Egypt’s Deepwater Oil and Gas Development: Technology will aid recovery from complex structures, find new fields

At its most fundamental, deepwater exploration and development is about cost and risk. In the past two decades, advancing technology has made it possible to dramatically reduce both. The result is increased exploration success and a lower commercial threshold that makes more discoveries—in ever deeper water—commercially viable.

Petroleum demand will continue to grow and deep water fields will be increasingly important in meeting that demand.

In late 2007, Douglas-Westwood updated its World Deepwater Market Report to cover 2008-2012. The report, for water depths of 500 m (1,640 ft) and more, forecasts annual worldwide capital spending will reach nearly $25 billion over the period. “The deepwater oil and gas industry is set for continued growth through to 2012, with over 30% growth forecast for 2008-2012, compared with the previous five years,” said John Westwood, Managing Director, at PennWell’s Deep Offshore Technology International Conference and Exhibition in Stavanger.

Deepwater oil production currently accounts for almost 15% of total offshore production, but deep water will represent about 20% of offshore production by 2011, he said. Together, Africa, the Gulf of Mexico and Brazil will account for 84% of global deepwater spending over the period, said Westwood.

Advancing technology continues to bring new discoveries in Egypt’s existing concessions. And it enhances interest in prospects in even deeper water, as evidenced by the results of a recent bidding round.

But executing Egypt’s deepwater projects pose a wide variety of technical challenges, including a difficult geo-technical environment, a variety of reservoir pressures and fluid compositions, and high temperature/high pressure conditions. Besides meeting these immediate challenges in each development project, the high cost of deepwater operations makes it important to provide for future growth and expansion.

Geologic setting

In Egypt’s prospective deepwater areas, the spectrum of technology available today to understand and optimize the life cycle value of a discovery is especially important because of the complexity of many of the productive zones. The main producing reservoirs in the western part of the Nile Delta deep water are mostly submarine channel features, with extended submarine fans farther north. Sealing rocks are provided by the intra-formational Pliocene-Pleistocene mud stone.

Gas comes from both thermogenic and biogenic sources and includes some condensate. Only shallow reservoirs in one or two fields contain gas entirely from a biogenic origin; the majority of discoveries suggests a predominantly thermogenic origin.

Migration of hydrocarbons from Oligocene- Miocene source rocks probably occurred along the active faults. Currently, evidence of the pre- Tertiary sources is proven by carbon isotopes.

The major structural elements are the southwest/northeast trending Rosetta fault and the east-northeast/west-southwest trending Nile Delta offshore anticline (NDOA) high. Both of these were active at various periods during the Pliocene-Pleistocene periods. But they have not had a major impact on the depositional geometries of the Upper Pliocene channels, which when traced in map and seismic sections, show no significant thickening or change in style across the features.

The crestal part of the east-northeast trending NDOA is collapsed by a tectonic listric fan developed in response to a cycle of negative tectonic inversion where the extensional regime dominated in the Upper Early Pliocene. This indicates that the time of the tectonic inversion along the east-northeast trend is younger than that on the northeast-trending Rosetta belt.

Applying technology

Using up-to-date techniques enhances reservoir understanding, leading to a more accurate estimate of reserves, and better well and reservoir optimization. Rashpetco uses the latest technology to maximize hydrocarbon productivity and reduce development risk in the offshore deltaic area.

Seismic inversion is used to calculate the relative and absolute acoustic impedance to discriminate between the hydrocarbon bearing sands and non-reservoir zones. However, this technology may fail to discriminate between shale and water-bearing sand, according to the company, and pre-stack amplitude variation with offset (AVO) inversion was used successfully as a lithology and fluid indicator.

The technique reduces drilling risk and improves static and dynamic reservoir models. The rock physics model is also essential in offshore deltaic sequences, according to Rashpetco.

In addition to defining lithology and fluid content, parallel multiple 3D seismic attributes are used to define the stratigraphic and structural setting of the area. Long offset seismic re-processing trials reduce risk by enhancing the horizontal and vertical resolutions of reservoir sequences.

Thin bedded intervals containing significant amounts of net pay identified in the Mediterranean are considered by Rashpetco as potential development targets. These thin bed successions are often less than 10 cm thick, sandstone and siltstone sheets deposited from sediment gravity flows and inter-bedded with shale.

Lateral continuity, connectivity and bed lengths are important influences on reservoir performance and recovery that cannot be deduced from seismic and conventional well log data. Rashpetco used combinations of tools in different fields to image these unconventional pays and quantify hydrocarbon pore volume.

Reservoir modeling was used to test the impact of these unconventional pays on gasin- place calculations.