Thin oil columns overlain by free gas and underlain by water pose difficult problems in well spacing and completion method, production policy, and reserves estimation. Whether an oil column is considered thin depends on costs to drill and produce the accumulation. For example, in the Bream field (Australia Bass Strait, 230 ft water depth), 44 ft was considered thin, whereas in the Troll field (offshore Norway, 980 ft water depth), 79 ft was considered thin. Onshore U.S.A., 20 ft is considered thin. Irrgang takes a pragmatic approach, defining thin oil columns as those that "will cone both water and gas when produced at commercial rates." The overall reserve estimate of oil from such accumulations can be influenced by well spacing and completion method and by gas-cap management policy.
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!
Water is the wetting phase. Figure 1.5 – Primary drainage, imbibition, and secondary drainage for an oil/water system in which the oil and water wet the solid surface equally. Figure 1.6 – Primary drainage and imbibition for unconsolidated dolomite powder (the lines merely connect the data). These authors wrote capillary pressure as the negative of Eq. 4 because oil was the wetting phase for most of the tests. The legend gives contact angles measured through the water phase (in degrees). Leverett and coworkers, based on the evaluation of gas/water capillary pressure data for drainage and imbibition in unconsolidated sands, proposed the following definition: ....................(15.6) The function j(Sw), defined in Eq. 15.6, is known to many as the "Leverett j-function." The j-function is obtained from experimental data by plotting against Sw. The combination is often considered an estimate of the mean hydraulic radius of pore throats.
Relative permeability and capillary pressure defines relative permeabilities as dimensionless functions of saturation with values generally ranging between 0 and 1. Relative permeability is important for estimating the flow of reservoir fluids. The semilog scale of Figure 1 is convenient for reading the relative permeabilities less than 0.05. For example, the relative permeability that increases in the direction of increasing oil saturation must be the oil relative permeability. The endpoints of the relative permeabilities in Figs. 1 and 2 are defined by the critical gas saturation Sgc and the residual oil saturation Sor. Common names and symbols for some saturation endpoints are listed in Table 1.
The component located below the lowest pump section and directly above the motor, in a standard electrical submersible pump (ESP) configuration, is the seal-chamber section. API RP 11S7 gives a detailed description of the design and functioning of typical seal-chamber sections. The seal-chamber section is basically a set of protection chambers connected in series or, in some special cases, in parallel. This component has several functions that are critical to the operation and run-life of the ESP system, and the motor in particular. Figure 1 shows the seal-chamber section of the ESP unit and its component parts.
Some of the technologies, such as mechanical and control devices commonly used in subsea well and manifold systems, are well developed and can be considered off-the-shelf items. Many of the emerging products are well-proven surface components modified for subsea application. As in any integrated system, a shortcoming in any one of the links will impair the performance of the whole. A clear understanding of the process and all its parameters is the first step toward a successful design. As in surface facilities, knowledge of the produced fluid properties, rheology, and flow characteristics are critical. Luckily, whether the process is carried out on the surface or a thousand meters subsea, the process is the same. However, effects of the environmental conditions may be more dramatic and detrimental. Fluids with high foaming tendency will complicate the design and may require mechanical or chemical solutions. For subsea applications, a passive mechanical foam-breaking device (such as a low-shear inlet momentum breaker) is preferred over the more costly to install and operate chemical injection systems. For three-phase separation, the more complex oil/water emulsion/dispersion chemistry will come into play, along with the viscosities of the oil and water and changes in water cut with time. Whether an oil/water mixture will form a stable emulsion or a more manageable dispersion often depends on the small concentrations of surface-active impurities in the fluid.
Subsea processing using subsea separation and pumping technologies has the potential to revolutionize offshore oil and gas production. When combined with relatively mature subsea production technologies (see subsea chapter on well systems, manifold, pipeline, power and control umbilical, and so on), it can reduce development cost, enhance reservoir productivity, and improve subsea system reliability and operability. Over the period from 1970 to 2000, millions of dollars have been spent to develop subsea separation and pumping systems. But because of unresolved technical issues, along with a lack of confidence and clear understanding of the costs and benefits, industry has not rushed to deploy the technology on a commercial basis. However, as the industry moves into remote deep and ultradeep water, various degrees of subsea processing are becoming more common. In deep water, the technology can enable hydrocarbon recovery from small reservoirs that are subeconomic by conventional means, ...
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 ...
Case studies can be instructive in the evaluation of other coalbed methane (CBM) development opportunities. The San Juan basin, located in New Mexico and Colorado in the southwestern U.S. (Figure 1), is the most prolific CBM basin in the world. It produces more than 2.5 Bscf/D from coals of the Cretaceous Fruitland formation, which is estimated to contain 43 to 49 Tscf of CBM in place. In the 1970s, after years of encountering gas kicks in these coals, operators recognized that the coal seams themselves were capable of commercial gas rates. CBM development benefited greatly from drilling and log data compiled from previous wells targeting the deeper sandstones and an extensive pipeline infrastructure that was built to transport conventional gas. These components, along with a U.S. federal tax credit and the development of new technologies such as openhole-cavity completions, fueled a drilling boom that resulted in more than 3,000 producing CBM wells by the end of 1992. The thickest Fruitland coals occur in a northwest/southeast trending belt located in the northeastern third of the basin. Total coal thickness in this belt locally exceeds 100 ft and individual coal seams can be more than 30 ft thick. The coals originated in peat swamps located landward (southwest) of northwest/southeast trending shoreline sandstones of the underlying Pictured Cliffs formation. The location of the thickest coals (Figure 1) coincides with the occurrence of overpressuring, high gas content, high coal rank, and high permeabilities in the San Juan fairway ("fairway"). The overpressuring is artesian in origin and is caused by water recharge of the coals through outcrops along the northern margin of the basin. This generates high vertical pressure gradients, ranging from 0.44 to 0.63 psi/ft, which allow a large amount of gas to be sorbed to the coal. Coal gas in the San Juan basin can contain up to 9.4% CO2 and 13.5% C2 . Chemical analyses suggest that thermogenic gases have been augmented by migrated thermogenic and secondary biogenic gas sources, resulting in gas contents ranging up to 700 ft 3 /ton. Coal rank in the fairway ranges from medium- to low-volatile bituminous and roughly coincides with those portions of the basin that were most deeply buried. Southwest of the fairway, Fruitland coals are typically 20 to 40 ft thick and are considerably underpressured with vertical pressure gradients in some areas of less than 0.20 psi/ft. The low gradients are attributable to low permeabilities, low recharge rates along the southern rim of the basin, and hydraulic isolation from the fairway area.
A useful first step in the characterization of any new coal area is to compare its characteristics with those of successful CBM projects. Table 2 summarizes the characteristics of several successful projects in the US and includes parameters related to reservoir properties, gas production, gas resources, and economics. The table shows that successful projects have many similarities, including high permeabilities and high gas resource concentration; however, the table does not include aspects such as government incentives or high-value markets, which could elevate a marginal project to commercial status.