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Abstract The objective of this work is to improve determination of two-phase and three-phase relative permeabilities by the use of saturation imaging techniques. The first part of the paper reports on steady-state and unsteady-state relative permeability experiments performed on restored-state carbonate reservoir cores. The aim was to study how relative permeability test methodology impacts relative permeability curves. hysteresis and residual oil saturations in these intermediate-wet cores. Refined oil was used. Significant hysteresis was observed in both the unsteady-state water and oil relative permeabilities. The characteristics of the unsteady-state water relative permeabilities imply that viscous instabilities were present during the waterflood Centrifuge capillary pressure-wettability tests performed on companion core plugs both before and after the relative permeability tests showed good agreement with the unsteady-state results. but indicated change towards less oil-wetness during the steady-state tests. The main conclusion of this work is that extensive flushing of a restored-state core with refined oil may lead to a non representative relative permeability data and should therefore be avoided. The second part of the paper presents a summary of results obtained from three-phase unsteady-state flow in water-wet sandstone (Berea and Clashach) cores. In-situ saturation measurements show that the water relative permeability is dependent on water saturation alone. and that there is no change in water relative permeability due to three-phase flow. The waterflood residual oil saturation was found reduced in the presence of a gas phase, and may depend on the phase (oil or gas) injected prior to waterflooding. Introduction It is often recommended that laboratory relative permeability experiments for reservoir performance predictions should be conducted under simulated reservoir conditions. In such experiments, it is expected to use formation brine and crude oil as the fluid phases and preferably native state reservoir core as the porous medium. In the industry. however, relative permeability tests are often conducted at ambient laboratory conditions using synthetic brine and refined oil. This use of laboratory condition and refined oil is a common practice because it is relatively less complicated and least expensive method. An extensive documentation of various experimental methods used to acquire relative permeability data has been presented by Honarpour et al. The two most commonly used techniques in the laboratory to obtain relative permeability data are the steady-state and the unsteady-state in which a JBN-method or its derivative is used to calculate the relative permeabilities. in this work, intermediate-wet carbonate cores have been tested for both steady-state and unsteady-state waterfloods and oilfloods. The choice of test method best suited for the acquisition of relative permeability data becomes complicated when the porous medium is not strongly water- or strongly oil-wet. Purpose. The purpose of this paper is twofold. One is to obtain information on how relative permeability test methodology (steady-state versus unsteady-state) impacts relative permeability curves. Emphasis has been on evaluating relative permeability hysteresis and residual saturations obtained in two-phase oil- and waterfloods in intermediate-wet cores. The other purpose is to summarize the results of unsteady- state three-phase flow studies performed on water-wet Berea and Clashach sandstone cores. The work is directed to improve three-phase relative permeability determination by using in-situ fluid saturation measurements. P. 643

Core-flood experiments using chalk outcrop cores with petrophysical properties similar to North Sea chalk reservoirs have been conducted and history-matched. The objectives were to enhance the understanding of the mechanisms of fluid displacement in permeable chalk and to evaluate the imaging technique with respect to measuring three-phase saturations in chalk cores. The displacements included miscible brine/brine, drainage, miscible oil floods and water floods. The brine and oil phases were respectively labelled with gamma-emitting 22 Na and 59 Fe tracers. Fluid saturations were measured by a Germanium detector moved along the length of the core. In this investigation, emphasis has been placed on local in situ saturation development, recovery efficiency, fluid-front behaviour and tracer adsorption. The benefits from knowing the local in situ saturations, the identification of rock heterogeneity and the reproducibility of the saturation imaging have been emphasized. A good comparison was obtained between in situ fluid saturation information and that from effluent fluid measurements. The additional information on local fluid saturations obtained from the in situ measurements, coupled with petrophysical measurements, has enhanced the characterization of chalk cores and thus will contribute to a better understanding of displacement mechanisms during hydrocarbon recovery from chalk reservoirs. The nuclear tracer imaging technique was found suitable for measurements of three-phase fluid saturations.

A nuclear tracer imaging technique, ref. 1,2, is used to study in-situ local saturation developments in spontaneous imbibition and waterflood experiments in chalk. Due to lack of reservoir material outcrop chalk from the Dania outcrop near Alborg, Denmark, has been used.

Abstract A nuclear tracer imaging technique is evaluated for use in core analysis in studies of oil recovery from chalk reservoirs. In-situ fluid saturation data in long-core flood experiments in chalk, enhance the interpretations of the data; especially in mapping the local recovery efficiencies. In various long core flood displacements, including both drainages and waterfloods, emphasis has been on recording local in-situ saturation development, obtaining recovery efficiencies and studying effects on the saturation profiles from displacement pressure drops, flow rates and initial and final water saturations. The benefits of having access to local in-situ saturation information, the importance of being able to identify rock heterogeneities and tests of repeatability have been stressed. Introduction Over the past 20 years extensive efforts have been put on research on improving hydrocarbon recovery from chalk reservoirs. The challenge to understand and predict oil production from tight chalk reservoirs fully came in focus when the enormous potential for oil and gas production from chalk reservoirs in the southern part of the North Sea was discovered. The chalk reservoirs in this region are heavily fractured and the interwell fluid transport is thus conducted through the fracture network. The production mechanism is based on spontaneous water imbibition into the low permeable rock matrix, expelling the in-situ hydrocarbons into the surrounding fractures; and by continuous waterflooding of the fractures transporting the expelled oil to the producing wells. The imbibition rate and the sweep efficiency due to the spontaneous water imbibition are both crucial factors for the economics of the oil production. Deterministic for these processes are the wettability conditions and the relationships between the interacting forces: the capillary hold up, the viscous forces and the gravity. Extensive work have been reported on the challenge to understand and describe the production mechanisms, both regarding the interaction between fluid transport in the fractures and the matrix imbibition/reimbibition, and the oil displacement mechanism governed by wettability induced spontaneous water imbibition (ref. 1-8). The major problems related to the latter are to determine endpoint saturations, production rates and may be most important how to convert such laboratory data to results valid for the in-situ reservoir conditions. With regard to the fracture/rock matrix interactions, the dual porosity approach for modelling purposes has frequently been used (ref. 9), however, the important effects induced by gravity; fluid segregation, reimbibition and gravity assisted drainage in matrix block systems in capillary contact, have yet not been adequately addressed. A thorough investigation of these problems requires access to in-situ saturation information during an experimentally simulated production situation. For core analysis various imaging techniques (ref. 10-16) are applicable, including NMR-imaging and CAT-scanning, in order to obtain detailed information of the saturation development during the oil displacement. However, these techniques are not well suited in larger scale experiments using long cores to minimize disturbance from the end-effects experienced in small core plugs and when studying gravity drainage. P. 571^

A recoil-mass selector has been used to detect evaporation residues formed by neutron emission from the compound nucleus /sup 176/Pt produced by bombarding /sup 144/Sm with 139.5- to 201-MeV /sup 32/S. The neutron-deficient platinum isotopes /sup 172/Pt (4n emission) and /sup 171/Pt (5n emission) were identified, among others, as well as their alpha daughters, /sup 168/Os and /sup 167/Os. The alpha-decay energies and half-lives are /sup 172/Pt: 6.09 MeV, 0.09 sec; /sup 171/Pt: 6.450 MeV, 0.02 sec, /sup 168/Os: 5.670 MeV, 2.2 sec; and /sup 167/Os: 5.843 MeV, 0.8 sec. Alpha branching ratios of these and other daughters were also measured. An alpha line at 6.547, observed at beam energies above 190 MeV, was tentatively assigned to /sup 170/Pt (6n emission) and at energies around 140 MeV indications of 1n emission were observed. The optimum cross sections for 1n, 2n, 3n, 4n, 5n, and 6n emissions in that order are approximately 0.003, 0.09, 1.5, 0.15, 0.02, and 0.002 millibarns. Formation of iridium isotopes by 2n1p evaporation, etc., was also observed, but is not discussed in detail in this paper.

Evaporation residues from the fusion reactions of 110 MeV /sup 32/S with /sup 58/Ni and 132 MeV /sup 32/S with /sup 70/Ge were observed with the aid of an energy-mass spectrograph. The residues were resolved by mass number, and the masses observed in the /sup 32/S + /sup 58/Ni reaction were A = 84 (23% +- 5%), A = 86 (27% +- 5%), and A = 87 (50% +- 10%). The /sup 32/S + /sup 70/Ge reaction yielded A = 94 (14% +- 1%), A = 95 (23% +- 1%), A = 96 (14% +- 1%), A = 97 (24% +- 1%), A = 98 (21% +- 1%), and A = 99 (5% +- 1%). Angular distributions and velocity spectra were obtained for each mass, allowing partial reconstruction of the residues' kinematic history, and consequently of the particle evaporation modes leading to each residue. Average particle energies and anisotropies for each residue mass may be inferred from comparison with a Monte Carlo simulation of the evaporation process. The results are discussed and compared with calculations made with the aid of a statistical model evaporation code.

SummaryIn a series of laboratory waterfloods, we investigate the extent of mixing of injection water and connate water, connate-water mobility, and connate-water banking during water injection for enhanced oil recovery (EOR). Local dynamic water saturations of connate water and injected water were imaged individually by use of a nuclear-tracer technique. The connate water was displaced from the pore space by the injected water and accumulated downstream in a connate-water bank that advanced toward the production end. The connate-water bank significantly reduced the contact between the injected water and mobile oil. During capillary displacement—i.e., during spontaneous imbibition without a viscous pressure drop—the connate water was also mobilized and accumulated downstream in the core. During viscous displacement—i.e. with a pressure gradient as small as 0.3 mbar/cm—the accumulated connate water was mobilized in a miscible displacement and produced from the core. Only a small mixing zone was observed between the injected and connate waters, even with fully miscible conditions by use of identical brine compositions. The results of the displacement mechanisms experimentally visualized in this work are important for water-based EOR techniques, including low-salinity-water and polymer injections, as well as any tertiary oil-recovery method based on chemical injection.

Polymer gel is frequently used for conformance control in fractured reservoirs, where it is injected to reside in fractures or high-permeability streaks to reduce conductivity. With successful polymer gel conformance control in place, increased pressure gradients across matrix blocks may be achieved during chasefloods, diverting water, gas or EOR chemicals into the matrix to displace oil. Knowledge of gel behavior during placement and chase floods is important, because it largely controls the success of subsequent injections. Polymer gel behavior is often studied in core floods, where differential pressure and effluents from fracture and matrix outlets give information about gel deposition during placement and flow paths during chasefloods. The work presented in this paper utilize complimentary PET-CT imaging to quantify the behavior and blocking capacity of Cr(III)-Acetate HPAM gel during chase waterflooding. In-situ imaging provides information about changes that may not be extracted from pressure measurements and material balance only, such as changes in local fluid saturations and dynamic spatial flow within the fracture and within the structure of the gel network. Polymer gel was placed in core plugs with longitudinal fractures that connected the inlet and outelt, and chase water was subsequently injected to measure the gel blocking capacity. The water phase was labelled with a positron emitting radiopharmaceutical (F-18) to visualize and quantify local flows with positron emission tomography (PET) during gel rupture and subsequent flooding. Using PET, we study gel rupture and the development of wormholes during gel erosion after rupture as a function of flow rate. A particular strength with access to dynamic, local flow patterns is the direct comparison to global measurements, such as differential pressure and production rate, to verify existing gel behavior models.