freshwater economically extractable from PW was estimated to be between 58 million m3 per year using reverse osmosis (RO) treatment only and 82 million m3 per year using a combination of RO and mechanical vapor compression to treat higher salinity waters. These volumes could meet 1–2 % and 49–70 % of the irrigation and livestock water demands in the basin, respectively. PW recovery could also modestly contribute to mitigating the decline of the Ogallala aquifer by ~2 %. RO treatment costs and energy requirements, 0.3–1.5 $/m3 and 1.01–2.65 kWh/m3, respectively, are similar to those for deep well injection. Treatment of higher salinity waters increases costs and energy requirements substantially and is likely not economically feasible in most cases. The approach presented here provides a valuable framework for assessing PW as a supplemental water source in regions facing similar challenges.

The water footprint of hydraulic fracturing for shale gas extraction in China

The rapid expansion of shale gas extraction worldwide has raised significant concerns about its impact on water resources. China is expected to undergo a shale revolution following the U.S. Most of the information on water footprint of shale gas exploration and hydraulic fracturing has been focused on the U.S. Here, we addressed this knowledge gap by establishing a comprehensive database of shale gas extraction in China, utilizing operational data from over 90 % of shale gas wells across the country. We present systematic analysis of water usage and flowback and produced water (FP water) production from all the major shale gas fields in China. Between 2012 and 2022, a total of 2740 shale gas wells were hydraulically fractured in China, primarily located in Sichuan and Chongqing Province. About 113 million m3 water was used for hydraulic fracturing, resulting in a cumulative shale gas production of 116 billion m3. As of 2022, the annual water use for hydraulic fracturing exceeded 20 million m3, and the annual FP water production reached 8.56 million m3. Notably, 80 % ~ 90 % of the FP water has been reused for hydraulic fracturing since 2020, accounting for 29 % to 35 % of the annual water usage for hydraulic fracturing. Water use per well in China varies primarily between 21,730 m3 to 61,070 m3 per well, and water use per horizontal length ranges primarily between 20 m3/m and 35 m3/m. The average ultimate FP water production per well in China was estimated to be 22,460 m3. The water use intensity (WUI) for shale gas extraction in China mainly ranges from 7 to 25.4 L/GJ, which is significantly higher than that of the U.S. This disparity is largely due to the lower Estimated Ultimate Recovery (EUR) of shale gas wells in China. Despite the considerable water consumption during the hydraulic fracturing process, shale gas has a relatively low water footprint compared to other conventional energy resources in China. The Produced water intensity (PWI) for shale gas extraction in China ranges from 3.9 to 7.3 L/GJ, which is consistent with the previously reported PWI values for shale gas extraction in the U.S. This study predicts water usage and FP production spanning the period 2023 to 2050 under two scenarios to assess the potential impact of shale gas extraction on water resources in the Longmaxi shale region in Sichuan Basin. The first scenario assumed a constant drilling rate, while the second assumed a yearly 10 % increase in drilling rate. With an assumed FP water reuse rate of 85 % for hydraulic fracturing, the estimated annual freshwater consumption for the two scenarios is 10.4 million m3 and 163 million m3, respectively. This accounts for only 0.28‱ and 4.4‱ of the total annual surface water resources in Sichuan and Chongqing Province. Our findings suggest that freshwater usage for hydraulic fracturing in humid Southern China is small relative to available surface water resources. However, prospective large-scale shale gas extraction in other arid and semi-arid regions may enhance the regional water scarcity. It is necessary to develop new hydraulic fracturing technologies that can use saline groundwater or other types of marginal water, and explore alternative management and treatment strategies for FP water.

Enhanced gas recovery: Theory, technology, and prospects

Research on the enhanced gas recovery (EGR) technology is urgently needed in most of China's major gas fields due to low recovery in their late development stages. To promote progress in ERG theory and technology, this paper establishes a unified and universal model for gas recovery evaluation, analyzes the key factors affecting the gas recovery, and expects the prospect of EGR. The results are obtained as follows. First, the production degree of reserves, pressure drawdown sweep efficiency and pressure depletion efficiency are key factors affecting the gas recovery, which is the product of the coefficients corresponding to these factors. Second, according to the development practice of Anyue Longwangmiao gas reservoir, Kela 2 gas field, Sulige gas field and Southern Sichuan shale gas, it is estimated that the recovery of conventional water-driven gas reservoirs and unconventional gas reservoirs (incl. tight gas and shale gas) can be improved by 6–15 percentage points by increasing the production degree of reserves, the pressure drawdown sweep efficiency and pressure depletion efficiency. Third, it is proposed that clarifying the EGR mechanism, developing new EGR methods, and promoting the field test of EGR technologies are directions for theoretical and technical researches. The study results provide a theoretical foundation for EGR. The EGR methodologies for different types of gas reservoirs provide technical support for improving gas recovery and stable production of existing gas fields, promote healthy and rapid development of natural gas industry in China and provide guidance for guaranteeing national energy security.

Water-Based Drilling Fluid Helps Control Extreme Conditions in Gas Shale Play

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 208307, “A Water-Based Drilling Fluid for Controlling Deep-Reservoir Extreme Conditions in an Abu Dhabi Gas Shale Play,” by Gabe Manescu, SPE, Schlumberger; Balazs Veer, SPE, TotalEnergies; and Panamarathupalayam Balakrishnan, SPE, Schlumberger, et al. The paper has not been peer reviewed. _ A combination of teamwork and fluids technology proved to be the formula for successfully drilling in high-pressure/high-temperature (HP/HT) conditions for an onshore UAE shale gas play. The success achieved in drilling deep [6200-m measured depth (MD)], long-lateral-displacement (2,000-m) wells with an integrated global operator is a combination dependent on frequent, transparent communication between team members. The environmentally acceptable aqueous drilling fluid delivered a barite sag-free operation in these highly deviated wellbores. Introduction The drilling of unconventional HP/HT wells in the Diyab field can experience difficulty in reaching target depth. One significant challenge is the design of a drilling fluid to manage reservoir pressures and temperatures. The reservoir temperature may reach 165.5°C, requiring mud weights (MW) greater than 20 lbm/gal. Tailoring the drilling-fluid formulation to balance economics and environmental regulations while overcoming HP/HT conditions is critical. In the Diyab drilling campaign, special emphasis was placed on designing the drilling fluid and then on its use in 8½-in. reservoir sections. Background The Upper Jurassic (Oxfordian to Middle Kimmeridgian) Diyab formation, also known as the Dukhan formation, has served as the source rock for several major oil and gas fields in the Middle East. The Diyab formation is unique because of its lower porosities, high carbonate mineralogy, and pressure gradient. Despite the lower porosity, the high-carbonate content defines an extremely brittle target conducive to hydraulic fracture stimulation. Several organic-rich intervals exist throughout the Diyab formation and are separated by less-organic tight limestones, which create different flow units. From a developmental perspective, this condition has the potential to create a high-impact stacked play. The extent of the prospective unconventional Diyab formation within the UAE is limited to the onshore north-central UAE, where most of this area is within Block 1, operated by TotalEnergies. The depth of the prospective basal Diyab interval across Block 1 ranges between 3758 and 4115 m. Three unconventional offset wells (DE-02, DE-03, and DE-04) were drilled by ADNOC within Block 1 to test the productivity of the three submembers of the greater Diyab interval (the Jubaila, Hanifa, and Tuwaiq Mountain formations). After determining that the Hanifa formation had the most-promising productivity, the first TotalEnergies appraisal horizontal well, DE-05, was drilled. After drilling this well, the DE-06 well was the second horizontal appraisal well to be drilled. Additionally, two more deep wells, DE-09 and DE-10, were successfully drilled and evaluated.

Investigation of trend between porosity and drilling parameters in one of the Iranian undeveloped major gas fields

Porosity is one of the main parameters that should be considered when a gas or an oil field is assessed. Hence, the availability of porosity is crucial in any rock and formation analysis. However, this parameter is not always available and direct measurement is scarce and usually is confined to appraisal phase of a field. Therefore, in this study it is aimed to find a relationship in order to estimate porosity in afterward phases. The data of 5 appraisal wells of an undeveloped gas field has been gathered to perform this purpose. The full set wireline logging data and drilling data were available. ‏The data inherit high level of fluctuation which is normal with respect to real direct measured data. The smoothed curving was utilized and as a result, the fluctuation was diminished considerably and the feasibility of carrying out the investigation was being established, accordingly. To normalize and gather drilling data in a parameter in order to have a better view and investigation, sigmalog method was employed. It was observed that there is a clear exponential relationship between porosity and drilling data and curve fitting was utilized to conduct a numerical relationship. The curve fitting was established with R2 = 0.83 and a trustworthy fitting resulted. The results demonstrate the possibility of porosity estimation by using drilling data. Furthermore, a numerical relationship is given for a specific field. The porosity estimation can lead to better analysis of newly drilled rocks and formations leading to more efficient field development strategies.

E&P Notes (January 2022)

E&P Notes (January 2022)

The 2019-2020 Khalili (Iran) Earthquake Sequence-Anthropogenic Seismicity in the Zagros Simply Folded Belt?

We investigate the origin of a long‐lived earthquake cluster in the Fars arc of the Zagros Simply Folded Belt that is colocated with the major Shanul natural gas field. The cluster emerged in January 2019 and initially comprised small events of M n ∼ 3–4. It culminated on 9 June 2020 with a pair of M w 5.4 and 5.7 earthquakes, which was followed by >100 aftershocks. We assess the spatiotemporal evolution of the earthquake sequence using multiple event hypocenter relocations, waveform inversions, and Sentinel‐1 Interferometric Synthetic Aperture Radar (InSAR) measurements and models. We find that the early part of the sequence is spatially distinct from the 9 June 2020 earthquakes and their aftershocks. Moment tensors, centroid depths, and source parameter uncertainties of 15 of the largest (M n ≥ 4.0) events show that the sequence is dominated by reverse faulting at shallow depths (mostly ≤4 km) within the sedimentary cover. InSAR modeling shows that the M w 5.7 mainshock occurred at depths of 2–8 km with a rupture length and maximum slip of ∼20 km and ∼0.5 m, respectively. Our results suggest that the 2019–2020 Khalili earthquake sequence was likely influenced by operation of the Shanul field, though elevated natural seismicity in the Zagros makes the association difficult to prove. Understanding how to distinguish man‐made from natural seismicity is helpful for hazard and risk assessment, notably in the Zagros, which is both seismically active and rich in oil and gas reserves.

Implementation of an Intelligent Drilling Automation System in the Middle East

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 203251, “Drilling in the Digital Age: Harnessing Intelligent Automation To Deliver Superior Well-Construction Performance in a Major Middle Eastern Gas Field,” by Brennan Goodkey, Gerardo Hernandez, and Andres Nunez, Schlumberger, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually from 9-12 November. The paper has not been peer reviewed. While breakthroughs in digital technology have rewarded many industries with a step change in productivity and efficiency during the past decade, the drilling industry has yet to benefit on a large scale from these advances. The complete paper details the introduction of a drilling automation system (DAS) to deliver superior well-construction performance in a major gas field in the Middle East. The DAS was deployed on two onshore gas drilling rigs. The paper discusses the technology itself, the deployment process, implementation challenges, the agile development model, and the results achieved. Introduction In 2018, Schlumberger partnered with a major Middle Eastern national oil company on one of the world’s largest lump-sum, turnkey gas-well-delivery projects, where drilling operations had already been optimized by targeting high-impact, low-effort areas of opportunity. Drilling automation was pursued to achieve an improvement in performance, specifically to shift the technical limit and to minimize the frequency of service incidents that could cost days of nonproductive time (NPT). An in-house solution under development for some time was designed to take control of the rig’s surface equipment to automate and optimize most drilling tasks and to generate value in the following areas: Automation of drilling actions to perform exactly as planned, within the safe limits of operation, by eliminating the inconsistency of manual operation and its susceptibility to human factors Identification and mitigation of drilling dysfunctions that could lead to costly tool failures and incidents by using intelligence engines that would adapt drilling parameters continuously for best performance Technology Overview The DAS was developed as the execution component of a well-construction platform designed to link planning and execution. The planning component allowed for all well-design stakeholders to collaborate online and create the well plan simultaneously. Once prepared, the plan would be exported to the rig as a machine-interpretable digital drilling plan that the DAS could digest. With the validation of rig personnel, the DAS would then take control of a selection of drilling actions and execute exactly as instructed in the well plan. While drilling, extensive information would be collected to serve as a vehicle to drive performance when planning future wells. In the deployment summarized in the complete paper, a pilot version of the drilling automation module was deployed as a standalone product. The key objectives of design included three categories - dynamic planning, safety and resilience, and interoperability.

A material balance based practical analysis method to improve the dynamic reserve evaluation reliability of ultra-deep gas reservoirs with ultra-high pressure

Ultra-deep major gas fields are typically characterized by high and ultra-high pressure, tight matrix and developed fractures, so the reserve estimation is of higher uncertainty. In order to accurately estimate the reserves of this type of gas reservoir, this paper analyzed the correlation between the effective rock compressibility and the cumulative effective rock compressibility based on the material balance equation of high and ultra-high pressure gas reservoirs, and accordingly selected the material balance based analysis method suitable for the reserves estimation of high and ultra-high pressure gas reservoirs. Then, the starting calculation conditions of reserve estimation were determined using the non-linear regression method. In addition, a semi-logarithmic type curve matching method was established for the cases where the starting conditions could not be met. Finally, this method was applied to calculate the reserves of three ultra-high pressure gas fields (reservoirs) to verify its reliability. And the following research results were obtained. First, the cumulative effective compressibility of gas reservoir in the material balance equation of high and ultra-high pressure gas reservoir is a key parameter influencing its reserves, and it is the function of original formation pressure and current average formation pressure, but its numerical value can be hardly obtained by core experiments. Second, it is recommended to adopt the nonlinear regression method without compressibility to estimate the reserves of high and ultra-high pressure gas reservoirs. Third, the calculation starting point of reserves by the nonlinear regression method (the starting point of dimensionless apparent formation pressure-cumulative gas production curve deviating from the straight line relationship) cannot be theoretically calculated. The calculation starting point for different dimensionless linear coefficients (ωD) obtained from the statistical results by the graphic method corresponds to the dimensionless apparent pressure depletion degree of 0.06–0.38, and that obtained based on the data statistics of the example gas reservoir falls within this interval. Fourth, when the starting conditions are not satisfied, the semi-logarithmic type curve matching method can be used for reserve estimation. The ratio of the reserves to the apparent geological reserves G/Gapp is a function of ωD.The higher the ωD, the lower the G/Gapp. Fifth, for the high and ultra-high pressure gas reservoirs in the production test stage, the test production time shall be extended as long as possible to improve the reliability of reserve estimation. And for those in the middle and late stages of development, it is necessary to prepare the comprehensive treatment measures on the basis of reserves so as to improve the development effects of gas reservoirs continuously.

ОСОБЕННОСТИ РАБОТЫ РОССИЙСКИХ НЕФТЕГАЗОВЫХ КОМПАНИЙ НА КОНТИНЕНТАЛЬНОМ ШЕЛЬФЕ ЮЖНО-КИТАЙСКОГО МОРЯ В СОВРЕМЕННОМ МИРЕ

Today, when almost all major oil and gas fields on land have been discovered and developed, Russian oil and gas companies pay special attention to one of their promising areas of activity — the exploration and development of hydrocarbon resources of the continental shelf. While technology and shale oil production are progressing rapidly, it is undeniable that the future of world oil production lies on the continental shelf of the world's oceans. In recent years, Russian oil and gas companies have shown interest in foreign projects. This, according to experts, is due to economic reasons, in particular, a high level of profitability. The cost of oil production in a number of countries is many times lower than in Russia. In Iraq, for example, the cost of producing a barrel of oil is sometimes below $1, and in Western Siberia the cost can reach $12 per barrel. Another advantage for Russian investors with participation in foreign projects is their access to advanced technologies.

Methane Emissions from Abandoned Oil and Gas Wells in California.

California hosts ∼124,000 abandoned and plugged (AP) oil and gas wells, ∼38,000 idle wells, and ∼63,000 active wells, whose methane (CH4) emissions remain largely unquantified at levels below ∼2 kg CH4 h-1. We sampled 121 wells using two methods: a rapid mobile plume integration method (detection ∼0.5 g CH4 h-1) and a more sensitive static flux chamber (detection ∼1 × 10-6 g CH4 h-1). We measured small but detectable methane emissions from 34 of 97 AP wells (mean emission: 0.286 g CH4 h-1). In contrast, we found emissions from 11 of 17 idle wells-which are not currently producing (mean: 35.4 g CH4 h-1)-4 of 6 active wells (mean: 189.7 g CH4 h-1), and one unplugged well-an open casing with no infrastructure present (10.9 g CH4 h-1). Our results support previous findings that emissions from plugged wells are low but are more substantial from idle wells. In addition, our smaller sample of active wells suggests that their reported emissions are consistent with previous studies and deserve further attention. Due to limited access, we could not measure wells in most major active oil and gas fields in California; therefore, we recommend additional data collection from all types of wells but especially active and idle wells.

Potential for carbon sequestration in the Hemlock Formation of the Cook Inlet basin, Alaska

Injecting fluids, such as carbon dioxide (CO2), into hydrocarbon reservoirs has great environmental and oil field development benefits. In this study, the fluid injection and storage potential of the Hemlock Formation was assessed in the whole Cook Inlet basin of southcentral Alaska as well as eight individual oil and gas fields (i.e., Swanson River, North Cook Inlet, Granite Point, Trading Bay, Middle Ground Shoal, Redoubt, Ninilchik, and Cosmopolitan fields) in the basin. The Hemlock Formation, similar to most formations in the Cook Inlet basin, is vertically and horizontally heterogeneous, resulting in compartmentalized reservoirs. Based on core data and petrophysical analysis, the Cook Inlet basin has an estimated CO2 storage range of 0.91–16.61 gigatonnes (Gt), with a 50% probability (that the quantity will equal or not exceed the calculated estimate) value of 4.33 Gt. The reservoir quality for the Hemlock Formation is assessed and compared among the major oil and gas fields in the whole basin. The eight oil and gas fields from both upper and lower Cook Inlet basin have been selected to better assess the potential of CO2 storage in the Hemlock Formation. Maps generated for the eight fields show fluid injection sweet spots. Variability among individual fields for fluid storage quantities is caused by changes in porosity, reservoir thickness, and the size of the field.

Distance effects of gas field infrastructure on pygmy rabbits in southwestern Wyoming

AbstractAs domestic energy development activity continues in the western United States, wildlife conservation planning in affected regions is increasingly important. The geologic basins where oil and gas energy exploration is occurring are primarily sagebrush steppe rangelands. Sagebrush steppe habitats may support more than 20 vertebrate species of conservation concern, and for many of these species, information is lacking on the effects of gas energy development. In earlier work, we demonstrated a negative relationship among development density of gas field infrastructure and pygmy rabbits (Brachylagus idahoensis). We now examine the spatial relationship among gas field infrastructure, pygmy rabbits, and their habitat on four major gas fields in southwest Wyoming. Using data collected from 120 plots over three years (2011–2013) and 2012 National Agriculture Imagery Program (NAIP) imagery, we evaluated (1) whether well pads are more likely to be located in areas of pygmy rabbit habitat, (2) whether the presence and abundance of pygmy rabbits are related to distance from infrastructure, and, if so, (3) how much of the total surface area on a gas field is affected. Well pads on three gas fields occurred in higher quality pygmy rabbit habitat than did a set of randomly generated points, and the abundance and probability of pygmy rabbits being present were lower within approximately 0.5–1.5 km of the nearest road and 2 km of well pads and utilities. Buffering a digital layer of roads and well pads on one gas field revealed that nearly 82% of the (4417 km2) surface area was within 1 km of infrastructure, and over 95% of the gas field surface area was within 2 km. This need not be the case on future gas fields. Directional and horizontal well drilling technologies now make it possible for gas to be recovered from a greater area per well pad, enabling future gas field developments that require fewer well pads, roads, and pipeline corridors. Such changes would enable increased well pad spacing and provide the opportunity to locate gas field infrastructure in areas of poor quality wildlife habitat, avoid high priority habitat, and conserve a greater amount of on‐field wildlife habitat overall.

Seal failure assessment of a major gas field via integration of seal properties and leakage phenomena

We present a seismic- and well-based interpretation of a large leakage zone above the Scarborough gas field, Exmouth plateau, North West shelf of Australia. This leakage zone, well imaged on three-dimensional seismic data, extends over a region of 100 km2 (39 mi2), encompassing both the crest and flanks of the anticlinal trap, and is termed here as distributed crestal leakage. The present-day gas–water contact is 85 m (278 ft), and the spillpoint is 110 m (328 ft) below the crest, implying that the trap is underfilled at present. The leakage zone comprises more than 500 pockmarks at the present-day seabed with no crosscutting or cannibalization, suggesting that they formed in a short interval of time. These are underlain by sediment remobilization features and amplitude anomalies, consistent with a relatively high flux leakage of gas from the underlying Cretaceous deep-water sand-rich reservoir. By analyzing the geometrical relationship between the leakage zone, the top-seal properties, and the gas–water contact, we conclude that the mode of leakage in this specific setting is not the result of gradual addition of gas charge but is instead consistent with a sudden increase of aquifer overpressure. We suggest two alternative models for seal failure in this case study: a conservative model consistent with a modest but rapid increase in aquifer overpressure leading to membrane seal failure and a model dominated by high aquifer overpressure leading to leakage through hydraulically dilated faults and fractures.

The Role of the Russian Arctic Gas Industry in the Northern Sea Route Development

The Russian region of the Arctic has been described in terms of unique hydrocarbon potential, as well as strong concentration of major natural gas fields. The article presents reserves of natural gas, oil and condensate in the main oil and gas provinces of the Russian Arctic. It is indicated that the development of Russia’s economic activity in the Arctic depends largely on the increased transport and infrastructure capacity of the region. The activities of the largest Russian extractive industries such as PAO Gazprom, PAO Rosneft Oil Company, PAO NOVATEK for the production of natural gas in the Arctic zone have been described. The implementation of the integrated investment project “Yamal-LNG”, which provides for the production of natural gas at the Yuzhno-Tambeyskoye field, its liquefaction, and supply to consumers has been singled out as one of the most significant areas for developing the resource base of the Arctic zone. The article touches on the production capacities of a liquefied natural gas (LNG) plant, as well as the logistic structures for delivering LNG to consumers. It is also indicated that transportation of liquefied natural gas along the Northern Sea Route has a variety of significant advantages. Review of the activities carried out by Russian companies in the development of the Arctic gas fields has revealed the relationship between the processes of implementing gas projects in the region and the rate of development of the Northern Sea Route (NSR). The dynamics of cargo transportation by the NSR has been analyzed and also external and internal factors that determine the effectiveness of the functioning of the NSR transport system have been highlighted. Current state of the icebreaking fleet has been appraised as one of the most important drivers in cargo transportation along the NSR. Availability of liquefied natural gas as marine fuel has been discussed as one of the advantages of the NSR, which will allow observing stringent environmental standards of shipping in the Arctic and reducing freight costs. Conclusions have been drawn on the high importance of gas production projects to be implemented in the Russian region of the Arctic for the development of shipping along the Northern Sea Route.

Hydrochemistry of flowback water from Changning shale gas field and associated shallow groundwater in Southern Sichuan Basin, China: Implications for the possible impact of shale gas development on groundwater quality

The worldwide expansion of shale gas production and increased use of hydraulic fracturing have raised public concerns about safety and risks of groundwater resources in shale gas extraction areas. China has the largest shale gas resources in the world, most of which are located in the Sichuan Basin. Shale gas extraction in the Sichuan Basin has been increasing rapidly in recent years. However, the potential impact on shallow groundwater quality has not yet been systematically investigated. In order to evaluate the possible impact of shale gas extraction on groundwater quality, we present, for the first time, the hydrochemistry and Sr isotopic data of shallow groundwater, as well as flowback and produced water (FP water) in the Changning shale gas field in Sichuan Basin, one of the major shale gas fields in China. The Changning FP water is characterized by high salinity (TDS of 13,100–53,500 mg/L), Br/Cl (2.76 × 10−3) and 87Sr/86Sr (0.71849), which are distinguished from the produced waters from nearby conventional gas fields with higher Br/Cl (4.5 × 10−3) and lower 87Sr/86Sr (0.70830–0.71235). The shallow groundwater samples were collected from a Triassic karst aquifer in both active and nonactive shale gas extraction areas. They are dominated by low salinity (TDS of 145–1100 mg/L), Ca-HCO3 and Ca-Mg-HCO3 types water, which are common in carbonate karst aquifers. No statistical difference of the groundwater quality was observed between samples collected in active versus nonactive shale gas extraction areas. Out of 66 analyzed groundwater, three groundwater samples showed relatively higher salinity above the background level, with low 87Sr/86Sr (0.70824–0.7110) and Br/Cl (0.5–1.8 × 10−3) ratios relatively to FP water, excluding the possibility of contamination from FP water. None of the groundwater samples had detected volatile organic compounds (VOCs). The integration of geochemical and statistical analysis shows no direct evidence of groundwater contamination caused by shale gas development.

Nanoparticle foaming agents for major gas fields in China

The conventional foaming agents have the problems of poor adaptability and high cost during the application in different types of gas fields, especially in high temperature, high salinity, high acidic gas and high condensate oil and gas fields. In this study, the Gemini foaming agent was used as the main agent to enhance foaming and foam stability of the foaming agent, the grafted nanoparticles were used as foam stabilizer to further improve the foam stability, and the characteristic auxiliaries were added to make the foaming agent suitable for different types of gas reservoirs. Two types and six subtypes of nanoparticle foaming agents have been prepared for the main gas fields of China. The experimental evaluation results show that the overall temperature resistance, salinity resistance, H2S resistance, CO2 resistance and condensate resistance of the nanoparticle foaming agents can reach 160°C, 250 000 mg/L, 100 mg/L, 100% and 40%, respectively. The new foaming agents have been used in 8685 wells in China. Compared with conventional foaming agent, the average gas flow rate per well increased by 62.48%, the pressure difference (casing-tubing) decreased by 18.9%, and the cost dropped by 45%. The effect of reducing cost and increasing efficiency is obvious.

Ground Deformation Revealed by Sentinel-1 MSBAS-InSAR Time-Series over Karamay Oilfield, China

Fluid extraction or injection into underground reservoirs may cause ground deformation, manifested as subsidence or uplift. Excessive deformation may threaten the infrastructure of the oilfield and its surroundings and may even induce earthquakes. Therefore, the monitoring of surface deformation caused by oil production activities is important for the safe production of oilfields and safety assessments of surrounding infrastructure. Karamay oilfield is one of the major oil and gas fields in China. In this study, we take the Karamay oilfield in Xinjiang as a case study to detect surface deformation caused by subsurface fluid injection. Sentinel-1A images of 32 ascending (Path 114) and 34 descending (Path 165) tracks spanning March 2017 to August 2018, were used to derive vertical and horizontal deformation over Karamay oilfield using the MSBAS-InSAR method. The observed two-dimensional deformation exhibited significant vertical and east-west deformation in this region. The maximum uplift and horizontal velocity was approximately 160 mm/year and 65 mm/year, respectively. We also modeled one of the typical deformation zones using a dislocation model in a homogenous elastic half-space.