Improved Techniques In Pulsed Neutron Evaluation In the Nipisi Gilwood 'A' Formation
Authors: Hamp T.A. , Edgson J.J. 
Published: March 2010

Abstract
This paper presents the development of improved log-derived permeability relationships through more accurate pulsed neutron evaluations of the Nipisi Gilwood "A" Sandstone. Existing pulsed neutron derivations have given an indication of flowing watercuts, potential flow profiles and residual oil saturation. Improved interpretation techniques combine existing open-hole porosity data with pulsed-neutron data to provide better evaluation of cased-hole water saturation, log porosity and log-derived permeability.

Introduction
Nipisi Gilwood Unit No. 1 is located approximately 200 miles (322 km) northwest of Edmonton (Fig. 1) and produces from a series of deltaic Gilwood sands in the Watt Mountain formation of Middle Devonian age. The reservoir was discovered in 1964 and was on primaryrecovery until the initiation of waterflood in March 1969. There are presently 26 water-injection wells and 176 oil-production wells in the unit.
In the past, injection profiles and conventional production logs have been combined with pulsed-neutron water saturation evaluation to define oil and water distribution in the various sandstone layers. The technique of determining a log-derived permeability at irreducible water saturation (ki) has been successful in delineating production from various sands within the Gilwood "A" Sandstone(1) However, anomalies that could not be attributed to well or formation problems were noted in some zones when compared with actual flow profiles. The purpose of this paper is to present a method of improved log interpretation to resolve these anomalies and provide a closer correlation between observed and interpreted results.

Reservoir Description
The Nipisi Gilwood Pool is composed of a series of deltaic Gilwood standstone within the Watt Mountain formation of Middle Devonian age. The pool is n stratigraphic trap (Fig. 2), pinching out in an updip direction along its eastern boundary. The reservoir is limited on the downdip edge by an aquifer(2). The field consists of three depositional facies: an alluvial plain in the west, consisting of braided-stream channel sands, and characterized by poor areal communication and poor pay;
a delta front in the east, consisting of sheet sands, and characterized by good vertical segregation and moderate pay; and
a delta plain in the central portion, consisting of stacked distributary channel sands. This area contains the bulk of oil reserves and it is here that logging activity in the field has been concentrated.
The pool has been shown to consist of up to five sands, which are interlain with shale and which have greatly varying porosities, thicknesses and permeabilities. This causes difficulty in achieving a uniform waterflood and can result in premature water breakthrough and unrecovered oil.
In 1973, results of flood tests on the native-state core from Well 250(3) indicated average connate water saturation to be 31 per cent, and provided the water-oil relative permeability curve shown in Figure 3.
The present weighted average reservoir presure of 2284, psia (15.7 MPa) is well above the bubble-point pressure of 1184 psia (8.2 MPa). Reservoir fluid properties are shown in Figure 4.(3)