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. The oil in oil sands is an immobile fluid under existing reservoir conditions, and heavy oils are somewhat mobile fluids under naturally existing pressure gradients. Unconsolidated sandstones (UCSS) are sandstones (or sands) that possess no true tensile strength arising from grain-to-grain mineral cementation. Many heavy oil reservoirs are located in unconsolidated sandstones.
Topside payloads range from 5 to 50,000 tons, producing oil, gas, or both. A vast array of production systems is available today (see Figure 1). The concepts range from fixed platforms to subsea compliant and floating systems. In 1859, Col. Edwin Drake drilled and completed the first known oil well near a small town in Pennsylvania, U.S.A. This well, which was drilled with cable tools, started the modern petroleum industry.
Below is a list of basins and fields; however this is a short list since there are more than 65,000 oil and gas basins and fields of all sizes in the world. However, 94% of known oil fields is concentrated in fewer than 1500 giant and major fields. Most of the world's largest oilfields are located in the Middle East, but there are also supergiant ( 10 billion bbls) oilfields in India, Brazil, Mexico, Venezuela, Kazakhstan, and Russia. Add any basins or fields that are missing from this list!
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.
In making the petrophysical calculations of lithology, net pay, porosity, water saturation, and permeability at the reservoir level, the development of a complete petrophysical database is the critical first step. This section describes the requirements for creating such a database before making any of these calculations. The topic is divided into four parts: inventory of existing petrophysical data; evaluation of the quality of existing data; conditioning the data for reservoir parameter calculations; and acquisition of additional petrophysical data, where needed. The overall goal of developing the petrophysical database is to use as much valid data as possible to develop the best standard from which to make the calculations of the petrophysical parameters. The second step in working with the petrophysical data is to evaluate the quality of each of these types of data. This step requires that the data inventory and database preparation steps are completed first so that this second step can occur as a systematic and complete process. The evaluation process is a "compare and contrast" exercise. The evaluation of log-data quality has many aspects. This should be noted in the petrophysical database. "Flags" of various types should be stored, for example, to denote intervals where the hole size exceeds some limit, or where there is cycle-skipping on the sonic logs. Logging tools sometimes become temporarily stuck as a log is being run. When the tool is stationary, each detector on it becomes stuck at a different depth, so the interval of "stuck" log will vary for each log curve. For example, the neutron log typically sticks over an interval approximately 10 ft above the stuck interval on a density log. It may be possible to "splice" in a replacement section of log from a repeated log section, or the invalid readings may simply be deleted. Second, each log is formally calibrated before the start of each logging run by various calibration standards. The logs are also checked again after the run. Calibration records may assist in determining the quality of the logs. Perhaps of equal importance are the written comments on the log heading made immediately after the job by the logging engineer. Third, systematic influences on the quality of log readings should be corrected. For example, if some of the wells are drilled with water-based mud (WBM), the effect of WBM-filtrate invasion on various resistivity logs can be quantified. This is done by computations made using the various resistivity logs in the same wellbore; however, where deep invasion of WBM filtrate occurs, offsetting wells drilled with oil-based mud (OBM) give a good comparison. The induction logs in OBM wells can provide accurate true reservoir resistivity values in thick hydrocarbon zones. See the chapter on resistivity and SP logging in this volume of the Handbook for more information on how invasion effects can be handled. Boreholes are not always right cylinders.
Water saturation (Sw) determination is the most challenging of petrophysical calculations and is used to quantify its more important complement, the hydrocarbon saturation (1 – Sw). Complexities arise because there are a number of independent approaches that can be used to calculate Sw. The complication is that often, if not typically, these different approaches lead to somewhat different Sw values that may equate to considerable differences in the original oil in place (OOIP) or original gas in place (OGIP) volumes. The challenge to the technical team is to resolve and to understand the differences among the Sw values obtained using the different procedures, and to arrive at the best calculation of Sw and its distribution throughout the reservoir vertically and areally. A 10% pore volume (PV) change in Sw has the same impact as a 2% bulk volume (BV) change in porosity (in a 20% BV porosity reservoir). This listing is the chronological order in which data are likely to become available, not in a ranked order based on the accuracy of the various methods. The choice of which Sw-calculation approach to use is often controlled by the availability of the various types of data. If no OBM cores have been cut, then this technique cannot be used unless funds are spent to acquire such data from one or more newly drilled wells. This is not a high incremental cost when OBM use is planned for other purposes. Resistivity logs are run in all wells, so these data are available for making standard-log-analysis Sw calculations. A key consideration when making calibrated Sw calculations is the availability of special-core-analysis (SCAL) data on core samples from the particular reservoir; that is, the number of laboratory electrical-property and Pc/Sw core-plug measurements that have been made. The technique chosen to calculate Sw is often a hybrid that combines the use of two of these basic data sources. For example, the OBM-core Sw data can be used in combination with the resistivity logs to expand the data set used to include all wells and the whole of the hydrocarbon column. Alternatively, the OBM-core Sw data can be used in combination with the Pc/Sw data. In this way, the OBM-core Sw data define the S w values for the majority of the reservoir, whereas the Pc/Sw data define the Sw values in the interval just above the fluid contact and perhaps in areas of the field where Pc data are available but OBM-core data are not. This section discussed the input-data availability and data quality issues for each Sw technique.
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. In the case of concentrated resistive heating, where a sinusoidal current of root mean square (RMS) magnitude I (Imax 2) flows through a wire resistance of resistance, R, the total power dissipated is I2R. The power per unit volume is uniform over the volume of the resistor if the skin depth is much larger than the wire radius.
In the 1970s, the United States government decided that the definition of a tight gas reservoir is one in which the expected value of permeability to gas flow would be less than 0.1 md. This definition was a political definition that has been used to determine which wells would receive federal and/or state tax credits for producing gas from tight reservoirs. 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. Eq. 7.1 clearly shows that the flow rate, q, is a function of permeability k; net pay thickness h; average reservoir pressure p; flowing pressure pwf; fluid properties β μ drainage area re; wellbore radius rw; and skin factor s. Thus, to choose a single value of permeability to define "tight ...
The drilling conditions described above have led to the following practices, which are reasonably uniform, in the geothermal drilling industry. Bits Because of the hard, fractured formations, roller-cone bits with tungsten-carbide inserts are almost universally used for geothermal drilling. The abrasive rocks mean that bit life is usually low (50 to 100 m), but many bits are also pulled because of bearing failures caused by rough drilling and high temperature. Polycrystalline diamond compact (PDC) bits have the dual advantages of more efficient rock cutting and no moving parts, but experience with PDC bits in geothermal drilling is both scant and unfavorable. Much research and development in hard-rock PDC bits is under way,  so it is possible that these bits will come into wider use in geothermal drilling.