Proper Core-Based Petrophysical Analysis Doubles Size of Ha'py Field
- William T. Bryant (BP Egypt Gas Business Unit) | Robert B. Truman II (Baker Atlas)
- Document ID
- Society of Petroleum Engineers
- SPE Annual Technical Conference and Exhibition, 29 September-2 October, San Antonio, Texas
- Publication Date
- Document Type
- Conference Paper
- 2002. Society of Petroleum Engineers
- 5.7 Reserves Evaluation, 4.1.2 Separation and Treating, 1.6 Drilling Operations, 5.1.2 Faults and Fracture Characterisation, 5.1 Reservoir Characterisation, 1.6.9 Coring, Fishing, 5.6.1 Open hole/cased hole log analysis, 4.1.5 Processing Equipment, 5.1.1 Exploration, Development, Structural Geology, 5.5.2 Core Analysis, 2.4.3 Sand/Solids Control, 5.6.2 Core Analysis, 1.2.3 Rock properties, 5.2 Reservoir Fluid Dynamics, 4.3.1 Hydrates
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The Ha'py Field is located offshore Egypt and is part of the Pliocene producing trend north of the Nile Delta. The original interpretation for the gas in place for the Ha'py Field by Amoco and others was 989 Bcf. Re-evaluation of the field increased the gas in place to 2045 Bcf proven. Subsequent production in the field has substantiated the large increase of the gas in place as a result of the re-evaluation. The initial underestimation of the gas in place was a result of the use of an incorrect log-derived porosity model. This porosity model is not compatible with the petrophysical water saturation relationship used. The incompatibility stems from the fact that petroleum engineers and petrophysicists have different definitions for the terms effective porosity and total porosity. The difference in definitions may lead a petrophysicist to improperly model the well logs to the available core analysis. In addition, the engineer may mis-apply the petrophysicist's results to the reservoir characterization. This improper application leads to a substantial underestimation of hydrocarbon pore volume. The higher the clay and shale content in the reservoir, the greater the error. Definitions will be clarified and explained as they apply to core analysis, reservoir engineering and petrophysics, along with examples using core analysis. Correct modeling of porosity data in these shaly reservoirs lead to the increased estimation of the gas in place.
The Ha'py Field is located in the frontier development area of the outer shelf of the Nile Delta.1 The offshore gas field, discovered by Amoco and IEOC (AGIP) in 1996, is one of the more significant gas discoveries in the Pliocene Trend, with gas in place estimated at approximately 2045 Bcf , (Figure 1).
The main reservoir in Ha'py Field is the A20 Sand of the Pliocene Kafr El Sheikh formation. In the Ha'py area, the Kafr El Sheikh consists of interbedded turbidite sands and prodelta shales.2 The A20 Sand is an unconsolidated clay-rich prograding fan built of slump deposits. The A20 Sand varies widely in thickness around the field, in places exceeding 100 m. The average porosity of the A20 Sand is 30 % with an average permeability of 10 md.
Structurally, the Ha'py Field lies within a province of northwest-southeast trending growth faults. The field is a structural trap formed where two of these growth faults merge. Kafr El Sheikh prodelta shales seal the trap, and is gas filled to the synclinal spill point. The reservoir ranges in depth from approximately 1350 to 1750 m, a 400-m gas column.
Ha'py Field was first recognized on the basis of a high-amplitude seismic anomaly, or "bright spot" as shown in Figure 2. Subsequent drilling of the Ha'py-1 discovery well confirmed the presence of gas in the A20 Sand that created the amplitude anomaly. Seismic mapping of the anomaly indicated a gas accumulation covering a large area (46 km , or 11,350 acres), but accurate determination of reserves within this area proved a difficult task. The anomalous interval exhibited variations in thickness and intensity, with numerous internal reflections as shown in both Figures 2 and 3. Furthermore, test results indicating a flow potential of up to 1.6 MCMD (56 MMcfd) appeared inconsistent with the shaly nature of the reservoir.
To address the uncertainties in resource size and deliverability, a reanalysis of the data and reservoir characterization study was conducted.
Definitions and Terminology
Petroleum engineers, in dealing with reservoir rocks, define two types of porosity: total porosity and effective porosity. "Total porosity is the ratio of the total void space in the rock to the bulk volume of the rock; effective porosity is a ratio of the interconnected void space in the rock to the bulk volume, each expressed in percent." 3
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