Analysis of Nitrogen-Injection Projects to Develop Screening Guides Projects to Develop Screening Guides and Offshore Design Criteria Summary In 1982 more than 500 million cu ft/D [ 14 ⨯ 10–6 M3 /d] of nitrogen was injected into oil or gas reservoirs. To date, 30 fields have used nitrogen for enhanced oil or gas recovery (EOR/EGR), In this paper, 29 nitrogen EOR/EGR projects are listed. Some pertinent reservoir, rock, and fluid data, as well as historical information and injection rates, are given for each field. On the basis of the literature and the analysis of these 29 fields, five applications of nitrogen are indicated: immiscible displacement, miscible displacement, gravity drainage enhancement, pressure maintenance, and as a driving fluid for a miscible slug. No single nitrogen application, however, is mutually exclusive in any field; two or more mechanisms (applications) may be involved, For each application, a specific field was chosen as an example and more detail was provided. A screening guide has been developed for each application. Most of the 29 fields fall within these guidelines for the respective nitrogen applications. As nitrogen EOR/EGR technology matures in onshore projects, operators will attempt to transfer this technology projects, operators will attempt to transfer this technology to offshore fields. To date, three barge-mounted nitrogen plants have been used in near-shore fields. Air plants have been used in near-shore fields. Air separation plants can be installed on platforms to supply nitrogen. Some offshore nitrogen supply parameters are presented and discussed. presented and discussed. Introduction Primary production and secondary recovery methods Primary production and secondary recovery methods (waterflooding or reinjection of produced natural gas) on the average produce less than one-third the original oil in place (OOIP). Enhanced recovery techniques (such as thermal, chemical, or gas injection) can be used to recover additional hydrocarbons. The literature is replete with information on thermal, chemical, and CO2 miscible displacement. Several publications, including the Natl. Petroleum Council publications, including the Natl. Petroleum Council (NPC), contain screening guides for most enhanced recovery processes. However, these screening guides and their respective reports are generally silent with respect to two processes, nonhydrocarbon immiscible displacement and nitrogen miscible displacement, both of which are considered by the U.S. DOE as EOR techniques ' 2 In the U.S. and Canada more than 500 million cu ft/D 14 × 10–6 m3/d] of nitrogen is being injected into reservoirs to enhance the recovery of oil or gas, In reviewing the literature, several facts are apparent:more than 30 fields have used nitrogen for EOR;no comprehensive list of the various nitrogen projects is available, andno screening guides for nitrogen are available or have been proposed. A comprehensive list of nitrogen-EOR projects and screening guides should be helpful to field operators who are considering enhanced recovery projects. For the most part, EOR has been limited to onshore fields. As the state of the art of EOR processes develops and as our offshore fields mature, operators will be using EOR processes offshore. Platform space and supply constraints will limit the operator's EOR options. Nitrogen injection, however, may not be as technically and economically constrained as other EOR options. Gas Injection-Historical Perceptions. Before 1970, natural gas (rich or lean) was the primary choice of operators for gas injection (miscible or immiscible). In the 1960's and 1970's, operators began seeking nonhydrocarbon sources of gas because natural gas was unavailable in some geographic areas or natural gas was becoming too expensive for reinjection. CO2 and nitrogen started to emerge as substitutes for natural gas. In the 1960's and early 1970's, operators seeking additional volumes of gas generated inert gas (mostly nitrogen, but containing some CO2 and other combustion products) by burning natural gas in boilers or internal combustion engines; processing the flue gas or engine exhaust gas, respectively, to remove water, heat, and undesirable combustion byproducts; and compressing the resultant processed gas using steam-driven compressors or the internal combustion engine. A more detailed description of these processes is contained in Refs. 3 and 4. In the mid- 1970's, operators sought a source of nitrogen that had no corrosion potential, had high reliability, and had economy of scale potential. In 1977 the first air separation plant appeared in the oil fields. JPT P. 1097

Nitrogen has recently emerged in the Rockies as an alternative to natural gas and carbon dioxiae. A number of fields, particularly in the overthrust, are using large volumes of nitrogen to increase the recovery of oil. The application of nitrogen in four Rocky Mountain nitrogen injection projects is described, giving r~servoir parameters, quantities of gas injected and some early predictions.In many gas injection projects an operator usually has a choice among alternative gases. After oetermining for each alternative the incremental barrels of oil recovered per thousand stanoard cuoic foot (MSCF) of gas injected and the rate of recovery, the operator should consider the following factors; the cost per MCF at delivery pressure at the field, the long term availability and reliability of supply, the physical and chemical properties, the incremental cost for corrosion and produced gas clean-up, and the impact of the Windfall Profits Tax.These factors are presented, discussed and compared for natural gas, nitrogen and carbon dioxide.

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Nitrogen, produced by air separation and compressed to high pressure has many potential applications in enhanced oil and gas recovery. Possible applications include using nitrogen as a driving gas for costly and limited carbon dioxide, and in some cases for miscible displacement. The displacement of gas cap gas, the production of attic reservoirs, the cycling of condensate reservoirs, the maintenance of reservoir pressure and other applications can also be considered. Nitrogen can be produced at almost any reservoir site using proven technology and various energy sources. Depending upon the pressure, quantities, and location, nitrogen may cost one-quarter (1/4) to one-half (1/2) the price of natural gas. Using existing technology, nitrogen can be separated from the produced associated natural gas.

Introduction There are a number of motivators driving LNG side-by-side as a cargo transfer option, not least the success of floating solu-tions in Oil and LPG production projects. The main problem faced is that present LNG ships are designed for conventional manifold loading only. This, coupled with the fact that suitable floating LNG hoses only being in the early stage of develop-ment, ensure that tandem loading is not an option at this time. We also have the situation where it is increasingly difficult to build a shore terminal for receiving Bulk LNG. Ports big enough for the ships are increasingly congested and bulk LNG terminals have strict HSE requirements. The option of having Floating Storage and Regasification Units (FSRUs) situated offshore but near to the ports, offers a solution that is being ex-plored by a number of importers. This again will require side-by-side for discharge, as the gas will increasingly come from the spot market on standard long-haul vessels. With FPSO LNG projects now coming off the drawing boards and going into the yards, companies have to be certain of the capabilities of the Ship-to-Ship (STS) Industry. STS Service Providers need to use their experience to provide an operational envelope that makes the economics work. Historically, Ship to Ship Transfers were generally considered something of a ‘risky’ operation, only carried out when abso-lutely necessary. There is now a growing confidence that the STS Industry today can deliver a high quality, repeatable opera-tion and meet the high safety standards expected in the LNG Industry.