Integration of Core and Log Data for Improved Reservoir Saturation ...

SPE 106350 Enhanced Petrophysics: Integration of Core and Log Data for Improved Reservoir Saturation Monitoring S. Mark Ma, A. A. Al-Hajari, D. G. Kersey, and Jim J. Funk, Saudi Aramco, K. Holmes and G. Potter, Core Labs

This paper was prepared for presentation at the 2006 SPE Technical Symposium of Saudi Arabia Section held in Dhahran, Saudi Arabia, 21-23 May 2006. Copyright 2006 Society of Petroleum Engineers This paper was selected for presentation by the Technical Symposium Program Committee following review of information contained in full manuscript submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members.

Abstract Oil migrating into a water saturated reservoir is a drainage process while waterflooding an oil reservoir is a water imbibition process. Many factors affect drainage and imbibition rock properties including pore structure, rock surface properties (lithology) and their interactions with pore fluids (wettability), and fluids displacement processes. Difference in drainage and imbibition is significant and this difference should be considered, but is often neglected, in reservoir saturation monitoring (RSM). In this study, fundamentals of rock properties and their interactions with oil and water were reviewed. In a specially designed laboratory special core analysis program, both drainage and imbibition rock properties were measured in the laboratory, at reservoir conditions, using reservoir rock samples, crude oil, and synthetic brine. Wettability was restored by aging the rock samples in crude oil at temperature. Pore structure was characterized by integrating capillary pressure and petrographic studies. Rock lithology was determined by X-ray diffraction measurements and thin section examinations. All laboratory measurements were integrated to better understand drainage and imbibition rock properties. In applying the laboratory determined rock petrophysics to field RSM, time-lapse resistivity logs were used to identify the current dynamic water-oil contact (DWOC). Above this DWOC, drainage rock properties were used for log processing while below this contact imbibition rock properties were used. Field examples are shown to demonstrate the applications of drainage and imbibition petrophysics in evaluating waterflood sweep and identifying intervals for potential side-tracks.

Introduction Monitoring reservoir saturation changes with time during waterflood is a basic measurement for reservoir management. With the dynamic data, reservoir engineers can make confident decisions on operations such as water shut-off, sidetrack for a new horizontal producer, or re-perforation for remaining oil. Reservoir saturation monitoring also provides reservoir engineers with data to evaluate the efficiency of improved oil recovery methods. To properly extract reservoir saturation from time-lapse logs, data needs to be integrated with information from other sources such as the original openhole logs, time-lapse production logs, well conditions and history, well test data, and laboratory core analysis data (Ma et al., 2005a). Performing data integration requires knowledge of fundamental rock petrophysics – properties of rock, oil, water and their interactions. The main objectives of this paper are to (1) review fundamental petrophysical aspects of fluid flow and distribution in reservoir rocks, (2) integrate rock petrophysics with time-lapse reservoir saturation monitoring logs for more accurate reservoir saturation monitoring, and (3) in-depth review the procedures used in this laboratory core analysis study and recommended improvement for future similar studies. Fundamentals of Rock/Oil/Water Interactions Capillary Pressure in Reservoir Rocks Capillary pressure (PC) in oil-water saturated rocks is the product of the oil-water interface curvature (COW) and the By interfacial tension between oil and water (σOW). conventional definition in reservoir engineering, capillary pressure in reservoir rocks is defined as the difference between oil phase pressure (PO) and water phase pressure (PW).

PC = C OW σ OW = PO − PW

(1)

During oil migration, oil phase pressure is higher than water phase pressure. The oil-water interface curvature is defined as positive and capillary pressure is positive. During

1

waterfloooding, the curvature of the oil-water interface changes sign and water phase pressure increases and eventually is higher than oil phase pressure, then capillary pressure becomes negative. Capillary pressure dominates fluid distribution and affects flow fluid in reservoir rocks. Capillary pressure can be expressed as a function of pore size, pore geometry, wettability (in terms of contact angle, θ), and saturation. For oil-water co-existing in a cylindrical tube with a diameter d, capillary pressure can be written, PC = C OW σ OW =

4σ OW cos(θ ) d

(1a)

Eq. 1a is most commonly used in determining pore-throat size (d) distribution from mercury injection capillary pressure measurements or in analyzing NMR log to derive information of pore-body size. For oil-water in a fracture formed by two parallel semiinfinite plates separated by a width w, capillary pressure is PC = C OW σ OW =

2σ OW cos (θ ) w

(1b)

For oil-water in a corner with an angle of 2α of an angular tube, capillary pressure can be expressed as a function of wettability (θ), pore geometry (α), pore size (L), and saturation (Sw). PC = C OW σ OW =

2σ OW cos (θ + α ) L( S w )

(1c)

Where L, a function of Sw, is the distance between the two symmetrical three-phase-contact lines of opposite of the corner. Drainage of Oil and Mixed Wettability Typical hydrocarbon reservoirs were originally saturated with water, i.e., water-wet (Fig. 1). During oil migration, oil displaced water and occupied part of rock pore spaces (center of large pores connected with large pore-throats) where capillary pressure was low (Figs. 2a and 2b). After oil invaded rock pore spaces, a water film existed between the rock surfaces and the invaded crude oil. The stability and durability of this water film depends on properties of water (salinity and pH, Gomari and Hamouda, 2005), oil (concentration of polar heavy compounds), rock (surface energy, roughness, and pore geometry), and reservoir conditions (temperature and pressure). After geological time (millions of years) of contact between oil, water, and rock, the water films between the rock surface and oil could be ruptured allowing oil to be absorbed onto the rock and rendering the rock surfaces oil-wet. The degree of the oil-wetness depends on the properties of the water film, oil and rock. In areas where capillary pressure is high (small pores or corners of large pores), rocks are still covered with water (connate water) and the rock surfaces covered with this bulk water remains water-wet. The overall wettability of the reservoir rock is often characterized as mixed-wet (water-rock

2

interfaces are water-wet and oil-rock interfaces have various degrees of oil-wetness). The degree of mix-wettability is strongly correlated with the magnitude of connate water saturation; other conditions are same (Zhou et al., 2000). Imbibing of Water and Trapping of Oil When injected water contacts a mixed-wet reservoir rock during a low rate waterflood, the water will first spontaneously imbibe into the rock pore space, starting from smaller pores or corners of large pores where capillary pressure is high (Fig. 3a). This spontaneous imbibition of water will cease when capillary pressure drop to zero and forced water imbibition will start with increasing in injected pressure. Before the water/oil/rock three phase contact line (point A of Fig. 3a-I) moves during forced imbibition, contact angle (a measure of wettability) changes from receding to advancing. Differences between receding and advancing contact angles indicate wettability hysteresis due to change in displacement process (Ma et al., 1996). In the process of the water/oil/rock three phase contact line movement, if two or more water-oil interfaces touch each other in the pore system, these interfaces will be merged and new interface(s) will be formed. In this interfaces redistribution, oil may be trapped through mechanisms such as snap-off (Fig. 3a-II). This trapped oil can be calculated from resistivity logs using imbibition rock electric properties (Ma et al., 2005b). Residual oil in reservoir rock is established when relative permeability to oil approaches zero at a displacement pressuredrop less than that required to reach the critical capillary number.* Residual oil saturation for mixed-wet rocks could be small (i.e., less than 10%). Fig. 4 illustrated typical capillary pressure curves of primary drainage and imbibition for a carbonate rock sample, tested in this study. In this example, both connate water and residual oil saturations are small. The magnitude of residual oil is strongly affected by rock wettability, as illustrated by Figs. 5 and 6 (Braun and Holland, 1995); in addition to rock pore structure. Experiments Understanding rock properties and rock/oil/water interactions is fundamental in designing fit-for-purpose laboratory special core analysis (SCAL) programs. In this study, a comprehensive formation evaluation SCAL program was designed for time-lapse resistivity reservoir saturation monitoring. Test Materials Core samples used in this study are reservoir rocks cored in 1994. These cores were subsequently sampled, solvent cleaned, measured for basic rock properties such as porosity, *

Capillary number (NC) is defined as the ratio of displacement pressure-drop (∆P) over capillary pressure (PC). When NC is less than a critical capillary number (NCC), residual oil saturation (SOR) is insensitive to ∆P. When NC>NCC, SOR decreases with increase in ∆P (Taber, 1969).

permeability, and matrix grain density. Geological description was also performed. Based on these measured rock properties and geological description of the cores, samples for rock electrical properties measurement were selected in 2003. The selected samples were CT scanned to detect any internal features (highly heterogeneous or fracture) that may disqualify them for future testing (Fig. 7). The finally selected samples cover a wide range of porosity from low to high in order to obtain representative Archie porosity exponents (m). They also include limestone and dolostone samples for study potential effects of rock lithology on electrical properties. A crude oil sample was collected from a near-by dry oil producer. The oil was filtered in the laboratory to remove any impurities. The cleaned oil was stored in a closed container for use of aging the rock samples for wettability restoration and core floods for electrical properties measurement. Synthetic formation water with a salinity of 200 ppk, similar to the reservoir connate water salinity, was used throughout this study. Test Procedures Laboratory test procedures for formation evaluation special core analysis need to be specifically designed to meet objectives of the test. Rock samples, crude oil, and formation water are different from reservoir to reservoir. Generic laboratory test protocols are used as a starting point for the reservoir specific laboratory test procedures. A detailed test procedure designed specifically for this study is documented in Appendix A. Laboratory Test Results and Discussions

Fig. 8 shows the cross-plot between rock porosity and formation factor (F) for all rock samples used in this study. Archie porosity exponent m is derived from the slope of a regression line across the data points, based on the first Archie equation (Archie, 1942). RO a = RW φ m

Archie Saturation Exponent, n While multi-rock-samples with a range of porosities are needed to determine the Archie porosity exponent m, Archie saturation exponent n is determined on a single rock sample. Fig. 11a shows a relationship between resistivity index (RI defined as the ratio between rock resistivity (RT) while it is saturated with both oil and water, Sw