The paper presents comparative economics for four different methods of converting associated gas into Methanol. The present study differs from other studies in that it is able to use knowledge gained from the design of 12 of the 16 plants in the world having a capacity of 1000 STPD, or greater. Additionally, a two year study of barge mounted methanol plants has provided a sound basis for estimating the capital costs of these units.
Because of the recognition both by governments and by individual companies that flaring of associated gas represents a wastage of a valuable resource, more attention is being focussed on the best means to convert it into a useful commodity. This study examines the technical and economic feasibility of converting it into methanol.
If the associated gas is on shore and in an area where there is some existing infrastructure, a supply of skilled labor, and a temperate climate, then the economic production of methanol presents no problems.
This study is not concerned with the easy to build methanol plant. It is more concerned with dealing with associated gas, onshore and offshore, in locations where an infrastructure may not exist, where there are no existing services, where there might be no local supply of skilled construction labor, and where the climatic conditions might be severe. Some, or all, of these conditions apply in: The North Sea, the Middle East, South East Asia, the Arctic and other places.
A specific problem arises when a government imposes a "no flaring" rule on an offshore marginal oil field with a very high GOR that is either too remote from existing gas pipelines or, because of the characteristics of the gas (e.g. high CO2 or high N2 contents), is not suitable without expensive treatment for introducing into existing pipelines. The gas quantities might also be of such a size (e.g. 70 MMSCFD) that pipelining to a monopoly purchaser with an existing adequate supply represents a very poor economic alternative to costly reinjection. An example of this type is considered.
Many previous studies have used capital costs which apply to an Inside Battery Limits scope of supply rather than to a facility on a virgin site that has sea water and a supply of gas and little in the way of services. It is hoped that this study gives a more realistic appraisal of capital costs for a remote plant whether it is onshore or offshore.
The plants that will be built in future will each have a capacity of more than 1000 STPD and are more likely to have a capacity similar to that of either the largest plant currently operating (2200 STPD) or to that of the largest plants currently being built (2 × 2760 STPD). This Study is based upon these three plants, nine others sized at 1000 STPD or larger, and five other plants either designed in the past ten years or being designed at present.
