Africa (Sub-Sahara) Algeria awarded four of 31 oil and gas field blocks on offer to foreign consortiums in its first auction since 2011. Shell and Repsol won permits for the Boughezoul area in the north of the country, while Shell and Statoil won permits for the Timissit area in the east. A consortium of Enel and Dragon Oil was awarded permits for both the Tinrhert and the Msari Akabli areas. Circle Oil's CGD-12 well, located onshore Morocco in the Sebou permit, encountered natural gas at different levels within the Guebbas and Hoot sands. Wireline logging analysis confirmed a net 9.7 m of pay. The first test, over the Intra Hoot sands, flowed gas at a sustained rate of 2.21 MMscf/D through an 18/64‑in. The primary target, the Main Hoot sands, flowed at a sustained rate of 4.62 MMscf/D through a 24/64-in.
Africa (Sub-Sahara) The drillship Ocean Rig Athena is preparing to drill appraisal and exploration wells offshore Senegal for a joint venture (JV) led by Cairn Energy. Two wells will appraise the SNE discovery, which was ranked by IHS CERA as the world's largest for oil last year. An exploration well will also be drilled in the Bellatrix prospect, for which mapping has indicated a potential 168 million bbl of oil resources. Cairn holds a 40% interest in the JV, with remaining interests held by ConocoPhillips (35%), FAR (15%), and Petrosen (10%). The Ksiri West-A exploration well drilled by Circle Oil on the Sebou permit onshore Morocco has flowed gas at a rate of 8 MMcf/D following tests. It is being readied for production.
Africa (Sub-Sahara) Tullow's Cheptuket-1 well in Block 12A of northern Kenya has encountered good oil shows over an almost 2,300‑ft interval, the company reported. The first well to test the Kerio Valley Basin, Cheptuket-1 was drilled to a final depth of 10,114 ft. The results indicate the presence of an active petroleum system with significant oil generation, the company said. Post-well analysis now under way will affect future basin exploration decisions. Tullow is the block operator with a 40% interest. Delonex Energy (40%) and Africa Oil (20%) are the other participants.
A new LWD ultrasonic imager for use in both water- and oil-based muds uses acoustic impedance contrast and ultrasonic amplitude measurements to obtain high-resolution structural, stratigraphic and borehole geometry information. Following extensive testing in the Middle East and the US, this paper presents results from the first European deployment of the new 4.75-in. high-resolution ultrasonic imaging tool.
An ultrasonic transducer, which operates at high frequency, scans the borehole at a high sampling rate to provide detailed measurements of amplitude and traveltime. A borehole caliper measurement is made, based on the time of arrival of the first reflection from the borehole wall. A second measurement detects formation features and tectonic stress indicators from the change in signal amplitude. The amplitude of the reflected wave is a function of the acoustic impedance of the medium. Resulting impedance maps have sufficient resolution to detect sinusoidal, non-sinusoidal and discontinuous features on the borehole wall.
Breakouts, drilling-induced fractures, and tensile zones were used for stress direction determination. Breakout identification was obtained both from amplitude images and oriented potato plot cross sections derived from traveltime measurements.
The orientation of natural fractures is parallel at the maximum stress direction, indicated by drilling-induced fractures and tensile zones. The World Stress Map confirms the maximum stress direction determination.
It was also possible to detect certain key-seat zones and investigate borehole conditions to prevent issues during the subsequent casing job.
The new LWD ultrasonic imaging technique represents an important alternative to density and water-based mud resistivity imaging, which has several limitations. Unlike the resistive imaging LWD tool that is very sensitive to standoff, the higher tolerance of the ultrasonic imaging tool enables the amplitude and traveltime ultrasonic images to contain fewer unwanted artifacts.
Twenty-one national geological surveys contributed to the European wide project ‘EU Unconventional Oil and Gas Assessment’ (EUOGA). The goal of EUOGA was to assess all potentially prospective shale formations from the main onshore basins in Europe and included contributions of twenty-one European geological surveys. Each participating geological survey characterized their domestic shale plays using thirty systematic parameters such as areal distribution, structural setting, average net to gross ratio of the shale reservoir, average Total Organic Carboncontent (TOC) and average mineralogical composition. The assessment covers 82 geological formations from 38 basins. Subsequently a stochastic volumetric probability assessment was performed on 49 of these formations which met the prerequisites for assessment. Importantly, this study for the first time used a unified methodology for assessing resources across European borders. Paleozoic plays in Poland, the United Kingdom, Denmark and Ukraine hold the largest potential gas resources. Most shale oil potential is observed in Bulgaria, the United Kingdom and Ukraine. The total resource potential for the geological formations that were evaluated in the project is 89.2 trillion cubic meter of gas initially in place (GIIP P50) and 31.4 billion bbl of oil initially in place (OIIP P50). The outcome of this project represents the most complete and accurate determination of shale hydrocarbon resources in Europe to date.
Europe may hold significant volumes of unconventional hydrocarbons as has been showed by both national and international agencies (e.g., EIA 2011, 2013, van Bergen 2013, Andrews 2013, 2014 , BGR 2012, Ladage 2016, PGI-NRI 2012). Interpretation and comparability of these studies is problematic, primarily due to difference in assessment methodology and both the quality and quantity of geological data that was available for the different plays. As a consequence the total European shale resource potential remains uncertain making long term planning, both political and economic, difficult. To overcome this problem a uniform assessment of European shale resources was required tailored to the specific challenges of the European situation.
Summary In this study, we investigate the reported ultrasonic measurements of core samples of organic shale and our lab measurements. We focus on Vp/Vs ratios, P-impedance, and velocity anisotropies for different types of organic shales. A layered model is constructed to explain why the silica-rich shales tend to have higher S-wave anisotropy and calcareous shales tend to have higher P-wave anisotropy. Hence, ratio may be potentially treated as an indicator for mineralogical composition in shale reservoirs. We also observe linear trends between Thomsen's parameters, / So rock physics models developed for clay-dominated mudstones are inappropriate and cannot be applied to organic shale.
Recent drilling results have highlighted the potential for the development of Jurassic source rocks of southern England as a shale oil play. Sustained natural oil flows have been reported by UKOG (2015) from the tight, Lower Kimmeridge limestones in the Horse Hill-1 well. According to the operator, this discovery is naturally fractured and can be produced without hydraulic fracture stimulation.
The occurrence of shale gas in the UK has been known of since the nineteenth century, but development of this resource attracted very little interest until recent years (Selley, 2012; Andrews, 2014). The first exploration well in the United Kingdom that was specifically drilled for shale gas was Preese Hall-1 in northwest England in 2010. This well was hydraulically fractured in the Bowland Shale, but operations were suspended following reports of repeated seismicity caused by the injection of fluid during hydraulic fracture treatment (Green et al., 2012). Assessments of the Carboniferous shale gas potential of northern England and Scotland and of the Jurassic shale oil potential of southern England have been published by the BGS/DECC (Andrews, 2013, 2014; Monaghan, 2014). These studies listed the various criteria for evaluation of shale plays and provided broad descriptions and resource estimates for the Carboniferous and Jurassic shale plays in the United Kingdom.
This paper presents the results of an integrated petrophysical and geological assessment of the Jurassic sequence in the south of England. The study area stretched from the Weald and Vale of Pewsey Basins in the north to the onshore parts of the Portland–Isle of Wight Basin on the Dorset coast in the south (Figure 1). The evaluation focused on the Kimmeridge Clay Formation, the Oxford Clay Formation, the Downcliff Clay Member, Charmouth Mudstone Formation and the Blue Lias Formation.
The stratigraphic framework used for the study is based on the extrapolation of the well-known outcrop stratigraphy on the Dorset Coast to the study wells. Wireline log data and new sedimentological core description results were used to constrain facies mapping. Detailed sedimentological core description was carried out on three of the twelve study wells. From the trends observed in the wireline log data, the lithofacies and level of oxygenation, 14 initial facies associations were assigned over the cored intervals ranging from restricted shallow marine through shoreface to shelfal environments. These facies associations were grouped into seven combined facies associations which were used as input for the electrofacies analysis and facilitated the extrapolation of facies to intervals that lacked core data Additionally this workflow provided a useful template for estimating Total Organic Carbon TOC from logs using the CARBOLOG® equation and this resulted in a significant improvement in the correlation between the laboratory measured TOC values and the log-based TOC estimates. Results from the mineralogical analysis of core and cutting samples were utilised to calibrate and improve the petrophysical interpretations and to assess the elastic properties of the rocks in the intervals of interest. The petrophysical data, elastic properties and the facies interpretations were used to evaluate and map the development potential of the Jurassic source rock intervals as unconventional reservoirs.
An extensive geochemical database was combined with new analyses to characterise the source rocks. This data was integrated into 1-D basin models to identify and map effective source kitchen areas. The organic matter in the analysed interval is dominated by Type II kerogen, with significant input of Type III kerogen towards the London-Brabant Massif. The Upper Jurassic Kimmeridge Clay and the Oxford Clay are within the early oil window, while the Lower Jurassic Downcliff Clay Member, Charmouth Mudstone Formation and the Blue Lias Formation have reached peak oil maturity in the deeper parts of the Weald Basin. The source richness and kerogen types were combined with the maturity maps to create generation risk maps.
The risk for ground water contamination from hydraulic fracturing was also evaluated. These results were combined with the reservoir and generation risk maps to produce common risk segment maps in order to identify the sweet spots in the study area.
John, Cédric M. (QCCSRC and Earth Science and Engineering, Imperial College London) | Hönig, Martin R. (QCCSRC and Earth Science and Engineering, Imperial College London) | Abbott, Sunshine (QCCSRC and Earth Science and Engineering, Imperial College London) | Fraser, Alastair J. (Earth Science and Engineering, Imperial College London)
Most regional studies of reservoir and seals focus on large-scale sequences and their architecture. However, understanding flow and geochemical processes happening in the subsurface requires a multi-scale approach from the pore-size to the field-size. Here we focus on an intermediate, ‘inter-well’ scale loosely defined as 100-1000 meter scale. This inter-well scale is crucial as it represents the minimum distance between an injector and a producing well. Hence, constraints on the heterogeneities in the reservoir or within a sealing lithology can guide the production geologist during EOR or CCS operations. In this paper, we present a review of existing outcrop analogues for the subsurface of Qatar that were considered for our study. Out of the different possibilities, we selected outcrops from Wadi Naqab (Ras-Al-Khaima, UAE) as an analogue for the subsurface reservoirs in Qatar, and we focused on mine outcrops in the U.K. as potential analogues to derive the 3D geometry of evaporite-carbonate sequences analoguous to the Hith Formation. The Jurassic limestones at Wadi Naqab appear layer cake at the scale of observation, but we demonstrate here that even though beds rarely pinch out, the facies within bed changes markedly at a scale of <200 meters. For subsurface applications, this could be significant if the change in facies correlates with a change in petrophysical properties. The anhydrite layers at Brightling Mine are mostly composed of nodular, sabkha-type layers, inter-bedded with shallow-water algal limestones and shales. These lithologies are continuous at a 500 meters scale, but scouring impacts on the thickness of the deposits. Again, this could have important mechanical implications during CCS operations, because the interface of different lithologies and their thicknesses control fracture propagation within reservoirs and seals. We conclude that more geometrical heterogeneities exist in both reservoir and seals than previously thought, and that inter-well scale data are needed to inform subsurface reservoir models. We also caution that one of the limitations of using outcrop analogues is that porosity and permeabilities are not preserved during uplift, and thus petrophysical properties within numerial reservoir modelling need to be populated using subsurface data.
Chenggang, Wang (PetroChina Exploration and Production Co.) | Anzhu, Xu (Research Inst. of Petroleum Exploration and Development, PetroChina) | Lun, Zhao (Research Institute of Petroleum Exploration and Development) | Qiong, Wu (No.4 oil Production Plant, Hua Bei Oil Field) | Lianbo, Zeng (China University of Petroleum)
Imaging logging can intuitively recognize fractures around borehole walls.However, expensive cost of imaging logging limits its popularization, so littledata of imaging logging can be used. How to use conventional logging data is animportant item in fracture recognition. Conventional acoustic logging hassensitive response to cavities and fractures. Fractal geometry variable scaleanalysis (R/S) in combination with acoustic logging data to calculate fractaldimensions of target layers is a new method . Fractal dimension based on R/Sanalysis can reflect the variability of acoustic logging data, namely reservoirvertical heterogeneity. The stronger vertical heterogeneity is and thebetter fractures develop , the higher fractal dimension is in fracturedlow-permeability sandstone reservoirs. So fractal dimension is used to forecastfracture development in oil-bearing formations of Y1, Y2 and Y3 which arelow-permeability sandstone reservoirs in X area of Western oilfield in OrdosBasin. Besides a significant discussion about fracture development depend onquantitative analysis of the results from field testing. Dynamic analysis,field outcrops and coring well evaluation show the forecast results have a goodagreement with the actual situation. The research results have certainsignificant guidance to fracture description.
Development practices of low permeability oilfield in both domestic andoverseas show that natural fractures play an important role in the practicaldevelopment result of low permeability reservoirs. So theresearch of natural fractures has become one of the key contents of reservoirsevaluation and forecast, and also one of the urgent needs of the oilfieldeffective development. Now there are lots of methods for fracture recognitionand description. But it is often difficult toeffectively identify and predict the distribution of fractures because of therestrictions of data types and quantities in a specific oil-bearing block.Conventional logging data are the most among the existing data in X area ofWestern oilfield. Conventional logging data to establishfracture logging response mechanism models to recognize fracture distributioncan be used? Through consulting a large number of literatures, there areexamples which use fractal geometry variable scale analysis (R/S) incombination with conventional logging data to recognize fractures relativedevelopment at home and abroad .So based on the characteristicsof low and ultra-low permeability reservoirs of Yanchang Formation in the OrdosBasin , ractal geometry variable scale analysis is used to make a tentativeforecast of fractures development of Y1,Y2 and Y3 layers, the main targetlayers in X area of Western oilfield .Besides fractal dimension to conduct acomprehensive classification evaluation at Y1 ,Y2 and Y3 layers is also can beused .And the results of evaluation are nearly identical to actual productionswhich have some vital guidance for effective development of oil -bearings.
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the 2012 SPE Hydrocarbon, Economics, and Evaluation Symposium held in Calgary, Alberta, Calgary, 24-25 September 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. Abstract On the today's global market it is an important issue to have an adapted management system, due to the fast change of beliefs in social communities and politics. In the last few years a significant change in E&P business could be recognized from conventional sources to unconventional ones. To realize an unconventional project in Europe, like shale gas, it is very important to adjust the project management to the given situation.