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At the present time, more than 9,000 offshore platforms are in service worldwide, operating in water depths ranging from 10 ft to greater than 5,000 ft. 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.
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.
Subsea processing using subsea separation and pumping technologies has the potential to revolutionize offshore oil and gas production. Between 1970 and 2000, millions of dollars were 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 did not rush to deploy the technology on a commercial basis. However, as the industry has moved 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, making small fields economically viable and large fields even more profitable.
Wells producing water are likely to develop deposits of inorganic scales. Scales can and do coat perforations, casing, production tubulars, valves, pumps, and downhole completion equipment, such as safety equipment and gas lift mandrels. If allowed to proceed, this scaling will limit production, eventually requiring abandonment of the well. Technology is available for removing scale from tubing, flowline, valving, and surface equipment, restoring at least some of the lost production level. Technology also exists for preventing the occurrence or reoccurrence of the scale, at least on a temporary basis. "Temporary" is generally 3 to 12 months per treatment with conventional inhibitor "squeeze" technology, increasing to 24 or 48 months with combined fracture/inhibition methods. As brine, oil, and/or gas proceed from the formation to the surface, pressure and temperature change and certain dissolved salts can precipitate. If a brine is injected into the formation to maintain pressure and sweep the oil to the producing wells, there will eventually be a commingling with the formation water. Many of these scaling processes can and do occur simultaneously. Scales tend to be mixtures.
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. For a long time, the Fruitland formation coals were recognized only as a source of gas for adjacent sandstones. 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. Coals in the fairway typically have low ash and high vitrinite contents, resulting in large gas storage capacities and excellent permeabilities of 10 md from well-developed cleat systems. 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.
Remote well monitoring is the ability to provide data obtained in or near the wellbore without requiring access and entry for intervention to the well. Downhole permanent monitoring has been a widely accepted technology since the early 1990s. There are advantages and disadvantages to all monitoring systems; however, improvements in reliability and the realization of the added value of information have made this technology commonplace in offshore and some land applications. Remote monitoring can be coupled with remote flow control applications in intelligent wells, or it can be run as a standalone system. Sensor systems may be electronic or optical based.
The Merriam-Webster Dictionary defines simulate as assuming the appearance of without the reality. Simulation of petroleum reservoir performance refers to the construction and operation of a model whose behavior assumes the appearance of actual reservoir behavior. The model itself is either physical (for example, a laboratory sandpack) or mathematical. A mathematical model is a set of equations that, subject to certain assumptions, describes the physical processes active in the reservoir. Although the model itself obviously lacks the reality of the reservoir, the behavior of a valid model simulates--assumes the appearance of--the actual reservoir. The purpose of simulation is estimation of field performance (e.g., oil recovery) under one or more producing schemes. Whereas the field can be produced only once, at considerable expense, a model can be produced or run many times at low expense over a short period of time. Observation of model results that represent different producing ...
Reservoir simulation is a widely used tool for making decisions on the development of new fields, the location of infill wells, and the implementation of enhanced recovery projects. It is the focal point of an integrated effort of geosciences, petrophysics, reservoir, production and facilities engineering, computer science, and economics. Geoscientists using seismic, well-log, outcrop analog data and mathematical models are able to develop geological models containing millions of cells. These models characterize complex geological features including faults, pinchouts, shales, and channels. Simulation of the reservoir at the fine geologic scale, however, is usually not undertaken except in limited cases.
This page provides a reservoir management case study for an offshore sandstone field under solution-gas drive in which water and gas injection techniques have been implemented. The highly faulted structure produces from six different productive horizons. The depositional settings range from deepwater marine turbidite fans through near shore and delta san facies to fluvial deposits. The reservoir has been developed from two separate platforms and has an extensive subsea development of satellite fields. More than 140 wells have been drilled from two platforms since initial development in 1976 with well lengths varying from 9,800 to 19,000 ft.
Nearly 150 workers have been evacuated or are due for evacuation from Shell's Shearwater project in the North Sea since a COVID-19 outbreak emerged at the end of June, the company said on 20 July, as the industry called for an exemption from self-isolation rules for offshore workers. So far, 26 people at the Shearwater oil and gas hub have tested positive for COVID-19, with another 122 categorized as having been "close contacts" of those infected, Shell told S&P Global Platts. Most have already been flown to shore, with a small number isolating at the facility before returning to shore, Shell said, adding that the spread of infection was slowing, with only five cases detected in the last 7 days of the outbreak. Shearwater is the focus of concerns that rising UK infection rates could spread to the offshore oil and gas sector, which normally provides 1 million B/D of oil including the Brent and Forties benchmark grades and meets about half the country's gas needs. Offshore workforce numbers have recently recovered to well over 10,000, following a steep fall last year in response the pandemic, according to industry figures.