Heavy oil is defined as liquid petroleum of less than 20 API gravity or more than 200 cp viscosity at reservoir conditions. No explicit differentiation is made between heavy oil and oil sands (tar sands), although the criteria of less than 12 API gravity and greater than 10,000 cp are sometimes used to define oil sands. Unconsolidated sandstones (UCSS) are sandstones (or sands) that possess no true tensile strength arising from grain-to-grain mineral cementation.
In downhole applications, most progressive cavity (PC) pump failures involve the stator elastomer and often result from chemical or physical elastomer breakdown induced by the wellbore environment. Successful use of PC pumps, particularly in the more severe downhole environments, requires proper elastomer selection and appropriate pump sizing and operation. PC pump manufacturers continue to develop and test new elastomers; over time, these efforts have resulted in performance improvements and an expanded range of practical applications. Despite this success, the elastomer component still continues to impose severe restrictions on PC pump use, especially in applications with lighter oils or higher temperatures. The performance of an elastomer in a PCP application depends heavily on its mechanical and chemical properties.
In-situ combustion is the oldest thermal recovery technique. It has been used for more than nine decades with many economically successful projects. In-situ combustion is regarded as a high-risk process by many, primarily because of the many failures of early field tests. Most of those failures came from the application of a good process to the wrong reservoirs or the poorest prospects. The objective of this page is to describe the potential of in-situ combustion as an economically viable oil recovery technique for a variety of reservoirs.
A passive tracer that labels gas or water in a well-to-well tracer test must fulfill the following criteria. It must have a very low detection limit, must be stable under reservoir conditions, must follow the phase that is being tagged and have a minimal partitioning into other phases, must have no adsorption to rock material, and must have minimal environmental consequences. The tracers discussed in the following sections have properties that make them suitable for application in well-to-well test in which dilution volumes are large. For small fields in which the requirement with respect to dilution is less important, other tracers can be applied. Figure 1.1 – Production curve of S14CN compared with the production curve of HTO in a dynamic flooding laboratory test (carbonate rock) (after Bjørnstad and Maggio). There are no possibilities for thermal degradation, and it follows the water closely. The 36Cl- is a long-lived nuclide (3 105 years), and the detection method is atomic mass spectroscopy rather than radiation measurements. The disadvantage is that the analysis demands very sophisticated equipment and is relatively time consuming. For mono-valent anions, the retention factors (see Eq. 6.2) are in the range of 0 to -0.03, which means that such tracers pass faster through the reservoir rock than the water itself (represented by HTO). A compound such as 35SO42- may be applied in some very specific cases but should be avoided normally because of absorption. Some anionic tracers may show complex behavior. Radioactive iodine (125I- and 131I-) breaks through before water but has a substantially longer tail than HTO. Both a reversible sorption and ion exclusion seem to play a role here. Cationic tracers are, in general, not applicable; however, experiments have qualified 22Na as an applicable water tracer in highly saline (total dissolved solids concentration seawater salinity) waters. In such waters, the nonradioactive sodium will operate as a molecular carrier for the tracer molecule. Retention factor has been measured in the range of 0.07 (see Eq. 6.2) at reservoir conditions in carbonate rock (chalk). Wood reported the use of 134Cs, 137Cs, 57Co, and 60Co cations as tracers.
In the modeling of any system, one is always faced with the dilemma of choosing the level of complexity that correctly predicts the response of interest. In the case of modeling the electrical heating of wells and reservoirs for heavy or extra-heavy oil at low frequencies (below the microwave range) and considering only one liquid phase and no gas phases, the systems of equations shown in this article are considered sufficient. The problem is still unsolved for the case of microwave heating of reservoirs, in which a complete model, which correctly takes into account the electric losses of a system of solid grains, liquids with dissolved gases and salts (with the corresponding complex geometrical, scaling, and electrochemical properties in the presence of electrical diffusion currents and space charges), is not yet available. For the case of concentrated heating (either resistive or inductive) and distributed heating in the reservoir and surrounding regions (at frequencies below the microwave range) or distributed heating in the metal elements (at any frequency) the equations given next (in a cylindrical coordinate system) are deemed sufficient. The third term on the left, the product of temperature multiplied by the divergence of the velocity, has been neglected in many models of heating of reservoirs (it is strictly zero only for incompressible fluids.).
Actually, the definition of a tight gas reservoir is a function of many factors, each relating to Darcy's law. The main problem with tight gas reservoirs is that they do not produce at economic flow rates unless they are stimulated--normally by a large hydraulic fracture treatment. Eq. 7.1 illustrates the main factors controlling flow rate.
The claim that the world is irresponsible in rapidly consuming irreplaceable resources ignores technical progress, market pressures, and the historical record. For example, the "Club of Rome," with the use of exponential growth assumptions and extrapolations under static technology, predicted serious commodity shortages before 2000, including massive oil shortages and famine. First, the new production technologies are proof that science and knowledge continue to advance and that further advances are anticipated. Second, oil prices will not skyrocket because technologies such as manufacturing synthetic oil from coal are waiting in the wings. Third, the new technologies have been forced to become efficient and profitable, even with unfavorable refining penalties. Fourth, exploration costs for new conventional oil production capacity will continue to rise in all mature basins, whereas technologies such as CHOPS can lower production costs in such basins. Fifth, technological feedback from heavy-oil production is improving conventional oil recovery. Finally, the heavy-oil resource in UCSS is vast. Although it is obvious that the amount of conventional (light) oil is limited, the impact of this limitation, while relevant in the short term (2000 to 2030), is likely to be inconsequential to the energy industry in the long term (50 to 200 years). The first discoveries in the Canadian heavy-oil belt were made in the Lloydminster area in the late 1920s. Typically, 10- to 12-mm diameter perforations were used, and pump jacks were limited by slow rod-fall velocity in the viscous oil to a maximum of 8 to 10 m3/d of production, usually less. Operators had to cope with small amounts of sand, approximately 1% in more viscous oils. Small local operators learned empirically that wells that continued to produce sand tended to be better producers, and efforts to exclude sand with screens usually led to total loss of production. Operators spread the waste sand on local gravel roads and, in some areas, the roadbeds are now up to 1.5 m higher because of repeated sand spreading. The sharp oil price increases in the 1970s and 1980s led to great interest in heavy-oil-belt resources (approximately 10 109m3). Many international companies arrived and introduced the latest screen and gravel-pack technology but, in all cases, greatly impaired productivity or total failure to bring the well on production was the result. To this day, there are hundreds of inactive wells with expensive screens and gravel packs. The advent of progressing cavity (PC) pumps in the 1980s changed the nonthermal heavy-oil industry in Canada. The first PC pumps had low lifespans and were not particularly cost-effective, but better quality control and continued advances led to longer life and fewer problems. The rate limits of beam pumps were no longer a barrier and, between 1990 and 1995, operators changed their view of well management.
Interwell tracer tests are widely used. This article reviews some of the studies reported in open literature. The selection introduces different problems that have been addressed, but the original papers should be studied to obtain a more detailed description of the programs. The Snorre field is a giant oil reservoir (sandstone) in the Norwegian sector of the North Sea. Injection water and gas were monitored with tracers, 18 and the resulting tracer measurements are discussed in this page.
The key technical considerations and decisions involved in selecting a progressing cavity pump(PCP) for a particular application include pump displacement, pressure capability, geometric design, elastomer type, and rotor coating characteristics. Other factors, such as local vendor choice and economics can also affect pump selection. Figure 1 provides a flow chart of the key decisions. When selecting a PC pump, the two most critical requirements are adequate displacement capacity and pressure capability to ensure that the pump can deliver the required fluid rate and net lift for the intended application. It is typical to select pumps with a design (i.e., theoretical) flow rate that is somewhat higher than the expected fluid rate to reflect pump inefficiencies during production operations.
Venezuela possesses a world-class, hydrocarbon source rock from one of the most prolific places for oil accumulation in the world. This source rock, the La Luna Formation, (Cretaceous in age) is located in eastern Venezuela's Maracaibo Basin. Local variations in depositional and diagenetic conditions have manifestly affected the preservation and dilution of organic matter to some degree, generating small-scale variability in the depositional environments, and thus creating a higher-quality source rock within the depositional sequence that can be more prospective than others. To understand the variability of the depositional conditions, variations in organic matter source, thermal maturity, depositional environments and the use of organic/inorganic geochemical parameters were crucial in this study. This combined source rock evaluation composed of geological and geochemical parameters indicated an excellent potential as an unconventional reservoir for oil and gas in the study area. Geochemical analysis (Pristane, phytane (Pr/Ph), distributions of regular steranes, hopanes, monoaromatic steroid hydrocarbons (MAS) and tentative identification of gammacerane) confirmed the excellent quality of the organo-facies with higher productivity and preservation. Thermal maturity parameters indicate that most of the studied cores are within the oil window. Liquid hydrocarbons in the study area occur in the northwest and southwest areas, and condensates and dry/wet gases occur in the northeast. The lithofacies association, the sequence-stratigraphic framework, relative hydrocarbon potential (RHP), and biomarker analysis identified the depositional environment as an epicontinental sea developed in a shallow marine, upper shelf euxinic environment represented by a series of third order sequences of Highstand and Transgressive System Tracts overlying the erosional top of the underlying Cogollo Group. These stark differences show the tremendous value that biomarkers provide in the exploration of prospective source rocks. Not only do they help to identify paleoenvironmental changes and redox conditions, but they also depict the best organo-facies and accurate maturity parameters of the rock.