Critical Gas Saturation Research Articles

Gas and oil production from waterflood residual oil: effects of wettability and oil spreading characteristics

In the depressurisation of reservoirs already produced to waterflooded residual oil, solution gas is released when the reservoir pressure drops to below the bubble point. This gas becomes mobilised when the critical gas saturation has been reached. Additionally, the oil itself can become mobile from its residual state and can also be produced under suitable physical conditions. The critical gas saturation, the rate of saturation change, and the gas saturation remaining at the end of the depressurisation process (unrecoverable gas) are important parameters in determining the overall economic performance when depressurising a reservoir. In this, and previous work, we are demonstrating that these quantities depend additionally upon other factors which affect the fluid distribution and the rate of gas generation, particularly the surface and interfacial properties. For instance, earlier visual experiments in glass micromodels suggested that wettability and oil spreading coefficient could substantially influence both the value of the critical gas saturation and the growth pattern for the developing gas bubbles, and thus the gas flow. In order to confirm these observations and to provide quantitative data, further experiments in large sintered packs, with different matrix wettability and with oils having different spreading coefficients (e.g. oil spreading onto a gas–water interface), have been carried out and are reported here. These new experiments show that the magnitude of the critical gas saturation for a water-wet system is about the same irrespective of whether the oil is spreading or non-spreading, but it is much higher than for the oil-wet case. In addition, oil is also produced but the rate of production is dependent upon the rock wettability and the oil characteristics. We find that in a water-wet medium, for spreading oils, the physical form of the oil becomes transformed from being immobile ganglia into mobile oil films, which can then be transported by the gas. For non-spreading oils, oil has to be pushed out by the gas as discontinuous ganglia so less is oil produced. In contrast, in an oil-wet system, the oil phase already exists as a continuous film on the surface of the solid so that the generation of gas effectively expands the oil phase, enabling the oil to be produced in larger quantities even at lower gas saturations. These new experiments give further evidence that rock wettability has an important influence on the performance of gas production from residual oil. Additionally, significant amounts of oil may be recovered after waterflooding from the residual condition, which could have a beneficial impact on the economics of the depressurisation.

Model for the gas evolution in a porous medium driven by solute diffusion

AbstractAn effective continuum model is derived to describe the nucleation and subsequent growth of a gas phase from a supersaturated, slightly compressible binary liquid in a porous medium, driven by solute diffusion. The evolution of the gas results from reducing the system pressure at a constant rate or withdrawing the liquid at a constant rate. The model addresses two stages before the onset of bulk gas flow, nucleation and gas‐phase growth. Negligible gradients due to gravity or viscous forces are assumed, so the critical gas saturation signaling the onset of bulk gas flow is only a function of the nucleation fraction. Important quantities characterizing the process, such as the pore number fraction hosting activated sites, deviation from thermodynamic equilibrium, maximum supersaturation, and critical gas saturation, depend crucially on the nucleation characteristics of the medium. Heterogeneous nucleation models using preexisting gas trapped in hydrophobic cavities or in terms of a rate‐dependent nucleation are used to investigate the nucleation behavior. Using a simpler analytical model the relevant quantities during nucleation can be expressed in terms of a simple combination of dimensionless parameters. The theory predicts that the maximum supersaturation is a weakly increasing function of rate, which in the region of typical experimental parameters can be approximated as a power law. It depends sensitively on the probability density function of nucleation cavity sizes. The final nucleation fraction (thus, the critical gas saturation) is predicted to be a power law of the decline rate. The theoretical exponents agree well with experimental data. The subsequent evolution of the gas phase and the approach to the critical gas saturation is also described.

Effect of Depletion Rate on Gas Mobility and Solution Gas Drive in Heavy Oil

Summary Some heavy oil reservoirs in western Canada and Venezuela show anomalously high primary recovery under solution gas drive process. The pressure decline rate in these reservoirs is low compared to that expected under solution gas drive in conventional oil reservoirs. There is now increasing evidence that gas mobility is extremely low in these reservoirs. The objective of this study is to conduct solution gas drive experiments in a sandpack saturated with a heavy oil and examine the effect of depletion rate. Depletion rate was varied by more than two orders of magnitude. The results showed that gas mobility was a function of depletion rate and decreased with increasing depletion rate. Other notable observations were that supersaturation increased with depletion rate and that critical gas saturation was 3 to 4%, slightly increasing with increasing depletion rate. Interpretation of the results confirmed that gas mobility is quite low. Representation of the low mobilities using relative permeability required low values of the order of 10−5–10−4, which decreased with increasing depletion rate.

Heavy-oil solution gas drive: a laboratory study

When some heavy-oil reservoirs are produced using solution gas drive, they show: (1) higher than expected production rates, (2) low produced gas–oil ratio, and (3) relatively high recovery. The reasons for this behavior are not clear. A series of X-ray computerized-tomography (CT)-monitored, heavy-oil pressure depletion experiments were carried out to examine the core-scale phenomena using high pressure/high temperature equipment. Viscous white mineral oil ( μ=220 cp at 20 °C) and 9° API heavy crude oil from the Hamaca region of the Orinoco Belt, Venezuela, were used. A transparent cell attached to the outlet of the sand pack allowed monitoring of bubble size and shape as bubbles exited the sand pack. Conventional solution-gas-drive behavior was observed in the experiments conducted with the mineral oil: large regions of pore space within the core became saturated with a continuous gas phase and ample gas mobilization was witnessed. In the heavy-crude-oil experiment, however, it was inferred that gas bubbles were of slightly greater size than pore dimensions. The fraction of gas mobilized was not large. The difference in behavior between mineral oil and crude oil results suggests an effect due to large oil-phase viscosity, relatively rapid depletion rate, and possibly the high asphaltene content of Hamaca crude oil. Critical gas saturation was gauged as the saturation at which mobile gas was first observed regardless of whether the gas was continuous. For both experiments, the critical gas saturation was observed to be around 3% to 4%.

Relative Permeability Measurements for Post-Waterflood Depressurization of the Miller Field, North Sea

Summary This paper describes a determination of critical gas saturations and relative permeabilities relevant to the depressurization of the Miller field. A series of reservoir-condition coreflood experiments and associated numerical simulations is described. Three experiments were conducted with aged Miller core and fluids at 120°C. Each was comprised of a waterflood at about 414 barg, followed by depressurization at different rates. The laboratory data included extensive three-phase in-situ saturation measurements that were used to derive gas relative permeabilities through the simulations. The rate-dependent critical gas saturations varied between 0.06 and 0.21, and gas relative permeabilities of the order of 0.0001 were deduced. These laboratory results are consistent with published data and suggest that conventional Corey-type gas relative permeabilities are an order of magnitude too large and do not represent the depressurization process.

Production of gas from waterflood residual oil: gas saturation build-up and relative permeabilities

When solution gas is released from waterflooded residual oil by depressurization, the gas becomes mobilized after the critical gas saturation has been reached, but the gas saturation continues to increase as more gas is generated. The rate of gas saturation change plus the unrecoverable gas (gas saturation remaining at the end of the depressurization) are important in determining the economic performance of the process. The values depend upon the rate of gas generation and the gas relative permeability. Experiments are reported to measure water and gas relative permeabilities when gas is released from waterflooded residual oil. The values for the gas phase were extremely low, approximately an order of magnitude lower than would be predicted using a Corey-type equation suggesting that gas relative permeabilities measured in normal gas–water displacement experiments are not applicable to the depressurization of waterflooded reservoirs. The low values of gas relative permeabilities can be explained by the fact that the filaments which form the channels for gas flow are not stable, and that the flow is intermittent. Visual observations of the flow behaviour in micromodels have confirmed this. As a result, the effective total area for flow at any particular gas saturation is substantially reduced, thus reducing the permeability to the gas. New algorithms need to be introduced into the network models for estimating relative permeabilities in these situations before they can be used to represent the cyclical nature of filament rupture and reformation.

Visualization and Measurement of Gas Evolution and Flow of Heavy and Light Oil in Porous Media

Summary In a number of experiments, the efficiency of solution-gas drive for both light and heavy oils was studied. In these experiments a special coreholder was used to visually observe the formation of gas bubbles on the rock surface of a Berea core and the production from the core outlet. The results from all the experiments reveal that the critical gas saturation for three hydrocarbon liquids; 1. a light model oil, 2. an 11-API gravity oil, and 3. a 35-API gravity oil, does not exceed 3%. However, the gas mobility for the heavy oil is very low and for the light model oil very high. Consequently, solution-gas drive for a heavy oil of 11-API gravity is more efficient than for a light oil.

Estimation of critical gas saturation during pressure depletion in virgin and waterflooded reservoirs

An important issue in petroleum engineering is the prediction of gas production during reservoir depletion--either following conventional waterflooding operations or in the early stages of hydrocarbon production. The estimation of critical gas saturation for use in corresponding simulation studies is clearly a primary concern. To this end, a 3D, three-phase numerical pore-scale simulator has been developed that can be used to estimate critical gas saturations over a range of different length scales and for a wide range of fluid and rock properties. The model incorporates a great deal of the known physics observed in associated laboratory micromodel experiments, including embryonic nucleation, supersaturation effects, multiphase diffusion, bubble growth/migration/fragmentation, oil shrinkage, and three-phase spreading coefficients. The precise pore-scale mechanisms governing gas evolution have been found to be far more subtle than earlier models would suggest because of the large variation of gas/oil interfacial tension (IFT) with pressure. This has a profound effect upon the migration of gas structures during depletion. In models pertaining to reservoir rock, the process of gas migration is consequently much slower than predictions from more simplistic models would imply. This is the first time that bubble fragmentation and IFT variations have been included in a model of gas evolution at the pore-scale and the implications for production forecasting are expected to be significant. In addition, novel scaling groups have been derived for a number of different facies under both virgin and waterflooded conditions. One future application of these groups would be to scale S gc values obtained from high rate depressurization experiments to the low rate conditions more characteristic of field operations.

Solution-gas Drive In Heavy Oil Reservoirs

Abstract Different hypotheses have been made to explain the highly favourable behaviour of some of the heavy oil reservoirs under solution-gas drive. The main reasons however remain unclear. Using experiments in an unconsolidated sandpack, we examined the solution-gas drive process in a light oil and a heavy oil. Pressure and volume measurements and visual observation of the flowing fluid at the in situ pressure for the heavy oil system revealed that: critical gas saturation was low (5% or less), the gas phase was not made of microbubbles flowing with the oil stream, liquid mobility did not improve upon nucleation or growth of the gas bubbles, and supersaturation effects were not dominant. The experimental and simulation results indicate that gas mobility in solution-gas drive in heavy oil is much less than in light oil, leading to improved recovery performance of the former. Introduction Production from some of the heavy oil reservoirs in Canada and Venezuela has led to unexpectedly high oil rates and recoveries under solution-gas drive. In an early paper, Smith(1) reported this behaviour in the heavy oil reservoirs of the Lloydminster area, Canada. Analysis of the field data showed production rates much in excess of that predicted by the Darcy law(1). Similarly, Loughead and Saltuklaroglu(2) and Metwally and Solanki(3) reported solution-gas drive oil recoveries as high as 14% and flow rates of one order of magnitude greater than the predictions of the Darcy radial flow. These and other authors reported coproduction of large volumes of sand and the delayed liberation of gas from the wellhead crude samples in open vessels. More recently, similar behaviour was reported in some of the heavy oil reservoirs in Venezuela. Mirabal et al.(4) presented examples of high flow rates under solution-gas drive from one of the heavy oil reservoirs of the Orinoco Belt. In addition to the unexpectedly high production rates, the reservoir pressure was nearly maintained in the 12 years of production history. The economic advantages of the initial development of many of these reservoirs under solution-gas drive are clear; the high costs involved in the traditional thermal methods are avoided(5–7). To explain the above behaviour, a number of mechanisms have been suggested which can be divided into two main categories; geomechanical effects such as sand dilation and development of wormholes comprise the first category. The second category, which is the subject of the current research, suggests that the special properties of the flowing fluids, the gas and the heavy oil are the main reasons for high production performance. The effect of many of the pressure maintenance mechanisms such as an active aquifer and the reservoir compaction have been found small in these reservoirs(1,2,4). Due to production, the pore pressure drops below the bubblepoint pressure to a critical supersaturation pressure, and then gas evolves in the porous medium. Kraus, McCaffrey, and Boyd(8) proposed that below bubblepoint, the evolved gas is retained in the porous media until the pressure reduces to a lower pressure called pseudo-bubblepoint pressure.

Heavy Oil Flow Under Solution-gas Drive: Pressure Depletion Tests

Abstract The formation of foamy oil has been postulated to be an important factor contributing to the success in primary production of heavy oil under solution-gas drive in Alberta and Saskatchewan. This paper presents the results of pressure depletion or blowdown tests on unconsolidated oil sand cores which were conducted to investigate the foamy oil flow phenomenon. Experimental results suggest that foamy oil flow is likely dominant between the bubble point and the critical gas saturation for fast tests (one-hour step duration), but may be much less important as free gas is produced via gas channels at gas saturation greater than the critical saturation. Foamy oil flow is also a function of step duration, and for slow tests (greater than 24-hour step duration), foamy oil flow may be absent. Tests also reveal that the total bitumen recovery was extremely high, ranging from 35 - 50%, and no obvious temperature effects were observed. Both features are perhaps caused by high pressure decline rates resulting from the step pressure decline. Whether foamy oil flow occurs or not, the solution-gas drive mechanisms in heavy oil reservoirs are similar to those in conventional oil. The liberation of solution gas and the expansion of free gas are the main pressure maintenance sources below the bubble point. Introduction In the primary production of heavy oil, the drive mechanism is generally believed to be solution-gas drive. It is also an important mechanism for cyclic steam stimulation. A better understanding of heavy oil reservoir performance under solution-gas drive is essential to both processes. The concept of foamy oil flow has been used to explain the anomalous performance of heavy oil reservoirs under solution-gas drive(1,2). Foamy oil flow refers to the simultaneous flow of gas bubbles and oil in a pseudo-continuous phase. Ward et al.(3) illustrated theoretically that in a closed volume, the size of the stable gas bubbles formed by a pressure drop depends upon the number of gas bubbles. The diameter of gas bubbles could be as small as 3 µm and as many as ten million bubbles could be formed in one cubic centimetre of live oil. This hypothesis prompted Smith(1) to postulate that gas bubbles could perhaps flow through the pore throat, unaffected by capillary forces. He assumed that the flow of the oil-gas mixture in the reservoir could be approximated by a single-phase flow. The average parameters for this single-phase mixture flow were estimated from the individual parameters of bitumen and gas. He reported that this single-phase model successfully predicted the pressure response observed in Lloydminster heavy oil reservoirs. Sarma and Maini et al.(4,5) studied experimentally the role of gas nucleation in the primary production of heavy oil under solution- gas drive. They concluded that the nucleation of gas bubbles was unlikely to increase the mobility of heavy oil, and that the heavy oil-gas mixture was flowing in the form of an oil-continuous foam. Poon and Kisman(6) investigated the effects of non-Newtonian fluid on the primary production of heavy oil.

Critical Review of Foamy Oil Flow

‘Foamy oil flow’ is a term coined to describe a form of two‐phase oil‐gas flow that appears to occur during solution gas drive in some heavy oil reservoirs and does not fit the classical models of two‐phase flow. Most of the evidence supporting the presence of this unusual flow mechanism is circumstantial and comes from attempts to explain much higher than expected well productivity and primary recovery factors in several heavy oil reservoirs. This paper is a review of the available literature on foamy oil flow in primary production of heavy oils under solution gas drive. The mechanisms operating in solution gas drive in heavy oil reservoirs are briefly discussed. The issues related to supersaturation in oil phase, bubble nucleation, critical gas saturation, and relative permeability are discussed. The possible role of rate processes related to the release of solution gas and the formation of a segregated gas phase is reviewed. The pore‐scale mechanisms involved in creation and propagation of dispersed gas flow are discussed. Several published mathematical models of foamy solution gas drive are reviewed with focus on their limitations. The review shows that the theoretical and experimental investigations of foamy oil flow are still in early stages. Although the occurrence of foamy oil flow has been verified in laboratory experiments, its existence at the reservoir scale has not been confirmed. The theoretical understanding of the mechanisms underlying foamy oil flow remains poor.

A Numerical Study of the Critical Gas Saturation in a Porous Medium

We use pore‐network simulations to study the dependence of the critical gas saturation in solution‐gas drive processes on the geometric parameters of the porous medium. We show that for a variety of growth regimes (including global and local percolation, instantaneous and sequential nucleation, and mass‐transfer driven processes), the critical gas saturation, Sgc, follows a power‐law scaling with the final nucleation fraction (fraction of sites activated), fq. For 3‐D processes, this relation reads Sgc∼fq0.16, indicating a sensitive dependence of Sgc to fq at very small values of fq.

Calculating immobile gas saturations

We present a simple, fast, analytical expression which can be used to estimate the reservoir pressure as a function of gas saturation, for gas saturations between zero and the critical gas saturation. Use of the relation also makes it extremely easy to assess the local recovery factor as a function of pressure from the bubble point down to the pressure at which the critical gas saturation is reached.

The depressurization of water-flooded reservoirs; wettability and critical gas saturation

The influence of wettability on the formation, growth and mobilization of bubbles formed when solution gas is released from water-flood residual oil have been visually observed in a series of experiments. The experiments were performed using a mixture of low boiling point hydrocarbons, which had a positive spreading coefficient for the oil phase in contact with water and its own vapour. In an oil-wet matrix, nucleation of gas bubbles occurred on the surface of the matrix. While it was impossible to determine where nucleation occurred in the water-wet condition, the results suggest that wettability influences the gas nucleation behaviour. In a water-wet system, the oil-water interfacial tension controlled the growth pattern for the gas bubbles, but in an oil-wet system the gas-oil interfacial tension was the controlling parameter. As a result, it seems likely that wettability influences the critical saturation for mobilization of the gas phase. The behaviour of the oil phase during depressurization is influenced by wettability. In a water-wet system the physical form of the oil is changed from immobile droplets into films which may be transported with the gas phase, and in which the oil is mobile. In contrast in an oil-wet system, the oil phase can move as films when the gas is released from solution but generally will not initially move over many pores.

Critical Gas Saturation and Supersaturation in Low-Permeability Rocks

Summary The laboratory methodology for determining critical gas saturation, Sgc, in field depletion processes is still uncertain. Through measurements on low-permeability rocks, we explore some of the key issues affecting laboratory determination of Sgc. Differences between laboratory depletion and external gasdrive experiments are measured and analyzed. We also investigate the relationship between average Sgc from material balance and true Sgc, source of supersaturation, gas nucleation conditions, and dynamics of gas bubble growth in depletion drive experiments. We assess the use of low-bubblepoint oils to reduce experiment time. Finally, we suggest some improvements to laboratory procedures.

Theory of multiple bubble growth in porous media by solute diffusion

We present a theoretical analysis of bubble growth in porous media by solute diffusion. Based on visualization experiments, a theoretical model is developed for bubble growth driven by a constant or a time-varying supersaturation in the far-field. It is shown that in porous media, gas evolution (patterns and rates) is much different than in the bulk. Patterns and rates of growth are identified for single and multiple gas clusters, using statistical models, such as percolation and diffusion-limited-aggregation (DLA). The effect of (heterogeneous) nucleation on the growth of multiple clusters is analyzed. Particular emphasis is placed on the critical gas saturation, S gc , which denotes the critical value of the pore volume fraction occupied by the gas for the formation of a sample-spanning cluster. This quantity is studied in terms of the system parameters, notably the nucleation fraction and the pressure decline rate (pressure/time). S gc is found to increase with the nucleation fraction and the pressure decline rate at relatively high rates, but to be independent of the latter at sufficiently small rates. The scalling of these results is also discussed.

Three-Phase Studies of Gas-Condensate Flow Behavior

Summary Experiments have shown that an oil phase introduced by condensation reduces gas relative permeability in the presence of an immobile water saturation. Such an oil phase, however, reduces both the waterflood residual gas saturation and the critical gas saturation for remobilization by depressurization after a waterflood almost to the extent of the oil-phase saturation.

Measurements of Supersaturation and Critical Gas Saturation

Summary Supersaturation and critical gas saturation were measured for two core samples with different pore structures. In these measurements, a pump with a constant rate of expansion was used to avoid steep pressure changes. Binary mixtures of C1/n-C10 at two saturation pressures were used as the fluid system. The surface tension of the binary mixtures varied from 2 to 13 dyne/cm. The data show that pore structure could significantly affect the degree of supersaturation. The supersaturation in a porous medium with small pores may be less than in a porous medium with large pores. The critical gas saturation data of this work are lower than literature values. Measurements on a chalk sample reveal critical gas saturations of about 0.5%.

Inflow Performance Relationships for Damaged or Improved Wells Producing Under Solution-Gas Drive

SPE Members Abstract Inflow performance of twenty-one theoretical solution-gas drive reservoirs was simulated using the Weller method. These reservoirs contained a wide range of rock properties, fluid properties, relative permeability characteristics and skin effects. Two permeability characteristics and skin effects. Two types of inflow performance relationships were developed from the 19,500 generated data points. For the first type, each curve represents dimensionless pressure versus the oil flow rate normalized to its pressure versus the oil flow rate normalized to its actual maximum, flow rate. The second relates dimensionless pressure to the ratio of flow rate to the theoretical maximum, undamaged flow rate. Results show that inflow performance is strongly dependent on bubble point pressure and reservoir depletion effects; while oil API gravity, residual oil saturation, critical gas saturation, absolute permeability and relative permeability have only a permeability and relative permeability have only a minor effect. Skin effect and reservoir extent have major effects only on the unnormalized curves. Nonlinear regression techniques were then used to develop empirical equations that fit dimensionless flow rate as a function of dimensionless pressure and skin. Equations were also developed that included the effects of depletion, bubble point pressure and ratio of reservoir extent to wellbore radius. The resulting equations proved to be statistically sound. In addition, several new reference curves that can be applied to solution-gas drive reservoirs in general are proposed. The new curves incorporate approximately 19,500 data points and a wide range of reservoir characteristics. Introduction One of the most important problems confronting a petroleum engineer is predicting pressure/production petroleum engineer is predicting pressure/production behavior in an oil and gas reservoir, given a host of possible operating schemes. By predicting the possible operating schemes. By predicting the response of an oil reservoir for various hardware and pressure scenarios, a first case estimate to maximize pressure scenarios, a first case estimate to maximize profitable reserves development can be achieved. profitable reserves development can be achieved. Computer solutions for the performance prediction of solution-gas drive reservoirs have evolved since the early 1-950's. However, most methods were algebraically intensive and required considerable computation time. In 1965. Weller devised improved method of calculating the performance depletion-type reservoirs. This method, with the help of a few simplifying assumptions, provided a fast and simple means of predicting pressure performance for gas-oil flow in a reservoir. By performance for gas-oil flow in a reservoir. By plotting flowing bottom-hole pressure versus flow plotting flowing bottom-hole pressure versus flow rate, a useful method of estimating oil well productivity, known as the performance productivity, known as the performance relationship (IPR), can be established. Vogel used the method of Weller to calculate IPR curves for wells producing from several depletion-drive reservoirs for a variety of PVT properties and relative permeability data. He introduced the notion of permeability data. He introduced the notion of dimensionless IPR curves. Vogel noticed that the dimensionless curves exhibited similar shape for various reservoir conditions. From this fact, he proposed a reference curve that could be used to estimate well productivity for most undamaged solution gas drive wells. productivity for most undamaged solution gas drive wells. Standings presented a companion set of curves to Vogel's curve that enabled the estimation of productivity for damaged or improved wells based on productivity for damaged or improved wells based on the flow efficiency. However, his curves do not hold for certain cases of low flowing pressure and high flow efficiencies. This study has tried to examine several factors that effect the calculation of IPR curves. Critical factors are reservoir rock properties, fluid properties, bubble point pressure and depletion. properties, bubble point pressure and depletion. Also, zonal damage around the wellbore, caused during drilling or completion, can dramatically decrease the productivity of a well. productivity of a well. P. 869

Liberation of Solution Gas During Pressure Depletion of Virgin and Watered-Out Oil Reservoirs

Summary Multipurpose experimental equipment was constructed to investigate the buildup of gas saturation during depressurization of virgin and watered-out oil reservoirs at representative conditions. The measured dependencies of critical gas saturations on gas/oil interfacial tension (IFT), amount of dissolved gas, pressure-decline rate, and structure of the porous medium are discussed. In addition, experimental results indicating significant reductions of waterflood residual oil saturation (ROS) owing to the presence of a gas saturation are presented.