Gas-producing Area Research Articles

An integrated approach to characterize diabase sills in Parnaíba Basin, based on geochemical data, cuttings description, and well logs interpretation

Igneous rocks play a fundamental role in the formation and evolution of petroleum systems in several basins around the world. In the Parnaíba Basin, northestern Brazil, the diabase sills and dikes, which compound the Mosquito and Sardinha formations, contribute as a thermal source for an unconventional hydrocarbon generation, as well as providing trap and seal for the petroleum system. To understand these intrusions, we propose a methodology to identify the igneous intrusions in well-logs and interpret their compositional variations. The methodology is based on detailed descriptions of cuttings, X-ray fluorescence (XRF), X-ray diffractometry (XRD) and well logs, such as Gamma Ray (GR), Density (RHOZ) and Photoelectric Factor (PEFZ), from six exploratory wells drilled in the main gas-producing area of the Parnaíba Basin. The intrusions present in these wells were identified through the Igneability Feature and classified based on the GR curve as either “Barriguda” or “Caixote” patterns. The “Barriguda” intrusions show variations in the well logs (GR, RHOZ and PEFZ) along their vertical section, as well as variations in aluminum, calcium, potassium, zirconium, iron, titanium, magnesium, nickel and chromium values, evidencing a great textural and mineralogical variation, confirmed by the mineralogical results of XRD. Data interpretation suggests that the “Barriguda” intrusions are characterized in distinct electrofacies- and chemiofacies that represent an internal variation from top to base, related to magmatic differentiation processes.

Study on Stable Loose Sandstone Reservoir and Corresponding Acidizing Technology

The Sebei gas field is in the Sanhu depression area of the Qaidam Basin, which is the main gas-producing area and a key profit pillar for the Qinghai oilfield. The Sebei gas field within the Qinghai oilfield is characterized by high mud content, poor lithology, interflow between gas and water layers, and a propensity for sand production. The reservoir rocks are predominantly argillaceous siltstone with primarily argillaceous cement. These rocks are loose and tend to produce sand, which can lead to blockage. During its development, the Sebei gas field exhibited significant issues with scale formation and sand production in gas wells. Conventional acidization technologies have proven to be slow acting and may even result in adverse effects. These methods can cause loose sandstone to disperse, exacerbating sand production. Therefore, it is necessary to elucidate the mechanisms of wellbore plugging and to develop an acidizing system for plug removal that is tailored to unconsolidated sandstone reservoirs. Such a system should not only alleviate gas well plugging damage but also maintain reservoir stability and ensure efficient and sustained stimulation from acidization treatments. In this paper, the stability of unconsolidated sandstone reservoirs and the acid dissolution plugging system, along with the technological methods for stabilizing sand bodies, are studied through mineral component analysis, acid dissolution experiments, core immersion experiments, and other laboratory tests. The principle of synergistic effects between different acids is applied to achieve “high-efficiency scale dissolution and low sandstone dissolution”. Three key indicators of dispersion, sand dissolution rate, and scale dissolution rate were created. The acid plugging solution formula of “controlled dispersion and differentiated dissolution” was developed to address these indicators. Laboratory tests have shown that the sandstone is predominantly composed of quartz and clay minerals, with the latter mainly being illite. The primary constituent of the wellbore blockage scale sample is magnesium carbonate, which exhibits nearly 100% solubility in acid. By adding a stabilizer prior to acid corrosion, the core’s corrosion can be effectively mitigated, particle dispersion and migration can be controlled, and the rock structure’s stability can be maintained. Laboratory evaluations indicate that the scale dissolution rate is greater than or equal to 95%, the sand dissolution rate is below 25%, and the system achieves a differentiated corrosion effect without dispersion for 24 h. Field tests demonstrate that the new acid solution plugging removal system enhances average well production and reduces operational costs. The system effectively mitigates the challenges of substantial sand production and reservoir dispersion, thereby furnishing a theoretical foundation and practical direction for acid plugging treatments in unconsolidated sandstone gas fields.

A quantitative model and controlling factors of secondary pore development for tight sandstone reservoirs in the carboniferous Benxi Formation, Ordos Basin, China

As the Ordos Basin is the largest gas-producing area in China, its central and eastern Paleozoic Carboniferous Benxi Formation is poised to become a significant source for increasing reserves and production within the basin. However, the extreme diagenesis, complex pore structure, and strong heterogeneity of this formation hinder the exploration of its “sweet spots”. The reasons are usually considered to be its large burial depth (>3000 m), differential uplift, highly acidic environment and strong hydrocarbon supply in the coal-bearing strata of this area. In this study, we performed qualitative and quantitative analyses of thin sections of Benxi Formation rocks, combined with scanning electron microscopy, X-ray diffraction, and fluid inclusion analyses to determine the development, type, and evolution sequence of secondary porosity from the diagenesis of the Benxi Formation. The main reservoir type of the Benxi Formation is characterized by secondarily dissolved pores (>0.5 μm) and micropores (<0.5 μm) within clay aggregates; the low porosity and permeability of <5.8% and <1 × 10−3 μm2 indicating a tight sandstone reservoir. Throughout the reservoir formation, its porosity has decreased by strong compaction and cementation, and also increased primarily by dissolution. Quantitative analyses of the thin-section porosity of the rocks based on the Scherer initial porosity recovery model and pore evolution parameters defined by Paxton and Ehrenberg showed 39.8% recovery of original porosity and a porosity increase due to dissolution of 1.0–5.4% (mean, 4.1%); this constituted 40–250% of the porosity prior to dissolution. The model-simulated results were closely correlated with the experimental measurements. The lithology, diagenetic fluid, and organic acids of the source rocks jointly controlled the development of secondary pores in the Benxi Formation. These findings indicate that the evolution and controlling factors of secondary pore development must be clarified to identify favorable areas for gas exploration. The results will provide a basis for predicting favorable reservoirs in the tight sandstones of the Benxi Formation in the central and eastern Ordos Basin.

Application of well testing data to forecast the productivity of water intake well in the northern part of the Shaimsky oil and gas producing area

The search for the most watered intervals in the section of the Kurtamysh horizon is an urgent task for providing the population with drinking water. Well testing data were used for this purpose. The methodology of the work included interpretation of gamma logging curves, normalization of samples obtained under various measurement conditions. The boundary values of the double difference parameter of natural radioactivity are determined. The possibility of using this method to characterize the filtration properties of rocks is evaluated. Statistical processing of data on the operation of water intake wells was carried out. The closest correlations have been established for the flow rate and specific flow rate of wells with a double difference parameter of natural radioactivity. According to the interpretation of the curves of the gamma logging of wells, forecast maps of the most promising intervals of the captage of water intake wells are constructed. The results of the study have methodological and applied significance, and can be used in the design of groundwater intakes.

E&amp;P Notes (August 2022)

E&amp;P Notes (August 2022)

Study of domestic wastewater in oil and gas field: A case study in the Cangkring river, Tuban, East Java

Mudi Field, Tuban is an oil and gas producing area in East Java. Pad B Mudi Field is an office area for the oil and gas industry. The oil and gas industrial office area in Pad B Mudi Field produces domestic wastewater, which is channeled into the Cangkring River. Domestic wastewater flows directly into rivers. This study aims to determine the water quality of the Cangkring River region, which is mixed with domestic wastewater from Pad B Mudi Field. Samples of river water were taken at 3 points along with the river flow. Sample evaluation included physical, chemical, and biological characteristics. Sample test results were adjusted according to domestic wastewater quality standards and water quality standards. Parameters tested include temperature, TSS, pH, BOD5, COD, ammonia (NH3), phosphate (PO4 3-), chromium, oils and fats, and total coliforms. The highest values of the three samples for each parameter were temperature of 20.8 °C, TSS of 13 mg/L, pH of 7.8, BOD5 of 6.53 mg/L, COD of 17.38 mg/L, ammonia (NH3) of 6.13 mg/L, phosphate (PO4 3-) of 1.15 mg/L, chromium of 0.01 mg/L, oils and fats of 1.6 mg/L, and total coliform of 2400/100 mL. The values of the three points of the Cangkring River water test results met all the parameters of the domestic wastewater quality standards. In testing water quality standards, Cangkring River water met all parameters of class 4 water quality standards, namely water quality that can be used to irrigate agriculture. So it can be concluded that the condition of the Cangkring River water is safe for the community but is not suitable for drinking water, recreational infrastructure, and aquaculture.

Research and application of supramolecular gel plugging agent in abnormal pressure reservoir

The Aktobe project is the largest oil and gas producing area of PetroChina in Central Asia. However, after years of exploitation, the pressure of the reservoir has dropped, making it difficult to increase the production of a single well. Both the Kenkyak block and North Troyes block of the project have induced fractured leakage, and frequent leakage affects safe and efficient drilling and completion operations and production. Therefore, the research on leakage prevention and control technology is very necessary. This article focuses on the characteristics of the cracks in the high-pressure area of the Kenkyak block and the cracks in the low-pressure area of the North Troyes block. Aiming at the fracture characteristics of the high-pressure zone in the Kenkyak block and the low-pressure zone in North Troyes block, and taking advantage of the synergistic effect of supramolecules, a supramolecular plugging-while-drilling agent was developed based on the deformable fiber composite gel. It forms a strong adhesion plugging layer on the inner wall of the leakage channel through the strong adhesion force, and it achieves a good plugging effect. The 300-500mD sand disc bearing pressure could reach 700psi when adding 3% agent, and the bearing pressure of 3-5D permeability sand disc could reach above 450psi. A supramolecular static plugging agent was also developed based on the dilatant gel. It is rich in strong shear reversible gel with supramolecular structure, which guarantees its pumpability and plugging performance. The effective rate of one-time plugging is over 80%, and the viscosity is greatly reduced after the gel is broken for 72hr, which benefits the reservoir protection.

Seismic Expression of Paleogene Talangakar Formation - Asri &amp; Sunda Basins, Java Sea, Indonesia

The Asri and Sunda Basin are located offshore Southeast Sumatra under the SE Sumatera Production Sharing Contract (PSC). Currently, Pertamina Hulu Energi OSES operates in the Asri and Sunda Basins, known as Southeast Sumatra (SES) Block. As one of Indonesian prime oil and gas producing area in the past 50 years, these basins have produced cumulatively more than 1,500 MMBOE with an average of 90,000 BOPD. Both Asri and Sunda Basins are part of a series of Cenozoic half grabens developed on the Asian continental margin, that have occupied a retro arc setting since early Neogene times.Hydrocarbon exploration activities in the offshore southeastern Sumatra began with a signed agreement of Contract Sharing between IIAPCO (Independent Indonesian American Petroleum Company) and Pertamina on 6 September 1968.The contract area included the offshore areas east of Sumatra and south of Bangka - Belitung Islands, covering an area of 124,000 km2. After the final relinquishment in 2008, the current PSC boundary covers an area of 5,851 km2.This paper presents the results of integrated petroleum geosciences framework, its implications for Oligo-Miocene reservoirs and hydrocarbon prospectivity of the basins using near field exploration approaches. A four-fold division comprising rift initiation, rift climax, immediate post rift and late-post rift stages of basin evolution characterize the basin filling. Seismic expression of these kinematic units gives an idea about the linkage of their deposition with different stages of rift evolution. The present study has also identified a new potential play concept in Oligo -Miocene reservoirs.

Integrating Geophysical, Geochemical and Geotechnical Characteristics to Assess Soil and Groundwater Resources in Ovade, South-South Nigeria

Integrated methods were employed to assess soil and groundwater resources in an oil and gas producing area. Earth resistivity meter was used for the electrical imaging of the subsurface. Physico-chemical, geochemical and geotechnical parameters of soil and groundwater samples were determined. The results of the resistivity data revealed that a high resistive plume with resistivity &gt; 2,000 Ohm-m has penetrated the soil beyond 20 m beneath the surface in some parts. The water samples show mild acidity with pH values in the range 4.3-5.5. Total dissolved solids (TDS) is low 26.55- 38.05 mg/L and conductivity ranges from 55.38-65.60 µS/cm. Iron content in water is fairly high (0.878-0.994 mg/L). Groundwater samples analysis using ultra violet (UV) detector and gas chromatography (GC) show that total petroleum hydrocarbons (TPH) is very low (&lt; 0.01 mg/L and &lt;0.031mg/L) respectively. It can be attributed to the sealing of the confined aquifer by impermeable clay in the case of the groundwater. The average permeability of the soil is 8.098 ´ 10-3cm/s indicating good drainage. The results have shown that shallow boreholes are prone to pollution. Groundwater of the area needs treatment before it can be consumed and integrated methods of investigation should be carried out periodically.

Improving the efficiency of additional development of depleted gas reservoirs by displacing the residual gas with nitrogen

Based on the analysis of publications in domestic and foreign scientific and technical publications, the directions of increasing gas recovery from depleted gas reservoirs, which include the displacement of residual gas from the porous medium with nitrogen, are substantiated. Nitrogen can be obtained from the air in any oil and gas producing area using membrane, adsorption or cryogenic types of plants produced by the industry. The final gas recovery factor can be adjusted by choosing certain values ​​of technological parameters that characterize the process of reservoir development. Using hypothetical digital models, the influence on the total final gas recovery factor and the residual gas recovery factor of the pressure of the beginning of nitrogen injection into the reservoir, the rate, duration and cyclicity of its injection, the system for locating production and injection wells on the gas-bearing area and the technological modes of their operation was investigated. The results of the studies are shown in the form of graphical dependencies of the final gas recovery factor and the gas recovery factor for residual gas on the investigated determining parameters. Using the research results, the optimal values ​​of the parameters of the nitrogen injection process into a depleted gas reservoir of square and round shapes and the corresponding values ​​of the gas recovery coefficient have been established. The results of the studies performed indicate a significant technological efficiency of the displacement of residual gas by nitrogen from depleted gas reservoirs. Depending on the system of placement of production and injection wells in the gas-bearing area and the technological parameters of the nitrogen injection process into the reservoir, the gas recovery factor for the residual gas varies on average within the range of 53,97 – 61,82 %.

Diagenetic alteration, pore-throat network, and reservoir quality of tight gas sandstone reservoirs: A case study of the upper Paleozoic sequence in the northern Tianhuan depression in the Ordos Basin, China

The Sulige gas field in the Ordos Basin is the largest gas field in China. The studied area, the northern Tianhuan depression, is located west of the gas field and is considered as a potential gas-producing area. The complex diagenetic alteration history and its effects on the pore-throat network and reservoir quality of the tight gas sandstones are explained. The upper Paleozoic first member of the Shanxi Formation and eighth member of the Shihezi Formation tight gas reservoir rocks are composed of coarse- to medium-grained sandstones and are dominated by sublitharenites. The most important diagenetic factor for porosity reduction was compaction, followed by cementation. Diagenetic mineral phases include quartz overgrowth, calcite cement and replacement, and kaolinite cement and replacement, with minor heulandite and chlorite. Pressure dissolution of quartz grains and quartzite fragments is the main source of silica for the early and late quartz overgrowth cementation (formed mainly from 120°C to 140°C). The hydrolysis and alteration of volcanic material and mica flakes released some silicon, calcium, and aluminum ions. Calcium and carbon in calcite cements could be derived from surrounding mudstones. Calcite replaced the quartz overgrowths. The formation of kaolinite, as cement and replacements, was controlled by the interactions of silica, aluminum, pH, and temperature (140°C). Because of deformation of detrital components (mica flakes and ductile rock fragments) and diagenetic replacement, clear negative correlations between reservoir quality and contents of the diagenetic minerals are lacking. A complex and isolated pore-throat network was created by strong diagenetic transformation. Based on analysis of thin sections, three-dimensional x-ray micro–computed tomography, and constant-rate mercury injection data, the samples with relatively good reservoir quality (porosity >10% and permeability >0.5 md) are characterized by dissolution pores and primary intergranular pores and commonly contain more and larger pore throats both in volume (counts >1800 and size >0.02 per unit volume) and diameter (>1.20 μm) than the samples with poor reservoir quality. The intercrystalline pores of kaolinite are very widespread and considered favorable for oil and gas accumulation because some asphalt was found within these pores. This study may be used, by analogy, to better understand diagenetic factors controlling the formation of tight gas sandstone reservoirs and predict the development of pore-throat systems.

Sedimentary characteristics and exploration direction in the south of the central block in Pre-Caspian Basin

The Pre-Caspian Basin experienced the history from the Late Paleozoic craton margin to the Mesozoic-Cenozoic depression. It has been explored for a long time. It is the most important oil and gas producing area in Kazakhstan, and a large number of oil and gas fields have been discovered in it. The oil and gas discoveries are located in clastic rock and platform carbonate rock below the Lower Permian salt domes. The study area is located at the eastern margin of the Pre-Caspian Basin, where reservoirs are deposited in an open carbonate platform in the shallow sea. The most developed subfacies are intraplatform shoals and sea between shoals. The microfacies in the intraplatform shoals include bioclastic shoals and algae shoals, and represent dominant high-quality reservoirs. The central gentle zone and the eastern slope zone in the study area are potential targets for exploration and evaluation. All reservoirs are structural-lithologic reservoirs controlled by high lithologic barriers or updipped pinch-outs.

The Battle over Fracking: The Mobilization of Local Residents

In the last decade, the natural gas industry has grown rapidly, and North Texas has become a major shale gas-producing area. This paper studies the power struggle of two rival groups (Frack Free Denton and Denton Tax Payers for a Strong Economy) over fracking in Denton. How did each of these groups challenge the claims-making activities and goals of their adversaries?” We conducted data from ten in-depth interviews from each side to compare concerns about fracking. This study focuses on the campaign of the two groups on each side of the debate. We developed the model of merging the theoretical frameworks of value-conflict and social construction of social problems by examining the stages of awareness, policy determination, and reform in the battle over fracking. This project finds that the new theoretical framework model is germane to many features of claims,” “claims-makers,” and “claims-making activities.

Relationship between tight sandstone reservoir formation and hydrocarbon charging: A case study of a Jurassic reservoir in the eastern Kuqa Depression, Tarim Basin, NW China

The Kuqa Depression in the Tarim Basin is a prolific tight sandstone gas-producing area in China. In the eastern part of the depression, the assessed tight sandstone gas resource is approximately 1 × 1012 m3. To more accurately analyse the accumulation process of tight sandstone gas reservoirs, based on a comprehensive investigation of the characteristics and porosity evolution of the sandstone reservoir and hydrocarbon charging history, the relationship between hydrocarbon charging and tight sandstone reservoir formation is analysed. Collective evidence indicates that the Lower Jurassic Ahe Formation tight sandstone reservoir in the eastern Kuqa Depression is strongly heterogeneous, and the reservoir space is predominantly intergranular and intragranular dissolution pores. The development of fractures could improve reservoir properties, whereas compaction mainly led to the formation of the tight reservoir. The evolution in reservoir porosity shows that the Ahe Formation was compacted (porosity was less than 10%) at circa 12 Ma. Fluid inclusion analysis shows that there were two charge peaks with characteristics of “early oil and late gas”. The first oil charge peak occurred during 23–12 Ma, and the second gas charge peak occurred during 5–2 Ma. The Ahe Formation tight sandstone reservoirs in the eastern Kuqa Depression had higher porosities during the period of oil charge than those during natural gas charge because the sandstone reservoirs had experienced strong compaction and caused the formation of tight sandstone reservoirs, which means that the period of reservoir densification was earlier than the period of large-scale natural gas charging. Abnormal pore fluid pressure is the major driving force of gas migration rather than buoyancy in the tight reservoir. The mechanism whereby the natural gas completely displaced the pore water in the tight reservoir created the current distribution of "upper gas and lower water". Since the Quaternary, intense tectonic movement has destroyed the tight gas reservoirs in the structural high and adjusted the tight gas reservoirs in the structural low, forming the present distribution of oil and gas.

Health Risk Assessment on Heavy Metals Ingestion through Groundwater Drinking Pathway for Residents in an Oil and Gas Producing Area of Rivers State, Nigeria

In the study, health risk assessment on heavy metals ingestion was presented through the groundwater drinking pathway for residents in an oil and gas producing area of Rivers State, Nigeria. The level of the ground water pollution was examined, the quality of the borehole and the well water was assessed and the quality of the ground water pathway for the resident in the oil and gas producing area was determined and compared with the national and international standards for the drinking water. This study adopted both the field and laboratory experimental analysis of physical and chemical parameters. Water samples were analyzed for Physico-chemical parameters following acceptable methods to determine the compliance, and the results were analyzed according to drinking water guidelines. Interestingly, the results show that the ground water contained high amounts of turbidity (21.5 NTU, 23.00 NTU and 19.0 NTU in the borehole water and well water), iron (5.3 mg/L in the ground water and 6.98 mg/L in the borehole water) and pHs of all water samples were acidic in the study area. These results show that ground waters including the borehole and the well waters of the study area had acquired reasonable levels of pollution. Whereas, other values were found to be lower or above and corresponding to the acceptable threshold limit values for the drinking water set by consensus standards. A high value of turbidity due to suspended minerals is the cause for milky-white colour. Hence, ground waters in the study area are mainly unsuitable for drinking (containing iron, pH and turbidity). This study clearly advises that some health deteriorating chemicals in the drinking water were at dangerous level and; therefore, the water quality could be a major health menace for residents of the oil and gas producing area of Rivers state. Furthermore, additional researches in medical test to ascertain the health of the people are recommended in this study. Comprehensive groundwater monitoring and adequate treatment should be implemented. The government should carry out clean-up exercise immediately because there is oil spill to prevent infiltration of oil into the groundwater. There is also a need for the continuous monitoring and auditing of water quality in the oil producing areas so as to protect the men and the environment.

E&amp;P Notes (December 2014)

E&amp;P Notes (December 2014)

Geological and geochemical characterization of the Lower Cretaceous Pearsall Formation, Maverick Basin, south Texas: A future shale gas resource?

As part of an assessment of undiscovered hydrocarbon resources in the northern Gulf of Mexico onshore Mesozoic section, the U.S. Geological Survey (USGS) evaluated the Lower Cretaceous Pearsall Formation of the Maverick Basin, south Texas, as a potential shale gas resource. Wireline logs were used to determine the stratigraphic distribution of the Pearsall Formation and to select available core and cuttings samples for analytical investigation. Samples used for this study spanned updip to downdip environments in the Maverick Basin, including several from the current shale gas-producing area of the Pearsall Formation. The term shale does not adequately describe any of the Pearsall samples evaluated for this study, which included argillaceous lime wackestones from more proximal marine depositional environments in Maverick County and argillaceous lime mudstones from the distal Lower Cretaceous shelf edge in western Bee County. Most facies in the Pearsall Formation were deposited in oxygenated environments as evidenced by the presence of biota preserved as shell fragments and the near absence of sediment laminae, which is probably caused by bioturbation. Organic material is poorly preserved and primarily consists of type III kerogen (terrestrial) and type IV kerogen (inert solid bitumen), with a minor contribution from type II kerogen (marine) based on petrographic analysis and pyrolysis. Carbonate dominates the mineralogy followed by clays and quartz. The low abundance and broad size distribution of pyrite are consistent with the presence of oxic conditions during sediment deposition. The Pearsall Formation is in the dry gas window of hydrocarbon generation (mean random vitrinite reflectance values, Ro = 1.2–2.2%) and contains moderate levels of total organic carbon (average 0.86 wt. %), which primarily resides in the inert solid bitumen. Solid bitumen is interpreted to result from in-situ thermal cracking of liquid hydrocarbon generated from original type II kerogen that was prevented from expulsion and migration by low permeability. The temperature of maximum pyrolysis output (Tmax) is a poor predictor of thermal maturity because the pyrolysis (S2) peaks from Rock-Eval analysis are ill defined. Vitrinite reflectance values are consistent with the dry gas window and are the preferred thermal maturity parameter. A Maverick Basin Pearsall shale gas assessment unit was defined using political and geologic boundaries to denote its spatial extent and was evaluated following established USGS hydrocarbon assessment methodology. The assessment estimated a mean undiscovered technically recoverable natural gas resource of 8.8 tcf of gas and 3.4 and 17.8 tcf of gas at the F95 and F5 fractile confidence levels, respectively. Significant engineering challenges will likely need to be met in determining the correct stimulation and completion combination for the successful future development of undiscovered natural gas resources in the Pearsall Formation.

The origin and distribution of natural gas in the frontal uplift area of the Kuqa depression, Tarim Basin

The frontal uplift of the Kuqa depression is an important oil and gas producing area. In this study, the distribution and origin of natural gas were discussed based on natural gas components and isotope data. The main components of natural gas were hydrocarbons with relatively high contents of C2+ component. Most gases were derived from terrestrial source rocks, and some came from marine rocks. The contents of non-hydrocarbon gases were high in the central part of the frontal uplift area and low in the two terminals. The distribution of oil composition was similar to that of natural gas, which was mainly controlled by the types of source rocks. Dry coefficient and maturity of natural gas in the frontal uplift were lower than those of gas in the Kelasu tectonic belt of the Kuqa depression, which was mainly affected by the difference of tectonic movements in both areas. In the frontal uplift, the traps were formed in the early stage and could capture the early formed oil and gas, and structural adjustment was slight in later stages, so the oil and gas could be effectively preserved. Multiperiodic oil and gas filling led to the complex distribution of natural gas.

Relative performance of different exposure modeling approaches for sulfur dioxide concentrations in the air in rural western Canada

BackgroundThe main objective of this paper is to compare different methods for predicting the levels of SO2 air pollution in oil and gas producing area of rural western Canada. Month-long average air quality measurements were collected over a two-year period (2001–2002) at multiple locations, with some side-by-side measurements, and repeated time-series at selected locations.MethodsWe explored how accurately location-specific mean concentrations of SO2 can be predicted for 2002 at 666 locations with multiple measurements. Means of repeated measurements on the 666 locations in 2002 were used as the alloyed gold standard (AGS). First, we considered two approaches: one that uses one measurement from each location of interest; and the other that uses context data on proximity of monitoring sites to putative sources of emission in 2002. Second, we imagined that all of the previous year's (2001's) data were also available to exposure assessors: 9,464 measurements and their context (month, proximity to sources). Exposure prediction approaches we explored with the 2001 data included regression modeling using either mixed or fixed effects models. Third, we used Bayesian methods to combine single measurements from locations in 2002 (not used to calculate AGS) with different priors.ResultsThe regression method that included both fixed and random effects for prediction (Best Linear Unbiased Predictor) had the best agreement with the AGS (Pearson correlation 0.77) and the smallest mean squared error (MSE: 0.03). The second best method in terms of correlation with AGS (0.74) and MSE (0.09) was the Bayesian method that uses normal mixture prior derived from predictions of the 2001 mixed effects applied in the 2002 context.ConclusionIt is likely that either collecting some measurements from the desired locations and time periods or predictions of a reasonable empirical mixed effects model perhaps is sufficient in most epidemiological applications. The method to be used in any specific investigation will depend on how much uncertainty can be tolerated in exposure assessment and how closely available data matches circumstances for which estimates/predictions are required.

米国メキシコ湾オフショア―拡大するニッチ・ビジネス―

The continental shelf of the U. S. Gulf of Mexico (GOM) is considered one of the most matured and overexploited oil and gas basins in the world. In fact, most of the large E & P companies have shifted their operational area to the deepwater since mid 1990s when Mineral Management Services (MMS) announced an incentive scheme on the federal royalties.Despite such circumstances, it is true that the GOM continental shelf still remains an important revenue source to such companies and it turns out that the area is the second largest oil and gas producing area (after Alaska) in the North America.One of the unique features in GOM is that the “niche” business exists and is growing along with the change of large companies' focus in their activities. Some niche players with sound business models have been demonstrating substantial growth in recent years, which, together with current eye-catching “deep Miocene” exploration, are helping to take the GOM into a new era.Mitsubishi Corporation (MC) has been aware of such a unique business environment in the GOM through their in-house studies, as well as their thorough monitoring on the local industry. MC has now reached such a level of confidence that they can establish a sustainable business without exposing themselves to an excessive risk associated with exploratory drillings. They have thoroughly examined several niche businesses to build an optimum business model to them. As a result, they have come to a conclusion of building a business model based on monetizing marginal proven undeveloped oil and gas discoveries (PUD).