Intraluminal resistance to gas transport between the microcirculation and tissue was neglected for a half-century following the early work of Krogh. In recent years it has come to be understood that this neglect is seriously in error. This paper reviews the background for the long period of misdirection, and progress in placing the simulation of gas transport processes on a more accurate, quantitative basis.

No abstract

The Madison reservoir in LaBarge Field in Wyoming, U.S.A., is a multi-zone carbonate on the crest of a regionally plunging anticline. It is ~800 ft thick, covers more than 1,000 square miles, includes 4,000 ft of structural closure and holds 22 TSCF initial methane in-place. Methane percentage varies from a high of 23% at the crest to a low of 5% near the gas-water contact, with inerts - CO2, N2, H2S and He - making up the remaining gas. ExxonMobil is the only operator producing from LaBarge Madison and has built a dedicated gas plant to monetize the resource. Current production is 700 MMSCF/d (150 MMSCF/d methane) with 16 crestal producers and two downdip injectors re-injecting 60 MMSCF/d acid gas into the Madison aquifer - one of the world's largest acid gas re-injection projects. Key project objectives are to:maximize methane production from the existing wells,efficiently operate the gas processing plant, andensure sufficient acid gas disposal capacity such that production is not constrained. Key reservoir and operational uncertainties include (1) the detailed initial distribution of methane vertically and areally, (2) the impact of the mountainous topography on surface facility flowline hydraulics and producer performance, and (3) long-term injectivity, movement and containment of the injected acid gas within the aquifer. This paper discusses the integration of reservoir characterization studies, geochemical analysis, surveillance data, reservoir simulation and surface facility network models to optimize the near-term development plan and evaluate potential expansions. Key subsurface results presented include:a potential explanation for the large gas compositional gradient and the history-match approach used to approximate the methane distribution anda method to incorporate temperature-dependent acid gas injector wellbore hydraulics and acid gas viscosity in order to more accurately model pressure and fluid flow. Integrated reservoir and facility modeling led to selection and implementation of large bore tubing workovers that are, in most cases, more economically attractive than new drillwells. Field Overview LaBarge Field is located in Sublette County in southwestern Wyoming, U.S.A., as shown in Figure 1. ExxonMobil owns and operates a majority of the leased acreage, as shown in Figure 2. The primary pay interval is the Madison formation, a deep Paleozoic Mississippian carbonate reservoir, composed of anhydrite and dolomite sequences interbedded with limestone. The Madison reservoir has an original in-place methane resource of 22 TSCF (3.7 billion BOE) distributed over more than 1,000 square miles, and is normally pressured. Methane composition varies from 23% on the crest to only 5% near the gas-water contact.

No abstract

Summary The LaBarge project demonstrates the successful commercialization of a very large gas resource representative of the increasingly challenging projects faced by our industry. Three particularly distinctive aspects are (1) it is one of the largest acid-gas-reinjection projects in the world, (2) the composition is nearly 80% nonhydrocarbon, and (3) the initial compositional gradient cannot be explained by gravity segregation. This paper describes integrated reservoir modeling studies conducted to evaluate key reservoir and operational uncertainties. The integrated studies led to a new hypothesis for the initial compositional gradient and illustrated fit-for-purpose modeling approaches for reservoir fluid charging and mixing, black-oil simulation, and an integrated production network. The studies were used to optimize the drilling and depletion plan to maximize methane production with current facilities and end-of-field-life assumptions, and to analyze acid-gas injection (AGI) into the aquifer.