An analysis of water or gas coning behaviour is particularly important in determining the future performance of gas reservoirs and thick oil reservoirs of the Rainbow-Zama- Virgo types. Investigations of coning in these reservoirs have only recently become practical. This paper describes results from two numerical coning studies - one a gas-water problem, the other a three-phase problem in a Virgo reef. The implicit numerical model used is described in detail. INTRODUCTION THE CONTROL OF GAS AND WATER CONING in petroleum reservoirs is essential in optimizing recovery and minimizing operational costs. Coning is the result of high-pressure gradients around the producing well which cause the oil-water contact to rise and the gasoil contact to depress near the wellbore. Gravitational forces tend to segregate the fluids according to their densities. However, when gravitational forces are exceeded by the flowing pressure, a cone of water and/ or gas will penetrate the producing interval. Only recently has it become practical to investigate coning as a non-steady-state flow phenomenon with heterogeneous reservoir properties. These investigations are now practical utilizing numerical coning models. Coning is simulated with a 2D radial (R – Z) grid system extending out from the wellbore to some external radius (Re). To obtain proper definition of the gas and water cones, a fine grid is used near the wellbore. The pore volumes of these interior grid blocks are typically 1 to 10 barrels, At a normal producing rate and with a reasonable time-step size, the fluid throughput per time step of the inner blocks is many times the pore volume of the blocks. This high throughput causes large saturation changes per time step and, in the past, these large saturation changes have caused model instabilities. Normally, in a reservoir simulator the transmissibilities governing flow between blocks and the production rates of oil, gas and water are calculated explicitly using the saturation conditions existing at the beginning of the time step. If explicit transmissibilities and production terms are used in a coning model, a practical time-step size will cause the predicted saturations to become unstable and the GOR's and WOR's to oscillate, These instabilities can be controlled by treating the transmissibilities and production terms implicitly rather than excplicity. The computation required per time step increases with a totally implicit model, but the resulting increase in the time-step size which can be taken more than offsets the greater computation requirements. The net result is a numerical model which can be used routinely, at low cost, on practical problems. The Appendix describes in detail the mathematics of this coning model. The following section describes two coning studies. The first case is a gas pool with an underlying aquifer. The second is a single-well bioherm reef being produced under primary depletion. Initially, it is without a gas cap, but it does have a small underlying aq Uifer, Both studies used a fully compressible threephase 2D radial model.

creasing production rate can adversely affect ultimate recovery. This rationale With the world wide high demand for oil, is in turn, partly derived from observathe rate of oil production from Alberta pools tions that counter-current imbibition and has dramatically increased over the last few gravity drainage are time-dependent reyears. This investigation was undertaken covery mechanisms and can more effectively "to determine if reservoirs, typical of the contribute to ultimate recovery at lower more important Alberta pools, are sensitive reservoir withdrawal rates.

A metal organic framework Cu(tpt)BF4·¾H2O was synthesized as a potential carbon capture material, with the aim being to exploit the Lewis base interaction of the incorporated ligand functionalities with acidic gas. The material displays high thermal stability but an exceptionally low surface area; however, this contrasts starkly with its ability to capture carbon dioxide, demonstrating significant activated diffusion within the framework. The full characterization of the material shows a robust structure, where the CO2 sorption is 120% greater than current industrial methods using liquid amine solutions; the thermal energy required for sorbent regeneration is reduced by 65%, indicating the true industrial potential of the synthesized material.

INTRODUCTION

This paper was prepared for presentation at the 47th Annual Fall Meeting of the Society of Petroleum Engineers held in San Antonio, Tex., Oct. 8–11, 1972. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by who the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract It is well recognized that the field deliverability of dual porosity reservoirs does not follow the projections made using standard analytical or two dimensional modelling techniques. Although the literature reports a number of methods to analyze the pressure buildups for such reservoirs, these methods do not provide a means of computing long term deliverability. This paper discusses the use of three dimensional modelling techniques to determine reserves and to project the deliverability of dual porosity gas reservoirs. The two field applications presented include:a naturally fractured reservoir, anda reservoir where severe stratification makes it behave like two or more independent reservoirs communicating through shale-breaks or "windows" between them. The pressure buildups recorded in these fields are unusual. Wells with core permeability of 20 to 40 md continue to buildup for more than fifteen months and exhibit an extraordinary rise near the end of the shut-in period. A history match using the above model resulted in the determination of the pore volume of each porosity system and the "flow capacity" between these systems. The model, for the prediction of deliverability, simultaneously solves the equations describing flux flow through the reservoir, the wellbores, the tubings and the surface system. Results show that the effect on deliverability of changes in the surface gathering system, number of wells or the operational strategy will be seriously miscalculated if the dual porosity effect is not considered. Introduction The ability to accurately forecast gas field deliverability under various operating conditions is a necessity for the optimum exploitation of any gas reservoir.