Water or gas coning in oil and gas wells worldwide is a typical situation in many reservoirs. These phenomena have been investigated numerous times unfortunately most of the efforts have been dedicated to critical rate and /or calculation of breakthrough time. Much of that work although useful in the initial stage of production or on a thick oil column and high permeability reservoirs, has limited practical used in the field worldwide because in many situations , many fields have had extensive coning already. Typically in coning situations, practical field type questions are: • Is water production due to cement channeling or poor bond in casing or is it due to coning? • What is my ultimate recovery factor and how does that correspond to water-oil ratios? • How would wells that cone behave in long term? • Is recovery factor rate sensitive? • What kind of bottomhole producing pressure should I produce at? This paper is directed at demystifying coning behavior and helping use production profile behavior as a diagnostic to answer some of the questions above. How much a well cones or crests water or gas in oil wells and water in gas wells depends upon two components. The first is related to how the pressure in the well locally distorts the contacts. The second component is how withdrawals of oil or gas cause the contact globally to change. An understanding of both components are necessary to understand behavior. The ability of a well to locally distort a contact is related to; • system permeability • mobility ratio • density difference • standoff distance • wellbore flow geometry The second component of how withdrawal effects global contacts is a function of • drive mechanism • the strength of the water leg or size of the gas cap • the size and shape function of the OOIP or OGIP • relative permeability • cumulative volumes removed • residual saturations The study examines the literature and a series of simulation models how to diagnose the critical factors in a coning problem and from that estimate reserves simply.
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