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.
The majority of offshore fields have been developed with conventional fixed steel platforms. One common feature of fixed steel structures is that it is essentially "fixed" (i.e., it acts as a cantilever fixed at the seabed). This forces the natural period to be less than that of the damaging significant wave energy, which lies in the 8- to 20-second band. As the water depth increases, these structures begin to become more flexible, and the natural period increases and approaches that of the waves. The consequence of this is the structure becomes dynamically responsive, and fatigue becomes a paramount consideration.
Figure 1.6--The Baldpate Compliant Tower is one of the tallest free-standing structures in the world – Empire State Building (right) for comparison (Web Photograph, Amerada Hess Corp., New York City). Figure 1.9a--Worldwide fleet of installed and sanctioned semisubmersible FPS (courtesy of BP). Figure 1.9c--Worldwide fleet of installed and sanctioned spars (courtesy of BP). Figure 1.10--Semisubmersible FPS planned for the Thunder Horse field (courtesy of BP). Figure 1.11--Alternative proven technology field development options (courtesy of BP). Figure 1.12--Subsea production trees used in conjunction with a fixed jacket structure (Intec Engineering, Houston).
Each of these is discussed briefly in the next two sections. Thereafter--except for another section on probabilistic procedures near the end--the chapter will focus on deterministic procedures because they still are more widely used. Both procedures need the same basic data and equations. Reserves calculated using such procedures are classified subjectively on the basis of professional judgments of the uncertainty in each reserve estimate and/or of pertinent regulatory and/or corporate guidelines. Probabilistic procedures recognize that uncertainties in input data and equations to calculate reserves may be significant.
This field produces from a structure that lies above a deep-seated salt dome (salt has been penetrated at 9,000 ft) and has moderate fault density. A large north/south trending fault divides the field into east and west areas. There is hydraulic communication across the fault. Sands were deposited in aeolian, fluvial, and deltaic environments made up primarily of a meandering, distributary flood plain. Reservoirs are moderate to well sorted; grains are fine to very fine with some interbedded shales. There are 21 mapped producing zones separated by shales within the field but in pressure communication outside the productive limits of the field. The original oil column was 400 ft thick and had an associated gas cap one-third the size of the original oil column. Porosity averages 30%, and permeability varies from 10 to 1500 md.
Although conformance-improvement gel treatments have existed for a number of decades, their widespread use has only begun to emerge. Early oilfield gels tended to be stable and function well during testing and evaluation in the laboratory, but failed to be stable and to function downhole as intended because they lacked robust chemistries. Also, because of a lack of modern technology, many reservoir and flooding conformance problems were not understood, correctly depicted, or properly diagnosed. In addition, numerous individuals and organizations tended to make excessive claims about what early oilfield gel technologies could and would do. The success rate of these gel treatments was low and conducting such treatments was considered high risk. As a result, conformance-improvement gel technologies developed a somewhat bad reputation in the industry. Only recently has this reputation begun to improve. The information presented in this chapter can help petroleum engineers evaluate oilfield conformance gels and their field application on the basis of well-founded-scientific, sound-engineering, and field-performance merits.
Transmitting electrical current to the subsurface can create special considerations. Successful application of electromagnetic heating often requires a multi-disciplinary approach combining electric engineering and petroleum engineering. To assist petroleum engineers considering this approach, this article identifies some of the issues that an electrical engineer might normally anticipate and address. In most practical situations, we are concerned with fields that vary periodically in time (the sinusoidal steady state generally). In these cases the electrical phenomena are properly described by Maxwell equations in terms of complex vector field intensities of electric and magnetic fields (E and H); complex vector field electric, magnetic, and current densities (D,B,J); complex charge concentrations (ρc); and complex material parameters: conductivity, permittivity, and permeability (σ, ε, μM).
Borehole gravity was pioneered by Smith and then applied to problems of reservoir evaluation by McCulloh et al. The borehole gravity meter or gravimeter responds to variations in density. Unlike the shallower-sensing density log, the borehole gravimeter is insensitive to wellbore conditions such as rugosity and the presence of casing. Because the Earth is a rotating oblate spheroid, the quantity g at mean sea level varies with latitude, and it must be corrected for tidal effects. The unit of g is the Gal [1 cm/s2]. Surface gravity surveys use the milliGal as the preferred unit.
The primary physical mechanisms that occur as a result of gas injection are (1) partial or complete maintenance of reservoir pressure, (2) displacement of oil by gas both horizontally and vertically, (3) vaporization of the liquid hydrocarbon components from the oil column and possibly from the gas cap if retrograde condensation has occurred or if the original gas cap contains a relict oil saturation, and (4) swelling of the oil if the oil at original reservoir conditions was very undersaturated with gas. Gas injection is particularly effective in high-relief reservoirs where the process is called "gravity drainage" because the vertical/gravity aspects increase the efficiency of the process and enhance recovery of updip oil residing above the uppermost oil-zone perforations. The decision to apply immiscible gas injection is based on a combination of technical and economic factors. Deferral of gas sales is a significant economic deterrent for many potential gas injection projects if an outlet for immediate gas sales is available. Nevertheless, a variety of opportunities still exist. First are those reservoirs with characteristics and conditions particularly conducive to gas/oil gravity drainage and where attendant high oil recoveries are possible. Second are those reservoirs where decreased depletion time resulting from lower reservoir oil viscosity and gas saturation in the vicinity of producing wells is more attractive economically than alternative recovery methods that have higher ultimate recovery potential but at higher costs. And third are reservoirs where recovery considerations are augmented by gas storage considerations and hence gas sales may be delayed for several years. Nonhydrocarbon gases such as CO2 and nitrogen can and have been used.
Hydrocarbon production potential is often limited by constraints, and it is important that these constraints are understood and correctly represented when generating a realistic set of production profiles. The focus of this section is physical constraints in the system through which the fluid flows, but constraints applied because of reservoir management, contractual terms and economics are also highlighted. A production system includes the reservoir, wells, facilities and export system. Constraints within the system can be associated with any of the produced fluids (oil, gas or water) or a specific combination of them. For example, important factors to consider beyond the base deliverability of the reservoir are potential near-wellbore formation damage (skin), well tubing constraints, artificial lift availability, shared gathering system back pressures, flow line erosion velocity limits and facility capacities.