Onshore wells

In general, the same compositions used for onshore wells also work for the offshore wells. Saline water retards the setting rate, and longer pumping time is available for the same CBS formulation in offshore wells compared with onshore wells. In addition, because the saline water contains dissolved solids, one needs to add more water in the slurry to obtain the same low initial Be. Results of the pumping time versus temperature are shown in Table 15.6 for formulations that are similar to those given in Table 15.5. 

In order to consider these dependencies and their respective uncertainties, in this paper an approach based on a fuzzy Bayesian network wiU be looked at. By mean of a BBN approach one can capture the dependencies among performance shaping factor through the conditional probability tables. Section two presents some concepts related to Bayesian networks and fuzzy logic, while section three presents the approach adopted, drawing on the opinions of the experts. Section four looks at the case study of the installation of an optical monitoring system in an onshore well in a Petrobras brown field. In section five some results and analyses are discussed, while in section six the conclusions are presented. 

A typical career path could involve working for two to four years offshore or on an onshore well site and then moving irrto an office-based design role. This path might eventually lead to working in an overseas office following a one month ort, one month off pattern. 

Not surprisingly, costs are several times higher than conventional wells. Nevertheless, overall project economics may favour ERD over other development options. For example, BP developed the offshore part of the Wytch Farm Oilfield (which is located under Poole Harbour in Dorset, UK) from an onshore location. The wells targeted the reservoir at a vertical depth of 1,500 meters with a lateral displacement of over 8,000 meters (Fig. 3.20). The alternative was to build a drilling location on an artificial island in Poole Bay. ERD probably saved a considerable amount of money and advanced first oil by several years. 

Whether on land or offshore, the principle of satellite development is the same. A new field is accessed with wells, and an export link is installed to the existing (host) facility. Development is not always easier on land, as environmental restrictions mean that some onshore fields have to be developed using directional drilling techniques (originally associated with offshore developments). A vertical well can be drilled offshore away from the host facility, and the well completed using a subsea wellhead. 

As decommissioning approaches and all well intervention opportunities to increase productivity have been exploited, enhanced recovery processes may be considered as a means of recovering a proportion of the remaining hydrocarbons. However, such techniques are generally very sensitive to the oil price, and whilst some are common in onshore developments they can rarely be justified offshore. 

Onshore processing facilities, and modules brought onshore, have to be cleaned of all hazardous compounds and scrapped. Cellars of single wells, drilling pads, access roads and buildings will have to be removed. If reservoir compaction affects the surface area above the abandoned field future land use may be prevented, in particular in coastal or low land environments. 

The requirements of both PSM and SEMP are, from a practical standpoint, identical and thus, SEMP can easily be applied to onshore facilities as well as offshore facilities. The basic concepts of SEMP are as follows ... 

The basic principles of rotary drilling defined for onshore operations are also applicable to offshore operations. The primary difference offshore is that a stable, self-contained platform must be provided for the drilling equipment. Communication with a well through possibly thousands of feet of water provides for mechanical as well as procedural differences, primarily in well control. Onshore technology can be applied to offshore operations in many instances on bottom-supported rigs, but the use of floating vessels has resulted in the development of new technology tailored to the offshore environment. 

The most fundamental difference found between onshore and offshore drilling occurs when the wellhead is located at the seafloor. This configuration makes communication with the well more complex. A marine riser provides communication and circulation capability between the surface and the seafloor, and is used at some point during most offshore drilling. The riser consists of large-diameter (17-20) in.) steel pipe joints of approximately 50-ft lengths, with quick-connect couplings. The riser can be connected at the seafloor to a wellhead or to a subsea blowout preventer stack. A diverter system is usually attached at the... 

Offshore, well control equipment and associated operations present some differences from that seen and used onshore. In some instances onshore equipment can be employed, but the offshore environment generally dictates a modification of equipment and procedures. There are several different well configurations used offshore, often on the same well at different drilling intervals, and each configuration has specific well control procedures that should be followed. A well may be equipped with a surface blowout preventer stack a subsea blowout preventer stack, riser and diverter system a riser and diverter system with no blowout preventer a diverter only or a riserless system with no well control equipment. 

The various fields of chemistry play an important role in the discovery and exploitation of oil and gas reserves. Improved drilling and well completion fluids, cement slurries, hydraulic fracturing and acidizing fluids to improve well productivity, various chemical additives to be used in these fluids, and chemicals for enhanced oil recovery are essential to the improvement of production economics and to an increase in recoverable hydrocarbon reserves. Chemistry will become increasingly important in future hydrocarbon production with the decreased likelihood of major onshore discoveries, increased discovery and production costs associated with deep offshore wells and Arctic frontier provinces, and the decline in drilling since early 1982. 

Xue Z., Tanase D., et al. Estimation of C02 saturation from time-lapse C02 well logging in an onshore aquifer, Nagaoka, Japan. 2006 Journal of Exploration Geophysics 37 19-29. 

The latest designs for onshore installations cater for a centralized control room, well distanced from the operating facility with sub control areas as part of a distributed control system (DCS). The sub-control areas are closer to the processes but contain fewer personnel and process control systems for the overall plant, so the overall risk level for the facility from a major incident is lowered. The outlying control buildings (sometimes referred to as PIBs or SIHs) still need to be sited against impacts from explosions and fires. 

The physical approach is not undisputable, as it does not take into account the conditions of the occurrences or of the production of the crude oil (e.g., onshore or offshore, water depths, climatic conditions, etc.). Therefore, some authors give a narrower definition of conventional oil. Campbell (2006), for instance, considers crude oil that is found under deep-water conditions (water depths greater 500 m) or in arctic regions, as well as NGL as unconventional oil. As a consequence, the remaining potential of conventional oil is estimated to be lower. 

Transportation of C02 by ships is suitable for offshore geological C02 storage and is favourable for longer distances (Heddle et al., 2003). One of the options where the use of ships could be favourable is the transportation of C02 from the onshore harbour with an intermediate storage facility to the underground geological storage site located offshore. There, C02 could be transferred into an injection well via a vertical pipeline. Ships would most probably come into play to supply offshore enhanced oil recovery projects with C02 (compare, e.g., Barrio et al., 2004). 

Large railway trains could be used as a means of transport for onshore distances as well (compare Odenberger and Svensson, 2003). However, the specific costs estimated by these authors for railway transportation were considerably higher than for pipeline transportation. 

Most studies of the chemical composition of particles in the troposphere to date have used analysis of bulk samples, which are usually collected in the boundary layer close to the earth s surface. As discussed in Chapter 6. J.3, there is a great deal of interest in the chemistry of the upper troposphere. Much less is known about the chemical composition in this region, particularly of particles. However, it appears that organics are also important constituents of particles in this region as well. For example, Novakov et al. (1997) in studies of particles both onshore and offshore of the eastern United States found that the mass fraction of the particles due to carbon compounds increased as a function of altitude. In the boundary layer, the fraction was typically 10-40%, increasing to 50-90%atan altitude of 2-3 km. 

Onshore, water usually will be reinjected by a disposal well. In very dry climates, small amounts of produced water may be disposed of in evaporation pits. However, this process is becoming less acceptable to environmental agencies and is not dealt with further in this article. 

In offshore operations, exploration wells are almost always plugged and abandoned even when they strike petroleum. Their sole function is to find oil or gas and to delineate the reservoir. The operator uses this information to pick a location for a permanent production platform from which development wells will be drilled to recover as much petroleum as economically possible. In onshore operations, however, successful exploration wells also become producers. 

The total investment will include 3600 million Euro allocated for the field development. This includes the sub sea well-stream pipeline system and the onshore processing plant and storage tanks. An other 700 million Euro will be invested in a LNG tanker fleet comprising 4 ships in the 140-145 000 m3 class [17]. The storage capacity of the Snohvit processing plant comprises two 125 000 m3 LNG storage tanks, one 45 000 m3 LPG tank and one 75 000 m3 condensate tank. 

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