Commercial Hydrocarbon Production Research Articles

Petroleum Potential Prospectivity of Muglad Basin, South Sudan: A Case of Source Rocks Characterisation in the Drilled Kaikang West-1 Well

This study focuses on Prospectivity of Petroleum Potential of Muglad basin, South Sudan, with the help of petroleum source rocks characterisation in the drilled Kaikang West-1 Well based on the organic matter quantity, quality, and the thermal maturation generation capability of the organic matter disseminated in the analysed rock samples. Muglad basin is a major petroliferous Western and Central African Rifts System (WCARS) member, with estimated reserves of 2,053 mm bbl. Muglad Basin comprises thick sandstones of Aradeiba and Bentiu Formations, considered to be the main petroleum prospectivity targets, with trapping mechanism being structural faults and lithological anticlines. The organic matter contents were determined directly from laboratory analyses of the source rock samples with the help of seismic and gamma ray profiles, total organic carbon (TOC wt %), maturity indices (OI, HI and PI), temperature maximum (Tmax °C), porosities and other sedimentological parameters. This study involved a series of analytical geochemistry and petro-physical studies to ascertain a number of effective source rock samples from the well cores which were then analysed in terms of TOC, OI, PI, HI, S2, S1 and Tmax to determine oil/gas prone samples (resource areas). These were then distinguished from strata with very high organic matter samples as well as very high TOC to help identify for possible source rock characterizations within the lithology pertaining to the well in terms of potential source-reservoir-seals combinations. The Rock-Eval pyrolysis data were useful in assessing and evaluating the type of organic matter, thermal maturity, and the generation capability of source rocks for hydrocarbon exploration rationale. The analyses revealed that some strata, within the sampled well data, have high hydrocarbon generation potential with the existence of commercial hydrocarbon production

Prospectivity of Pliocene-Miocene deposits of the Khasilat field of the Absheron oil and gas bearing region according to surface and well seismic data

Prospectivity of Pliocene-Miocene deposits of the Khasilat field of the Absheron oil and gas bearing region according to surface and well seismic data

RIFT DEPRESSIONS AS A PROSPECTIVE HYDROCARBON PRODUCTION FACILITY IN THE TERRITORY OF TRANSBAIKALIA

Currently, commercial production of hydrocarbons in Russia has the widest geography. This allows most entities to extract and process hydrocarbon raw materials in quantities necessary for uninterrupted economic activity and ensuring socio-economic stability. One of the few regions in which there is an insufficiently studied resource base, but at the same time there are completely no oil and gas production facilities introduced into industrial development, is Transbaikalia. This situation has led to the fact that this region is almost completely dependent on the supply of petroleum products from outside, which requires additional capital costs for the placement and maintenance of the strategic reserve of already processed raw materials, as well as the organization of uninterrupted supplies and its subsequent distribution throughout the region. One of the most poorly studied types of geological objects containing a fairly large amount of hydrocarbon resources in Russia is the intermountain rift genesis basins. It is known that the main resources of hydrocarbon raw materials in the territory of Transbaikalia are confined to just this type of facilities, the account of which goes to dozens. Such rift troughs are Mesozoic in age, and their resource potential can be hundreds of millions of tons of oil equivalent. Therefore, interest in this type of objects and their further study looks natural. In the future, hydrocarbon production at such facilities can amount to hundreds of thousands and even millions of tons of oil equivalent, which makes them extremely important not only in terms of increasing the level of oil production in general, but also as a determining factor in increasing the level of energy security of the entire region.

Identification and Characteristics of Source Rocks in Lt-1 Well, Northern Kenya

This study on the hydrocarbon source rocks identification of LT-1 well in a Tertiary rift basin, northern Kenya, which had oil and gas shows was based on the organic matter quantity, quality, and the thermal maturation generation capability of the organic matter disseminated in the analysed rock samples. The organic matter contents were determined directly from laboratory analyses of the source rock samples with the help of seismic and gamma-ray profiles, total organic carbon (TOC wt%), maturity indices (HI and PI), temperature maximum (Tmax °C), porosities and other sedimentological parameters. This study involved a series of analytical geochemistry and petro-physical studies in ascertaining a number of effective source rock samples from the well cores which were then analysed in terms of TOC, PI, HI, S2, S1 and Tmax to determine oil/gas prone samples (resource areas) and distinguish them from strata with very high organic matter content. The samples with very high TOC were identified for possible source rock characterisations of the lithology pertaining to the well in terms of potential source-reservoir-seals associations. The Rock-Eval pyrolysis data were useful in assessing and evaluating the type of organic matter, thermal maturity, and the generation capability of source rocks for hydrocarbon exploration rationale. The analyses revealed that some strata within the sampled well data have high hydrocarbon generation potential with the existence of commercial hydrocarbon production. In conclusion, after an in-depth comparison and study of organic carbon content, hydrogen and production indices, type of organic matter content and maturity of organic matter, we confirmed that the studied resource areas are favourably considered for medium- to large-size hydrocarbon discoveries.

Generative potential, thermal maturity, and TOC modeling of petroleum systems in Southwestern Khuzestan Province, Zagros Basin, Iran

ABSTRACT In this study, a series of analytical geochemistry and petro-physical studies has been done to a number of effective source rock samples in the southwestern region of Khuzestan province and it illustrates that some strata’s in investigated wells have high hydrocarbon generation potential with the existence of commercial hydrocarbon production. There are some practical drawbacks to these analytical strategies, which can be solved through a combination of the results of different analyses, such as Thermal maturity, TOC, Rock Eval analysis that the main reason behind implementing different strategies in this paper. Twenty-five samples were analyzed in terms of TOC, PI, HI, OI, S3, S2, Tmax and we could determine oil/gas prone samples (resource areas) and distinguish them from strata’s with very low organic matter content Larter & Douglas, (1982). These predictions are quite crucial to E&P stage hydrocarbon exploitation as they will lead to solid predictions and they would avoid substantial expenses and eliminate uncertainties. In conclusion, after in depth comparison and study of organic carbon content, hydrogen and oxygen index, Type of organic matter content and Maturity of organic matter, we determined that studied resource areas are considered for medium to large size hydrocarbon discoveries and should be considered favorable.

The history of development and features of gas industry in Norway and the Netherlands

Natural gas occupies one of the leading places in the energy system of the modern world. More and more countries are using environmentally friendly raw materials for domestic needs, moving away from coal consumption due to the decarbonization policy. The article provides an overview and analysis of data on two leaders in natural gas deposits in Europe: Norway and the Netherlands. Special attention is paid to the history of the development of the kingdoms gas market and its impact on the formation of this industry in the European Community and in the world. Both the largest deposits of Troll and Groningen and little-known small deposits discovered at the moment, such as Ekofix, Frigg, Drogen, Ozberg, OrmenLang, F4B, K5A, F4, FA and others, are considered. The development of oil and gas resources on the Norwegian Continental Shelf has followed different paths since the first commercial production of hydrocarbons began in 1971. All licensees on the Norwegian Continental Shelf are responsible for the sale of their own gas. In contrast, the Netherlands, which required very large investments for the development of the Groningen field, developed a new type of take or pay – “take or pay” contract, and the gas price was tied to the oil price to return a large amount of public investment. Some results on the development of the industry in the countries have been summed up.

Effects of Entrained Hydrocarbon and Organic-Matter Components on Reservoir Quality of Organic-Rich Shales: Implications for “Sweet Spot” Identification and Enhanced-Oil-Recovery Applications in the Duvernay Formation (Canada)

Summary The hydrocarbon (HC)-storage capacity of organic-rich shales depends on porosity and surface area, whereas pore-throat-size distribution and pore-throat-network connectivity control permeability. The pores within the organic matter (OM) of organic-rich shales develop during thermal maturation as different HC phases are generated and expelled from the OM. Organic-rich shales can potentially retain a large proportion of the HCs generated during the diagenesis process. Commercial HC production from liquid-rich shale reservoirs can be achieved using completion technologies such as multistage-fractured horizontal wells. However, the ability of industry to identify “sweet spots” along multistage-fractured horizontal wells for both primary and enhanced oil recovery (EOR) is still hampered by insufficient understanding of the effects of type/content of entrained HC/OM components on reservoir quality. The primary objectives of the current study are therefore to establish an integrated experimental workflow to investigate the effect of entrained HC/OM on storage and transport properties of the organic-rich shales, and to provide examples of that experimental workflow through analyzing a selected sample suite from a prolific shale-oil reservoir (the Duvernay Formation) in western Canada. To accomplish this goal, a comprehensive suite of petrophysical analyses is performed on a diverse sample suite from the Duvernay Formation that differs in OM content (2.8 to 5 wt%; n = 5), before and after sequential pyrolysis by a revised Rock-Eval analysis [extended-slow-heating (ESH) Rock-Eval analysis]. Using the ESH cycle, different HC/OM components can be distinguished more easily and reliably during the pyrolysis process: free light oil (S1ESH; up to 150°C), fluid-like HC residue (FHR) (S2a; 150 to 380°C), and solid bitumen/residual carbon (S2b; 380 to 650°C). The characterization techniques used at each stage are helium pycnometry (grain density, helium porosity); low-pressure gas [nitrogen (N2), carbon dioxide (CO2)] adsorption (LPA) [pore volume (PV), surface area, pore-size distribution (PSD) within micropores, mesopores, and smaller macropores]; crushed-rock gas [helium, CO2, N2] permeability; and rate-of-adsorption (ROA) analysis (CO2, N2). Scanning-electron-microscopy (SEM) analysis is further conducted to verify/support the petrophysical observations. Powder X-ray-diffraction (XRD) analyses were performed on all samples in the “as-received” state and after Stage S2b (thermal pyrolysis up to 650°C) to quantify variations in mineralogical compositions and their possible controls on the evolution of petrophysical properties (i.e., porosity/permeability). Organic petrography was conducted on selected samples to characterize the nature of OM. Compared with the “as-received” state, porosity, permeability, modal-pore-size distribution, and surface-area increase with sequential pyrolysis stages, associated with the expulsion and devolatilization of free light oil and FHR (S2a; up to 380°C). However, the change in petrophysical properties associated with the degradation of solid bitumen/residual carbon (S2b; up to 650°C) is variable and unpredictable. The observed reduction in porosity/permeability values after Stage S2b is likely attributed to the occlusion of PV with solid bitumen/residual carbon degradation (i.e., coking); sample swelling caused by water loss from the lattice structure of clay minerals (i.e., illite); and sample compaction as a result of OM removal from the rock matrix. Among various stages of the ESH Rock-Eval pyrolysis, the petrophysical properties that are measured after Stages S1ESH and S2a, as they are related to the expulsion of the lighter and heavier free-HC compounds from the rock matrix, are expected to be the most important for primary and EOR applications. Quantification of the evolution of reservoir quality with HC generation/expulsion has important implications for identifying petrophysical “sweet spots” within unconventional reservoirs, optimizing stimulation design, and targeting specific zones within the reservoir of interest with the OM content/type amenable to maximizing gas storage/transport during cyclic solvent injection for EOR applications. The integrated experimental workflow proposed herein could be of significant interest to the operators of organic-rich shale/mudstone plays (e.g., the Duvernay) as a screening tool for developing optimized stimulation treatments for improving primary and enhanced HC recovery.

New insights into the organic geochemistry of the Otway Basin

The Penola Trough of the Otway Basin in South Australia has enjoyed over 20 years of commercial hydrocarbon production from the sandstones of the Early Cretaceous Otway Group with 71.46 PJ sales gas and 65840 kL of condensate produced from five fields until production ceased in 2011. Recent success in Haselgrove 3, where a newly discovered deeper reservoir underlying depleted reservoirs of the Pretty Hill Formation flowed 25 MMscfd on test heralds a new phase of exploration and appraisal with a 2C Contingent Resource of 87 PJ assigned to the discovery. These hydrocarbons are considered to have been principally derived from lacustrine, floodplain and back swamp facies of the Pretty Hill Formation and lacustrine facies of the underlying Casterton Formation. The South Australia Department for Energy and Mining is currently investigating an unnamed Late Jurassic syn-rift sequence of interbedded metasediments, tuffaceous sediments and organically-rich shale, first identified as fractured basement in Sawpit 1, located on the northern flanks of the Penola Trough and which unconformably underlies the Casterton Formation. A low-sulfur medium-gravity paraffinic oil was recovered from drill stem tests from this well and subsequent total organic carbon and Rock-Eval analyses for the same unit in nearby Sawpit 2 identified a source rock containing algal organic matter and thought to be deposited in a deep anoxic lake setting. In this paper, we will present the preliminary results of detailed geochemical analyses of rocks and rock extracts from this previously unrecognised syn-rift sequence and discuss implications for hydrocarbon prospectivity in the deeper portions of the Penola Trough.

New insights into the stratigraphy of the Otway Basin

The Otway Basin is one of the best known and most actively explored of a series of Mesozoic basins formed along the southern coastline of Australia by the rifting of the Antarctic and Australian plates during the Cretaceous. The basin offers a diversity of play types, with at least three major sedimentary sequences forming conventional targets for petroleum exploration in the onshore basin. The Penola Trough in South Australia has enjoyed over 20 years of commercial hydrocarbon production from the sandstones of the Early Cretaceous Otway Group comprising the Crayfish Subgroup (Pretty Hill Formation and Katnook sandstones) and Eumeralla Formation (Windermere Sandstone Member). Lithostratigraphic characterisation and nomenclature for these sequences are poorly constrained, challenging correlation across the border into the potentially petroleum prospective Victorian Penola Trough region. The Geological Survey of Victoria (GSV), as part of the Victorian Gas Program, commissioned Chemostrat Australia to undertake an 11-well chemostratigraphic study of the Victorian Otway Basin. The South Australia Department for Energy and Mining, GSV and Chemostrat Australia are working collaboratively to develop a consistent, basin-wide schema for the stratigraphic nomenclature of the Otway Basin within a chemostratigraphic framework. Variability in the mineralogy and hence inorganic geochemistry of sediments reflects changes in provenance, lithic composition, facies changes, weathering and diagenesis. This geochemical variation enables the differentiation of apparently uniform sedimentary successions into unique sequences and packages, aiding in the resolution of complex structural relationships and facies changes. In this paper, we present the preliminary results of detailed geochemical analyses and interpretation of 15 wells from across the Otway Basin and the potential impacts on hydrocarbon prospectivity.

A pragmatic approach for identifying effective lacustrine shale payzones

Compared with the marine shale payzones, lacustrine shale payzones generally contain more interbed layers (e.g., sandstone interbeds and carbonate interbeds), bringing about a higher complexity to the identification of effective lacustrine shale payzones. In this work, a pragmatic but systematic approach is developed to identify the effective lacustrine shale payzones with commercial hydrocarbon-production potentials. Such identification approach is developed based on three easily accessible data sources that are obtained from multiple wells drilled in a given region: 1) well logging data; 2) measured properties of the core samples; and 3) production test data. In this approach, the first step is to identify shale-containing formations based on the lithology profile along a well that has been interpreted using the well logging data. Secondly, a shale-dominated formation is extracted from a given shale-containing formation if the ratio of total shale thickness to the total formation thickness exceeds 60%; this cut-off value is selected based on the consideration that such formation has a higher possibility of industrial production potential. Lastly, a shale-dominated formation can be classified as an effective shale payzone if the total organic carbon (TOC) content, porosity, and effective thickness are all greater than the given threshold values. By using this proposed method, one can obtain the total effective thickness and the regional distribution of effective lacustrine shale payzones, which could help to locate the sweet spot of the shale payzones as well as subsequently design proper methods for recovering the shale resources. The Lower Jurassic formations possess abundant lacustrine shale layers that are widely considered to be the potential lacustrine shale gas payzones in the northwest of Sichuan Basin in China. A case study in this formation is presented to demonstrate the efficacy of the newly developed approach in identifying the effective lacustrine shale payzones. Validation results prove that this new method can be used to effectively identify the effective lacustrine shale payzones with commercial production potentials.

Rock-Eval Pyrolysis Results from the Bijeel 1 Well, Kurdistan Region, Iraq

We used Rock-Eval pyrolysis to examine the petroleum source potential of rock samples from the Bijeel 1 Well in Kurdistan Region of northern Iraq. The results show that Sargelu and Sehkaniyan marine Type IIS kerogen are potential sources of hydrocarbons and are thermally mature with respect to the oil window. In the samples that we studied, carbonate are more organic-rich and more oil-prone than carbonaceous shales and silty mudstones, which appear to be potential sources of natural gas. The Paleocene rocks from Bijeel 1 Well are thermally immature. Lithologically similar rocks may be present in the deeper parts of the subsurface of Iraqi Kurdistan located south of the Bijeel 1 Well, where they may have been buried deeply enough to generate oil and (or) gas. The Tertiary rocks are sparsely examined and mostly unexplored and no commercial production of hydrocarbons has been obtained. However, the existence of potential source rocks of oil and gas, as shown by our Rock-Eval results, suggests that undiscovered petroleum accumulations may be present in the area.

Sequence stratigraphy, sedimentary systems and implications for hydrocarbon exploration in the northern Xujiaweizi Fault Depression, Songliao Basin, NE China

Recent drilling data from the northern Songliao Basin reveal considerable hydrocarbon exploration potential in deep-seated small-scale faulted basins. In this paper, the Shahezi Formation of the northern Xujiaweizi Fault Depression within the Songliao Basin was investigated as a case study. Sequence stratigraphy, sedimentary systems and the hydrocarbon exploration potential of the small-scale faulted basin were investigated through observations and descriptions of cores; analyses of conventional log curves, imaging data and logging data; and interpretations of 3-D seismic profiles. Four third-order sequences, mainly controlled by sediment supply and fault activity, were identified based on unconformities at the basin margins and in sedimentary successions. System tracts in the third-order sequences were also recognized through lithological associations and geophysical response characteristics. The distributions of sedimentary systems, including fan deltas, braided deltas, lacustrine deposits, subaqueous fans, volcaniclastic deposits and incised-valley deposits, in the sequence framework are associated with basin evolution. During the early stage of the Shahezi Formation (SQ1 and SQ2), the sedimentary area was mainly covered by fan deltas, and lacustrine deposits were not very developed. Additionally, incised-valley systems formed on basin margins and subaqueous fans formed along basin-controlled faults. During the middle stage (SQ3), fan delta deposits on gentle slopes were gradually replaced by braided delta deposits, and the sizes of lacustrine facies increased with basin expansion. In the late stage (SQ4), the basin and lacustrine deposit areas reached their maximum sizes, and braided deltas became the dominant sedimentary systems on gentle slopes. With continuous sediment supply, fan and braided deltas migrated forward, and the lacustrine system was locally distributed. In this small-scale faulted basin, the lacustrine mudstones and coal seams widely developed in SQ4, especially in SQ4-HST, and they also exhibited good source rock properties for gas generation. Sandbodies of fan deltas and braided deltas in the upper Shahezi Formation, exhibiting good contact relationships with underlying source rocks, can be favourable reservoirs for hydrocarbon accumulation, as confirmed by the newly drilled Well Songs9H (with a daily gas production of 20×104 m3). However, due to low porosity and permeability (averages of 4.7% and 0.28×10−3µm2, respectively), these reservoirs may need fracturing for commercial hydrocarbon production.

A basin modeling study of the Jafurah Sub-Basin, Saudi Arabia: Implications for unconventional hydrocarbon potential of the Jurassic Tuwaiq Mountain Formation

The Middle-Upper Jurassic organic-rich carbonate mudrocks of the Tuwaiq Mountain Formation in the Jafurah Sub-Basin of the Central Arabian Basin have long been recognized as the source of hydrocarbons trapped primarily in Upper Jurassic carbonate reservoirs of Saudi Arabia (e.g., Giant Ghawar Field). With the recent development of commercial hydrocarbon production from unconventional reservoirs in North America, these organic-rich, carbonate mudrocks are now recognized as potential shale-gas and shale oil plays.Three conventional source rock intervals (the Tuwaiq Mountain (TQMN), Hanifa and Jubaila Formations) exist within the Jurassic petroleum system of the Jafurah Sub-Basin. The TQMN formation is being evaluated for shale-gas and shale-oil potential by Saudi Aramco because the TQMN Fm. holds excellent unconventional gas characteristics, such as high total organic carbon content (TOC) and low clay content, and proper maturity window for oil and gas generation.Five wells, representing the first unconventional gas exploration wells drilled in the Jafurah Sub-Basin have been selected for 1D and 2D basin modeling work. The work was performed to investigate the burial and thermal maturity evolution of the TQMN Formation in the Jafurah Sub-Basin. The maturity of the TQMN Formation in the study wells varies from 0.8 to 1.25%VRE (covering peak oil to wet gas generation stage), despite only slight differences in present-day burial depths. The present day temperature gradients have been calculated to be higher at well locations where the source rock is at higher maturity. Modeling results suggest that higher temperature gradient areas of the basin probably has higher basement heat flow which leads to satisfactory match between measured and predicted maturity and temperature at present day. This increased basement heat flow in areas of higher temperature gradient correspond to the interpreted change in crustal composition (most likely granitic basement) generating more radiogenic heat.The modeling results suggest that TQMN source rocks started generating oil at about 100Ma and they reached the peak oil generation at about 70Ma. Present-day they are in the wet-gas generation window in the northern and eastern parts of the Jafurah Sub-Basin, where the thermal gradients are >28°C/km or higher. The central and southwestern parts of the Sub-Basin are cooler, and here, the TQMN source rocks are within the peak oil generation window. The warmer parts of the Sub-Basin have higher shale-gas potential compared to the cooler parts of the Basin. We note that proper modeling and estimation of gas content in these source rocks, and probably in unconventional resource estimation work in general, some skilled modifications in basin modeling parameters are necessary. Variation of the oil saturation threshold is necessary until a gas saturation level equal to or higher than the gas adsorption capacity of the source rock is obtained, otherwise, modeling will lead to overestimation of the oil migration out of the source rock and thus the amount of the oil that can be retained and cracked to gas at higher temperatures will be miscalculated. Therefore, the eventual gas content estimations will may be severely underestimated.Following our basin modeling study, we note that improvement of the present day subsurface temperature data will be necessary in the future to estimate the maturity and shale-gas potential of the TQMN source rocks in the Jafurah Sub-Basin.

Evaluation of Gas Reservoir of the Meghna Gas Field, Bangladesh Using Wireline Log Interpretation

The gas reservoir from the well Bakhrabad-09 of the Meghna Gas Field, Bangladesh was evaluated in this study in order to appraise the qualities of the reservoir based on quantitative analysis of petrophysical parameters. Among 24 permeable zones, two zones were gas-bearing and rests were water-bearing zones which identified in the study well. Relatively high resistivity, high SP log, low gamma ray log, very low neutron and low density log responses indicate hydrocarbon type might be gas-bearing zones than that of water-bearing zones. The shale volume of those zones ranged from average 21% to 22 % indicated that shaly sand dominating lithology and less affect the water saturation values in the gas reservoir. The average porosity of these zones ranged from 31% to 34 % which was within the limit for good hydrocarbon accumulation. Three saturation equations were used to evaluate the water saturation which was converted to gas saturation. The average gas saturation values of these zones were more than 60 % indicate high hydrocarbon accumulation. The average permeability of these zones ranged from 42.5 md to 50 md respectively which was within ranged for commercial gas accumulation. Average bulk volume of water ranged from 0.045 to 0.053 was shown that the reservoir consist of mainly fine to very fine grained sandstone and more or less at irreducible water state. It can be concluded that gas reservoir are good qualities for commercial hydrocarbon accumulation and production. erroneous values for water saturation and porosity in the presence of shale effect. The determinations of reservoir quality and formation evaluation processes are largely depend on quantitative evaluation of petrophysical analysis. Petrophysical analysis of gas reservoir of different gas field was carried out by Islam et al. (3-7) in Bengal Basin, Bangladesh. Rahman et al. (8) was carried out the analysis of reservoir sand of Titas-15 well using well log interpretation. In this regard, the study was focused on the gas reservoir evaluation in the well Bakhrabad-09 of Meghna Gas Field, Bangladesh using wireline log interpretation. The objective of the study is to identify the gas zones of reservoir using composite log responses and to determine petrophysical parameters of the gas reservoir of the Meghna Gas Field, Bangladesh. It is located in Bancharampur upzila under Brahmanbaria District some 40 km away of northern most east direction from capital city of Dhaka, Bangladesh. Meghna Gas Field was discovered by BAPEX in 1990 (9) (Figure 1).

Morphology, Genesis, and Distribution of Nanometer-Scale Pores in Siliceous Mudstones of the Mississippian Barnett Shale

Research on mudrock attributes has increased dramatically since shale-gas systems have become commercial hydrocarbon production targets. One of the most significant research questions now being asked focuses on the nature of the pore system in these mudrocks. Our work on siliceous mudstones from the Mississippian Barnett Shale of the Fort Worth Basin, Texas, shows that the pores in these rocks are dominantly nanometer in scale (nanopores). We used scanning electron microscopy to characterize Barnett pores from a number of cores and have imaged pores as small as 5 nm. Key to our success in imaging these nanopores is the use of Ar-ion-beam milling; this methodology provides flat surfaces that lack topography related to differential hardness and are fundamental for high-magnification imaging. Nanopores are observed in three main modes of occurrence. Most pores are found in grains of organic matter as intraparticle pores; many of these grains contain hundreds of pores. Intraparticle organic nanopores most commonly have irregular, bubblelike, elliptical cross sections and range between 5 and 750 nm with the median nanopore size for all grains being approximately 100 nm. Internal porosities of up to 20.2% have been measured for whole grains of organic matter based on point-count data from scanning electron microscopy analysis. These nanopores in the organic matter are the predominant pore type in the Barnett mudstones and they are related to thermal maturation. Nanopores are also found in bedding-parallel, wispy, organic-rich laminae as intraparticle pores in organic grains and as interparticle pores between organic matter, but this mode is not common. Although less abundant, nanopores are also locally present in fine-grained matrix areas unassociated with organic matter and as nano- to microintercrystalline pores in pyrite framboids. Intraparticle organic nanopores and pyrite-framboid intercrystalline pores contribute to gas storage in Barnett mudstones. We postulate that permeability pathways within the Barnett mudstones are along bedding-parallel layers of organic matter or a mesh network of organic matter flakes because this material contains the most pores.

Preventive Diplomacy and Pro‑Activity in the South China Sea

Introduction The dispute concerning sovereignty over the Spratly Islands and maritime jurisdiction in the South China Sea remains the most volatile, dangerous, and intractable issue in ocean affairs today. It is also the most discussed, although a great deal of what has been said on the subject is of questionable value, mainly because of the inability of analysts to appreciate or deal with the full complexity of the topic. To some extent, this is understandable or even excusable, but only up to a point. The debate cannot flourish while commentators cling doggedly to one view of the issue - their own - and do their best to dismiss or discount the views of others. Law of the Sea experts, for instance, persist in viewing the issue as one which requires the steady application of the rules of international law. Proponents of realpolitik are apt to dismiss such an approach as idealistic, at best. For them, might may not be right, but is of more consequence than legal norms or arguments hammered out in the security of a research office. And so on. To some extent, the problem lies in the different views of commentators as to what the dispute in the South China Sea is actually about. The common view, of course, is that oil is the ultimate prize, with maritime hegemony/dominance and national pride thrown in for good measure. There has been very little discussion as to the merits or value of these views; indeed, recent scholarship has (wittingly or otherwise) tended to support the oil lobby, if support it needs.(1) The very scale and complexity of the issues arising here is also daunting, but the problem is exacerbated by a failure to undertake a structured analysis. For instance, much ink has been spilt on the vexed issue of who owns the Spratlys?, while there has been little consideration of whether the answer really matters - for example, there is an assumption that the key to the dispute lies in the resolution of sovereignty over those islands. But such a contention would be absurd in any other marine area: no-one has suggested that the key to maritime jurisdiction in the Mediterranean lies in sovereignty over Corsica, Malta and Cyprus, and any one of these has a land area very much greater than all the Spratlys put together. Much is made of the potential of the Spratly area for the commercial production of hydrocarbons, but on what evidence? The focus of much of the debate has been on these two issues. But since the first is of greatly exaggerated importance, and the second largely a matter for speculation, it is hardly surprising that much of the literature is simply unhelpful, and is apt to miss the point. There has generally been a failure to question basic assumptions and to allow the protagonists - or the most vocal of them - to drive and set the terms and conditions of the debate. This article will argue that mono-disciplinarity - indeed, the contumacious disregard for the relevance of other points of view - vitiates much of the commentary and analysis of the situation in the South China Sea. It will offer a synopsis of developments in the South China Sea. The focus will to some extent be on the informal workshops that have attended attempts to resolve the disputes in that sea. It also looks at bilateral efforts, as well as the work of multilateral fora in reaching such a resolution. The starting point for the inquiry must be the international Law of the Sea, for it is that law which invests states with the very rights (and duties) over their adjacent ocean-space which are so fiercely contested between them. Claims and Counter-Claims This is not the place for a discussion of the rival claims and counterclaims either to the Spratly or Paracel Islands, or to the waters of the South China Sea; these issues have been discussed at length in the literature, though not always helpfully or accurately. The intractable nature of the debate stems from the tenacity with which the littoral states have maintained their respective positions; this is one of the reasons why discussion of issues of sovereignty and jurisdiction is prohibited at South China Sea Workshop meetings. …

Exploiting the Self-Sourcing Cane Creek Zone of the Paradox Formation with Horizontal Wells

The Cane Creek zone of the Paradox Formation produces oil and gas from fracture-induced permeability and porosity in the Big Flat/Lisbon area of the Paradox basin. Only one of approximately 110 vertical wildcats has been a commercial Cane Creek success, having recovered more than 900,000 bbl oil. Horizontal drilling significantly improves a wildcat success rate by increasing well-bore contact with near-vertical fractures. Six horizontal Cane Creek wells resulted in three discoveries, each with initial flow rates in excess of 1000 BOPD and potential reserves in excess of 500,000 bbl of oil per well. The Cane Creek Shale is the thickest and most productive of the 29 clastic intervals in the Paradox Formation. The reservoir is self-sourced from interbedded black sapropellic dolomites with up to 28% total organic carbon. Micro- and macrofractures, along with some matrix porosity, contribute to reservoir storage capacity, although the relative importance of each remains undetermined. Matrix permeability is very low. Overlying and underlying salt beds provide very effective seals. Well-bore communication with a network of natural fractures is essential to establishing commercial hydrocarbon production. Silty and sandy carbonates are the most fracture-prone lithofacies. The middle silty carbonate zone of the Cane Creek is the primary targetmore » for horizontal drilling because of the relative thickness of fracture-prone lithologies, the absence of interbedded anhydrites, and the presence of the best source-rock facies.« less

Porosity development in deep sandstones, Taranaki Basin, New Zealand

Reservoir quality in the Taranaki Basin is controlled by both depositional facies and diagenesis. High initial porosities and permeabilities in manyfluvial and littoral sandstones directed fluid flow such that these facies underwater widespread cementation by silica, carbonate and authigenic clays, and later dissolution of carbonates. Current commercial production of hydrocarbons in mainly from secondary, dissolution porosity in sandstones at depths of 1750–3600 m. Recent studies suggest that oil may not be released from terrestrial source rocks in western New Zealand until depths of 5.5 km or more. Knowledge of porosity development at such depths is therefore essential for understanding migration pathways and the controls on hydrocarbon accumulation. Organic species and/or carbon dioxide evolved from kerogen before liquid hydrocarbons are important to the formation of secondary porosity in sandstones by carbonate dissolution. Further, hydrocarbon migration should follow soon after the evolution of these, in order that re-cementation does not occur. High resolution nuclear magnetic resonance (NMR) spectroscopy shows that in western New Zealand basins, the evolution of solvents continues to at least 4 km and may persist almost until the expulsion of liquid hydrocarbons.

THE DEVELOPMENT OF THE HIDES GASFIELD, PAPUA NEW GUINEA

The Hides gasfield was discovered by BP, and its Joint Venture Partner Oil Search Ltd, in Petroleum Prospecting Licence No.27 in Southern Highlands Province in late 1987 by the exploration well Hides-1. The well tested gas at rates of up to 15.9 mmscf/d with small volumes of associated condensate from four separate intervals within the Toro Sandstone.Negotiations with Placer Dome, a Vancouver-based mining company, led to an agreement to sell gas to supply electrical power for the Porgera gold mine in Enga Province 70 km North East from Hides. Approximately 10 mmscf/d of gas will be produced from two wells, one being the original Hides-1 discovery well, via an 8 km pipeline, to a gas processing plant in the nearby Tagari valley. The processed gas will be fed to turbines to generate approximately 42 M W of electrical power which will be fed to the Porgera mine by overhead transmission lines.BP has undertaken technical studies relating to the feasibility of producing the gas from Hides. In association with the technical work BP has also undertaken an environmental study of the impact of development and has embarked upon a survey of various local and land-related issues. It is anticipated that construction operations will start in early 1990, leading to first gas production in mid-1991, only 3½ years after the discovery. The Hides gasfield development will constitute the first commercial hydrocarbon production in PNG.

Oil and gas in Australia

Commercial hydrocarbon production had evaded Australia for a long time. Despite a number of encouraging discoveries during the first half of the century, commercial exploitation was not achieved until 1961, when the Moonie oil field was discovered in eastern Queensland and natural gas delivered for electricity generation to the town of Roma. Additional discoveries followed in quick succession. At the beginning of the 1970ies the basic pattern of oil and gas production had been established but both, adverse political influences and sociological issues severely curtailed exploration and delayed the development of some of the fields by almost 20 years. Discovery rate was reduced but new fields have been found in the Timor Sea, both off- and onshore West Australia, in South Australia and in Queensland.