Significant Volumes Of Gas Research Articles

AREA DISTRIBUTION OF GAS SHOW (METHANE AND THE SUM OF HEAVY HYDROCARBONS) INTENSITY IN THE DEEPWATER PART OF THE SOUTH CASPIAN

Geological structure of the Southen Caspian testifies to the possibility of significant volumes of gas. In this regard there occurred a necessity in the study of the Southen Caspian in order to distinguish zones of gas accumulation by area. The aim of the research is to study hydrocarbon gases intensity distribution by area, as well as to determine gas generation zones. The study also used gas survey data (1282 gas sam¬ples) acquired within the Southern Caspian, as well as data from geological and geophysical studies and other materials. The data were interpreted using the Kingdom Suite 2017 licensed software package. Research methods are based on interpretation of chemical composition of hydro¬car¬bon gases of the Southern Caspian. Maps of the methane, ethane, propane, butane, iso-, normal pentane were compiled for gas generation assessment within upper part of the section. The Bakhar field is characterized by a relatively low concentration of methane from 5,37×10-4 to 152944×10-4 % (average 9109,0354×10-4 %). The Shah Deniz oil and gas field is characterized by the maximum values from 4,6200×10-4 to 367,840×10-4 % (average of 85,572,3×10-4 %). The results of gas surveys within the deep water part of the South Caspian showed that gas generation is characteristic of this zone with two predominant components: methane and ethane. Intensive yields of methane homologs were established only in а number of zones near the struc-tures D-12, D-13, D-15, D-19, D-29, D-66, D-71, Guneshli, and Chirag. For other zones, the intensity of their occurrence is minimal. Thus, it can bе expected that gas hydrates bearing methane homologs will bе estab¬lished in the zones of structures D-12, D-13, D-15, D-19, D-29, D-66, and D-71. Analysis of the gas-geo¬chemical material shows that Anthropogene-Plio¬cene depo¬sits are characterized bу widespread intense hydrocarbon gas seeps, the activity of which varies depending on the territorial affiliation. Hydrocarbon gases that form in the diagenetic zone are present in sufficient volumes and can create crystallization sites. The formed gas hydrates cement marine sediments, making them practically impermeable to hydrocarbon gases. This significantly limits the diffusion dispersion of gas hydrocarbons and contributes to their retention. Another important factor is the increase in gas hydrates in stability zones. This is due to the influx of significant volumes of gas hydrates from the under lying sediments into stability zones. The substrate sed¬iments are underlying Pliocene-Quaternary deposits. Results of hydrocarbon gases intensity distribution study can be applied for evalua¬tion of a role of gas in the near surface layers of the geosphere, especially with regard to their possible impact on the ecology of the Caspian Sea region and gas hydrates. Keywords: Gas survey, South Caspian, faults, mud volcanoes, gas content.

Impact of Mineralogy and Diagenesis on Reservoir Quality of the Lower Cretaceous Upper Mannville Formation (Alberta, Canada)

The Lower Cretaceous Upper Mannville Formation in West- Central Alberta has been intensively penetrated by wells targeting deeper reservoirs during the last decades. Production and well log data in this area suggest that significant volumes of gas are still present in both conventional and tight reservoirs of this formation.The Upper Mannville reservoirs in West-Central Alberta consist of fluvial sandstones filling incised valleys. The valley infills are made up of arkosic sandstones with a complex mineralogy. The matrix of these sandstones is made up of various amounts of quartz, feldspars, clay minerals and rock fragments. They were subjected to a complex diagenetic history and the resulting paragenesis influenced the present reservoir properties. Consequently, heterogeneities in the petrophysical properties result in significant exploration risks and production issues.We present in this paper results of a diagenetic study, performed within a well constrained stratigraphic framework, that aims at understanding the impact of mineralogy and diagenesis on reservoir quality evolution. Seventy one core samples from eight wells were collected to perform a petrographic analysis, and to propose a paragenetic sequence. Four main diagenetic events were identified that occurred during burial:– clay coating around the grains;– compaction/dissolution of matrix grains;– quartz and feldspars dissolution that initiated smectite-illite transformation and kaolinisation;– carbonate cementation in the remaining pore space.Clay minerals content and carbonate cementation are the main factors that altered the reservoir quality of these sandstones. The Smectite-Illite transformation was initiated after potassium was released in the formation fluids due to K-feldspars dissolution. This transformation proportionally increased with temperature during burial. Carbonate cementation occured during the uplift phase of the basin, intensively plugging the pore space where the clay content is reduced.Additional SEM and XRD analyses allowed characterizing and quantifying more accurately the different mineralogical phases occluding the porous network. The characterization of both mineralogy and petrophysical properties gives useful keys to locate the diagenetic phases laterally and vertically, and to predict the petrophysical properties distribution.

Characterization of alkali-activated thermally treated incinerator bottom ash

The fine fraction (<14 mm) of incinerator bottom ash (IBA) obtained from a UK energy from waste plant has been milled and thermally treated at 600, 700, 800 and 880 degrees C. Treated materials have been activated with Ca(OH)(2) (10 wt%) and the setting times and compressive strengths at different curing times measured. In addition to decomposition of CaCO(3) to CaO, thermal treatment increases the content of gehlenite (Ca(2)Al(2)SiO(7)), wollastonite (CaSiO(3)) and mayenite (Ca(12)Al(14)O(33)). Thermally treated samples were significantly more reactive than milled IBA and heating to 700 degrees C produced a material which rapidly set. Silica, gehlenite and wollastonite were the main crystalline phases present in hydrated samples and a mixed sulphate-carbonate AFm-type phase (Ca(4)Al(2)O(6)(CO(3))(0.67)(SO(3))(0.33).11H(2)O) formed. Significant volumes of gas were generated during curing and this produced a macro-porous microstructure that limited strength to 2.8 MPa. The new materials may have potential for use as controlled low-strength materials.

Deformation and the timing of gas generation and migration in the eastern Brooks Range foothills, Arctic National Wildlife Refuge, Alaska

Along the southeast border of the 1002 Assessment Area in the Arctic National Wildlife Refuge, Alaska, an explicit link between gas generation and deformation in the Brooks Range fold and thrust belt is provided through petrographic, fluid inclusion, and stable isotope analyses of fracture cements integrated with zircon fission-track data. Predominantly quartz-cemented fractures, collected from thrusted Triassic and Jurassic rocks, contain crack-seal textures, healed microcracks, and curved crystals and fluid inclusion populations, which suggest that cement growth occurred before, during, and after deformation. Fluid inclusion homogenization temperatures (175–250C) and temperature trends in fracture samples suggest that cements grew at 7–10 km depth during the transition from burial to uplift and during early uplift. CH4-rich (dry gas) inclusions in the Shublik Formation and Kingak Shale are consistent with inclusion entrapment at high thermal maturity for these source rocks. Pressure modeling of these CH4-rich inclusions suggests that pore fluids were overpressured during fracture cementation.Zircon fission-track data in the area record postdeposition denudation associated with early Brooks Range deformation at 64 3 Ma. With a closure temperature of 225–240C, the zircon fission-track data overlap homogenization temperatures of coeval aqueous inclusions and inclusions containing dry gas in Kingak and Shublik fracture cements. This critical time-temperature relationship suggests that fracture cementation occurred during early Brooks Range deformation. Dry gas inclusions suggest that Shublik and Kingak source rocks had exceeded peak oil and gas generation temperatures at the time structural traps formed during early Brooks Range deformation. The timing of hydrocarbon generation with respect to deformation therefore represents an important exploration risk for gas exploration in this part of the Brooks Range fold and thrust belt. The persistence of gas high at thermal maturity levels suggests, however, that significant volumes of gas may have been generated.

Summary of the AAPG Research Symposium on Lacustrine Basin Exploration in China and Southeast Asia

In this paper, we review the work presented at the AAPG-Shengli Petroleum Administration Research Symposium dealing with lacustrine basin exploration in China and southeast Asia. This meeting, held in the fall of 1995, revealed that there has been an expansion of the available knowledge base associated with these basins. This increase in information has resulted in a better understanding of lacustrine basin-fill properties and characteristics, even though many of the causal mechanisms for these properties have not yet been established. The many papers presented suggest that there are two primary causes for economic failure within many of these basins: (1) communication between source and reservoir and (2) the limited reservoir potential within the lacustrine sequence of these basins. More effective petroleum systems are found in basins where marine sandstones are in communication with lacustrine sources. The discussions also clearly demonstrated that lacustrine basins are sensitive to environmental changes, causing complex sedimentary facies successions. Each facies, however, displays unique characteristics that can be mapped. Several presenters also suggested that within extensional lacustrine settings the stratigraphic succession follows a distinct pattern. Although most of these basins are predominantly oil prone, several lacustrine basins within the region contain significant volumes of gas. Included within these gas reserves are biogenic accumulations that appear to have formed nearly penecontemporaneously with deposition. Recent work on several of the Chinese basins suggests the possibility for immature hydrocarbon generation and expulsion in a manner different than that associated with marine type II-S kerogens. Even with the progress that this symposium revealed there are several key questions that remain, including questions associated with how technology might be used to improve the economics of many of these systems that display limited reservoir potential.

THE LA BELLA AND MINERVA GAS DISCOVERIES, OFFSHORE OTWAY BASIN

In the past 100 years of hydrocarbon exploration in the Otway Basin more than 170 exploration wells have been drilled. Prior to 1993, success was limited to small onshore gas fields. In early 1993, the La Bella-1 and Minerva-1 wells discovered significant volumes of gas in Late Cretaceous sandstones within permits VIC/P30 and VIC/P31 in the offshore Otway Basin. They are the largest discoveries to date in the basin and have enabled new markets to be considered for Otway Basin gas. These discoveries were the culmination of a regional evaluation of the Otway Basin by BHP Petroleum which highlighted the prospectivity of VIC/P30 and VIC/P31. Key factors in this evaluation were:geochemical studies that indicated the presence of source rocks with the potential to generate both oil and gas;the development of a new reservoir/seal model; andimproved seismic data quality through reprocessing and new acquisition.La Bella-1 tested the southern fault block of a faulted anticlinal structure in the southeast corner of VIC/P30. Gas was discovered in two Late Cretaceous sandstone intervals of the Shipwreck Group (informal BHP Petroleum nomenclature). Reservoirs are of moderate to good quality and are sealed vertically, and by cross-fault seal, by Late Cretaceous claystones of the Sherbrook Group. The gas is believed to have been sourced from coals and shales of the Early Cretaceous Eumeralla Formation and the structure appears to be filled to spill as currently mapped. RFT samples recovered dry gas with 13 moI-% CO2 and minor amounts of condensate.Minerva-1 tested the northern fault block of a faulted anticline in the northwest corner of VIC/ P31. Gas was discovered in three excellent quality reservoir horizons within the Shipwreck Group. Late Cretaceous Shipwreck Group silty claystones provide vertical and cross-fault seal. The hydrocarbon source is similar to that for the La Bella accumulation and the structure appears to be filled to spill. A production test was carried out in the lower sand unit and flowed at a rig limited rate of 28.8 MMCFGD (0.81 Mm3/D) through a one-inch choke. The gas is composed mainly of methane, with minor amounts of condensate and 1.9 mol-% C02. Minerva-2A was drilled later in 1993 as an appraisal well to test the southern fault block of the structure to prove up sufficient reserves to pursue entry into developing gas markets. It encountered a similar reservoir unit of excellent quality, with a gas-water contact common with that of the northern block of the structure.The La Bella and Minerva gas discoveries have greatly enhanced the prospectivity of the offshore portion of the Otway Basin. The extension of known hydrocarbon accumulations from the onshore Port Campbell embayment to the La Bella-1 well location, 55 km offshore, demonstrates the potential of this portion of the basin.

Inventory Verification of Gas Storage Fields

Summary In gas storage field operations, some fields experience an ongoing unaccounted-for loss of significant volumes of gas. The procedure used by some operators to determine such losses and thereby verify gas inventory is discussed here. Two gas storage fields in which the recovery mechanism is gas expansion are described; in one, no gas loss has been experienced, and in the other there is an ongoing unaccounted-for gas loss. Also described is an aquifer gas-storage field with an active water drive that experiences an ongoing unaccounted-for gas loss. Introduction During the primary production period of a gas field, espedally older gas fields, the operator usually is not aware of any gas loss from the reservoir, such as loss to shallower or deeper formations by means of wellbore communication, gas vented from surface production equipment, or gas lost by leaks in such equipment. Even if the operator is aware, a reasonably accurate accounting is seldom attainable or required. However, in gas storage operations, losses can be experienced from the usual causes encountered during primary production as well as from other causes. Because of the necessity of maintaining storage-field performance and because of cost considerations, the operator of a gas storage field must give close attention to verification of gas inventories. Consequently, the operators of storage fields, including those fields that originally contained only water (aquifer gas storage fields), routinely gather reservoir performance data to verify that gas injected into the field is indeed within the reservoir and, in the event gas is being lost, to determine the magnitude of such loss. Most gas storage fields were originally gas fields that were converted to gas storage after depletion of the native gas reserves. Many of these fields were bounded downstructure by water; the production of native gas allowed water to expand into the gas reservoir, reducing the pressure in the aquifer in the vicinity of the field. To inject into the gas reservoir a volume of storage gas equal to that produced from the field during primary production, reservoir space voided by primary production and now occupied by encroached water must be regained during gas injection by the movement of water back into the aquifer. Bypassing of encroached water and movement of gas beyond the original gas/water contact has been observed during gas injection in numerous gas storage fields. This is because the aquifer pressure has been reduced by primary production and gas will flow through the paths of least resistance. The result is gas loss that is now unrecoverably tied up in the aquifer as residual gas saturation. Further, to return the average reservoir pressure to its original value obviously requires exceeding the original pressure by some increment at the injection wells. Although usually quite small, this increase over original pressure may result in gas flow and gas losses through the caprock overlying the gas storage formation. If gas is being lost, the storage-field deliverability (the rate at which gas can be withdrawn from a storage field at given book inventory) declines from year to year because the actual or real gas inventory is decreasing each year. The deliverability of the field must be maintained by the operator for meeting its peak day delivery requirements during the winter heating season. Also, the seasonal volume of gas available for withdrawal will be reduced each year by unrecognized losses and such volume, therefore, will be unavailable for withdrawal.

Some Paleontological Evidence on the Age of the Oil-Bearing Horizon at Burkburnett, Texas

The prospectivity of the Papuan Basin has been appreciated, since oil seeps were first discovered in 1911. Initially, the mountainous terrain, a deeply karstified limestone surface covered with tropical rainforest, fed by 300 inches of rain each year, restricted access to the adventurous. Early exploration was focussed along the coastline and river systems, with only limited success. The development of helicopter transportable rigs during the 1970s was the technological advance that led to success, as the crests of anticlines became accessible to the drill. Even so, the lack of seismic due to severe terrain conditions and structural complexity, still constrains our ability to image trap. Despite these limitations, the oil discovery at Lagifu-2 in 1986, led to the development of the Kutubu Field by a Chevron led joint venture, with first oil in 1992. The Kutubu Field was developed at a cost of US$ 1 billion. Reserves are in excess of 250 mmbo with production currently at 1,00,000 bopd. PNG's second oil development will be the Gobe / SE Gobe Fields, also in the Papuan Thrust Belt, and thought to contain around 100 mmbo. Discovered in the late 1980s, the field is expected to produce 25 000 bopd from 1997.more » Significant volumes of gas have been discovered in the Highlands at Hides, where 3 wells have now confirmed a gas column in excess of 1 km. Additional large gas discoveries have been made in the Papuan Basin, highlighting the potential for PNG to become a long term LNG s producer.« less