Core Analysis Results Research Articles

Oil-Base Coring For Connate Water Saturation Utikuma Keg River Sandstone

Abstract A successful oil-base coring operation has resulted in identification of an average Connate Water Saturation (Swc) at Utikuma Lake oilfield supporting low Swc from recently completed Single Well Tracer (SWT) tests. As oil-base coring was intended to validate SWT results, careful design of the coring program was required. Alteration of Swc by the coring procedure itself WAS eliminated by preserving wettability through appropriate coring fluid selection and surface handling of the core. Special attention to the drilling program design eliminated contamination by uphole formation and drilling fluids. This paper presents details of the oil-base coring program, including drilling program design, equipment and coring fluid selection core handling and core analysis results. Introduction Utikuma Lake Field is located north of the town of Slave Lake, Alberta, between the Nipisi and Red Earth fields (Fig. 1). Field characteristics are summarized in Table 1. Utikuma produces 1500 m3/d of light, sweet oil under primary water drive from 180 wells completed in the Keg River sandstone. Utikuma Keg River oil is paraffinic with low asphaltene content. Oil properties are listed in Table 2. Formation water is highly saline, with 275 000 mg/l total dissolved solids, as indicated in the water analysis data presented in Table 3. Geology Utikwna Keg River sands were derived from the Peace River Arch west of the field, being deposited in Utikuma as numerous separate pools in topographic lows of irregular highs in the eroded Precambrian granite. The porous Keg River sands were encased in impermeable shales that formed upper and lower seals. Keg River sands consist largely of interbedded sand and shale, each being several centimetres to several decimetres thick. The sands are feldspar-rich quartzose with calcite and anhydrite cementation, and fine to very coarse grains. Clays are almost entirely illite, a non-swelling clay. Average porosities and permeabilities for the Keg River sands are 20% and 1000 mD. Average net pay is 3 m. Need for Oil-base Coring Oil-base coring was undertaken at Utikuma to confirm low connate water saturations (Swcs) identified by Single Well Tracer (SWT) tests conducted during 1986–1988. Swcs of 10% to 15% from SWT tests were significantly lower than the 29% Swc recognized for most Utikuma Keg River pools. Oil-base coring was justified by the significant impact on reserves estimates and field development plans that would be caused by adopting the lower Swcs. Oil-base coring has been undertaken at two development well locations in Utikuma. The first attempt at well 5-30-81-9 WSM in December 1987, did not provide representative Swc data as the Keg River sand was determined to be entirely within a transition zone above an unexpected oil/water contact. Experience gained from well 5–30 was used in the subsequent successful oil-base coring project at well 7-33-81-9 WSM in July 1988. The 7–33 oil-base coring project is the subject of this paper. Oil-base Coring Project Design The Utikuma oil-base coring project began with selection of a project team comprising reservoir, production and drilling engineers, laboratory representatives and downhole equipment and drilling fluid suppliers.

A Vertical Permeability Study

Abstract A vertical permeability study was performed on three Rainbow field cores to examine the effect of crossflow on vertical permeability and to determine the best method for averaging vertical permeabilities. The study consisted essentially of a series of permeability measurements that were made as whole cores were progressively cut into smaller pieces. Results show that crossflow does contribute to vertical permeability. Further, the effect of crossflow varies inversely with the length-to-area ratio of the cores and is a very important factor to consider when determining a formation vertical permeability. Formation vertical permeabilities determined from the usual core analysis results are probably low because crossflow bas been minimized by using cores with a relatively high length-to-area ratio. For this reason, a more representative formation vertical permeability can be obtained by using a greater number of shorter permeability samples. As expected, the harmonic average of a series of core vertical permeabilities was found to best approximate the core permeability itself. The geometric average of the same permeabilities was found to be more representative of the formation where crossflow contributes to the vertical permeability. Introduction The Rainbow field was discovered in northwestern Alberta in 1965 and is presently comprised of some 50 separate reef reservoirs. Production is primarily from the Middle Devonian Keg River formation that lies at a depth of about 6,000 ft. Most of these reefs have high-vertical-relief (up to 600 ft) oil-bearing zones that usually are underlain by an aquifer and are sometimes capped by an initial gas cap. The production mechanism in these reservoirs, whether it be primary depletion or pressure maintenance by gas, solvent, or water injection, will therefore be gravity controlled and drainage will be predominantly in a vertical direction. Under these conditions, the vertical permeability of the reservoir will be a major factor in determining recovery efficiencies. Knowledge of the representative vertical permeability of the reservoir is therefore important to predict recovery efficiencies. Like other limestone reef formations, the Keg River is very heterogeneous, containing vugs, caverns, stylolites, and fractures. Because of the heterogeneities, it is difficult to determine the representative formation vertical permeability value from core analysis data. This paper deals with an attempt to determine the degree of contribution of crossflow to vertical permeability and to determine the best method for averaging vertical permeabilities. Some work in the same broad category has been done in the past. Cardwell and Parsons indicated that the effective permeability in a radial system of heterogeneous sands lies between an upper and lower limit approximated by the arithmetic and harmonic averages, respectively. Warren and Price concluded from computational experiments that the most probable effective permeability value of a heterogeneous system can be approximated by the geometric mean. More recently, Lishman arrived at several of our conclusions in his computer study simulating a three-dimensional random arrangement of isotropic permeability cells.

Athabasca Oil-Sand Evaluation Using Computer and Data-Processing Methods: ABSTRACT

A 4,000-acre oil-sand mining operation in northeastern Alberta is being conducted by Great Canadian Oil Sands, Ltd. The sandstones contain as much as 18 per cent by weight of low-gravity oil or tar, they are lenticular and interbedded with barren shale and siltstone. In order to determine in-place oil content and other ore-body characteristics, an extensive coring and well-logging program was conducted during the winters of 1963-64 and 1964-65. Using a comprehensive well-log-analysis computer program, core-analysis data, and a geological data-processing system, the average grade, in-place oil reserves, and other characteristics of the mining lease were determined. Of all logging devices tested, the formation density-laterolog 3 combination provided the best borehole measu ements of porosity and water saturation. Numerous comparisons of core versus log analysis results indicate that accurate oil content can be ascertained in the oil-sands using conventional log-analysis methods. Core and log information was combined to produce continuous oil saturation, water saturation, porosity, and bulk-density profiles for each test hole. Stratigraphic correlations and oil-grade cutoff tops and bases also were included for each test hole. From this information numerous maps and cross sections for use in defining the ore body and in mine planning were produced, using the computer-plotting combination. End_of_Article - Last_Page 463------------

Possibility of identifying cavernous and jointed limestones by applied geophysical methods

The procedure described was based on the comparison of the porosity values determined from the laterolog (kL) and from the neutron-gamma log (k NG). According to the analysis: 1) The cavernous porosity did not affect the kL, while it affected greatly the kNG; 2) the fractured structure affected strongly the kL, especially if the granular porosity was low, and had practically no effect on the kNG; 3) a cavernous layer was characterized by kL, < kNG, while the opposite was true for a fractured layer (kL > kNG); and 4) the kL ≃ kNG was true for both a granular porosity, or a combination structure of cavernous porosity with fractures. The interpretation was more definite when the core analysis results were used. When k core was substantially lower than kNG, it was assumed that the layer was both cavernous and fractured. --Petroleum Abstracts.

The Effect of Gypsum on Core Analysis Results

Published in Petroleum Transactions, AIME, Volume 216, 1959, pages 221–224. Abstract The presence of gypsum in samples subjected to standard core analysis introduces serious errors in the measurement of water saturation and porosity. The magnitude of these errors, depending upon the type of analysis procedure used, has been evaluated experimentally and theoretically. Water-saturated pore volumes determined by vacuum distillation or retort procedures may be too high by as much as 48 per cent of the volume of gypsum present. The maximum error in this value determined by Dean-Stark extraction with toluene is 36 per cent of the gypsum volume. If pore space is measured by a Boyle's law type porosimeter the maximum error due to gypsum is 38 per cent of the original gypsum volume present. The conscientious core analyst may eliminate the errors caused by gypsum by either of two methods. He may apply suitable corrections for the water of crystallization removed from gypsum, or take special precautions to prevent dehydration of gypsum during core cleaning and analysis procedures. These alternatives are discussed and methods for obtaining reliable core analysis data are proposed. Introduction Gypsum (CaSO42H2O) occurs as a common mineral in many of the world's sedimentary basins. In addition to its presence as primary bedded evaporitic deposits, it is often found as secondary replacement zones and pore-fillings in host rocks. That it may cause false indications in porosity, both on neutron logs and in standard core analysis, has been generally recognized. False porosity interpretations from neutron logs result because the chemically bound water in gypsum attenuates neutrons as effectively as free water. Errors in core analysis result when gypsum is dehydrated prior to or during the analysis. Vacuum retort procedures used by many laboratories to determine fluid saturation and porosity effect a complete removal of water of crystallization from gypsum. The crystal water, distilled and collected with free water from the sample, is counted as water-saturated pore space.