Asia Pacific Santos discovered gas with the Corvus-2 well in the Carnarvon Basin, offshore Western Australia. The well, located in permit WA-45-R, in which Santos has a 100% interest, reached a total depth of 3998 m. It intersected a gross interval of 638 m, one of the largest columns discovered across the North West Shelf. Wireline logging to date has confirmed 245 m of net hydrocarbon pay across the target reservoirs. Total SA and partners ExxonMobil and Oil Search have signed a gas agreement with the government of Papua New Guinea that defines the fiscal framework for the Papua LNG project in the country's Eastern Highlands. The plan involves construction of three 2.7-mtpa LNG trains on the existing PNG-LNG plant site at Caution Bay just west of Port Moresby. Total has 31.1% interest, ExxonMobil has 28.3% interest, and Oil Search has 17.7%.
Africa (Sub-Sahara) Mazarine Energy has started a two-well drilling campaign in the Zaafrane permit in central Tunisia. The first well, Cat-1, has been spudded and is targeting the Ordovician interval at a planned total depth of 3900 m. Mazarine (45%) is the operator with partners ETAP (50%) and MEDEX (5%). Asia Pacific China National Offshore Oil Company (CNOOC) has made a natural gas discovery at its deepwater Lingshui 25-1 well, northeast of Ledong sag in the South China Sea's Qiongdongnan basin, where the average water depth is 980 m. The well was drilled to a depth of 4000 m and encountered 73 m of oil and gas pay. During a test, the well produced approximately 35 MMcf/D of natural gas and 395 BOPD. CNOOC holds full operated interest in the license.
Africa (Sub-Sahara) Bowleven began drilling operations at its Zingana exploration well on the Bomono permit in Cameroon. Located 20 km northwest of Douala, Cameroon's largest city, the well will target a Paleocene (Tertiary) aged, three-way dip closed fault block. The company plans to drill the well to a depth of 2000 m and will then spud a second well in Moambe, 2 km east of Zingana. Bowleven is the operator and holds 100% interest in the license. Asia Pacific China National Offshore Oil Company (CNOOC) has brought its Dongfang 1-1 gas field Phase I adjustment project on line ahead of schedule. The field is located in the Yinggehai basin of the Beibu Gulf in the South China Sea and has an average water depth of 70 m. The field is currently producing 53 MMcf/D of gas and is expected to reach its peak production of 54 MMcf/D before the end of the year.
Africa (Sub-Sahara) Bowleven has started drilling operations at the Moambe exploration well on the Bomono permit in Cameroon. Moambe is the second well in a two-well program, approximately 2 km east of the first well, Zingana. It targets a previously undrilled Paleocene Tertiary three-way dip fault block containing multiple sands and will be drilled to an estimated 1620 m in measured depth. Both wells will be logged. Bowleven is the operator and holds 100% interest. Asia Pacific Murphy Oil discovered gas at its Permai exploration well in deepwater Block H in the South China Sea offshore Malaysia. The find is Murphy's eighth consecutive success in the area around the Rotan floating liquefied natural gas project, which is planned to begin its first production in 2018.
Africa (Sub-Sahara) Eni discovered gas and condensate in the Nkala Marine prospect offshore Congo. The discovery could hold from 250 MMBOE to 350 million MMBOE in place, the company said. In a production test, the Nkala Marine 1 discovery well in the Marine XII block yielded more than 10 MMcf/D of gas and condensate. Eni is the operator with a 65% interest in the block. The remaining shares are held by New Age (25%) and Societé Nationale des Pétroles du Congo (SNPC) (10%). Sonangol and Total will break ground on a deepwater oil pumping project that will increase Angola's production by more than 30,000 B/D.
We present a case of seismic reservoir characterization within a multi-source depositional setting. To resolve issues of non-uniqueness between intrinsic reservoir properties and the seismic data, we use a probabilistic approach. Stochastic rock physics relationships are used to establish a link between elastic parameters and various lithology classes. We highlight the importance of concurrently using multiple lithological prior models to achieve an improved understanding of the seismic response of the Edvard Grieg field. Application of a one-step inversion approach, which assesses the direct conditional (posterior) distribution of elastic parameters, yields improved reservoir prediction particularly in regions where the reservoir sandstones are thin. Quantitative prediction and interpretation of impedances and lithology volumes is done in light of selected models and associated uncertainties.
Presentation Date: Monday, October 15, 2018
Start Time: 1:50:00 PM
Location: 206A (Anaheim Convention Center)
Presentation Type: Oral
Summary A profile across the Edvard Grieg field has been used to test and benchmarking various Seismic BroadBand acquisition and processing technologies during its rapid development between 2010 and 2015. This includes Geostreamer, BroadSeis, Isometrix, P-Cable and a series of variable 2D cable geometries which will be presented. Furthermore, test results from form a newly develop multivessel Broadband acquisition concept will be presented. Introduction The Utsira High South referred to as the Haugaland High was explored on and off for 40 years before the Edvard Grieg 16/1-8 breakthrough discovery was made in 2007 (186 million bbls oil). This discovery opened up for the Johan Sverdrup 16/2-6 discovery in 2010 (1,7-3,0 billion bbl oil), figure 1.
Chatterjee, Amitabha (Schlumberger) | Baig, Mirza Hassan (Schlumberger) | Sylta, Karl-Erik Holm (Schlumberger) | Datir, Harish (Schlumberger) | Donadille, Jean-Marc (Schlumberger) | Leech, Richard (Schlumberger) | Kollien, Terje (Lundin Norway AS) | Foyn, Sven Erik (Lundin Norway AS) | Gianotten, Ingrid Piene (Lundin Norway AS)
Until recently, an exploration petrophysicist expecting a pay zone with good porosity and high resistivity might simply have disregarded a conglomerate reservoir on the Norwegian continental shelf. The conglomerates observed in the North and Barents seas are mineralogically complex and present either low-resistivity/low-contrast or low-porosity/low-hydrocarbon pore volume conditions. However, in recent years, newer measurements and evaluation techniques have become available, which in addition to conventional logs, have been used to enhance the petrophysical evaluation of a number of important oil and gas conglomerate discoveries made in both siliciclastic and carbonate settings in the North and Barents seas. These Jurassic-Triassic aged reservoirs hold economically viable contingent reserves and exhibit production rates varying from 1,000 BOPD to more than 3000 BOPD.
Conventional logs acquired in the carbonate conglomerates of the Barents Sea and the conglomeratic sandstones of the North Sea have proven difficult to interpret. Low porosities, varied mineral distributions, heterogeneous pore systems, low resistivity contrasts between hydrocarbon- and water-bearing intervals, variation in rock texture, and the presence of immovable hydrocarbons can represent a formidable petrophysical evaluation challenge. Even at depths where the presence of hydrocarbon is established, formation testing in some cases results in either tight (low-mobility) tests or flows water during sampling. For this reason, hydrocarbon moved by mud filtrate invasion is often a better indicator of producible pay than that inferred from favorable hydrocarbon saturations alone.
We present an integrated petrophysical evaluation technique combining induced gamma ray spectroscopy measurements, used to create a reliable lithology/porosity model, with dielectric dispersion measurements, used to provide fluid saturations. The resulting analysis accurately reveals the subtle differences in shallow versus deep saturations that are critical in predicting movable hydrocarbon in the conglomerates. Provided as a timely delivery prior to formation testing, the predictive power of the petrophysical evaluation is illustrated by agreement with the subsequent formation testing data.
Four field examples, one from the North Sea and three from the Barents Sea conglomerate reservoirs, are discussed in this paper. The proposed evaluation technique is based on an integrated petrophysical analysis of dielectric dispersion, induced gamma ray spectroscopy, and standard log measurements. The method has consistently proven successful at defining intervals containing producible pay in multiple wells across the complex and varied conglomerate discoveries on the Norwegian continental shelf.
Magne Emhjellen, Petoro A/S; and Petter Osmundsen, University of Stavanger Summary Socioeconomic criteria for climate projects were used in analyzing the value of the climate benefit of a reduction in carbon dioxide. These reports are optimistic, yet European carbon-captureand-storage (CCS) demonstration plants are not implemented as expected. Little attention was devoted to profitability assessments on the basis of commercial considerations. Economic valuation of climate projects, seen from the perspective of the commercial companies that are to implement the projects, is the subject of this article. We examine key economic parameters of 27 oil and gas projects and compare them to a CCS project. We find that the CCS project ranks the lowest and is unlikely to be implemented by a private company. Our findings may explain why it is hard for oil companies to justify climate projects in their portfolios.