Fig. 16-Equivalent counterion conductance (B) vs. resistivity of equilibrating brine at various temperatures.

A simple physical model describing shaly sand conductivity was previously described by Waxman and Smits. The electrical conductivity of a water-saturated shaly sand was expressed as a function of a geometry factor, the brine conductivity, an effective concentration of clay exchange cations, and their equivalent ionic conductance. Experimental data support this relation. The model was extended to cases where the sands were oil-bearing. An expression was obtained relating the resistivity index to water saturation, brine conductivity, and the clay parameters mentioned above. The assumptions involved in the model for oil-bearing sands have now been confirmed by additional laboratory conductivity measurements. We conclude that the effective concentration of clay exchange cations is increased by a quantity proportional to the decrease in water saturation. Twelve different rock samples from seven fields were utilized in these studies, incorporating a wide range of brine conductivities, oil saturations, and cation exchange capacities. Further, the temperature coefficients of electrical conductivity were measured for a set of shaly sands equilibrated with salt solutions covering a wide range of concentrations. When compared at the same electrolyte concentration, these temperature coefficients increased systematically with increasing clay content of the sands.

This technique determines the value of cation-exchange capacity per unit pore volume (QJ of a shaly sand formation sample by using it as a membrane in an electrochemical cell. This new technique is nondestructive, eliminates prior core analyses, uses small samples, and provides representative values of Q, for nonisotropic and homogeneous samples. JOURNAL OF PETROLEUM TECHNOLOGY

Summary Determination of the type and quality of hydrocarbon fluid that can be produced from a formation prior to construction of production facilities is of equal economic importance to predicting the fluid rate and flowing pressure. We have become adept at making such estimates for formations drilled with water-based muds, using open-hole formation evaluation procedures. However, these standard open-hole methods are somewhat handicapped in wells drilled with synthetic oil-based mud because of the chemical and physical similarity between the synthetic oil-based filtrate and any producible oil that may be present. Also complicating the prediction is that in situ hydrocarbons will be miscibly displaced away from the wellbore by the invading oil-based mud filtrate, leaving little or no trace of the original hydrocarbon in the invaded zone. Thus, normal methods that sample fluids in the invaded zone will be of little use in predicting the in situ type and quality of hydrocarbons deeper in the formation. Only when we can pump significant volume of filtrate from the invaded zone to reconnect and sample the virgin fluids are we successful. However, since the in situ oil and filtrate are miscible, diffusion mixes the materials and blurs the interface; as mud filtrate is pumped from the formation into the borehole, the degree of contamination is greater than one might expect, and it is difficult to know when to stop pumping and start sampling. What level of filtrate contamination in the in situ fluid is tolerable? We propose a procedure for enhancing the value of the data derived from a particular open-hole wireline formation tester by quantitatively evaluating in real time the quality of the fluid being collected. The approach focuses on expanding the display of the spectroscopic data as a function of time on a more sensitive scale than has been used previously. This enhanced sensitivity allows one to confidently decide when in the pumping cycle to begin the sampling procedure. The study also utilizes laboratory determined PVT information on collected samples to form a data set that we use to correlate to the wireline derived spectroscopic data. The accuracy of these correlations has been verified with subsequent predictions and corroborated with laboratory measurements. Lastly, we provide a guideline for predicting the pump-out time needed to obtain a fluid sample of a pre-determined level of contamination when sampling conditions fall within our range of empirical data. Conclusions This empirical study validates that PVT quality hydrocarbon samples can be obtained from boreholes drilled with synthetic oil-based mud utilizing wireline formation testers deployed with downhole pump-out and optical analyzer modules. The data set for this study has the following boundary conditions: samples were obtained in the Gulf of Mexico area; the rock formations are unconsolidated to slightly consolidated, clean to slightly shaly sandstones; the in situ hydrocarbons and the synthetic oil-based mud filtrate have measurable differences in their visible and/or near infrared spectra. Specifically, this study demonstrates that during the pump-out phase of operations we can use the optical analyzer response to predict the API gravity and gas/oil ratio of the reservoir hydrocarbons prior to securing a downhole sample. Additionally, we can predict the pump out time required to obtain a reservoir sample with less than 10% mud filtrate contamination if we know or can estimate reservoir fluid viscosity and formation permeability. Extension of this method to other formations and locales should be possible using similar empirical correlation methodology. Introduction The high cost of offshore production facilities construction and deployment require accurate prediction of hydrocarbon PVT properties prior to fabrication. In the offshore Gulf of Mexico, one method to obtain a PVT quality hydrocarbon sample is to use a cased hole drill stem test. However, this procedure is usually quite costly due to the need for sand control. Shell has been an advocate of eliminating this costly step by utilizing openhole wireline test tools to obtain the PVT quality sample of the reservoir hydrocarbon. The success of this approach depends upon the availability of a wireline tool with a downhole pump that permits removal of the mud filtrate contamination prior to sampling the reservoir fluids, and a downhole fluid analyzer that can distinguish reservoir fluid from filtrate. One such tool is the Modular Formation Dynamics Tester (MDT).1 The optical fluid analyzer module of the MDT functions by subjecting the fluids being pumped to absorption spectroscopy in the visible and near-infrared (NIR) ranges. Interpretation of these spectra is the subject of this paper. Tool descriptions and basic theory of operations were presented in an earlier text.2 The concept of using visible and/or NIR spectroscopy to characterize the fluids being sampled while pumping is straightforward when there are measurable differences in the spectra of the mud filtrate and the reservoir hydrocarbons. As shown in Fig. 1, there are well known areas3,4 of the NIR spectrum (800-2000 nm) that are diagnostic of water and oil. The optical fluid analyzer module (OFA) of the MDT has channels tuned at 10 locations as indicated in Fig. 1, and thus the response in channels 6, 8, and 9 can be used to discern water from hydrocarbon. Another section of the OFA is designed to detect gas by measuring reflected polarized light from the pumped fluids, but we do not discuss its operation further except to say that it is a reliable gas indicator.

This paper reviews quantitative determinations of swept-zone residual oil saturation in the slightly consolidated sandstones of the Tertiary System of the Gulf Coast. Different residual oil saturation measuring techniques were evaluated. Results obtained from all techniques showed good agreement of residual oil saturation values among the different techniques. Introduction The volume of oil remaining in major reservoirs after water floodout is potentially attractive for tertiary projects. However, an accurate determination of residual projects. However, an accurate determination of residual oil saturation (Sor) is essential for every reservoir, not only to evaluate the potential for tertiary recovery, but also to understand a waterflooded reservoir's current performance. performance. Evaluation of primary and secondary production mechanisms and ultimately, the prediction of potential tertiary reserves, hinge on the Sor-porosity product, (Sor phi). Yet, the determination of Sor (assuming porosity can be determined accurately) has not been easy porosity can be determined accurately) has not been easy to achieve in the soft formations of south Louisiana. Mechanical problems with tools and techniques together have made this important parameter difficult to obtain. Thus, evaluation of the most promising of the existing Sor measuring techniques was necessary to provide guidance for future determinations. The reservoir chosen for this vanguard effort was the 7,800-ft (2400-m) "Q2" sand of Reservoir A in the Main Pass Block 69 Field, offshore Plaquemines Parish, LA (Fig. 1). The "Q2" Sand is an upper Miocene, fault-controlled, deltaic formation and was produced first in the Reservoir A fault block in 1956. Fig. 2 is a log section showing the Sor project well, S.L. 1357 No. 46, and a nearby well, S.L. 1357 No. 16. Stringer drainage and uneven water encroachment are common in this multilayered reservoir (Figs. 2 and 3). The original reservoir pressure was 3,700 psi (25.5 MPa) which had dropped to about 3,000 psi (20.7 MPa) before water injection began. The reservoir pressure is now stabilized at about 2,500 psi (17.2 MPa). Initially, the crude oil was saturated and the reservoir had an original gas cap (Fig. 4). At the onset of this test, the best estimate for Sor in the good quality rock in the "Q2" sand of Reservoir A was about 20 to 30%; however, a good chance of significant error in this estimate existed. Therefore, Shell wanted to determine as accurately as possible the swept-zone residual oil saturation for this major reservoir. Well S.L. 1357 No. 46, a field development well, was chosen for this project. Because it was recognized that this would be a difficult project, many man-months were spent in, planning. Every effort was made to anticipate technical problems and many of the staff at Shell Development Co.'s Bellaire Research Center worked to find solutions. Wellsite work was supervised closely by experienced personnel from the Coastal Div. and the research center. This supervision included continuous calculating and monitoring. This ensured that all necessary data of good quality were gathered. Presentation of Operations Presentation of Operations Fig. 5 compares the schematic hole profile and penetration rate plot for this well with the sand section depicted penetration rate plot for this well with the sand section depicted by a dual induction log. JPT P. 513