Development of Heavy-Oil Reservoirs
- P.J. Briggs (British Petroleum Co. Ltd.) | P.R. Baron (BP Exploration Co. Ltd.) | R.J. Fulleylove (BP Exploration Co. Ltd.) | M.S. Wright (BP Exploration Co. Ltd.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- February 1988
- Document Type
- Journal Paper
- 206 - 214
- 1988. Society of Petroleum Engineers
- 4.3.4 Scale, 4.3.3 Aspaltenes, 7.1.10 Field Economic Analysis, 5.8.5 Oil Sand, Oil Shale, Bitumen, 5.2.1 Phase Behavior and PVT Measurements, 4.2.3 Materials and Corrosion, 5.3.1 Flow in Porous Media, 4.6 Natural Gas, 3.1.1 Beam and related pumping techniques, 7.1.9 Project Economic Analysis, 5.3.2 Multiphase Flow, 1.8 Formation Damage, 4.1.2 Separation and Treating, 5.2 Reservoir Fluid Dynamics, 5.7.2 Recovery Factors, 6.1.5 Human Resources, Competence and Training, 5.4.2 Gas Injection Methods, 4.1.9 Heavy Oil Upgrading, 2.4.3 Sand/Solids Control, 5.8.6 Naturally Fractured Reservoir, 5.8.7 Carbonate Reservoir, 5.4.6 Thermal Methods, 2 Well Completion, 5.5.8 History Matching, 4.2 Pipelines, Flowlines and Risers, 4.1.5 Processing Equipment, 5.5 Reservoir Simulation, 5.4.10 Microbial Methods
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Summary. Although complex categorizations are in vogue, "heavy oils" can be defined simply in terms of their flow properties in the reservoir e.g., a 100-cp [100-mPas] or greater viscosity. Such heavy oils are a major world hydrocarbon resource that is exploited where indigenous demand exists. Efficient methods of production require enthalpy input to the reservoir by hot-fluid injection or by creation of heat in the reservoir. Heat losses must be minimized to achieve maximum production efficiency. The widely used cyclic-steam-injection process is examined analytically to indicate which parameters govern successful exploitation. Steamflood and in-situ combustion techniques are discussed with reference to recent developments. Heavy-oil recovery from the more difficult carbonate reservoirs, such as those of the Middle East, is reviewed and potential production mechanisms are examined. Production techniques are described together with export handling schemes.
Heavy-oil recovery is traditionally thought of as thermal stimulation of low-API-gravity oil, which may range from 4 to 20 degrees API [1.04 to 0.93 g/cm3]. Heavy oil is defined as having an API gravity of less than 20 degrees API [greater than 0.93 g/cm3]. Standard practice in the U.S. also uses this gravity definition. The API gravity, however, does not fully describe the flow properties of the crude; this is better represented by the oil viscosity. For instance, some crudes may be heavy (low gravity) but have a relatively low viscosity at reservoir temperature compared with some lighter crudes (Table 1). The oil viscosity and its response to increased temperature control the flow rate under thermal stimulation, and because the flow rate is a much more important factor in the economic exploitation of the reserve than the oil gravity, it is proposed that heavy oilsi.e., those requiring stimulation by heat or by other meansbe defined as crudes having viscosities greater than 100 cp [greater than 100 mPas] at reservoir conditions. Normally, pumped cold-oil production rates will be less than 10 B/D [1.6 m3/d] when the oil viscosity exceeds 100 cp [100 mPas]. The term "bitumen" is used interchangeably with heavy oil although its use does tend to signify the heavier end of the heavy-oil spectrum. The United Nations Inst. for Training and Research proposes that bitumen be defined as having a viscosity greater than 10(4) cp [greater than 10(4) mPas] and an API gravity less than 10 degrees [less than 1 g/cm3]. Another definition of bitumen is a naturally occurring viscous mixture consisting mainly of hydrocarbons heavier than pentane that may contain sulfur compounds and that, in its naturally occurring viscous state, is not recoverable at an economical rate through a well. The term "tar sand" is often applied to such deposits found in the Canadian Athabasca sands, which are shallower and accessible by mining. Heavy oil in this paper refers only to those deposits that have to be exploited in situ and that will normally be located at depths ranging between 1,000 and 4,000 ft [300 and 1200 m]. In common with tar-sand oil, heavy oils frequently have high asphaltene, sulfur, and metal contents compared with conventional oils. The nonhydrocarbon content tends to increase with decreasing API gravity, which, in combination with decreasing quantities of lighter ends, reduces the market value of the crude. Table 2 compares typical heavy-oil properties with conventional oil.
Main Locations of World Heavy Oil
We have estimated the total discovered heavy oil in place in the world to be 4,600 x 10(9) bbl [730 x 10(9) m3]. This should be compared with our estimate of remaining proved and probable conventional oil reserves as of Jan. 1, 1986, of some 700 x 10(9) bbl [110 X 10(9) m3]. As can be seen, an average heavy-oil recovery factor of 15 % would be required to equate heavy-oil reserves with the remaining conventional reserves. The total world consumption of oil as of Jan. 1, 1986, was about 537 x 10(9) bbl [85 x 10(9)m3], which shows that the heavy-oil resources are important long-term supplies of petroleum. The main known heavy-oil deposits are summarized in Table 3. The largest heavy-oil deposits are located in Canada, Venezuela, and the Soviet Union and represent over 90% of the known heavy oil in place in the world. Of these deposits, sandstone reservoirs are estimated to contain 3,000 x 10(9) bbl [480 x 10(9) m3], with the remaining 1,600 x 10(9) bbl [250 x 10(9) m3] contained in carbonate reservoirs. Table 4 shows the distribution of the 1985 world production by thermal techniques, which averaged 923,000 B/D [147 x 10(3) m3/d]. In the past, economics have dictated that a high oil price is necessary before heavy-oil production becomes attractive on a large scale. In many areas of the world, however, conventional oil reservoirs are becoming increasingly marginal as the giant fields remaining to be discovered become fewer and the exploration risks for offshore fields and their development costs become large. There are risks associated with developing offshore fields because very few early appraisal data can be collected and no long-term well performance observations are possible. In most cases, pressure maintenance will be required from the outset and has to be based on theoretical estimates and not pilot results. Thus, these conventional oil prospects require front-end capital, the majority of which is at risk should the project fail. In addition, the uncertainty of future oil prices and the currently perceived low-price scenarios reduce the estimate of potential reward. In contrast, large quantities of heavy oil have already been discovered; therefore, no exploration cost is required. In addition, these discoveries awaiting development are mainly onshore and are at shallow depth. Development wells are low cost and the capital expenditure (capex) profile is continuous throughout the project, rather than being front-end loaded. Such thermal processes as cyclic steam injection are well understood, and the technical and geologic risks are therefore small. These advantages, even though the heavy-oil price will be discounted, allow potential heavy-oil production to compare favorably with many high-risk conventional oil plays. Typical predicted cash-flow profiles for a marginal North Sea development and a heavy-oil development are compared in Fig. 1. Table 5 summarizes the resource and development economics of the two fields. Carbonate reservoirs also contain large quantities of heavy oil, but the technology and experience of producing such heavy-oil reservoirs are not well developed. Nevertheless, they are important development targets. The potential production mechanisms that may take place during the thermal stimulation of these reservoirs are discussed later.
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