Summary Experimental results on the rheology of gas/water foam essentially show that if the gas flow rate is increased at an imposed water rate, the pressure gradient increases, reaches a maximum (the break point), and then decreases. A model for foam flow was formulated that explains this behavior semiquantitatively. It consists of a highly simplified model for foam in a single capillary coupled with a description for foam flow in a bundle of identical parallel capillaries. Below the break point, capillaries filled with foam occur with water-filled capillaries; above the break point, the water-filled capillaries are replaced by gas-filled capillaries. A consequence of the model is that if one plots the results in a special way, a universal curve is obtained, dependent on only the porous medium and the fluid properties. The experimental data more or less conform to this curve, which can be used (in the same way as relative permeabilities) to predict pressure gradients for gas/water rates other than those experimentally measured. Consequences of the foam model for numerical simulation of foam flow are discussed. Introduction Because the mobility of gas flowing through a porous medium is reduced considerably when the gas is flowing as a foam, foams have been, proposed for many oil recovery processes involving gas injection. For practical applications, one would lie to know the basic relationships between gas/liquid fluxes, pressure gradient, and saturations. Also, the dependence of these relationships on several factors-such as surfactant type and concentration, the properties of the porous medium, and the presence of oil-warrants investigation but was ignored in this study. Some confusion exists in the literature about the basic relationships between fluxes and pressure gradient. Most investigators find a decrease in foam mobility when the foam quality is increased for "cold" gas/water foams, whereas others find an increase. For steam foam, only an increase in foam mobility with increasing quality has been reported. (Foam quality is the volume gas rate in the foam as a fraction of the total volumetric rate, whereas steam quality is the mass vapor rate in the steam as a fraction of the total mass rate.) Although in steam foam other processes than those in gas/water foam (condensation and evaporation) play a role, we thought that these additional processes should not effect such significant differences. Consequently, we studied the rheology of nitrogen/ water foam in porous media, concentrating on a quality range between gas/water foam (qualities normally less than 95 %) and steam foam (qualities normally >99 %). We show that steam and gas/water foams of comparable foam quality exhibit similar behavior. Experimental Setup and Results The experimental setup is basically a standard coreflow experiment in which gas and liquid flow rates are imposed and the resulting steady-state pressure gradients are measured with a number of pressure taps. Foam is generated outside the porous medium by means of a stainless-steel porous plug in front of the inlet. The foam's texture (the bubble size) has been shown to be an important variable in determining foam mobility. Varying the texture of our injected foam by varying the properties of the foam generator did not influence the results within experimental error. We conclude, therefore, that the foam texture is changed by the porous medium to a value independent of the injected texture in porous medium to a value independent of the injected texture in such a short distance that the effects are not noticeable in our experiments. The pressure gradients were measured over several sections of the porous medium, and the results were found to be comparable. The pressure gradient was measured over a 10-mm [0.4-in.] section approximately halfway along the porous medium. Because of the high pressure gradients measured and the compressibility of the gas phase, pressure differences should be small compared with the phase, pressure differences should be small compared with the pressure level. pressure level. We performed two sets of experiments (Sets 1 and 2) in slightly different equipment. The data are summarized in Table 1. Set 1 experiments were performed at ambient temperature on a Clemtex sandpack of 4.2-/im permeability.

When a waterflooded oil reservoir is to be depressurised, it is important to predict the production of solution gas from the by-passed and trapped oil. To quantify the gas saturation build-up and the relation between gas mobility and gas saturation, we have carried out a large number of experiments on core samples. These pressure-depletion experiments, which were conducted at various depletion rates and with both model fluids and actual reservoir fluids, began from one of two starting conditions: reservoir rock at initial conditions (i.e. containing oil and connate water) or watered-out reservoir rock (i.e. containing brine and residual oil). Relating the experimental results to field conditions was a major concern for two reasons:The experimental results were sensitive to the depletion rate (and the field depletion rate is two orders of magnitude lower than what was possible in the laboratory).The experimental results were sensitive to the fluid/rock system used. In this paper we discuss the interpretation of the experimental results and the approach we have adopted for extrapolating them to field conditions, so that the reservoir engineer can assess their practical consequences for field development. We found that when the experiments were run starting under initial reservoir conditions, the nucleation properties of the fluid/rock/pressure combination, together with the depletion rate, determine the gas saturation build-up. To extrapolate such laboratory results to the pressure-decline rate of the field, it is essential that the experiments be conducted with reservoir fluids at reservoir pressure and temperature. When the experiments were run under watered-out conditions, no such dependency on nucleation properties was found. Instead, the mobility of the gas could be correlated with the total hydrocarbon saturation, the same correlation applying to different fluid/rock/pressure combinations. Introduction The Brent Field in the North Sea is currently producing oil under pressure maintenance by waterflooding. A future development phase involves a reservoir depressurisation to recover most of the reservoir gas and to increase oil recovery. To properly plan this development phase so that the hydrocarbon recovery is optimised, it is important to know the critical gas saturation above which liberated solution gas becomes mobile enough to be produced. A considerable effort has been put into laboratory experiments to determine this critical gas saturation and, in fact, to plot the complete gas saturation build-up versus declining pressure. P. 361^

The inflow performance of gas wells in gasicondensate fields may be impaired when condensate banks form near the wellbore as a result of the pressure dropping below the dewpoint. This impairment may be alleviated

Summary Analytical techniques were used to study improvement of gas/oil gravitydrainage by steam injection in a densely fractured dome-shaped low-permeabilityreservoir containing viscous oil. Aspects of the process studied include mixingof the steam and hydrocarbon gas, the temperature distribution in the caprockand reservoir, and oil production by thermal expansion and gravity drainage. The models developed are applied to the Qarn Alam reservoir of Oman, which maybe a candidate reservoir. The steam-injection process appears very attractivefor this reservoir; an oil/steam ratio of 0.5 m3/Mg may be achieved. Introduction The Qarn Alam reservoir is a densely fractured chalk formation with amaximum oil column of 165 m containing moderately heavy oil (a density of 956kg/m3 and a viscosity of 220 mPa.s). The reservoir has 221.5 × 106 m3stock-tank oil originally in place (STOOIP) and an ultimate primary recovery of3.6 × 106 m3. The field came on production in early 1975 and produced 3.13 × 106 m3 by the end of 1989 under a strong natural produced 3.13 × 106 m3 by theend of 1989 under a strong natural waterdrive. The major contribution torecovery has been from the fractures (an estimated 75%), and less than 0.5% ofthe matrix STOOIP has been produced. The current oil cut of the wells is 5%. Currently there is a produced. The current oil cut of the wells is 5%. Currently there is a 20-m-thick secondary gas cap in the fracture system at thecrest; the oil column in the fracture system is 30 m. The main oil productionmechanism is considered to be gravity drainage. Of the current 165-m3/d oilproduction rate, about 50 m3/d is produced by gas/oil gravity drainage andabout 115 m3/d by water/oil gravity drainage. . A possible means of increasingthe oil production rate is to lower the gas/oil contact (GOC) in the fracturesand so increase the area, thereby increasing the gas/oil gravity-drainage rate. The required pressure depletion also will cause oil expulsion from critical gassaturation buildup. Owing to the very strong aquifer, pressure depletion can beachieved only by producing water at a significantly higher rate. An alternativemeans of increasing the gas/oil gravity-drainage rate is to reduce the oilviscosity by injecting heat into the gas cap. This paper discusses this lattermeans. With a porosity of 30%, initial oil saturation of 0.95, and a matrixpermeability from 5 to 25 md, the reservoir properties are attractive forpermeability from 5 to 25 md, the reservoir properties are attractive forthermal recovery. Several similar reservoirs have been developed by steaminjection. Fig. 1 is a schematic of the Qarn Alam reservoir showing thepositions of the oil/water contact (OWC) and GOC in the fracture system, positions of the oil/water contact (OWC) and GOC in the fracture system, thehot/cold interface in the matrix system, and the processes that distribute theheat. Injected steam and hydrocarbon gas mix, resulting in a temperature dropfrom the steam temperature to the temperature at which the mixture has aminimum density. This convective mixing process is analyzed in the nextsection. The mixing rate is investigated from the density of the steam/gasmixture at different temperatures in terms of Rayleigh convection cells, and anestimate of the area over which mixing occurs is made. The heat distribution inthe caprock and in the reservoir then is determined. The matrix blocks areassumed to be so small that they can be considered uniformly heated. At thecrest, a uniform-temperature zone is created. Beneath this zone the temperaturedeclines gradually to the original temperature deep in the reservoir. Theisotherms are approximated by horizontal planes, the validity of which isdiscussed in Ref. 5. In a later section, the oil production rate from gravitydrainage and oil expansion is derived. The temperature distribution andcapillary forces are incorporated into the derivation. Finally, the cumulativeoil/steam ratio (COSR) for several matrix permeabilities is presented anddiscussed as a function of time. Steam/Gas Mixing A temperature lower than that of the steam exists at which thehydrocarbon-gas/steam mixture density has a minimum. This feature isresponsible for the effective mixing of injected steam and hydrocarbon gas byfree convection in the highly permeable fracture network.

In the wake of the Kyoto protocol, CO2 emission reduction to control the level of CO2 in the atmosphere has become an important goal. One possibility of reducing greenhouse gas emission is to separate and inject CO2 from gas fired power plants into gas fields. To investigate the effects of CO2 injection on methane recovery, five different CO2 injection strategies were investigated for an example gas reservoir. The injection scenarios included installation of a Zero Emission Power Plant (ZEPP) at surface, supplying the reservoir with a constant CO2 rate over 25 years. Installation of a ZEPP enabled using a lower tubing head pressure than for gas delivery to the gas distribution grid resulting in accelerated methane production. For most of the cases investigated, the cumulative methane production was increased as well. CO2 breakthrough occurred between 3 and 15 years. The CO2 which was produced in the production wells was fed into the ZEPP and re-injected with the newly generated CO2. The highest incremental gas recovery was obtained for the case of conventional depletion of the gas reservoir until abandonment and subsequently injection of CO2, leading to enhanced gas recovery. The maximum incremental gas recovery was about 10% of Gas Initially In Place (GIIP). For the case of injection of CO2 early in the life of the gas field, the methane recovery was decreased compared with conventional gas production by depletion. Introduction In the wake of the Kyoto protocol, CO2 emissions reduction to control the level of CO2 in the atmosphere has become an important goal. Due to the lack of suitable alternatives for large-scale energy generation in the short- and medium-term, solutions for reducing CO2 emissions from burning hydrocarbons are intensively investigated. One possible solution is to sequester CO2 in the subsurface. Hydrocarbon reservoirs have a cap-rock which was sealing in geological history for geological times and are prime candidates for sequestration of CO2. CO2 injection into oil reservoirs has been extensively investigated and is commercially pursued, in particular in the USA. Current oil production from fields in which CO2 is injected is about 300,000 bbl/day. A small but significant fraction of the CO2 used for Enhanced Oil Recovery (EOR) in the USA is coming from anthropogenic sources. Currently, a number of feasibility studies are being performed to investigate the use of CO2 generated by power plants in EOR projects. CO2 injection into coalbed methane reservoirs is extensively being studied as well. Numerous laboratory experiments have been performed. In the last few years, field tests of this technology were conducted. CO2 enhanced gas recovery (EGR) has not been studies as extensively. The reason might be the already high recovery of gas for conventional depletion of reservoirs. Due to the fact that in some countries huge gas reserves exist and only a limited number of oil fields, sequestration of CO2 into gas fields might be an attractive option. In the study reported here, integrated power plants with CO2 separation (Zero Emission Power Plants - ZEPP) in combination with a number of different injection schemes into a gas reservoir were evaluated. For an example scheme of a power plant and gas field see Figure 1. To simulate the effects of CO2 injection on methane recovery, an example gas reservoir was chosen. In the following paragraph, the key properties of the field are presented. Then, simulation results for different injection strategies will be given.