A Simulator for Solution-Gas Drive in Heavy Oils

Abstract Solution-gas drive in heavy oil reservoirs is a complex process, and the mechanisms involved are not fully understood. In the past, these reservoirs have been modelled by altering variables such as critical gas saturation, bubble point pressure, relative permeability curves, fluid properties, and rock properties during sand production. Numerous investigations have shown that gas mobility in heavy oil remains extremely low. Furthermore, experimental observations have suggested that gas mobility depends not only on gas saturation, but also on depletion rate and oil viscosity. It is therefore thought that the viscous forces at the microscopic level affect gas mobility. The dependence of relative permeability to gas on parameters other than gas saturation has been observed previously in processes such as foam flow through porous media, and displacement near miscible conditions, where the ratio of viscous forces to capillary forces is large. In this work, we have developed a numerical simulator where the "apparent" gas relative permeability is a function of rate and gas saturation. The developed model is used to simulate a previously reported set of experiments of solution-gas drive in heavy oils, where the dependence of gas mobility on depletion rate has been observed. It is shown that a model with rate-dependent relative permeability functions can explain many features of solution- gas drive in heavy oil, in particular, its rate-dependent recovery behaviour. Introduction Field experience in many heavy oil reservoirs in Canada and Venezuela have shown that recoveries in the order of 10 - 15% may be achieved under primary depletion(1, 2). Typical observations are high oil production rate, high primary oil recovery, and good pressure maintenance. This behaviour is in contrast with the traditional view of solution-gas drive, where gas flows much faster than oil, leading to high producing GOR, loss of reservoir energy, and low recovery. Many of these reservoirs are produced along with significant amounts of reservoir sand. In addition to the related geomechanical effects, a special fluid flow behaviour is necessary to explain some of the observations, including low producing GOR and high recoveries. There have been very different explanations for the abnormal characteristics observed during solution-gas drive in these heavy oil reservoirs. Smith(1) suggested a simultaneous oil and gas flow in porous media in which the gas is entrained in the oil as tiny bubbles. More recently, Kamp et al.(3) developed a model for the entrained flow of gas in oil, which incorporated a constitutive equation for the viscosity of the bubbly mixture. Maini et al.(4) conducted experiments using unconsolidated sand-packs with heavy oils, and observed high pressure gradients representative of very low gas mobilities. The authors attributed this behaviour to what they called "Foamy Oil Flow." Pooladi-Darvish and Firoozabadi(5) were the first to report quantitative estimates of the phase mobilities under solution-gas drive in heavy oil. They performed depletion experiments in a sand-pack saturated with live oil, and used both light and heavy oil for comparison. Analysis of the data suggested that gas relative permeabilities in heavy oil might be as low as 10−6 - 10−5. </jats:sec

Effect of Hydrates on Sustaining Reservoir Pressure in a Hydrate-Capped Gas Reservoir

Abstract A hydrate-capped gas reservoir is defined here as a reservoir that consists of a hydrate-bearing layer underlain by a two-phase zone involving mobile gas. In such a reservoir, hydrates at the top contribute to the produced gas stream once the reservoir pressure is reduced by gas production from the free-gas zone. Large gas reservoirs of this type are known to exist in Alaska and Siberia and are expected to exist in the Mackenzie Delta of the Northwest Territories in Canada. Gas production from a hydrate-capped gas reservoir is a process governed by a combination of mechanisms of heat transfer, fluid flow, thermodynamics and kinetics of hydrate decomposition. Using a comprehensive numerical simulator, an extensive simulation study indicates that some of the non-linear processes involved in gas production from hydrate reservoirs (i.e. the convective heat transfer and the kinetics of hydrate decomposition) have a negligible effect on the overall physics of the process. This significantly reduces the complexity of the heat and fluid flow equations and legitimizes the construction and use of simplified models. In this work, we invoke the above approximations and develop a generalized gas material balance equation. This equation has two significant differences from the material-balance equation for conventional gas reservoirs, including the incorporation of:the effect of cooling due to endothermic decomposition of the hydrate; andthe effect of generated gas and water from the hydrate decomposition. In this model, it is assumed that a mobile phase exists in the hydrate zone; thus, no sharp hydrate dissociation interface is assumed. Considering the sensible heat of the hydrate zone and heat transfer from cap and base rocks, the gas and water generation rates are determined on the basis of the equilibrium rate of the decomposition process. Verification of the solution is obtained by comparing results with those of a comprehensive hydrate reservoir numerical simulator. The model developed here can be used as an approximate engineering tool for evaluating the role of hydrates in improving the productivity and extending the life of hydrate-capped gas reservoirs. Introduction Natural gas hydrates are solid molecular compounds of water with natural gas that are formed under certain thermodynamic conditions. There is evidence that enormous amounts of natural gas exist in the form of hydrate deposits in many regions of the world(1). These deposits occur in sub-oceanic sediments as well as in arctic regions. Every unit volume of gas hydrate has the potential to contain 170 to 180 volumes of gas at standard conditions, making the energy content of one cubic metre of a hydrate reservoir more than other types of unconventional gas reservoirs(2). In view of the large untapped resources of natural gas hydrates, extensive research and development work is underway to determine what fraction of this resource is recoverable. A number of recovery processes have been suggested for producing gas from hydrates in sediments. Sloan(3) and Makogan(4) have presented an extensive review of the suggested methods including depressurization, thermal stimulation and inhibitor injection. </jats:sec

Experiments and Modelling of Water Injection in Water-wet Fractured Porous Media

Abstract For predicting the performance of water injection in naturally fractured reservoirs, scale-up of the recovery data from immersing an oil-saturated core into water is commonly used. Oil recovery from some of the naturally fractured reservoirs of the North Sea has been better than what was predicted using the immersion laboratory experiments. In the field, the matrix blocks do not become surrounded by water at once; they experience an advancing fracture-water level (FWL). In this paper, the results of experiments of water injection in fractured porous media comprising a number of water-wet matrix blocks are reported for the first time. The blocks experienced an advancing fracture-water level (FWL). Immersion-type experiments were performed for comparison; the dominant recovery mechanism changed from co-current to counter-current imbibitions when the boundary conditions changed from advancing FWL to immersion-type. We performed single block experiments of co-current and counter-current imbibitions and found that co-current imbibitions led to more efficient recovery. Kansas chalk and Berea sandstone were investigated. A column of three blocks of Berea sandstone (Φ = 0.22, k = 0.62 µm2, pore volume (PV) = 8,800 ? 10−6 m3) and a stack of 12 blocks (four rows and three columns) of an outcrop Kansas chalk (Φ = 0.30, k = 0.002 - 0.005 µm2, PV = 13,900 ? 10−6 m3) were used. Breakthrough recoveries were 0.2 - 0.4 for the Berea and 0.2 - 0.6 of PV for the chalk experiments. Corresponding ultimate recoveries were around 0.5 and 0.65 of PV; oil recovery from low permeability chalk was better than that of high permeability Berea. Fracture apertures in all the above experiments were in the range of 150 - 200 µm. An approximate mathematical model was developed for counter-current imbibition. It was found that the late-time matrix-fracture transfer function simplifies to an exponential function. Hence, the physical significance of the empirical transfer function of Aronofsky et al. was demonstrated. The exponential transfer function was incorporated in a model, which was used to match the water injection experiments performed on a stack of very low permeability Austin chalk (Φ = 0.05, k = 0.00001 - 0.00005 µm2, PV = 287 ? 10−6 m3). These experiments were dominated by counter-current imbibition. Introduction Water injection is known as an important method for oil recovery from some fractured reservoirs. In water-wet fractured reservoirs, the capillary pressure contrast between the fracture and the matrix media provides the main driving force for water imbibition which can be an efficient recovery mechanism(1). Field application of water injection in fractured reservoirs has been implemented since the early fifties(2). Many issues, however, remain unresolved in the understanding of this process. Since the early studies, it was understood that recovery behaviour from a block totally covered by water is different than the same block in contact with water from some faces and with oil from other faces(2). However, the majority of studies have centred on immersion-type boundary conditions(3). Intuitively, if a block is surrounded by water, oil is forced to flow in the opposite direction of water flow, hence by counter-current imbibition. </jats:sec

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. </jats:sec

Dynamic Modelling of Solution-Gas Drive in Heavy Oils

Abstract Some heavy oil reservoirs in Canada show atypically high production rates and high primary oil recoveries under solution-gas drive. Much attention has been given to the anomalous behaviour observed in such heavy oil reservoirs, and several models have been suggested to explain these anomalies. There are two classes of effects responsible for the unusual behaviour of solution-gas drive in heavy oil reservoirs, including fluid effects and rock/geomechanical effects. This study focuses exclusively on fluid effects. In at least two ways, solution-gas drive in heavy oils differs from that in light oils. In heavy oils, the concentration of gas in the oil can be significantly greater than the equilibrium value; the oil could be significantly supersaturated. Additionally in heavy oils, recovery and gas mobility show rate dependent behaviour. Both of these effects are taken into consideration in this study. In this paper, we develop a dynamic model that captures many important processes that affect heavy oil recovery. The non-equilibrium early time behaviour is modelled by introducing a kinetic equation describing the rate of evolution of solution gas into free gas. The equation is derived based on a phenomenological analysis which takes into account bubble nucleation and growth. A second component of this model captures the low gas mobility in heavy oil reservoirs and its dependency on viscous forces. To account for the effect of viscous forces on gas mobility, relative permeability functions are introduced that not only depend on gas saturation but also on local oil phase velocity and viscosity. While many of the previous models apply several kinetic equations associated with a large number of parameters, we have shown that the modifications suggested in this study enable predicting many of the unusual behaviours observed in solution-gas drive in heavy oil reservoirs, using only one kinetic equation with a smaller number of fitting parameters. </jats:sec

Network Modelling of Apparent-Relative Permeability of Gas in Heavy Oils

Abstract Some of the solution-gas drive heavy oil reservoirs known as foamy oil reservoirs, in Canada, Venezuela, and other countries have demonstrated a high primary oil recovery factor (&amp;gt;10%), a low producing gas-oil ratio, a low reservoir pressure decline, and a high oil production rate. One of the hypotheses to explain these unusual behaviours is that the gas mobility in a foamy oil flow is much lower than that in conventional oil, leading to improved recovery performance. In this study, the immiscible two-phase micro-displacement in porous media is modelled by using a network of pores of converging-diverging geometry. The effect of viscosity of one phase (oil) on the mobility of another phase (gas) is included in the model. The developed model is used to simulate the motion of the dispersed bubbles in an initially oil-filled network, and to determine bubble mobility. The obtained results showed that bubble mobility decreased drastically by increasing the oil viscosity. The results also showed that dispersion of gas leads to lower mobility of bubbles. Dispersed gas flow and low bubble mobility are believed to lead to improved recovery in foamy oil reservoirs. Introduction Some of the solution-gas drive heavy oil reservoirs in Canada, Venezuela, China, and Oman have demonstrated unusually high primary production rates, high primary oil recovery factors (&amp;gt;10%), low producing gas-oil ratios, and low reservoir pressure declines(1, 2). To explain these unusual behaviours, three fundamental reasons have been suggested: geomechanical effects(3), special fluid properties(4), and unusual flow dependent properties of oil and gas(5). Most researchers now believe that the low mobility of gas is the main reason for low producing GOR and high recoveries obtained(1, 2). Gas mobility in a heavy oil system is investigated in this paper. In one study, solution-gas drive experiments were performed in an identical sand-pack, using light oil and heavy oil(5). The experimental studies clearly showed that gas mobility in the two experiments differed by about four orders of magnitude. It has been observed that matching of field(6) and laboratory depletion data(5) required assigning extremely low values of gas relative permeability. The relative permeability functions of these studies, however, were obtained through history matching. Of primary interest is, how can relative permeability functions be determined for a particular system a priori? Following this question, the first step is to find what parameters affect relative permeability functions; the second is to find how these factors are ranked in their importance. These steps are investigated in this paper. A microscopic scale (network) model is developed and used to investigate the effects of different parameters, in particular, oil viscosity on gas mobility in porous media. Network models are simplified mathematical representations of real porous material. The objective of a porous network model is to provide a reasonable idealization of the complex geometry of a real porous medium on a microscopic scale, so that the related fluid flow can be treated mathematically at a manageable level of complexity. </jats:sec

SAGD Operations in the Presence of Overlying Gas Cap and Water Layer-Effect of Shale Layers

Abstract The technical and commercial success of SAGD projects over the past decade has opened the door to the development of a large number of bitumen reservoirs in Canada, previously thought uneconomical to produce. Some of these reservoirs have overlying gas caps and/or water zones. Some studies have suggested that gas-cap production might "sterilize" the underlying bitumen. Many such studies however, assumed rather thick continuous pays with high permeability, and considered an infinite gas-cap. In this work, a simulation study was conducted to examine the feasibility of bitumen production from a certain project area in Alberta, using the SAGD process, and to study the effect of production from the gas cap. A decision needed to be made as to whether gas production should be delayed until after bitumen production. The large well spacing did not allow a detailed description of the connectivity of the shale layers. The uncertainty was compounded by the geological setting of the study area, a system of channel sands cut through the original marine sand and shale deposits. Since the actual shale connectivity and thickness was unknown, a methodology was developed to incorporate different geological descriptions using the available core and log data. Five reservoir models were developed. Bitumen recovery, average oil production rate, and cumulative steam-oil ratio (SOR) obtained from thermal simulation were the three main parameters used for evaluation of the attractiveness of bitumen recovery operations. These numbers were compared with some of the corresponding values reported and/or forecast for economically feasible operations such as the UTF and Christina Lake projects. The effect of pressure reduction (caused by gas-cap production) on production rate and SOR was also investigated. The results indicated that for conditions considered in this study the effect of gas production on bitumen recovery was minor, and appeared as a small deceleration of the recovery and a small increase in SOR. Introduction Many bituminous reservoirs in Alberta contain overlying gas. The gas owners would like to produce the gas. However, there is concern as to whether or not gas production might adversely affect any possible bitumen recovery process in the future. The primary candidate recovery method for such bitumen formations is the Steam-Assisted Gravity Drainage (SAGD)(1) process. The objective of this study is to examine the feasibility of bitumen recovery from the underlying sands, and to determine the effect of "prior" gas production on the process. The effects of overlying gas and/or water sands on the SAGD process are presented first. This is followed by a discussion of the effect of continuous and discontinuous shale layers, and their incorporation in the numerical model, along with the determination of rock properties. Thermal simulation results and conclusions follow. Background The UTF project demonstrated the viability of the SAGD process for production of some of the bituminous reservoirs of Alberta(2, 3), where more conventional thermal processes are less successful due to immobility of the bitumen at reservoir conditions. </jats:sec