Higher Production Index Research Articles

The Production Of Conventional Heavy Oil Reservoirs With Bottom Water Using Steam-Assisted Gravity Drainage

Abstract Developing and producing conventional oil economically from reservoirs containing bottom water is' one of the most challenging technical problems in Canadian petroleum engineering This paper investigates a new, innovative thermal oil recovery process that shows potential for the economic of production heavy oil from reservoir when recovery is limited by water coning. The process as envisaged at present, would use parallel horizontal wells placed near the bottom of the reservoir with horizontal steam injection wells located vertically above the producers near to the top of the reservoir. Experiments were performed using a scaled, two-dimensional reservoir model containing an active aquifer system. The model was designed to provide dimensional similarity with specific "Lloydminister-type heavy oil" field conditions. The study investigated the mechanism, the process and the effects of steam injection Pressure, bottom water thickness, and the location of the production well; the laboratory results were extrapolated to the field conditions. It is shown that the process may produce heavy oils economically. The severity of steam coning is because the high productivity index of a horizontal well, allows practical production alrates which are below the critical steam coning rates. Water production from the aquifer is greatly reduced by operating the production wells at pressures close to that of the aquifer. The cumulative oil recovery varied from 48% (bottom water case with 41% water in the model) to 87% (no bottom water with 0% water in the model) of original oil-m-place above the production well (OOIP*). The thickness of the bottom water zone and The well configurations employed had a significant effect on the cumulative oil recovery. Introduction In Canada, there i, a vast amount of heavy oil reserves (3.5 million M3) underlying the Lloydminster area of Alberta and Saskatchewan(1). These heavy oils are usually mobile al reservoir conditions and most can be produced at a low ultimate recovery by primary production. Waterflooding is not effective because the mobility ratio of heavy oil to Water is not favourable. Most heavy oil reservoirs in Saskatchewan have thin pay zone, which have been judged unsuitable for thermal recovery. Many of the thicker reservoirs have underlying water, Attempts to produce such reservoirs by conventional means result, quickly, in the production of excessive water. The mechanism for this is well understood and is a result of the much lower viscosity or water compared to that of the oil; the Water "cones" upward into tlte well. The conventional steamflood or in situ combustion processes are usually unsuccessful due to prohibitive heat loss or air channelling through the underlying water and also excessive water will be produced(2). Therefore, the chance of recovering this type of petroleum reserves is further limited. An advantage of the technique Studied here is that the process can be operable, even though there is a significant underlying water layer. The reason that the water can be tolerated is that the pressures involved in the SAGD process, can be adjusted so that there is no tendency for water to now from the aquifer to the production well(s).

Rock-Eval Data Relating to Oil-Source Potential of Shales of New Albany Group (Devonian-Mississippian) in Illinois Basin: ABSTRACT

Only limited data on petroleum source rock potential of New Albany Group (Devonian-Mississippian) shales have been reported, with the exception of vitrinite reflectance and some petrographic analyses. The New Albany Group contains the thickest and most widespread continuous black shale beds in the Illinois basin. The New Albany extends from northwestern Illinois to southwestern Indiana and western Kentucky and is thought to have played a major role in petroleum generation throughout the basin. In this study, Rock-Eval pyrolysis was used to measure the petroleum-generative potential and production index of the shale. Seven geochemical logs, based on 143 core samples from across the basin, and a production index map, based on a total of 252 samples (cuttings and cores) in Illinois, were generated. Systematic variations of petroleum-generative potential of the shale were observed. The variations are related to the differences in shale lithofacies, depth, and geographic location. The upper portion of the New Albany - the Hannibal and Saverton Shales - has the lowest oil-generative potential. The Grassy Creek, Sweetland Creek, and other stratigraphically lower shales of the New Albany Group generally have good oil-generative potential. However, samples from the Hicks dome area of extreme southern Illinois are overmature and havemore » no oil-generative potential. Source rocks that have both good oil-generative potential (> 6 kg hydrocarbons per ton of rock) and a higher production index (> 0.09) are generally located at depths of 2,500-5,300 ft.« less

Evaluation of Fish Communities Through Assessment of Zooplankton Populations and Measures of Lake Productivity

Abstract Knowledge of zooplankton size structure and measure of lake productivity can facilitate interpretation of data from fishery surveys. Our findings demonstrate that, for small warm-water lakes containing predominantly centrarchids and percids, the size composition of the zooplankton community and growth and size structure of the fish community are closely correlated. Spatial-temporal differences between lakes suggest the fishery manager can obtain a useful measure of zooplankton size by sampling at deeper, offshore sites in August. Measurement of zooplankton size as an index of predator-prey balance in the fish community offers a simple, yet economical, approach for assessing the status of a fish population and determining management options. Comparisons of Fee's productivity index, zooplankton biomass, and catches of fish in variable-mesh gill nets indicate that lakes with a high productivity index generally support a larger biomass of planktivorous fish. Finally, evaluation of fish communities th...

Geochemical study of the organic matter in outcrop samples from Agardhfjellet, Spitsbergen

An organic geochemical study of a homogeneous shale sequence of Mesozoic age at Agardhfjellet, Spitsbergen, in the Svalbard archipelago is reported. Analyses on the soluble extracts were undertaken together with visual kerogen and vitrinite reflectance analyses to estimate the maturity of the organic matter. The sequence is found to be in the “Oil Window”. Rock-Eval pyrolysis indicated that most of the Cretaceous samples contain type III kerogen, whereas the Jurassic samples contain mainly type II kerogen. A high production index for hydrocarbons was found for most of the samples. The variation in quantity and quality of the soluble extracts, with respect to changes in maturity, is discussed together with the effect that weathering might have had on some of the results.

Auk Field Development: A Case History Illustrating the Need for a Flexible Plan

The Auk field produces from thin, but highly permeable, Zechstein dolomites. The reserves of the field were defined poorly after the initial four wells were drilled, primarily because of the lack of seismic control. This paper contrasts the initial development plan with the historical sequence and shows how unexpected reservoir response was monitored and interpreted and how it influenced development drilling. Introduction The Auk field, discovered in 1971, is not typical of the North Sea. This small carbonate oil reservoir already has reached an advanced stage of development. All except one of the 10 slots on the drilling/production platform have been drilled - some deviated at angles up to 65°. The cumulative production is already more than one-half the estimated ultimate recovery. The field is unusual in that the very thin Zechstein carbonate producing horizon could not be mapped directly by seismic data, so that both the structural attitude and areal spread of the accumulation initially were defined very poorly. Potential difficulties during development of the Auk field were apparent at an early stage, and we realized that a flexible approach would be needed. A small integrated team of specialists was responsible for planning the development strategy. This team included a seismologist, geologist, reservoir engineer, production engineer, and an economist. Planning decisions thus have benefited from multidisciplinary analysis, and conclusions and recommendations were those of the whole team. This approach proved both necessary and effective. The main aim of this study is to illustrate how the continuous flow of information necessitated radical revisions of our initial concepts of the Auk field and how development plans were modified continually. Because of space limitations, it is impossible to detail how the views of the various disciplines interacted when formulating each proposal. However, the overriding factors are pointed out, and the reasoning behind changes of policy are indicated. Discovery and Appraisal Shell/Esso's Field A in the U.K. North Sea (Auk) was discovered when Well 30/16-1, drilled in about 280 ft (85 m) of water, encountered oil-bearing, thin, vugular Zechstein dolomites unconformably overlain by Cretaceous chalk.1 The well tested 5,900 B/D (938 m3/d) of 37°API (0.84 g/cm3) oil with an extremely high productivity index. The underlying Rotliegend formation, which had formed the main objective of the well on the pronounced Auk horst structure, was found to be water-bearing. Because the thin Zechstein formation could not be distinguished on seismic sections, the extent of the accumulation was in doubt. The high productivity of the Zechstein formation also could have been a local phenomenon because tight Zechstein was present in nearby exploration wells.

The summer characteristics of primary productivity in the Tasman and Coral seas

An analysis of productivity data from 150 stations in the area, carried out in the period January-March from 1958 to 1962, showed that the area could be divided into five homogeneous regions, each with characteristic magnitudes, vertical profiles, and diurnal variations. A comparison of these regions with the hydrological structure showed a close parallel to a system of three external water masses which mix to form all the major characteristics of the area. In the northern Coral Sea is a region of moderately productive waters (25 mgC/hr/m²) mainly of equatorial origin, with sharp vertical stratification at 50 m, and a high productivity index (3.7 mg C/ hr/mg chl.a) in the upper 50 m. The central part of the area is dominated by waters of the west central South Pacific Ocean with a low productivity (11 mg C/ hr/ m², no vertical stratification, and a low productivity index (1 -2). The southern Tasman Sea is dominated by waters of subantarctic origin with a very high productivity (49 mgC/ hr/ m²), a large subsurface maximum at 50 m, a sharp stratification below 50 m, and a high productivity index (3.9). Between these three regions are two others formed by mixing, and these have intermediate characteristics. In all five regions there are subsurface maxima of chlorophyll a below the layers of maximum productivity, and these sink even deeper as the productivity decreases. This suggests that the phytoplankton sink and lose their ability to photosynthesize as the waters become poorer. Diurnal variations of productivity in the five regions show an inverse relationship with latitude, the ratio of maximum to minimum productivity decreasing from 3.1 at 15� S. to 2.1 at 45� S, but this decrease is less than would be expected from other values published.