- Home
- Conferences
- Conference Proceedings
- Conferences
PGCE 2008
- Conference date: 14 Jan 2008 - 15 Jan 2008
- Location: Kuala Lumpur, Malaysia
- Published: 14 January 2008
41 - 60 of 79 results
-
-
The Application of CSEM (Controlled Source Electromagnetic) Technology as a Tool to Complement 3D Seismic Interpretation and Avo Analysis in a Deepwater Prospect: A Case Study on Prospect B, Block 2F, Offshore Sarawak
By Wong Eng YaoThe Controlled Source Electromagnetic (CSEM) method has emerged into the oil and gas exploration industry, especially in deepwater exploration, and provides geoscientists another tool to assess a prospect by looking at another physical property, i.e. resistivity, besides acoustic properties that can be derived from seismic and AVO analysis. In this context, CSEM technology is no doubt a tool to complement seismic interpretation and AVO analysis by offering an independent data set to exploration work. However, as the technology is purely based on resistivity contrast down-earth, there is still room for debate as to whether or not the technology is capable enough to help in delineating the true geology of an area. This paper presents the result of a 2D CSEM survey over Prospect B of Block 2F, Rajang Delta, offshore Sarawak. The 3D seismic of the prospect shows a high amplitude anomaly at both crest and flanks of the structure (Figure 1); while AVO analysis over the crest of the structure gives a Class III AVO response which hints at an existence of a gas cap (Figure 2). The CSEM response displays a positive magnitude buildup which indicates a resistive body lying beneath (Figure 3). The question left here is the geological model that would explain all the responses obtained whilst honoring the geological (stratigraphic) information from wells drilled in the area before; Whether what lies beneath is truly a sizeable and quality gas reservoir, or, considering the limited resolution of seismic and stacking response of CSEM technology, just thinly-bedded siltstones that wouldn’t bring much excitement. A discussion will be presented in this paper based on the Depth Migration result of CSEM method.
-
-
-
Recent CSEM Learnings in Deepwater Borneo
Authors Matthew Choo, Chester Young, Ling Chin Tiong and James Beer and Peter ShinerControlled Source Electromagnetic (CSEM) is an emerging technology with the potential to provide detailed resistivity images of the subsurface. In the context of exploration in DW Borneo, given the potential to directly image the high-resistivity zones associated with hydrocarbon pay, the technology was regarded as the ideal tool to reduce one of the most significant exploration risks in the basin – seal failure. A number of significant early successes over DW Borneo’s toe-thrust anticline plays confirmed the potential promise of the technology as an exploration tool in the basin. Following on this string of successes, CSEM data was acquired over a number of similar structures in 2006. Application of industry-standard processing and interpretive techniques on the data revealed an encouraging CSEM anomaly. However, proprietary inversion techniques indicated the possible presence of a shallow surface resistive body, while hinting at the presence of slightly elevated resistivities at depth. An exploration well campaign was carried out over the prospect late in 2006, but rather than encountering the expected hydrocarbon pay, the well encountered a near surface and resistive hydrate layer. Good quality but waterbearing reservoir was encountered at the target depth. This disappointment was the first CSEM negative test in the basin and highlights the need for further development of processing and interpretation methodologies. This paper will present the key CSEM experiences in DW Borneo to date, highlighting on the pros and cons of a still promising and evolving technology in what is still a challenging area.
-
-
-
CSEM Pilot Survey in Southeast Asia: Challenges and Takeaways
Controlled Source Electro-Magnetic (CSEM) surveys have proved to be useful in de-risking the hydrocarbon prospects in the deep water environment, due to their capability to distinguish between the brine and hydrocarbon saturated reservoirs. However, the interpretation of CSEM response in marginal water depths and complex geological setups remains challenging due to the interference of airwave with electromagnetic field and the background resistivity variations. In the year 2006, PETRONAS conducted a pilot CSEM survey in one of its offshore block in Southeast Asia. The survey was aimed to understand the key risks of the two hydrocarbon prospects identified in the area and to evaluate the strengths and limitations of the CSEM technique for its future application in shallow water depths and complex geological setups.
-
-
-
Channel Chasing in Malay Basin Using Mega Merged Data
More LessIn 2005, the Basin Studies Group of PRAM, PMU merged 29 3D dataset of the South Eastern part of the Malay Basin. The 3D dataset for the merging ranges from vintage data of 1995 to 2004 covering an areas of approximately of 20,000 sq km with a volume of 1.7 Terra byte of data (Figure 1). The Regional Study of the Malay Basin was carried out by utilizing the 3D Mega Merged Seismic data. With the huge volume of data involved, new technology of hardware and software was applied to handle the data. 3D volume interpretation software and a high end machine (i.e. 128G Machine) is required to do structural and horizons interpretation for the purpose of evaluating any new leads and prospects available in the entire South eastern part of the Malay Basin. By leveraging and integrating the rich information content of geophysical and geological data of the Malay Basin, near field opportunities of new play type and leads/ prospects will be able to be identified/emerged from the study. Malay Basin is a mature basin in terms of exploration activities in Malaysia and one of the objective of the Mega merge project is to carry out a seismic modeling on regional scale to define regions of common response i.e. channel, point bar. Total of ten (10) horizons tops (D, E, F, H, I, J, K, L, M & Basement) and almost 400 faults were interpreted on the mega merge seismic cube. Forty (40) control wells were also used as formation tops for calibration. Fifteen (15) Regional 2D RC lines were also incorporated in the study for areas where no overlapping of the 3D seismic. Extensive attribute works i.e. Spectral Decomposition, Sweetness, Amplitude Extraction, Reflection Strength has been carried out to identify potential stratigraphic leads and prospect and possible fracture basement. Multiple and stack channels trending from different levels can be observed from the attributes work generated. Most of the channels identified are from Group E, F, I and H of the Lower to Middle Miocene trending NE – SW direction (Figure 2 & Figure 3). Majority of channels presents are observed in Block PM 309 and PM 312 and others are seen in most of the PM Blocks
-
-
-
Innovative Frontier Exploration Using Seismic and SeaSeep Data, Indonesia: Implications for Malaysia
More LessMost of the world’s oil was discovered using onshore surface maps and seeps. Within the past few years, technologies developed for conventional marine hydrographic surveys and anti-submarine warfare have been upgraded, modified, and integrated for offshore petroleum exploration and in particular, deepwater (400– 3,500m) exploration. Very high resolution maps of the sea bottom and zones of oil and gas seepage may be identified using a vessel traveling at 10 knots and surveying a swath of about 4 km. Similar advances in subsea positioning enable accurately-navigated piston-core to sample features we identified on sea-bottom map. These cores can be subjected to modern geochemical analysis and therefore locations of thermogenic hydrocarbon charge may
be identified. In December 2006, TGS-NOPEC commenced the world’s largest multibeam and the world’s first non-exclusive SeaSeepTM survey as part of an innovative exploration program in the offshore frontier basins of Indonesia. The program was underwritten by Black Gold Energy and co-sponsored by Joint Study partner MIGAS.
-
-
-
Time-Lapse Seismic Modelling in Malay Basin
More LessTime-Lapse seismic has become as an important petroleum reservoir monitoring and management tools since its successful application in 1990s. The fundamental principle underlying the time-lapse seismic is simple, that is, the changes in reservoir parameters or properties are directly related to the differences in seismic response between the monitor and the base surveys. In reality however, the application is not that simple. There are many issues needed to be understood and considered before concluding any differences observed are due to changes in reservoir properties and not due to other factors such as seismic acquisition parameters and seismic processing artifacts. Feasibility study prior to a full time-lapse seismic project is crucial in providing information that helps guide our expectations. Changes in fluid type and saturation may not necessarily be significant enough to induce a large impedance contrast and consequently detected by seismic signal. The reservoir pore-fluids, rock matrix and frame, and reservoir conditions need to be fully understood to ensure the success of any timelapse seismic study. There are many aspects of a time-lapse feasibility study that need to be considered such as seismic acquisition design, processing algorithm and parameters, reservoir production, reservoir fluid properties, reservoir rock properties, reservoir monitoring program, geomechanics, seismic modeling, etc. This paper will focus on the fluid properties and seismic modeling aspects of the feasibility which is thought able to give, if even not full, a sufficient understanding on how pore-fluid type and saturations in the reservoir with varying types and thicknesses of cap rock could affect the resultant seismic amplitude, the fundamental element of any time-lapse seismic study.
-
-
-
Fit for Purpose Time Lapse Seismic at F6
Authors Elvis Chung and Paul HagueF6 is Shell’s largest gas field in the offshore Sarawak, with a GIIP (Gas Initially In-Place) of around 7Tcf (Trillion Cubic Feet). Production commenced in 1987 from a single platform located above the central pinnacle of the carbonate build-up. By 2006, 4Tcf had been produced, but scope for redevelopment still remains in the form of further drilling and late life compression. However, the biggest uncertainty is the strength of the aquifer and the movement of the GWC (Gas Water Contact). Pulsed neutron logging indicates a GWC rise near the main producing area beneath the platform but a large uncertainty remains towards the flanks. The first 3D seismic survey over F6 was acquired in 2002 (15 years after production start-up), which means there is no suitable pre-production 3D baseline survey. Prior to commitment to the project, a feasibility study was carried out within SSB (Sarawak Shell Berhad) using the 2002 dataset as the 3D baseline. The objectives were primarily, to determine if production-related sweep signals are observable on seismic and if so, when is the ideal time to carry out the monitor survey in order to impact business decisions. The feasibility studies showed that a time-lapse seismic response could be expected in 2006 but highlighted that the timelapse
signals on the flank may be weak to image. This is largely driven by the two different reservoir model inputs in the feasibility study, which could be a uniform rise of the GWC or cone-shape rise of the GWC. Both models also have significant impact on recoverable gas on the flanks as illustrated as in Figure 1. Finally, the changes in the velocity and impedance from both models were found to be small (<5%) and thus, requires good repeatability and good signal-to-noise ratio (S/N) seismic data in order to observe time-lapse signals. Considering the possibilities from the study and the business impact of additional recoverable volume at the flank, the time-lapse seismic was a timely exercise to help understand the extent of water influx and derisk future investment on the field.
-
-
-
Large-Scale Pore Pressure Prediction after Pre-Stack Depth Migration in The Caspian Sea
More LessDespite all the difficulties, it seems that a successful attempt has been made in predicting the pressures in this difficult area. The main challenges are (1) the pressure compartmentalisation, (2) non pressure related influences on resistivity logs, (3) variable pressures, (4) sands and shales often not in pressure equilibrium and (5) an extremely difficult velocity and imaging environment. It is still required to undertake real time prediction of pore pressures while drilling. The current volumes can be used as a reference. Due to the challenges listed and the seismic limitations, there will always be an associated uncertainty and error with respect to the pressure predictions. But the best attempt has been made, and the PSDM has increased the accuracy and reliability of the velocity model. The pressure model used can be updated when new well data becomes available. Of vital importance and value is the combination of well mechanical and operational knowledge and seismic processing expertise.
-
-
-
Reservoir Characterization and Monitoring Using Multi-Transient Electromagnetic (MTEM)
More LessThe Multi-Transient Electro-Magnetic (MTEM) method implements a current bi-pole source with a sequence of receiver stations that measure the resulting voltage. Source and receiver stations are located in a straight line similar to 2-D seismic. Onshore and offshore acquisition systems have been developed providing continuous coverage of the subsurface including the transition zone. The earth’s impulse response is obtained for each source receiver pair by deconvolving the received voltage for the input current. The source signal is a Pseudo Random Binary Series (PRBS) that combined with vertical stacking allows us to maximize S/N. The subsurface resistivity is evaluated from the very shallow sediments down to the target depth by continuously optimizing the acquisition parameters. This involves adjusting the length of the source bi-pole, the bandwidth of the source PRBS, and the sampling rate of the recorded signal to be optimal for each offset range. The method allows for real time monitoring of the signal and real time assessment of the subsurface resistivity. The final deliverables are 2-D depth sections inverted to resistivity along 2-D profiles.
-
-
-
Oil and Gas Outlook: Acquiring a Clear Image of the Future
By Hovey CoxThe oil and gas industry, over its history, has seen times of great strength and long periods of weakness. It has also demonstrated a propensity for proving wrong those who try to predict its cycles and peaks. Over recent history we have experienced one of the greatest, if not the greatest, period of long-term economic growth worldwide. This expansion was literally powered by the relatively clean and inexpensive energy that fossil fuels, oil and gas in particular, provide. Over the past ten years, as economic development strengthened and energy consumption continued to climb, especially in the World’s emerging economies, several underlying factors in the energy landscape have started to challenge the oil and gas industry’s historic models. To meet the growing need for energy, E&P budgets increased across the industry focused primarily on production technology to optimize recovery from known assets. This reduced the risks associated with quarterly returns in the capital markets worldwide and at the same time increased depletion rates. When combined with flat-lining exploration spending and the resulting decrease in discovery rates, it also dramatically reduced spare capacity. Together these trends arguably, at least at the current time, moved the oil and gas marketplace from a supply-side to a demand-side driven market. Changes are needed. When the trends outlined above are compounded with: the growing geological and geopolitical complexities in our business, the rising concern worldwide over increasing energy costs and the industry’s environmental impact, it provides a clear opportunity to examine our current business as our historic models may not work as well in the future as the did in the past. We today, as an industry, sit at a unique place in history that suggests a review of possible directions and decisions. This presentation explores the current state of the industry along with its fundamental drivers to uncover the key challenges companies face today to successfully produce results tomorrow.
-
-
-
Petroleum Geomechanics: From the Plate-Scale to the Reservoir-Scale
More LessThe last 10-15 years have seen an explosion in the application of present-day stress data to petroleum exploration and development-related issues. Borehole breakouts, zones of wellbore where the cross-sectional shape is enlarged and elliptical, were first-named and recognised as being due to present-day stresses in the late 1970s (Figure 1). However, even by the early 1990s, few in the oil industry were familiar with borehole breakouts. Now they are used routinely, along with other present-day stress data, to
○ evaluate fault reactivation and reservoir seals; ○ evaluate naturally fractured reservoirs; ○ assess wellbore stability, and; ○ plan fracture stimulation and water flooding operations. This talk will illustrate how the reservoir geomechanical model (present-day stress and strength data) is determined using logging and drilling data. It will discuss the plate-scale, regional and local tectonic controls on present-day stress with examples from Brunei and the North Sea. Finally it will illustrate the application of the geomechanical model to exploration and development, with examples from Brunei and the North Sea.
-
-
-
Organic Facies Variation in Lacustrine Source Rocks in the Southern Malay Basin
Authors Abdul Jalil Muhamad and Awang Sapawi Awang JamilThis paper attempts to look at, in more detail, the source rock quality of the lacustrine shales within the Groups K, L and M in the southern flank of the Malay Basin. This study is made possible through the use of state-of-the-art linked-scan gas chromatography / mass spectrometry / mass spectrometry or GCMSMS to provide highly sensitive measurements of biomarkers which are typically in low concentrations in source rock extracts and oils, and especially so in condensates. Since only one well dataset is available, only the vertical variation in the source rock quality of the lacustrine shales is discussed. Stratigraphically, there is a noticeable change in the source rock quality within the three groups. In general, the TOC content of the lacustrine shale
sequences in Groups K, L and M range from 0.35 to 2.00 wt% (Fig. 1). Kerogen composition of these shales varies, showing mixtures of Type II and Type III indicating variable contributions from algal, bacterial and higher plant organic matter deposited in a highly to less oxidising environment (Fig. 2). This is indicated by hydrogen index (HI) values ranging from 137 to 403. Group L lacustrine shales seem to provide the best oilprone source rock with TOC values of 0.45 to 1.95 wt% and HI values in the range of 300 to 400 indicating predominantly Type II kerogens (Fig. 2).
-
-
-
Lacustrine Oil Families in the Malay Basin
Authors Abdul Jalil Muhamad and Awang Sapawi Awang JamilThe oils and condensates of the Malay Basin are being generated by two main source rocks - lacustrine and fluvial-deltaic, with varying degrees of mixing between them. In addition, a recent study on the petroleum systems in the northern part of the Malay Basin has also shown that fluvial-marine source rocks could also generate these oils. The focus of this paper is on the lacustrine oils i.e. with respect to their biomarker characteristics and the possibility of grouping them into different oil families. The area of study is the Anding and adjacent fields located in the southern Malay Basin.
-
-
-
Distal Turbidites of the Semantan Formation (Middle-Upper Triassic) in the Central Pahang, Peninsular Malaysia
More LessThe Semantan Formation has been interpreted as deep-marine deposits based on sedimentological and palaeontological studies (e.g. Metcalfe et al. 1982; Metcalfe & Azhar Haji Hussin, 1994; Mohd Shafeea Leman & Masatoshi Sone 2001). Convergence between the Eastmal/Indosinia and Sibumasu blocks during the late Triassic resulted in closure of the Paleo-Tethys Ocean (Hutchison, 1989). Remnants of this ocean are represented by the deep-marine deposits of the Semantan Formation (Middle to Upper Triassic) in the Central Belt of Peninsular Malaysia. Some outcrops of the Semantan Formation at SK Sri Tualang and Taman Mutiara, near Temerloh and along the Karak-Kuantan highway, were studied to gain a better understanding of the deep-marine sedimentary facies and sedimentation processes in the distal parts of submarine fans and basin plain environments (Figure 1).
-
-
-
Turbidite, Debrite or Something in Between: Re-Thinking the West Crocker Formation
Authors Ku Rafidah Ku Shafie and Mazlan MadonThe Oligo-Miocene West Crocker Formation (WCF) of West Sabah is often referred to as a sand-rich turbidite system, and has been the subject of detailed sedimentological studies during the last few years. The essential features of the WCF sediments can be observed at outcrops scattered within driving distance from Kota Kinabalu (Fig. 1). For the most part, thickly bedded facies, representing the high-density, sandy turbidites is found in most of the outcrops studied, with the exception of Taman Maju, Sepangar (Fig. 1), where there are more of the “classical” flysch-like, thin-bedded turbidites. In general, the Crocker is sand-rich and very thickly bedded (> 1 m), commonly 1.5-3 m thick, while some may be up to 35 m. Based on the presence of subtle scour and
amalgamation surfaces, these thick beds were formed not by a single flow but multiple flow events. Internally, the thick beds, most of which are poorly sorted despite the overall normal grading, are characterized by faint low-angle laminations, resulting from traction, passing upwards into contorted bedding due either to deposition from a slurry, or to soft-sediment deformation and dewatering. Deposition from slurry involves rapid dumping of a dense muddy and water-saturated mass of sediment. Hence, in these types of beds at least, there is strong evidence for some form of high-density (sandy) turbidity flows, slurry, or both. Erosion at base of the flows, indicated by flute casts and various other sole marks are common. Well-developed load structures, including large ball-and-pillow (or “jam roll”) structure due to loading and sinking of these dense flows into water-saturated muddy substrate are indicative of the scale and dynamics of these flows.
-
-
-
The Geographic and Stratigraphic Distribution of Cored-Sections in the Malay Basin
More LessThis paper shows the geographic and stratigraphic distribution of cored-sections based on the inventory of data from over two hundred wells (Chart 1, 2). These charts provide a quick assessment of the depth of well penetration and length of cored-section, stratigraphic tops, gross lithology and core availability within each stratigraphic unit.
-
-
-
Temana: Old Field, New Ideas and New Insights
Temana Field is located approximately 30km offshore from Bintulu in water depth of about 90 feet and was discovered in 1962 by exploration well TE-1. Development commenced following commercial volume confirmation by appraisal wells TE-9 and TE-10 in 1972. The field is divided into three areas; Temana West, Central and East. For more than 35 years, the development concept in Temana has been driven by the presence of structural plays. Well locations being placed mostly in the crest of anticlines. Even though there was a belief that a stratigraphic component was involved in the trapping mechanism, the bold move to test this concept was deferred until recently. Approximately 90% of the field’s production is from the H and I series which are characterized by
Miocene aged fluvial sands. The I60/I65 series in particular are said to have been deposited in a lower coastal plain environment with tidal influence. Developing the Temana fields entails several challenges, mostly due to the field’s rather intricate structure, consisting of over 80 structurally and stratigraphically isolated reservoir compartments. Furthermore, the channelised I60/I65 sands results in several pinch-outs, limiting the sand distribution across the field and resulting in relatively thin reservoirs. A new appraisal well TE-72 was drilled in 2004 in the Temana Saddle area to test the seismic anomaly on a plunging anticline for the presence of a combination stratigraphic and structural play. This appraisal well was motivated by encouraging results from wells TE-54ST1 and TE-71 for the I60 reservoir, in which a similar amplitude anomaly response was proven as oil bearing (Figure 1). Although the amplitude anomaly was not conformable with the structure at TE-72 well location, the well penetrated 58ft of thick
blocky I65 sands, confirmed as hydrocarbon bearing. The sand is observed to be shaled-out in the up-dip offset wells (Figure 2). This pinching-out of the I65 sands towards the northeastern direction gives the reservoir the stratigraphic play needed to act as a trapping mechanism for the hydrocarbon accumulation. Following the success of TE-72, several geological and geophysical studies were undertaken including a fluid substitution study and a reservoir characterization study on acoustics impedance inversion
volumes (Figure 3 & 4). This led to the drilling of three development wells (TE-73ST1, TE-74ST2 and TE- 51ST2) in the Temana Saddle area in 2006/07 to delineate fluid contacts and provide drainage points for I65 reservoir. The success of the drilling campaign is reflected in the production figure whereby production from a single well could reach as high as 3600 bopd. The producing wells confirmed the geological model and further established the integrity of the trapping mechanism. The accomplishment of the Temana Drilling campaign triggered more interest to further dissect the field. Existing seismic cube was reprocessed and subsequently an AVO study was embarked to further delineate the hydrocarbon bearing sands. The discovery from the appraisal well and the success of the recent development campaign inspire a new paradigm in exploring the Temana Field and opening a new chapter of stratigraphic and structural play concept, hence giving a new direction of exploration towards the flank of the structure.
-
-
-
Condensed Section Intervals within the Cycle II (Early Miocene) of the D35 Field, Balingian Province, Offshore Sarawak: Occurrence and Significance
More LessA marine condensed section is a thin stratigraphic interval characterized by very slow depositional rates (<1-10 mm/yr). The interval often comprises fine-grained sedimentary rocks characterized by the presence of highly radioactive and organic rich shales, glauconite, chemical sediments and hardgrounds/firmgrounds. The interval may be thoroughly bioturbated, variably fossiliferous and locally show concretionary cement. Condensed sections reflect particularly slow accumulation rates and thereby representing a significant pan of time within only a thin layer. Condensed sections commonly develop during transgressions, in such cases they may be connected with "maximum flooding surfaces" and form important sequence stratigraphic markers.
-
-
-
Using Gravity Data to Help Identify and Differentiate Mobile Shale Bodies, Offshore Sabah
Authors S. J. Campbell and M. Lennane and S.E. PisapiaThe reliable identification and definition of shale diapirs is important to reduce exploration risk. This poster describes the work carried out to establish the degree to which these shale bodies can be identified using high resolution gravity data from offshore Sabah. Test models show that, assuming reasonable density contrasts, mobile shale bodies of a typical size and geometry would give a 2-3 mGal amplitude and 7 to 9 km wavelength gravity low response. Therefore they should be resolvable with good, high resolution gravity data. The picture, however, is complicated in this area by the presence of numerous large bathymetric canyons. The larger of these are shown to yield a similar gravity response as the possible shale diapir bodies, although the gravity effect of these bathymetric canyons can be diminished to some degree by the use of the Bouguer gravity anomaly. The mobile shale bodies manifest themselves on seismic data as disturbed zones, often with a distinct high impedance contrast on the top. These have been identified on several seismic sections and usually correspond directly with observed 1 to 2 mGal low anomalies in the Bouguer gravity profiles, which can be further highlighted by the use of careful filtering. This gravity response is observed irrespective of whether there is interference from the bathymetric canyons or not. Given that this characteristic gravity response is observed in several places, disturbed areas in the seismic where there is uncertainty can be verified by looking at the Bouguer anomaly profile. The poster shows that such an uncertain zone with this characteristic gravity response is confirmed as a shale diapir by viewing the cross-line trace. For disturbed areas on the seismic data that don’t correspond to this same gravity response, alternative explanations might be sought such as the existence of a gas chimney.
-
-
-
Detection of 3D Distribution of Reservoir Sand Bodies by ANN– A Case Study in the North Malay Basin (1)–
More LessDetection of reservoir distribution in 3D is one of the most important tasks for petroleum exploration in the Malay Basin and Gulf of Thailand, where highly stratified thin sand reservoirs are distributed complicatedly. Geology Driven Integration (GDI)*1 is one of the most effective techniques utilized to analyze the seismic pattern and to predict reservoir distribution and lithologic change directly from seismic attributes applying Artificial Neural Network (ANN) method. This paper presents the case study in the North Malay
Basin which was carried out by JGI and CPOC in 2007.
-