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- Volume 22, Issue 4, 2004
First Break - Volume 22, Issue 4, 2004
Volume 22, Issue 4, 2004
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Soft computing for qualitative and quantitative seismic object and reservoir property prediction. Part 2: Fuzzy logic applications
Authors F. Aminzadeh and D. WilkinsonThis is the second instalment of the series of review papers on soft computing applications in the petroleum industry. In this paper Fred Aminzadeh and David Wilkinson focus on fuzzy logic applications, including a brief overview of fuzzy logic technology, recent applications of fuzzy logic in various exploration and development scenarios, and a proposed framework to use fuzzy logic for seismic stratigraphy analysis and to explore applications of fuzzy differential equations. In the companion paper to this series (Aminzadeh and de Groot, 2004), the main advantages of soft computing were highlighted. Among them were integrating information from various sources with varying degrees of uncertainty. Geosciences data used in exploration are inherently imprecise, uncertain and fuzzy. This, combined with many linguistic rules and subjective treatment of the data, make it a good candidate for the use of fuzzy set theory for the processing, analysis and interpretation of E&P data. Figure 1, from Wilkinson et al (2003), illustrates the difficult task of modelling and analyzing the mother earth (geologic outcrops) with numerical (in this case seismic) measurements. The main advantage of fuzzy logic is its versatility in combining the quantitative data and qualitative information and subjective observation and rules. Given the nature of the information available for interpretation (such as seismic data, well logs, geological and other geosciences data) fuzzy sets theory can help in developing an appropriate framework to carry out quantitative analysis of the information and data which are the aggregate of both qualitative and quantitative types. After a brief overview of prior work, we give several examples of applications of fuzzy logic in exploration.
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Reassessing the shared earth model makes sense
By D. HardyDavid Hardy, business development manager at Roxar Software Solutions, which specialises in products and solutions to optimize production and maximize recovery from oil and gas reservoirs, spells out why petroleum geologists and all the other disciplines have to collaborate on a genuinely shared earth model. Anyone who has worked in the oil industry for a few years will know what integration isn’t. Not that long ago oil companies were arranged along functional lines with each discipline consigned to a particular box. Geophysicist, geologists and engineers existed in virtual isolation. Huge barriers existed between the disciplines and there was little opportunity for knowledge sharing across disciplines even when working on the same project. Added to this, there is a new challenge. With rationalisation and reorganisation, asset teams are now expected to do the same work but with an ever decreasing team. Team members are now expected to take on wider roles. The requirement to work closely together and make decisions based on models that incorporate data from all the disciplines now appears obvious. It did, however, take the industry many years to reorganise based on the asset team. Even today not all disciplines or assets teams have broken down the barriers. With the need greater than ever and the availability of the correct tools, it appears that there is a resurgence in interest for a truly shared earth model. The un-shared earth model With historically poor communication between disciplines it is not surprising that applications developed in isolation and were poorly integrated. Software merely replicated the practices and workflows of the industry. Even within single disciplines, software was poorly integrated with staff required to learn different software packages for each step of their project workflow. The same data were often entered multiple times into different packages and in the worst cases there may have been different vintages of the same data used by the geoscientist versus the engineer. A lot of time was also wasted formatting and transferring data.
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Desire aims to put lustre back into Falklands offshore oil and gas campaign
Following a first exploration drilling programme in 1998, talk of hydrocarbons prospects off the Falkland Islands in the South Atlantic has been notably muted. This could be about to change, as First Break reports. Without much fanfare Desire Petroleum, a small UK-based oil exploration company, has taken what it hopes to be the next big step in reviving interest in oil and gas prospects off the Falkland Islands. Desire announced in January that the Fugro Geoteam vessel Geo Pacific had begun a 40-45 day 3D seismic survey over at least 800 km2 in Tranches C and D, as well as a small portion of Tranche F in the licensed waters north of the Falklands. The company is hoping that the new survey covering three large structures in the North Falkland Basin identified by previous 2D surveys will be the start of something really big. The initiative follows the subdued reaction to the six wells drilled in 1998, after the initial licensing of the Falklands offshore region for exploration by the international oil industry. However, Desire believes that it has found the key to unlocking what could be very substantial hydrocarbon riches. Dr Colin Phipps, the company’s chairman, told shareholders not so long ago that a new geological model had been developed which has identified areas within the North Falklands Basin, and below the source rock, most likely to contain substantial reservoir rocks and traps for oil. The model provided the momentum to plan the new seismic survey, which also took into account discussions with potential farm-in partners who stressed the importance of 3D seismic in refining the major drilling targets. Echoing the findings of the British Geological Society, adviser to the Falkland Islands government on oil and gas exploration, Phipps says the initial drilling campaign in the North Falkland Basin encountered a very thick, lacustrine, source rock which has proved to be the second richest yet discovered worldwide. Calculations indicate that from 60 to 110 billion barrels of oil have been generated and expelled from the mature section of this source rock. At least one other, deeper, source rock was also encountered. All six of the wells drilled to date were targeted at structures which proved to be above the source rock but, because the upper, immature, section of the source rock forms an almost complete seal across the whole of the Basin, only oil shows were encountered. The new geological model has concentrated on identifying potential reservoirs and structures below and adjacent to the source rock. As a result of a worldwide slowdown in offshore drilling activity, the costs of carrying out 3D seismic surveys fell sufficiently at the end of last year for Desire to think about a survey to test the theory on the hydrocarbon bearing structures. The company went to the market and raised some £5 million in total, and is therefore able to pay its own way for the survey. But it is also canvassing potential farm-in candidates, offering significant equity in the equivalent of more than 13 North Sea blocks, and suggesting that breakeven point for any commercial development would be the discovery of 50 million barrels of recoverable oil reserves, assuming the use of floating production, storage and offshore loading (FPSO) technology.
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Restoring the seismic image with a geological rule base
Authors S. Bland, P. Griffiths and D. HodgeStuart Bland, Paul Griffiths and Dan Hodge of Midland Valley Exploration, Glasgow, Scotland discuss a new conceptual model for understanding the development of structures. This paper presents a technique that optimises the use of seismic data through manipulation of the image using a geological rule base. The approach can be readily used in routine interpretation and saves time by quickly focusing effort on fruitful interpretational models and by increasing confidence in picking in poor data areas and in complex structure. Seismic imaging is a primary source of information used in the exploration of hydrocarbons. Analogies have been drawn between the uses of seismic in exploration and production (E&P) and that of medical imaging in healthcare. There are similarities in the core functions of the seismic interpreter and the radiologist: both rely on high resolution images as 2D sections or 3D models to reveal what can’t be observed directly. In both disciplines the key aims are to note salient features in order to produce an accurate diagnosis of the situation and to advise others of their conclusions. Neither driller nor surgeon will appreciate surprises and will expect to have been appraised of critical factors and potential risks. The surgeon is interested in the location and most efficient route. Likewise the drilling engineer in the hydrocarbon accumulation needs to define the target. However, in both scenarios, whatever leading-edge technology is applied, the outcome is dependent on the interpretation of the data that, until drilling or surgery, remains an estimation of reality. At a fundamental level in hydrocarbon exploration, the interpretation of data is the product of a continual stream of decisions - ‘What does the horizon look like?’, ‘Can it be correlated across faults?’, ‘Where do the faults terminate?’, ‘Are the faults linked?’, ‘Is the horizon folded?’ One technique available to help the geophysicist is to flatten the seismic on key marker horizons. This is the digital version of the interpreter taking a folded paper section and overlaying one part on another to check character and correlation. Taking this technique a stage further we can use it to mimic simple deformations where flat-layered rocks become folded or faulted. Since horizons are both spatial and temporal objects – they are defined by geometry and age - horizon flattening can reveal significant features present at a particular time. Unfortunately this process has a number of drawbacks that require the interpreter to overlook distortions in the image, artefacts of the flattening process. These artefacts can arise where the horizon is interpolated across a fault or more generally because the flattening does not replicate the deformation observed in the section. These artefacts can significantly mislead the interpreter if not recognised. Where the medical doctor can refer to records to gain an insight into the patient’s medical history, the geologist can restore the section to understand its evolution. By using structural restoration to sequentially remove the effects of sediment compaction, isostatic adjustment faulting and fault-related folding that have altered the present-day section since deposition, we have a geologically valid way of looking at the history of the development of our structure while referencing the seismic image of the present day. Structural validation aids the decision process between alternative interpretations by testing the results within the framework of our understanding of geological history and evolution. Inclusion of the seismic enables validation of the geohistory within the context of the data. Three case studies are presented to illustrate the techniques involved in restoring the seismic image and the bene- fits from adopting this approach. Each case study has a distinctive setting, characteristic, key issues and associated risks. The first example is set within an extensional fault system of the Gullfaks, northern North Sea and depicts an untested interpretation. The second, an inverted series of half Grabens in the southern North Sea, typifies the problem of degrading seismic quality at depth. The final case study is taken from a Foreland Thrust basin in the Alberta Foothills, Canada. Each example demonstrates an enhanced level of detail and reduced risk of error in the final interpretation from apparently simple structures.
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West Greenland is target of new licensing round
The Greenland and Danish governments are this month launcing a new licensing round for selected areas offshore West Greenland between approximately 63°N and 68°N. First Break offers this update. An opening meeting in Copenhagen to launch the latest round of licensing offshore West Greenland was due to be hosted on 1 April 2004. Hopefully the April Fools Day date will have no bearing on the outcome of this latest attempt to persuade the international oil industry, which has shown no great enthusiasm in the past, that Greenland is a viable exploration proposition. Closing date for applications is 1 October 2004 and new licences are expected to be granted at the turn of the year. Four licence areas, all said to be characterised by the presence of giant structures in favourable basinal settings, have been selected for the round. These are: ■ Parts of Lady Franklin Basin between approx 63°N and 65° N covering approx 10 500 km2 ■ Kangaamiut Basin and Ridge around 66°N covering approx 4900 km2 ■ Parts of Ikermiut Fault Zone/Sisimiut Basin between approx 67°N and 68°N covering approx 7000 km2 ■ Parts of the Atammik and Fylla Structural Complexes between approx 63°N and 64°N covering approx 11 200 km2 What has changed since the last licence award in 2002 to Canadian oil company Encana and Nunaoil, Greenland’s own oil company, is that nearly 9000 km of additional seismic data have been acquired off western and southern Greenland. This activity last summer prompted, for the first time ever in Greenland waters, the need for two seismic vessels which were acquiring data until the end of November thereby considerably extending the normal seismic season. TGS-NOPEC continued its longstanding commitment in Greenland by acquiring approximately 7400 km of non-exclusive data. Acquisition was within the new venture areas (3100 km) to provide a better regional grid, to cover actual giant structures and to delineate deep basins. Some 3200 km of data were also acquired within EnCana’s licence area and around 1100 km as part of longer-term activities off southern Greenland. Additionally, approximately 1500 km were acquired off south Greenland by GEUS, the Geological Survey of Denmark and Greenland) as part of preparations for staking claims beyond 200 nautical miles as described in Article 76 of the UN Convention on the Law of the Sea. Following the success in earlier years of using a long streamer to acquire information on hitherto unknown deep structures and basins offshore West Greenland, an even longer streamer of 6000-8000 m was used last year.
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Gas reserves and reservoir trends in The Netherlands
More LessThe Netherlands is one of the largest gas producers in Europe with about 71.2 Bcm (2.51 Tcf) of gas produced during the year 2002, half of which is exported, supplying Europe with about 20% of its total consumption. Significant gas production in The Netherlands started in 1965, reached a peak during 1976 with 101 Bcm (3 Tcf) and by year end 2002, a total of 2622 Bcm (92.6 Tcf) had been extracted. Currently the government limits yearly gas production to 80 Bcm, although the rate in the past four years has been well under this limit. Early exploration was started before the Second World War by a precursor of NAM (the 50/50 Shell-Exxon joint venture active in The Netherlands) and in 1943 the Schoonebeek oil field was found followed by Coevorden gas field in 1951. In 1959, the giant Groningen gas field was discovered by NAM, changing the face of exploration in The Netherlands. Since that time NAM has retained its dominant position as operator controlling about three quarters of annual gas production and reserves. Public domain access of data on gas and oil fields in The Netherlands is scarce, with pre-2003 legislation allowing operators to hold tight all information on onshore wells. Since most onshore concessions are large, held over long periods of time (several in perpetuity), and have no relinquishment obligations, many fields have been found and are in production without any data entering the public arena. Offshore, pre-2003 legislation required operators to release well data after 10 years. Offshore concessions are relatively large and many contain several producing fields for which no or little data is in the public domain. Following the new legislation in force since 1 January 2003 detailed production data and all on- and offshore wells and seismic data older than 5 years have to be released. However, reserve figures of fields are not in the public domain. Reserve data submitted by the operators remain confidential for a period of 10 years and in the absence of any legal requirement operators use this advantage. On a yearly basis, the government publishes general estimates on reserves, but not for individual fields. Data on the current reserve distribution for fields, reservoir trends and for licence holders are not easily ascertained. This paper attempts to fill this information gap by reviewing reserves whether these are in developed or undeveloped fields. Reserves are oil or gas volumes that can be commercially recovered at current economic conditions, industry practices and government regulations. Developed reserves are those being produced today while undeveloped fields are not yet on stream. Remaining reserves are those left in a producing field. Initial (or ultimate) reserves of a field are the cumulative production plus the remaining reserves. Because the technical data of the fields are not available, the different reserves categories are used here informally and without strict definitions. In this paper a difference has been made between the giant Groningen gas field and the other fields that are collectively called the ‘Small fields’. This term is used in a comparative sense with the Groningen field as the measuring stick, and is applied due to the Small Field Policy in The Netherlands, which allows operators priority to bring small gas fields immediately on stream in lieu of production from the Groningen field. Exploration for and production from small fields is therefore not constrained by demand for gas. Moreover because the Groningen field acts as a swing producer, small fields can produce with high load factors. The Small Field Policy sets production constraints on the Groningen field. In addition the gas price is kept relatively high because it is linked to a basket of oil product prices. Without these production constraints and the linkage of the gas price to that for oil, the low production costs and high production capacity of the Groningen field would result in low gas prices for Western Europe and most small fields in The Netherlands and surrounding countries would have been uneconomic during much of the lifetime of the Groningen field.
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Utilization of seismic attributes for reservoir mapping: A case study from the Cambay Basin, India
Authors A. K. Srivastava, B.G. Samanta, V. Singh and G. SenMultilayered Hazad sands of Middle Eocene age deposited in a deltaic environment are the main hydrocarbon producers in the south Cambay basin, India. These sands are broadly divided into 12 units (1 to 12) from bottom to top. These individual sand units are further subdivided into smaller subunits which are selectively charged and produce hydrocarbons in different parts of the south Cambay Basin. The study area covers a part of the Gandhar oilfield situated in the Broach-Jambusar block of the basin where subunits 3A and 12A have produced oil and gas in commercial quantities. Due to its widespread deposition and greater thickness, unit 3A was delineated and developed, based on conventional interpretation of 2D seismic data. The development strategy for unit 12A could not be completely resolved in the absence of a precise sand geometry map. A 3D seismic survey was carried out in the study area with one of the objectives being to map the lateral extent of thin pay sands exactly. According to the well data, the thickness of unit 12, consisting of subunits 12A, B and C, varies from 0 to 18 m, and wherever unit 12 is thicker, subunit 12A is present. Unit 12 is not resolved in the available seismic data but its seismic response is detectable. Synthetic seismic modelling has been carried out for a better understanding of the seismic response and for precise calibration. The seismic attributes extracted from the 3D data volume corresponding to unit 12 are utilized to generate a net thickness sand map of this unit using an artificial neural network technique. The sand geometry map of subunit 12A was prepared with the help of a net thickness map of unit 12 and well data. The thickness map of unit 12 helped in mapping the precise sand geometry of unit 12A and also an additional area for cost-effective exploration and development of this pay, which in turn improves the in-place reserves.
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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)