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- Volume 23, Issue 11, 2005
First Break - Volume 23, Issue 11, 2005
Volume 23, Issue 11, 2005
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Middle East opens up to increased oil and gas exploration opportunities
By J. CraigJonathan Craig, regional manager, IHS Energy, reviews on a country-by-country basis some of the significant events likely to shape the future of exploration and development in the Middle East region. Iran’s President Mahmoud Ahmadinejad in late August appointed the former deputy oil minister in coordination affairs, Kazem Vaziri Hamaneh, as the caretaker of the Ministry of Petroleum. The move came following the rejection by parliament of four cabinet nominees on the grounds of lack of ministerial experience. Due to the delay in appointing a new minister, many contracts are in limbo and/or not expected to be signed until after the appointment of a new oil minister. Recent developments Norsk Hydro in August was assigned the 7740 km2 Khoramabad Block in the Zagros Fold Belt. The company is in discussions with Iran’s NIOC Exploration Directorate on the details of the contract. The company’s subsidiary Hydro Zagros Oil and Gas (75%, operator) has begun preparing a commerciality report for the Anaran block to file with NIOC by end-3Q 2005. The submission will be the starting point for beginning buy-back development negotiations for the 2700 km2 block, western Iran, on the border with Iraq. NIOC was sidetracking its Kish 2 wildcat on Kish Island from around 3850 m by late June, after an unsuccessful fishing job at a TD of 4034 m. Logging was run to 3897 m, presumably near the depth of the top of the fish, and a cement plug was set. However, on 10 September 2005 Iranian press reported that a ‘massive’ gas reservoir was penetrated at 4100 m. Kish 2 has objectives in the Permian to Lower Triassic Kangan, Dalan, and Faraghan formations (sandstone below Dalan).
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Exploring the High Zagros (Iran): a challenge for geophysical integration
Authors Chr. Henke, J. Schober, U. Weber, F. Gholami and H. TabatabaiThe purpose of a combined geological and geophysical study in the High Central Zagros area near the townships of Lordegan and Yasuj was to find answers to the following main questions: ■ Is the High Zagros Fault (HZF) an overthrust fault? ■ Are there vertically separated structural/ tectonic units in the ‘Complex’ Foreland of the Zagros? ■ Are there possible hydrocarbon exploration targets beyond the HZF? While Bosold et al.(2005) have published the results of a geological study, this paper focuses on the geophysical contribution to the above questions. Integration of seismic and potential field geophysical methods played a key role in this study. The area of investigation is located in the Zagros Fold-Belt (‘Complex’ Zagros Foreland), close to one of the oldest and richest oil and gas provinces in the world and the Zagros Thrust-Belt (High Zagros). Most of the oil and gas fields were discovered in the ‘Simple’ Zagros Fold-Belt in front of the Mountain Front Fault (MFF), which marks the front of the ‘Complex’ Zagros Foreland. Decades of successful activity of the petroleum industry have led to the acquisition of extensive knowledge of this area, whereas the orogenic zones further into the interior of the Zagros have been studied to a much lesser extent. The higher degree of structural complexity in combination with rugged surface topography is one of the main reasons. In the area between the Mountain Front Fault (MFF) and the High Zagros Fault (HZF) little seismic has been acquired previously and few wells have been drilled. These wells are often based exclusively on surface geology without seismic control, many of them having resulted in petroleum discoveries. North of the HZF, however, no data other than detailed surface geological mapping have ever been acquired prior to this study. In 2000, the exploration team of RWE Dea realized that new or previously undetected exploration plays could be present in the ‘Complex’ Zagros Foreland or even in the High Zagros adjacent to the established petroleum province. In 2001 a profirst posed two and a half year joint study programme in the Lordegan-Yasuj area was agreed with NIOC.
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Khuff formation Permian-Triassic carbonate in the Qatar-South Fars arch hydrocarbon province of the Persian Gulf
By A. BashariSince the 1948 discovery of prolific gas reservoirs in Bahrain, Middle East explorationists have been interested in the Khuff Formation (Permian-Triassic carbonate). Several supergiant gas fields (reserves above 10 tcf) have been found in the region. North of the Persian Gulf very large gas fields have been discovered in Permian strata of south Iran, especially in coastal Fars, such as Kangan, Dalan, Nar, Aghar, Bandubast, Mand, Varavi, Asaluyeh, as well as in the Persian Gulf. Qatar-South Fars province contains light and heavy crude oil ( Bashari, 1988), in addition to being one of the most important gas provinces in the world. Qatar’s North field is the largest of all the giant Khuff gas reservoirs, with total reserves of 436 tscf and field life of around 200 years at planned production rates. It covers an area of 6000 km2. The gas reservoirs are found at shallow depth in the Khuff, usually between 2470 and 2830 m below sea level (Al-Marri and Al-Bader, 1989). In fact the field is even bigger than indicated because its reservoir extends across the political boundary in the Persian Gulf under Iranian waters (South Pars Field). There are efforts to evaluate extensions of the field in Qatar waters, especially to the east and southeast of production areas. There is a strong probability that current reserves in the North field will increase as a result of such work (Al-Attayah, 1998). In 1992, Iran discovered the supergiant South Pars field, in the Persian Gulf, close to Qatar’s North field, (Fig.1). South Pars has reserves estimated at 436 tscf. (Petropars, 2005). The South Pars field is formed by an extremely large open periclinal structure. North field and South Pars fields overlie the broad Qatar arch, which subdivides the Khuff depositional basin, into two basins located north west and south east of the arch. This paper describes the Khuff carbonates distributions in terms of Lithostratigraphy- Biostratigraphy, (diachroneity) of this formation and also reservoir development of Khuff formation.
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The offshore EM challenge
Authors J. Hesthammer and M. BoulaenkoExploration for hydrocarbons in offshore settings is both challenging and expensive. The chance of an exploration well finding hydrocarbons remains relatively low despite significant improvements in seismic acquisition and processing methods over the past decades. This is partly due to seismic data not being a strong fluid indicator. There are numerous examples of discoveries where seismic data revealed no indications of hydrocarbons, only a structural or stratigraphic closure. In other cases, flat-spots and bright-spots turn out to be caused by a residual 5-10% gas saturation (i.e. non–commercial reserves). Obviously, any means to increase the chance of discovery will be of great benefit for those involved in oil and gas exploration. In 2000, Statoil tested the concept of using marine controlled source electromagnetic (MCSEM) induction for direct hydrocarbon detection in deep water offshore settings (Eidesmo et al., 2002, Ellingsrud et al., 2002). They found that the method was suitable for detection of reservoirs with high (i.e. commercial values) hydrocarbon saturation levels of 60-70% or more. This led to the establishment of ElectroMagnetic GeoServices (emgs), the first company to successfully utilize MCSEM (called Sea Bed Logging by emgs) for direct hydrocarbon detection in offshore settings. Shortly after emgs was founded, two other industry competitors started to provide similar services for marine hydrocarbon prospecting using MCSEM. These are Offshore Hydrocarbon Mapping (OHM) and AGO/Schlumberger. Both utilize mobile horizontal electric dipole sources and a set of electromagnetic field sensors deployed on the seafloor similar to that used by emgs. Less than three years after the establishment of these companies, more than 100 surveys have been conducted world wide and many of these have been verified by wells. The concept of using electromagnetic (EM) data for direct hydrocarbon detection is now proven and is already identified by many as a game changer in the petroleum industry and potentially the most important technology since the introduction of 3D seismic data a couple of decades ago. Large E&P companies such as Statoil, ExxonMobil, and Shell have already started to implement the technology, whereas smaller companies are still struggling to evaluate the potential of MCSEM and how it can be used in their exploration strategy. This creates a window of opportunity for aggressive start-ups and first movers such as Rocksource, the first independent E&P company to establish EM technology as the fundament for their exploration and production strategy by being expert users of MCSEM. Although the use of MCSEM soundings for direct hydrocarbon detection is proven successful, it is not obvious for the industry how to develop and use the technology to its full extent. This paper discusses some of the aspects related to the future needs for equipment design, survey planning, 3D/4D modelling and inversion, joint inversion with seismic and geological data, and finally, integration of MCSEM data into an E&P company workflow. These are important aspects that must be addressed if the full potential of offshore EM technology is to be reached and if the technology is to be brought into more complex settings and potentially into production for reservoir monitoring purposes.
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4D reservoir volumetrics: a case study over the Izaute gas storage facility
By D. BateDr Duncan Bate (ARK Geophysics) presents a recent oil company sponsored case study in France pointing to the value of 4D microgravity modelling as a cost-effective and unintrusive way of enhancing reservoir information. Measuring the Earth’s gravitational field as a means to mapping subsurface density distributions has been an exploration technique for decades. Gravitational anomalies may be related to subsurface geological structures and thus indicate features including faults, intrusives, and salt structures. High spatial resolution gravity data (as acquired with 3D seismic surveys) may be used in combination with 3D modelling to help define end member salt volumes in seismic imaging processes such as pre-stack depth migration (PSDM). The measurement of the time varying (4D) gravity field as a method of observing subsurface fluid flow in a hydrocarbon reservoir is a more recent application of gravity data. ARK Geophysics (ARK) conducted a time-lapse microgravity field trial over the Izaute gas storage reservoir in the Gascoigne district of South-Western France approximately 60 km north of Pau, between January 2003 and June 2004. The reservoir is operated by Total Infrastructure Gaz France (TIGF). The project was coordinated by ITF and funded by Statoil, Shell, and Total. The reservoir is a domestic gas storage buffer – filled throughout the summer months and depleted during the winter. The objective of this trial was to investigate whether time changes in the observed gravity field could practically be measured and if so, whether the observations correlated to known changes in gas stock levels. Twelve repeat gravity surveys were performed (each comprising over 200 stations) and two continuous gravity meters were employed. Overall the measured time-lapse gravity data correlate well with the predicted gravity changes from the reservoir model. Any observed differences between the predicted gravitational response of the reservoir model and the measured time varying gravity field requires further investigation. Sources of such observed discrepancies include system noise but also geological information that may not have been captured in the reservoir model such as reservoir compartmentalization, porosity, and permeability differentials as well as unmapped thief zones. The continuous data recorded over the reservoir show a good correlation with the reservoir gas pressure data. The aim of this study was to assess whether the time varying gravity field generated by a propagating density interface (e.g. oil-water or gas-water contact) can be measured by currently available cost-effective instrumentation. A two-fold approach was employed, utilizing time-lapse (or dynamic) and continuous gravity acquisition techniques. A dynamic gravity project comprises repeat static gravity surveys and is sometimes referred to as time-lapse or 4D. Workers in this field have successfully applied this technique to hydrothermal energy exploration (Hallinan et al., 1989; Allis et al., 1986) and hazard monitoring (Rymer & Brown, 1986; Yokoyama, 1989). A continuous gravity survey involves recording the variations in gravity continuously over a period of time. This technique has previously been used for long term studies of earth tides and volcano monitoring. There are several designs of gravity meter that can measure to the required accuracy for this project. The LaCoste and Romberg G and D meters with Aliod electrostatic feedback nulling system were used. This system has a range of approximately 100 mgal (+/-50) with a resolution of 0.01, or 0.001 mgal depending on which version is fitted. The Izaute, and its neighbouring Lussagnet, gas storage facilities have been created from porous submolassic sand reservoirs in the upper section of a vast multi-layer reservoir that contains the ‘inframolassic aquifer’ stretching from the Pyrenees to north of Bordeaux. The Izaute reservoir is formed by a gently plunging anticline, with an overburden of approximately 500 m. The reservoir thickness ranges from 50 to 80 m, has a porosity of between 25% and 35% and a permeability of between 6 and 20 Darcys. Gas is injected in the summer months (May to October) and recovered in the winter months (November to April). The total seasonal variation in the depth to the gas-water contact is 24 m.
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A helicopter time-domain EM system applied to mineral exploration: system and data
Authors D. Fountain, R. Smith, T. Payne and J. LimieuxDavid Fountain, Richard Smith, Tom Payne, and Jean Lemieux (Fugro Airborne Surveys) describe recent progress in developing helicopter systems for time-domain airborne electromagnetic surveys, once the ‘domain’ of fixed-wing aircraft. The first operational fixed-wing airborne electromagnetic (AEM) system was introduced in 1948 and was followed by the first operational helicopter AEM system in 1955 (Fountain, 1998; Fountain and Smith, 2003). There has been parallel development of both fixedwing and helicopter AEM since that time and, up to the early 1960s, all these systems were frequency-domain. However, since the late 1970s, fixed-wing AEM systems have been primarily time-domain while the helicopter systems remained primarily frequency-domain. With the new millennium, and especially since 2002/ 2003, there has been significant development and introduction of helicopter time-domain AEM systems (Boyko, et al., 2001; Balch et al., 2003; Eaton et al., 2004; Sorenson and Auken, 2004; Vrbancich and Fullagar, 2004; Witherly et al., 2004). The pace of introduction has been such that, today, the number of time-domain systems in use is equal to the number of frequency-domain systems. Fugro Airborne Surveys and its predecessor companies have been leaders in the continuing development of fixedwing AEM systems, including the introduction of the GEOTEM, MEGATEM, and TEMPEST systems (Smith and Annan, 1997; Lane et al., 2000; Smith, Fountain and Allard, 2003). By the same token, Fugro has been involved in the continuing development of helicopter frequency-domain AEM systems including DIGHEM and RESOLVE. Based upon this combined experience and seeing the need for a broader band, high power helicopter time-domain AEM system, Fugro has introduced the HeliGEOTEM system in 2005. This system brings together the proven GEOTEM/ MEGATEM technology with the greater operational flexibility and improved lateral resolution of helicoptermounted AEM systems.
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Pre-drilling prediction of the tectonic stress field with geomechanical models
By A. HenkKnowledge of the tectonic stress field in a reservoir is essential to optimize drilling and production. Borehole stability, orientations of natural and hydraulically induced fractures, fluid flow anisotropies, among others, all depend critically on the present-day stress distribution. Several techniques ranging from dipmeter analysis of borehole breakouts to anelastic strain recovery and shear acoustic anisotropy analysis of core samples (e.g., Yale, 2003; Sperner et al., 2003) can be used to determine the in-situ stress orientations and relative magnitudes, but obviously this valuable information will only become available after the well has already been drilled. However, there are also numerous cases where the stress orientation should be known prior to drilling. For example, if multiple fracs in a horizontal well are planned, the stress field orientation needs to be known beforehand because for optimal frac design the horizontal well path must be aligned parallel to the orientation of the least principal stress axis σ3. Similarly, the planning of well trajectories with respect to borehole stability as well as the design of secondary and tertiary recovery measures (e.g., water injection, hydraulic fracture treatments) are significantly improved by a pre-drilling knowledge of the subsurface stress field. Information on the regional stress orientations can be derived from large-scale data collections like, for example, the world stress map project (Zoback, 1992; Sperner et al., 2003). The orientation and magnitude of the stress field in sedimentary basins, however, can be highly variable and, particularly near faults, the local stress orientations can differ by up to 90° from the regional trend (e.g., Yale, 2003). In such cases, inference of reservoir-scale in-situ stress orientations from regional scale maps would inevitably lead to an incorrect pre-drilling prediction. This paper uses a numerical modelling approach to determine the magnitude and orientation of the tectonic stresses in a reservoir and, particularly, the local stress perturbations near faults. The model is based on reservoir and fault geometries taken from seismic data and boundary conditions representing the regional stress field. Thus, this tool is also applicable to cases where well data are absent. Following a brief outline of the modelling approach, a case study is presented to assess the practical value of such geomechanical models for the pre-drilling prediction of the tectonic stress field in fault-controlled reservoirs.
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Volumes & issues
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Volume 42 (2024)
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Volume 41 (2023)
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Volume 40 (2022)
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Volume 39 (2021)
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Volume 38 (2020)
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Volume 37 (2019)
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Volume 36 (2018)
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Volume 35 (2017)
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Volume 34 (2016)
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Volume 33 (2015)
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Volume 32 (2014)
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Volume 31 (2013)
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Volume 30 (2012)
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Volume 29 (2011)
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Volume 28 (2010)
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Volume 27 (2009)
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Volume 26 (2008)
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Volume 25 (2007)
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Volume 24 (2006)
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Volume 23 (2005)
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Volume 22 (2004)
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Volume 21 (2003)
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Volume 20 (2002)
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Volume 19 (2001)
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Volume 18 (2000)
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Volume 17 (1999)
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Volume 16 (1998)
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Volume 15 (1997)
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Volume 14 (1996)
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Volume 13 (1995)
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Volume 12 (1994)
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Volume 11 (1993)
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Volume 10 (1992)
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Volume 9 (1991)
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Volume 8 (1990)
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Volume 7 (1989)
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Volume 6 (1988)
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Volume 5 (1987)
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Volume 4 (1986)
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Volume 3 (1985)
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Volume 2 (1984)
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Volume 1 (1983)