Hydrocarbon Volumes Research Articles

Seismic tectono-stratigraphy of fluvio-deltaic to deep marine Miocene silicoclastic hydrocarbon reservoir systems in the Gulf of Hammamet, northeastern Tunisia

Most of hydrocarbon accumulations within the Gulf of Hammamet foreland basins in eastern Tunisia are reservoired within the Upper Miocene Birsa and Saouaf sandstones. It is the case of Birsa, Tazarka, Oudna, Baraka, Maamoura, Cosmos and Yasmine fields. These sandstones constitute oil and gas fields located on folded and faulted horst anticline highs and described as varying from shoreface to shallow marine and typically exhibit excellent reservoir quality of 30 to 35% porosity and good permeability from 500 to 1100 md. In addition, the fracturing of faults enhanced their reservoir quality potential. However, due to the lack of seismic stratigraphic studies to highlight depositional environment reservoir characterization and distribution, petroleum exploration faces structural and stratigraphic trap types and remains on targeting only high fold closures with limited reserve volumes of hydrocarbons. As an example of the Birsa concession case, syn-sedimentary tectonic structuring and geodynamic evolution during Middle to Upper Miocene Birsa reservoir sequences have guided the distribution of depositional environment of sandstone channel systems around horst and grabens by E-W, NE-SW and N-S strike slip flower faults controlling the subsidence distribution combined with the eustatic sea level variations. Seismic sequence stratigraphy study of Miocene Birsa reservoir horizons, based on the analysis and interpretations of E-W and N-S 3D selected regional lines that were compared and correlated to outcrops and calibrated by well data, permitted to highlight the basin configuration and sequence deposit nature and distribution. Sedimentary infilling of the basin from Langhian Ain Ghrab carbonate to Serravallian Tortonian Birsa and Saouaf sandstone and shale formations is organized in four third-order seismic sequences, limited by regional erosional toplap, onlap and downlap unconformity surfaces and by remarkable chronostratigraphic horizons of forced and normal erosive lowstand and highstand system tracts separated by transgressive and maximum flooding surfaces. Reconstructed sedimentary paleo-environment distribution vary from deltaic fluvial proximal deposits in the northern part of the high central Birsa horst to a delta front and prodelta coastal and shelf shore face and shore line channelized deposits in the surrounding borders of grabens. Distal deposits seem to be distributed from upper to lower slope fans and probably to the basin floor on the flanks of the subsiding grabens. Synthetic predictive paleogeographic depositional reservoir fairway map distribution of Lower, Middle and Upper Birsa sandstone reservoirs highlights four main domains of channelized superposed and shifted reservoirs to explore.

Defining the 3D geometry of thin shale units in the Sleipner reservoir using seismic attributes

Defining the 3D geometry and internal architecture of reservoirs is important for prediction of hydrocarbon volumes, petroleum production and storage potential. Many reservoirs contain thin shale layers that are below seismic resolution, which act as impermeable and semi-permeable layers within a reservoir. Predicting the storage volume of a reservoir with thin shale layers from conventional seismic data is an issue due to limited seismic resolution. Further, gas chimneys indicative of gas migration pathways through thin shale layers, are not easily defined by conventional seismic data. Additional information, such as borehole data, can be used to aid mapping of shale layers, but making lateral predictions from 1D borehole data has high uncertainty. This paper presents an integrated workflow for quantitative seismic interpretation of thin shale layers and gas chimneys in the Utsira Formation of the Sleipner reservoir. The workflow combines the use of attribute and spectral analysis to add resolution to conventional seismic amplitude data. Detailed interpretation of these analyses reveals the reservoirs internal thin shale architecture, and the presence of gas chimneys. The comprehensive interpretation of the reservoirs internal structure is used to calculate a new reservoir storage volume. This is done based on the distribution of sand and interpreted shale layers within the study area, for this active CO2 storage site.

Hydrocarbon volume optimization using improved net-to-gross estimates through core-log calibration of the “Akar field,” Niger Delta

Net to gross (NTG) is an important parameter in evaluating the volumes of hydrocarbon in place (VHIP) in reservoirs, and proper evaluation of this parameter will lead to significant accuracy in the estimated reserves. The use of conventional petrophysical log evaluations often does not provide sufficient resolution for net sand analysis of reservoirs, especially in laminated reservoir rocks. The uncertainties associated with log-derived net-to-gross estimates arise from the petrophysical shale volume (Vsh) cutoffs used in deriving the net sand count over a reservoir interval. One way of improving the net-to-gross estimates is by using a model that calibrates log-derived net to gross to a core equivalent, which is the more accurate representation of net sand counts. In this study, a model for calibrating log-derived net to gross to a core equivalent based on genetic units and facies associations of reservoir rocks in three wells (wells 7, 36, and K008) was established. Ultraviolet core photographs show a good contrast between hydrocarbon-stained sandstones and shales, and combining it with white light-slabbed core images facilitated a manual net sand count of the core photographs on a bed-by-bed basis. Petrophysical shale volume (Vsh) cutoff derived from two volumes of shale indicators was applied to generate net sand counts, which were used to get log-derived net-to-gross values. Then, the net to gross from core images and petrophysical clay volume (Vsh) analysis were compared by facies associations, and this comparison yielded a reliable core-calibrated net-to-gross model, which reduces the uncertainties in net-to-gross values estimated from Vsh cutoffs. The results show that for the distributary channel sands, net to gross derived using Vsh cutoff results in an underestimation of net to gross by about 6–10 % when compared with the core-calibrated net to gross, while for the upper shoreface units, Vsh cutoff overestimates net to gross by about 7–10 % when compared to its core-calibrated equivalent.

Fracking in Tight Shales: What Is It, What Does It Accomplish, and What Are Its Consequences?

Fracking is a popular term referring to hydraulic fracturing when it is used to extract hydrocarbons. We distinguish between low-volume traditional fracking and the high-volume modern fracking used to recover large volumes of hydrocarbons from shales. Shales are fine-grained rocks with low granular permeabilities. During the formation of oil and gas, large fluid pressures are generated. These pressures result in natural fracking, and the resulting fracture permeability allows oil and gas to escape, reducing the fluid pressures. These fractures may subsequently be sealed by mineral deposition, resulting in tight shale formations. The objective of modern fracking is to reopen these fractures and/or create new fractures on a wide range of scales. Modern fracking has had a major impact on the availability of oil and gas globally; however, there are serious environmental objections to modern fracking, which should be weighed carefully against its benefits.

NEW DATA ON ZEOLITE MINERALIZATION IN THE WEST SIBERIAN PLATE RESERVOIR ROCKS

The paper reviews the new data on the secondary zeolite mineralization characteristics for the Lower Cretaceous deposits of the West Siberian plate north. The authors suggest that the zone of distribution of altered rocks is much wider and in addition covers the area of Russkoye field. A new method of accounting of the volume of minerals of the zeolite group is proposed based on using the value of the volume fraction content of zeolites, which allows for a more qualitative approach to calculation of volumes of hydrocarbons in this type of reservoirs. It is shown that in major foreign deposits, complicated by the zeolitization processes, in order to improve the performance of the bottom-hole zone it is recommended to use a solution of hydrochloric acid.

Prioritization of sites for sediment remedial action at Randle Reef, Hamilton Harbour

Hamilton Harbour, an enclosed embayment at the western end of Lake Ontario, was designated as an Area of Concern in 1985 under the Great Lakes Water Quality Initiative. The harbour has been disturbed by wastes from steel industries, municipal wastewater discharges, and urban runoff. The area of the harbour known as Randle Reef has the largest volume of polycyclic aromatic hydrocarbon contaminated sediment on the Great Lakes and will be undergoing a major remediation project. An engineered containment facility will be constructed on top of the most contaminated sediment and surrounding sediments will be dredged and placed inside the engineered containment facility, or capped. To determine where remediation was required, areas were prioritized according to toxicity and contaminant concentrations. Although benthic invertebrate community assessment can be the best indicator of in situ toxicity, this was problematic in the harbour due to lack of appropriate reference areas for comparison and potential effects of other stressors (e.g. disturbances of sediments from ship traffic, seasonal low hypolimnetic oxygen concentrations). Initial prioritization of areas for remediation was therefore based on toxicity to benthic invertebrates and the associated contaminant levels. In 2002, 80 sites were sampled and laboratory bioassays conducted with the Amphipod Hyalella azteca and the Mayfly Hexagenia spp. Initial site prioritizations were established based on: (1) high contamination and toxicity; (2) high contamination and no/low toxicity; (3) low contamination and toxicity; and (4) low contamination and no toxicity. Final prioritizations considered study design and area considerations as well as additional sediment data obtained to address data gaps. Of the 80 sites, 79% were classed in a priority subgroup, while remaining sites were deemed non-priority.

BURIAL AND THERMAL HISTORY MODELLING OF THE MANNAR BASIN, OFFSHORE SRI LANKA

The Mannar Basin is a Late Jurassic – Neogene rift basin located in the Gulf of Mannar between India and Sri Lanka which developed during the break‐up of Gondwana. Water depths in the Gulf of Mannar are up to about 3000 m. The stratigraphy is about 4 km thick in the north of the Mannar Basin and more than 6 km thick in the south. The occurrence of an active petroleum system in the basin was confirmed in 2011 by two natural gas discoveries following the drilling of the Dorado and Barracuda wells, located in the Sri Lankan part of the Gulf. However potential hydrocarbon source rocks have not been recorded by any of the wells so far drilled, and the petroleum system is poorly known. In this study, basin modelling techniques and measured vitrinite reflectance data were used to reconstruct the thermal and burial history of the northern part of the Mannar Basin along a 2D profile.Bottom‐hole temperature measurements indicate that the present‐day geothermal gradient in the northern Mannar Basin is around 24.4 oC/km. Optimised present‐day heat flows in the northern part of the Mannar Basin are 30–40 mW/m2. The heat flow histories at the Pearl‐1 and Dorado‐North well locations were modelled using SIGMA‐2D software, assuming similar patterns of heat flow history. Maximum heat flows at the end of rifting (Maastrichtian) were estimated to be about 68–71 mW/m2.Maturity modelling places the Jurassic and/or Lower Cretaceous interval in the oil and gas generation windows, and source rocks of this age therefore probably generated the thermogenic gas found at the Dorado and Barracuda wells. If the source rocks are organic‐rich and oil‐ and gas‐prone, they may have generated economic volumes of hydrocarbons.

Source rock characterisation of under-explored regions of Queensland

Historically, petroleum exploration in Queensland has focused on the Bowen-Surat and Cooper-Eromanga basins, with only cursory examination of other basins across the state. As part of the Queensland Industry Priorities Initiative, two projects (Round 1 and 2) were submitted to the Geological Survey of Queensland (GSQ) to examine the geochemical characteristics of potential petroleum source rocks throughout Queensland. The analysis conducted provides a better understanding of generative potential for petroleum, and predicts the timing, volume, composition, and physical state of hydrocarbons retained in and expelled from source rocks. It is an integral component to petroleum systems analysis used to identify the potential for undiscovered accumulations of petroleum from conventional and unconventional reservoirs. Of particular interest were the Georgina, Drummond, Eromanga, and Maryborough basins. Of these, the Georgina and Maryborough basins have known hydrocarbon shows identified through exploration drilling, though no commercial discoveries have yet been made. The Drummond Basin was targeted to identify a potential source for oil and gas shows encountered in drilling within the Galilee Basin. The Toolebuc Formation in the Eromanga Basin has been noted as having the potential for a shale oil play and this study is supporting further assessment to identify optimal areas for future exploration through predictive modelling. This report details the results from Round 1 of the study for samples taken from the Georgina Limestone and Scartwater, Ducabrook, Mount Hall, Toolebuc, and Maryborough formations, where limited analysis of source rock characteristics has historically been undertaken. Ninety-seven samples were chosen from nine wells and sent to Geos4 in Potsdam, Germany, for source rock analysis. All samples were screened for suitability of further analysis using Rock-Eval and TOC by LECO, with immature and organic-rich samples being preferentially selected for further testing. Screened samples were analysed using pyrolysis gas chromatography (n=27), thermovaporisation (n=23), bulk kinetics (n=5), compositional kinetics (n=4), late gas analysis (n=14), and biomarker and bulk isotope analysis (n=15). These results have been integrated with existing analyses to better understand the prospectivity of the under-explored basins of Queensland.

Evaluation on occluded hydrocarbon in deep–ultra deep ancient source rocks and its cracked gas resources

Oil-cracked gas, as the main type of high-over mature marine natural gas in China, is mainly derived from occluded hydrocarbon. So it is significant to carry out quantitative study on occluded hydrocarbon. In this paper, the occluded hydrocarbon volume of the main basins in China was calculated depending on their types, abundances and evolution stages by means of the forward method (experimental simulation) and the inversion method (geologic profile dissection). And then, occluded hydrocarbon evolution models were established for five types of source rocks (sapropelic, sapropelic prone hybrid, humic prone hybrid, humic and coal). It is shown that the hydrocarbon expulsion efficiency of sapropelic and sapropelic prone hybrid excellent source rocks is lower than 30% at the low-maturity stage, 30%–60% at the principal oil generation stage, and 50%–80% at the high-maturity stage, which are all about 10% higher than that of humic prone hybrid and humic source rocks at the corresponding stages. The resource distribution and cracked gas expulsion of occluded hydrocarbon since the high-maturity stage of marine source rocks in the Sichuan Basin were preliminarily calculated on the basis of the evolution models. The cracked gas expulsion is 230.4 × 1012 m3 at the high evolution stage of occluded hydrocarbon of the Lower Cambrian Qiongzhusi Fm in this basin, and 12.3 × 1012 m3 from the source rocks of Sinian Doushantuo Fm, indicating good potential for natural gas resources. It is indicated that the favorable areas of occluded hydrocarbon cracked gas in the Qiongzhusi Fm source rocks in the Sichuan Basin include Gaoshiti–Moxi, Ziyang and Weiyuan, covering a favorable area of 4.3 × 104 km2.

Case Study: Completion-Design Optimization for Barnett Oil-Producing Area

Summary Throughout the past several years, economic and technological advancements in the North American shale market with respect to drilling and hydraulic-fracturing operations have helped create a “typical” operating scheme for producing from the multiple shale-formation reservoirs currently being exploited. This typical scheme focuses on operational efficiency and cost reduction to drive profitability in these markets. Although operational efficiency and effective cost control have led to more-profitable operations in these shale reservoirs, the unknowns regarding the subsurface of these highly complex formations can often create situations of operating without sufficient information to optimally design drilling-and-completions strategies to produce larger volumes of hydrocarbon from the reservoir. Opposed to conventional operations, the amount of basin and asset knowledge being collected and developed in most of these shale plays is much lower, and thus can result in poor development decisions, leading to less than optimum economic performance. Focus on subsurface knowledge as well as collaboration between the various aspects of developing an asset is essential to helping discover and produce more oil and gas from these complex reservoir systems. This paper examines a case study of three wells in Wise County, Texas, in the Barnett shale, where a collaborative subsurface insight investigation and a drilling-and-completions optimization process were used to illustrate the production benefit achieved through improved reservoir understanding. Within this process, an asset Earth model was created with the collected information from wireline logging, logging while drilling, core testing, mechanical rock and fluid properties, formation mineralogy, and wellbore-image logging. In addition, for the completions-design strategy, microseismic measurement and image-log fracture matching and complex-fracture modeling software tools were used to define and model the growth of the stimulated fracture network during hydraulic-fracturing completions. This paper presents an overview of “typical” previous completions and subsurface information collected before implementation of the new process in comparison to changes made to the drilling-and-completions designs used on three wells, as well as an overview of the types of information collected to supply the Earth model. Examples of the fracture matching and complex-fracture modeling for the wells help illustrate the design and optimization of hydraulic-fracturing treatments in a complex shale reservoir. Finally, a production-results comparison is presented to illustrate a significant increase to production of hydrocarbon through better reservoir understanding and drilling-and-completion designs.

Petroleum potential and kinetic models for hydrocarbon generation from the Upper Cretaceous to Paleogene Latrobe Group coals and shales in the Gippsland Basin, Australia

Pyrolysis experiments (open and closed systems) and kinetic modelling of primary cracking of kerogen have been carried out to investigate hydrocarbon generation characteristics and source rock facies variability within the Upper Cretaceous to Paleogene Latrobe Group in the Gippsland Basin. On the basis of Rock-Eval data, the interbedded coals, coaly shales and carbonaceous shales contain different types of kerogen (Type III, Type II–III, Type II) with variable potential for both gas and liquid hydrocarbon generation. Open system pyrolysis–gas chromatography data indicate that the organically lean marginal marine shales of the Santonian–early Campanian Tricolporites apoxyexinus and Nothofagidites senectus biozones produce gas and condensate. However, coal and coaly to carbonaceous shales sampled from the Paleocene Lygistepollenites balmei, Maastrichtian Forcipites longus, late Campanian Tricolporites lilliei and Turonian Phyllocladidites mawsonii palynological biozones are heterogeneous with the capacity to generate both low and high wax paraffinic–naphthenic–aromatic (P–N–A) oils, and paraffinic oils with a high wax content. The main phase of petroleum formation from these later biozones, assuming a constant geological heating rate of 3.3°C/Ma, is predicted to occur between 150–179°C, indicating different orders of kinetic stability as a result of different types of organic matter and their state of preservation. The thermally immature shales have variable bulk kinetic characteristics, but the measured compositional kinetics and phase behaviour show that they have the potential to generate black oils at early stages of kerogen cracking, and either light oils or wet gases at higher levels of thermal stress. These findings suggest that upon thermal maturation, the interbedded shales of the Latrobe Group may have contributed significant volumes of hydrocarbons to the oil and gas accumulations in the Gippsland Basin. In addition, this study not only supports the premise that over-reliance on Rock-Eval/TOC data alone can be misleading for assessment of petroleum generation, but also represents a strategy for kerogen type and generative potential determination for fluvio-deltaic coals and subordinate lithologies.

INTEGRATED ANALYSIS AND TOOLS FOR LAND SUBSIDENCE SURVEYING AND MONITORING: A SEMI-QUANTITATIVE APPROACH

Abstract. This paper presents an integrated approach for land subsidence monitoring using measures coming from different sensors. Eni S.p.A., the main Italian oil and gas company, constantly surveys the land with all the state of the art and innovative techniques, and a method able to integrate the results is an important and actual topic. Nowadays the world is a multi-sensor platform, and measure integration is strictly necessary. Combining the different data sources should be done in a clever way, taking advantages from the best performances of each technique. An integrated analysis allows the interpretation of simultaneous temporal series of data, coming from different sources, and try to separate subsidence contributions. With this purpose Exelis VIS in collaboration with Eni S.p.A. customize PISAV (Permanent Interferometric Scatterometer Analysis and Visualization), an ENVI extension able to capitalize on and combine all the different data collected in the surveys. In this article are presented some significant examples to show the potential of this tool in oil and gas activity: a hydrocarbon storage field where the comparison between SAR and production volumes emphasise a correlation between the two measures in few steps; and a hydrocarbon production field with the Satellite Survey Unit (S.S.U.), where SAR, CGPS, piezometers and assestimeters measure in the same area at the same time, giving the opportunity to analyse data contextually. In the integrated analysis performed with PISAV not always a mathematical rigorous study is possible, and a semi-quantitative approach is the only method for results interpretation. As a result, in the first test case strong correlation between injected hydrocarbon volume and vertical displacement were highlighted; in the second one the integrated analysis has different advantages in monitoring the land subsidence: permits a first qualitative “differentiation” of the natural and anthropic component of subsidence, and also gives more reliability and coverage to each measurement, taking advantages from the strong points of each technique.

EL CAMPO PETROLERO CANTARELL Y LA ECONOMÍA MEXICANA

Major oil fields have played an essential role in the global hydrocarbon supply, but the majority are now in decline. The Cantarell macro-reserve has produced significant volumes of hydrocarbons and brought countless benefits to the country, but starting in 2004, the exhaustion of the Cantarell supply began to affect the oil production platform. This research studies all of the factors that have had an impact on the performance of this macro-reserve, which are fundamental to explain the current state of affairs. The conclusion is that the management of the Cantarell oil field was less than optimal during the three time periods identified in the paper, as decisions were made on a non-technical basis, which contributed to the decline and the series of challenges facing the oil complex today. These difficulties could, in turn, be mitigated through the use of technology.

Prospectivity evaluation with 3D CSEM

Evaluation of the prospectivity potential of hydrocarbon exploration ventures is a process of integration. Information provided by different technologies needs to be integrated into a single evaluation. This paper details a method for embedding the additional information provided by 3D Controlled Source Electromagnetic (CSEM) surveys into existing (or independently generated) prospect evaluations. Workflows are designed to leverage the primary value of the CSEM information in exploration (sensitivity to hydrocarbon volume), while minimizing the disruption and potential increase in risk associated with the adoption of a new technology. This is achieved through a focus on maintaining the independence of information sources and visibility of measurement uncertainties, along with adoption of standard performance-tracking methodologies. Previously-described workflows for embedding CSEM information in a prospect evaluation process (e.g., Buland et al., 2011; Baltar and Roth, 2013) focus either on updates to the Probability of Success (PoS), or volume assessment. In contrast, we show that the nature of the information provided by CSEM is more suited to a coupled reassessment of both risk and volumes. This generates a more robust update not prone to the shortcomings associated with existing stand-alone approaches. Workflows are illustrated with the use of realistic synthetic examples; a published prediction using the methodology is also reviewed in light of recent drilling results. When applied systematically across a CSEM-sensitive portfolio, the new information provided by 3D CSEM has the effect of polarising existing evaluations, making CSEM a valuable tool in exploration venture evaluation.

Recognizing pitfalls of seismic structure and amplitude anomalies in Osprey field, Brunei

The Osprey gas field was discovered in 1975 in the western offshore area of Brunei Darussalam. Two discovery wells penetrate the hanging wall of two separate growth faults and are associated with bright seismic amplitudes. Multiple thin reservoirs are separated by shales of 10 to a few hundred meters in thickness. In addition to seismic tuning of thin layers, there are many shallow gas clouds above these reservoirs, which cause significant and varying amount of push-down in seismic time data. Visualizing as seismic depth data reduces the amount of push-down but doesn’t remove it totally because, to date, the velocity model has been neither detailed nor accurate enough to fully constrain the seismic processing. Time-to-depth conversion includes significant uncertainties in the reservoir time interpretation, with only one well control per fault block. The shallow gas clouds also cause severe amplitude distortion at reservoir levels in the time and depth data, resulting in difficulties for discriminating gas distribution from stratigraphic variations or tuning effects. Furthermore, the shallow gas clouds cause false or enhanced rollover structures and artificial fault features adjacent to expressions of “real” features in the seismic data. Thus, estimates of reservoir spatial distribution and hydrocarbon volumes have large uncertainties. Recognizing these structure and amplitude pitfalls and handling them properly are important to improve reservoir understanding and volumetric estimations and to optimize development of the field. We have uncovered a variety of pitfalls and developed some mitigation methods. One method uses the seismic flat spot to correct the gas push-down effect, and the check-shot velocity was adjusted accordingly. This led to reduced uncertainty in the reservoir depth prognosis of the planned wells. Four wells were drilled in 2014, and the actual depth in all wells came out within only a 4-m difference, validating the correction method for shallow gas push-downs.

Mineral-chemistry quantification and petrophysical calibration for multimineral evaluations: A nonlinear approach

The mineralogical complexity of mudstone reservoirs has led to the increased usage of multimineral optimizing petrophysical models for estimating porosity, water, and hydrocarbon volumes. A key uncertainty in these models is the log response parameter assigned for each log equation related to each volumetric variable. Default parameter values are commonly used and often need to be modified by considering subjective local knowledge or intuition to achieve a result that is considered acceptable. This paper describes the methods developed at Chevron for calibration of mineral log response parameters using core data. Mineral log response parameters are controlled by the major and trace element chemistry of the individual minerals in the formation rock matrix. BestRock™ uses a nonlinear approach to optimize whole-rock chemistry with mineralogy to calculate individual mineral structural formulas and trace element associations from which certain log response parameters can then be calculated. Accurate quantitative phase analysis (QPA) to determine mineral content is a critical step in the process, which is achieved here by rigorous sample preparation methods and QPA by x-ray diffraction (QXRD). The QXRD in combination with whole-rock elemental analyses are processed using Chevron’s BestRock optimization software to provide refined quantities of the mineral species present in the formation, their structural formulas, and their predicted wireline log responses. Calibrated petrophysical models are built from the information obtained from the QXRD and BestRock results. The method described herein provides an independent and robust method for determining petrophysical parameters that is independent of the interpreter, quick to implement, and supported by quantitative measurements.

Sea Lion Field discovery and appraisal: a turning point for the North Falkland Basin

In 1998, the first six wells were drilled in the North Falkland Basin, and demonstrated the presence of excellent source rock and good reservoirs. Oil and gas shows were encountered in all but one well; however, no commercial volumes of hydrocarbons were proven. At that time, the focus of exploration was almost exclusively on traditional structural traps mapped on two-dimensional (2D) seismic surveys. Eleven years later, in May 2010, Rockhopper Exploration discovered the Sea Lion Field, which has over a billion barrels of estimated oil in place. Discovery well 14/10-2 was drilled on three-dimensional (3D) seismic data acquired by Rockhopper in 2007. Unlike the targets of the first campaign, the Sea Lion prospect was a stratigraphic trap imaged as a series of fan-shaped amplitude anomalies. Following a successful drill stem test of the SL10 and SL20 fans in the discovery well, Rockhopper embarked on an aggressive field appraisal and exploration drilling programme in the Sea Lion area. A second fully engineered production test was successfully performed on a later well to establish commercial flow rates. In addition to appraising the Sea Lion reservoirs, a further three hydrocarbon-bearing reservoirs were proven (Casper, Casper South and Beverley). Comprehensive data acquisition and analysis has been key to de-risking the first commercial development in the basin. A full suite of wireline logs was run in all the appraisal wells; seven wells were extensively cored and fluid samples were recovered for analysis from all reservoirs. In parallel with the drilling campaign, in 2010–11 a total of 4500 km 2 of 3D seismic data was acquired and processed in a collaborative programme with Argos and Desire. In 2012, Premier Oil farmed-in to the licence and assumed operatorship with 60% equity. Dynamic modelling indicates that estimated resources of approximately 160 million barrels (160 mmbbl) can be recovered from the north-east flank of the field based on a Floating Production, Storage and Offloading (FPSO) facilities concept for Phase 1 of the field development. The concepts for additional phases of field development are currently being evaluated.

Petrophysical analysis and hydrocarbon potentialities of the untested Middle Miocene Sidri and Baba sandstone of Belayim Formation, Badri field, Gulf of Suez, Egypt

All over the Gulf of Suez, the Miocene sediments seem to have a very important role in oil accumulation. Badri field is one of the most prolific places in the Gulf of Suez which locates in the southern part of the gulf. Presence of sandstone streaks in the Sidri and Baba Members within Belayim Formation which belongs to the Middle Miocene (Serravallian) age in some wells within this field of relatively high resistivity signature in Electric logs is the main reason to investigate its petrophysical parameters to delineate the main characterization of these sands and to evaluate their ability for hydrocarbon accumulation and production. These members lie between two productive sandstone zones; Kareem Formation and Hammam Faraun Member. They can be a e good promising reservoir with hydrocarbon potentiality which will be added to the Egyptian oil production. A petrophysical analysis of these sandstone zones was undertaken using the electric logs and subsurface geologic data to obtain information about the main reservoir characteristics of the studied sandstones. This study revealed that six wells contain hydrocarbon accumulation within these two members. Petrophysical analysis of the electrical logs (Resistivity, Density-Neutron, Sonic and Gamma-Ray) of Sidri and Baba (S.S.) Members reveals that the shale volume, effective porosity, water saturation, hydrocarbon saturation, and net-pay thickness, are varying between 6 to 18%, 12 to 22%, 18 to 38%, 62 to 82%, and 17 to 37 feet respectively. The type of the present fluids in this reservoir are oil and gas. The hydrocarbon potential of the study area was evaluated through the vertical and the lateral distribution of the petrophysical parameters and hydrocarbon occurrence. The lateral distribution was studied and explained in the form of iso-parametric maps (effective thickness, shale content, effective porosity and hydrocarbon saturation), while the vertical distribution of petrophysical characteristics was studied and explained in the form of litho-saturation crossplots. Also, the hydrocarbon volume was calculated in these zones. All these analyses were performed for Sidri sandstone as one unit and for Baba Sandstone as another unit.From the previously mentioned results the following recommendations should be noteworthy: 1 – BDR-A9 and BDR-A16 wells for the Baba (S.S.) Member and BDR-C14 and BDR-D8A wells for the Sidri Sandstones Member should be perforated, these zones were proved to be oil bearing formations. 2 – BDR (A8) well for the Baba sandstone and BDR (B9) for the Sidri sandstone should be perforated which were proven to be gas zones. 3 – Re-evaluation of all wells in Badri field that were correlated with these studied sandy facies should be performed.

Building a Career in Reserves Estimation

Discover a Career The substantial reduction in global oil prices has put the oil and gas community in a challenging and yet vaguely familiar position. It is once again reminded of the effect oil and gas prices have on companies working to profitably exploit these resources. When there are changes in prices, reserves estimation can dictate the profitability an operator can ultimately obtain. Larry Mizzau, principal for reserves and resources governance at Cenovus Energy reflects on his 30-plus years of experience in the industry and shares his thoughts on how commodity prices impact operators, reserves consultants, and young professionals (YPs) looking to establish a career in reserves estimation. What is reserves estimation? Reserves estimation is a key step in understanding an oil and gas company’s resource base and the opportunities it affords. It is found at the crossroads between asset management and financial stewardship. It involves the estimation of remaining volumes of hydrocarbons economically recoverable from an oil and gas operator’s subsurface assets using current technology. Given that reserves exist deep in the ground, they cannot be determined with absolute certainty and, as such, can only be estimated. To assist investors in understanding this uncertainty, reserves estimates are typically determined at different confidence levels. In Canada and the United States, public operating companies must disclose an updated estimate of their remaining oil and gas reserves on a yearly basis as part of their yearend financial reporting. Specifically in Canada, operators are required to disclose assessments prepared or audited by independent qualified reserves evaluators (IQREs) who can be externally or internally retained by the company.

DETERMINATION OF GAS ACCUMULATIVE AREAS WITHIN THE COAL BASINS BY TRANSIENT ELECTROMAGNETIC SOUNDING METHOD

Accidents and disasters happen, mainly because of the explosion of coal mine methane and coal dust, sudden outbursts of coal, rock and gas. In the overwhelming majority of cases the cause of major accidents in the mines is a methane explosion. In order to reduce the risk of accidents to a minimum, you must identify the areas of generation and migration routes of gas within the coal basins. Very successful in the search for methane accumulation method of point electromagnetic sounding (TEMS) is used. The works on the definition of the zones of generation and migration of gas within the coal basins were carried out on the site Tomaszіwska (Donets Basin, Ukraine) and in one of the areas coalfield San Juan (United States). Method TEMS is able not only to identify areas of coal mine methane accumulations, but also the presence and configuration of the connecting feed channels, identify areas of generation and migration routes of gas. Its application allows to predict gas flows and thus significantly reduce the risk of accidents in the mines and get additional volumes of hydrocarbons.