All-Time Modeling of Co-Current Spontaneous Water Imbibition Into Gas-Saturated Rocks Using a Novel Transition Time

2020 ◽  
Vol 143 (6) ◽  
Author(s):  
Lin Jia ◽  
Kewen Li ◽  
Lipeng Zhao ◽  
Bhekumuzi Mgijimi Mahlalela
Keyword(s):  
Water Saturation ◽  
Spontaneous Imbibition ◽  
Production Performance ◽  
Petroleum Reservoir ◽  
Gas Reservoirs ◽  
Time Model ◽  
Water Imbibition ◽  
Time Modeling ◽  
Capillary Pressures ◽  
Saturation Profile

Abstract Spontaneous imbibition (SI) into a porous medium is an important transport phenomenon in petroleum reservoir engineering. The study of spontaneous water imbibition is critical to predict the production performance in these reservoirs developed by waterflooding, especially in the fractured gas reservoirs with active aquifers. While some studies have been reported to characterize spontaneous water imbibition into gas-saturated rocks, they are either limited or inaccurate due to the fact that the existing models have specific assumptions that cannot be applied in other time intervals. To this end, we proposed a novel transition imbibition time t* and developed an all-time (including both early- and later-time SI) model to match the experimental SI data. Furthermore, we proposed a novel model to estimate capillary pressures at different water saturations and to characterize the water saturation profile in capillary-dominated stage. Comparison with the existing capillary pressure estimation models was performed to test the differences. The results demonstrated that the all-time model could fit the experimental imbibition data of the entire SI process satisfactorily. The new saturation model established in this paper can be well fitted with the water saturation profile measured by the X-ray computer tomography (CT) scanners. The results and findings from this work may be of great significance in many areas related to SI, particularly in the development of naturally fractured gas reservoirs with active aquifers.

Residual Gas Saturation Revisited

2001 ◽  
Vol 4 (06) ◽  
pp. 467-476 ◽  
Author(s):  
Apostolos Kantzas ◽  
Minghua Ding ◽  
Jong Lee
Keyword(s):  
Oil Recovery ◽  
Water Saturation ◽  
Spontaneous Imbibition ◽  
Gas Reservoirs ◽  
Initial Water ◽  
Gas Saturation ◽  
Water Imbibition ◽  
Residual Gas ◽  
Trapped Gas ◽  
Residual Gas Saturation

Summary The determination of residual gas saturation in gas reservoirs from long spontaneous and forced-imbibition tests is addressed in this paper. It is customarily assumed that when a gas reservoir is overlaying an aquifer, water will imbibe into the gas-saturated zone with the onset of gas production. The process of gas displacement by water will lead to forced imbibition in areas of high drawdown and spontaneous imbibition in areas of low drawdown. It is further assumed that in the bulk of the reservoir, spontaneous imbibition will prevail and the reservoir will be water-wet. A final assumption is that the gas behaves as an incompressible fluid. All these assumptions are challenged in this paper. A series of experiments is presented in which it is demonstrated that the residual gas saturation obtained by a short imbibition test is not necessarily the correct residual gas saturation. Imbibition tests by different methods yield very different results, while saturation history and core cleaning also seem to have a strong effect on the determination of residual gas saturation. It was found, in some cases, that the residual gas by spontaneous imbibition was unreasonably high. This was attributed to weak wetting conditions of the core (no water pull by imbibition). It is expected that this work will shed some new light on an old, but not-so-well-understood, topic. Introduction When a porous medium is partially or fully saturated with a nonwetting phase, and a wetting phase is allowed to invade the porous medium, the process is called imbibition. For the problem addressed in this work, the nonwetting phase is assumed to be gas, and the wetting phase is assumed to be the aquifer water. If the medium is dry and the water is imbibing, then the imbibition is primary (Swi=0). If the water is already in the medium, the imbibition is secondary (Swi>0). If there is no driving force other than the affinity to wet, the imbibition is spontaneous. If there is any other positive pressure gradient, the imbibition is called forced. Numerous papers have been written on the subject of residual oil saturation from imbibition, but fewer have been prepared on the subject of residual gas saturation from imbibition. The common perception is that many of the principles that cover oil and gas reservoirs are the same. Agarwal1 addressed the relationship between initial and final gas saturation from an empirical perspective. He worked with 320 imbibition experiments and segmented the database to develop curve fits for common rock classifications. Land2 noted that available data seemed to fit very well to an empirical functional form given asEquation 1 In this model, the only free parameter is the maximum observable trapped nonwetting phase saturation corresponding to Sgr (Sgi=1). This expression does not predict residual phase saturation, only how residual saturation scales with initial saturation. Zhou et al.3 studied the effect of wettability, initial water saturation, and aging time on oil recovery by spontaneous imbibition and waterflooding. A correlation between water wetness and oil recovery by waterflooding and spontaneous imbibition was observed. Geffen et al.4 investigated some factors that affect the residual gas saturation, such as flooding rate, static pressure, temperature, sample size, and saturation conditions before flooding. They found that water imbibition on dry-plug experiments was different from waterflooding experiments with connate water. However, they concluded that the residual gas saturation from the two types of experiments was essentially the same. Keelan and Pugh5 concluded that trapped gas saturation existed after gas displacement by wetting-phase imbibition in carbonate reservoirs. Their experiments showed that the trapped gas varied with initial gas in place and that it was a function of rock type. Fishlock et al.6 investigated the residual gas saturation as a function of pressure. They focused on the mobilization of residual gas by blowdown. Apparently, the trapped gas did not become mobile immediately as it expanded. The gas saturation had to increase appreciably to a critical value for gas remobilization. Tang and Morrow7 introduced the effect of composition on the microscopic displacement efficiency of oil recovery by waterflooding and spontaneous imbibition. They concluded that the cation valency was important to crude/oil/rock interactions. Chierici et al.8 tested whether a reliable value of reserves could be obtained from reservoir past-production performance by analyzing results from six gasfield experiments. They concluded that different gas reservoir aquifer systems could show the same pressure performance in response to a given production schedule. Baldwin and Spinler9 investigated residual oil saturation starting from different initial water saturation using magnetic resonance imaging (MRI). They concluded that at low initial water saturation, the presence of a significant waterfront during spontaneous water imbibition indicated that the rate of water transport was less than that of oil. At high initial water saturation, the more uniform saturation change during spontaneous water imbibition indicated that the rate of water transport was greater than that of oil. The pattern of spontaneous imbibition depended on sample wettability, with less effect from frontal movement in less water-wet samples. Pow et al.10 addressed the imbibition of water in fractured gas reservoirs. Field and laboratory information suggested that a large amount of gas was trapped through fast water imbibition through the fractures and premature water breakthrough. The postulation was made that such gas reservoirs would produce this gas if and when the bypassed gas was allowed to flow to the production intervals under capillary-controlled action. The question of whether the rate of imbibition could enhance the production of this trapped gas was raised. Preliminary experiments on full-diameter core pieces showed that the rates of imbibition were extremely slow and that if the different imbibition experiments were performed in full-diameter plugs, the duration of the experiments would be prohibitively long. These experiments formulated the experimental strategy presented in the following sections.

Influence of Initial Water Saturation on Recovery by Spontaneous Imbibition in Gas/Water/Rock Systems and the Calculation of Relative Permeability

2006 ◽  
Vol 9 (04) ◽  
pp. 295-301 ◽  
Author(s):  
Kewen Li ◽  
Kevin Chow ◽  
Roland N. Horne
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Water Saturation ◽  
Water Injection ◽  
Spontaneous Imbibition ◽  
Rock Properties ◽  
Initial Water ◽  
Gas Recovery ◽  
Water Imbibition ◽  
Theoretical Predictions

Summary It has been a challenge to understand why recovery by spontaneous imbibition could both increase and decrease with initial water saturation. To this end, mathematical models were developed with porosity, permeability, viscosity, relative permeability, capillary pressure, and initial water saturation included. These equations foresee that recovery and imbibition rate can increase, remain unchanged, or decrease with an increase in initial water saturation, depending on rock properties, the quantity of residual gas saturation, the range of initial water saturation, and the units used in the definitions of gas recovery and imbibition rate. The theoretical predictions were verified experimentally by conducting spontaneous water imbibition at five different initial water saturations, ranging from 0 to approximately 50%. The effects of initial water saturation on residual saturation, relative permeability, capillary pressure, imbibition rate, and recovery in gas/water/rock systems by cocurrent spontaneous imbibition were investigated both theoretically and experimentally. Water-phase relative permeabilities and capillary pressures were calculated with the experimental data of spontaneous imbibition. Experimental results in different rocks were compared. Introduction Spontaneous water imbibition is an important mechanism during water injection. Prediction of recovery and imbibition rate by spontaneous water imbibition is essential to evaluate the feasibility and the performance of water injection. For example, is water injection effective in the case of high initial water saturation in reservoirs? Answers to such a question may be found by investigating the effect of initial water saturation on spontaneous water imbibition. It has been observed experimentally that initial water saturation affects recovery and production rate significantly (Blair 1964; Zhou et al. 2000; Viksund et al. 1998; Cil et al. 1998; Tong et al. 2001; Li and Firoozabadi 2000; Akin et al. 2000). However, the experimental observations from different authors (Zhou et al. 2000; Cil et al. 1998; Li and Firoozabadi 2000; Akin et al. 2000) are not consistent. On the other hand, few studies have investigated the effect of initial water saturation on recovery and imbibition rate theoretically, especially in gas reservoirs. Using numerical-simulation techniques, Blair (1964) found that the quantity and the rate of oil produced after a given period of imbibition increased with a decrease in initial water saturation for countercurrent spontaneous imbibition. Zhou et al. (2000) found that both imbibition rate and final oil recovery in terms of oil originally in place (OOIP) increased with an increase in initial water saturation, whereas oil recovery by waterflooding decreased. Viksund et al. (1998) found that the final oil recovery (OOIP) by spontaneous water imbibition in Berea sandstone showed little variation with a change in initial water saturation from 0 to approximately 30%. For the chalk samples tested by Viksund et al. (1998), the imbibition rate first increased with an increase in initial water saturation and then decreased slightly as initial water saturation increased above 34%.Cil et al. (1998) reported that the oil recovery (in terms of recoverable oil reserves) for zero and 20% initial water saturation showed insignificant differences in behavior. However, the oil recovery for initial water saturation above 20% increased with an increase in initial water saturation. Li and Firoozabadi (2000) found that the final gas recovery in the units of gas originally in place (GOIP) by spontaneous imbibition decreased with an increase in initial water saturation in both gas/oil/rock and gas/water/rock systems. The imbibition rate (GOIP/min) increased with an increase in initial water saturation at early time but decreased at later time. Akin et al. (2000) found that the residual oil saturation was unaffected significantly by initial water saturation. In this study, equations, derived theoretically, were used to study the effect of initial water saturation on gas recovery and imbibition rate. The equations correlate recovery, imbibition rate, initial water saturation, rock/fluid properties, and other parameters. Experiments of spontaneous water imbibition in gas-saturated rocks were conducted to confirm the theoretical predictions. The effect of rock properties on gas recovery and imbibition rate was also studied. An X-ray CT scanner was used to monitor the distribution of the initial water saturation to confirm that the initial distribution of the water saturation was uniform. In this study, we only focused on cocurrent spontaneous imbibition. It was assumed that there were no chemical reactions or mass transfer between gas and liquid.

Material Balance Calculations with Water Influx in the Presence of Uncertainty in Pressures

1962 ◽  
Vol 2 (02) ◽  
pp. 120-128 ◽  
Author(s):  
C.R. Mcewen
Keyword(s):  
Least Squares ◽  
Water Saturation ◽  
Material Balance ◽  
Production Data ◽  
Petroleum Reservoir ◽  
Gas Reservoirs ◽  
Reservoir Water ◽  
Water Influx ◽  
Material Balance Calculation ◽  
Line Fitting

Abstract This paper presents a technique for calculating the original amount of hydrocarbon in place in a petroleum reservoir, and for determining the constants characterizing the aquifer performance, based on pressure-production data. A method for doing this based on a least-squares line-fitting computation was proposed by van Everdingen, Timmerman and McMahon in 1953. We found that their method would not work when there is error in the reservoir pressure dataeven moderate error. The technique presented here appears to give reasonable answers when pressure data are uncertain to the degree expected in reservoir pressure determinations. The major change introduced in the present analysis is to limit the least-squares line-fitting to yield only one constant the amount of hydrocarbon in place. The water-influx constant is then taken as proportional to the oil (or gas) in place. The constant of proportionality can be computed from estimates of effective compressibility and reservoir water saturation. It is also pointed out that the commonly used least-squares analysis assumes all of the uncertainty to be in the dependent variable. The material balance should be arranged so that this condition is fulfilled if correct inferences are to be made from statistical calculations. Examples are shown of the application of the new technique to gas reservoirs both hypothetical and real and to the oil reservoir example of van Everdingen, Timmerman and McMahon. Introduction The amount of hydrocarbon originally in place in a petroleum reservoir can be estimated by means of the material-balance calculation. Simultaneous observations of pressure and amounts of produced fluids are required, together with the PVT data applicable to the reservoir fluids. If water encroachment is occurring, it is desirable to try to infer the behavior of the aquifer, as well as the original hydrocarbon in place, from the pressure-production data. This imposes additional demands on the method of calculation, and uncertainty in the data can result in large uncertainty in the answer. In addition, if the size of a gas cap is to be established, the whole problem becomes indeterminate, as pointed out by Woods and Muskat. Brownscombe and Collins simulated a gas reservoir and its aquifer on a reservoir analyzer and derived quantitative information on the effect of uncertainty in pressure and aquifer permeability on computed gas in place. Among the various techniques of estimating the performance of an aquifer, the method of van Everdingen and Hurst, based on compressible flow theory, seems to have been the most generally successful (see Ref. 4, for example). In this paper we shall confine ourselves to their representation of the aquifer. In 1953, van Everdingen, Timmerman and McMahon introduced a statistical technique for deriving the amount of oil originally in place and the parameters which describe the aquifer. (We shall refer to this technique as the "VTM method", as suggested by Mueller.) Their example reservoir had no gas cap. It has been our experience that the VTM method gives a reasonable answer when the data are very accurate, but that inaccuracy (particularly in pressure) can cause the method to break down. The effect was first observed in gas reservoirs, but has since been seen in oil reservoirs also. In this paper we present another statistical method which has been successful in achieving a reasonable answer where the VTM method has failed. In the new method, one less parameter is derived from material-balance computations. It is assumed that values can be established for effective compressibility in the aquifer and reservoir water saturation independently of the material-balance calculation. The water-influx constant can then be obtained from these data and the quantity hydrocarbon in place. SPEJ P. 120^

scholarly journals Experimental study on production performance and reserves utilization law in carbonate gas reservoirs

2021 ◽  
Author(s):  
Mengfei Zhou ◽  
Xuan Xu ◽  
Yuxuan Zhang ◽  
Chunyan Jiao ◽  
Yu Tang ◽  
...  
Keyword(s):  
Water Saturation ◽  
Production Performance ◽  
Formation Pressure ◽  
Pressure Balance ◽  
Gas Reservoirs ◽  
Reservoir Permeability ◽  
Stable Production ◽  
Well Pattern ◽  
Production Period ◽  
Original Water

AbstractCarbonate gas reservoirs in China are rich in reserves. In the development process, there are many reserves with low permeability, low efficiency and low recovery degree. It is difficult to stabilize gas well production and prolong its life cycle. Under the condition of original water saturation (Sw) of 0%, 20%, 40%, 55% and 65%, respectively, the physical simulation experiment of gas reservoirs depletion development was carried out by using long core multi-point embedded pressure measuring system. The long cores with average gas permeability of 2.300 mD, 0.485 mD and 0.046 mD (assembled from 10 carbonate cores) were used to carry out this experiment. During the experiment, the pressure dynamics at different positions inside the long core and the gas production dynamics at the outlet were recorded in real time to reveal the production performance and reserves utilization law of carbonate gas reservoirs. The results show that the stable production period of tight reservoir in carbonate gas reservoirs is short, and the low production period is relatively long. The stable production time and recovery rate of gas reservoir increase with the increase of reservoir permeability and decrease with the increase of water saturation. The production of tight carbonate gas reservoirs with permeability less than 0.1 mD is greatly affected by pore water, and the reservoir pressure distribution shows a steep pressure drop funnel, and the reserves far from well are rarely used. Therefore, the reserves far from well should be utilized by closing well to restore formation pressure balance, densifying well pattern or transforming reservoir. The variation range of water saturation in the development of carbonate gas reservoirs is influenced by reservoir permeability and water saturation, and closely related to formation pressure gradient in production process. It decreases with the increase of reservoir permeability and increases with the increase of original water saturation. The research results provide a theoretical basis for understanding the relationship between physical properties of carbonate gas reservoirs and production performance, reserves utilization law, and realizing balanced utilization, efficient development and long-term stable production of carbonate gas reservoirs.

scholarly journals Performance Evaluation and Mechanism Study of a Silicone Hydrophobic Polymer for Improving Gas Reservoir Permeability

2020 ◽  
Author(s):  
Jie Zhang ◽  
Xu-Yang Yao ◽  
Bao-Jun Bai ◽  
Wang Ren
Keyword(s):  
Surface Tension ◽  
Water Saturation ◽  
Gas Production ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Mechanism Study ◽  
Gas Reservoirs ◽  
Tension Reduction ◽  
Surface Tension Reduction ◽  
Reservoir Permeability

The permeability of tight gas reservoirs is usually lower than 1 md. When the external fluids from drilling and completion processes invade such reservoirs, formation damage occurs and causes serious damage to oil and gas production. Fluorocarbon surfactants are most often recommended for removing such damage because they have extremely low surface tension, which means that they can change the reservoir wettability from water wet to gas or oil wet. However, they are not normally applied in the field because they are not cost-effective. Besides, some environmental concerns also restrict their application. In this work, we studied the effects of an oligomeric organosilicon surfactant (OSSF) on wettability modification, surface tension reduction, invasion of different fluids, and fluid flow back. It was found that the amount of spontaneous imbibition and remaining water could be reduced by the surfactant as a result of surface tension reduction and wettability alteration. Compared to the distilled water, the concentration of 0.20 wt% OSSF could decrease water saturation of cores by about 4%. At a flow-back pressure of 0.06 and 0.03 MPa after 20 PV displacement, permeability recovery could increase from 8 to 7–93% and 86%, respectively. We also found that the mechanism of OSSF includes the physical obstruction effect, surface tension reduction of external fluids, and wettability alteration of the reservoir generated. Meanwhile, quantum chemical calculations indicated that adsorbent layer of polydimethylsiloxane could decrease the affinity and adhesion of CH4 and H2O on the pore surface.

scholarly journals Impact of Petrophysical Properties on Hydraulic Fracturing and Development in Tight Volcanic Gas Reservoirs

Geofluids ◽  
2017 ◽  
Vol 2017 ◽  
pp. 1-13 ◽  
Author(s):  
Yinghao Shen ◽  
Mianmo Meng ◽  
Tao Liu ◽  
Hongkui Ge ◽  
Yuelei Zhang
Keyword(s):  
Hydraulic Fracturing ◽  
Water Saturation ◽  
Spontaneous Imbibition ◽  
Petrophysical Properties ◽  
Gas Reservoirs ◽  
Volcanic Gas ◽  
Volcanic Reservoir ◽  
Fracturing Fluids ◽  
Irreducible Water Saturation ◽  
Fast Flow

The volcanic reservoir is an important kind of unconventional reservoir. The aqueous phase trapping (APT) appears because of fracturing fluids filtration. However, APT can be autoremoved for some wells after certain shut-in time. But there is significant distinction for different reservoirs. Experiments were performed to study the petrophysical properties of a volcanic reservoir and the spontaneous imbibition is monitored by nuclear magnetic resonance (NMR) and pulse-decay permeability. Results showed that natural cracks appear in the samples as well as high irreducible water saturation. There is a quick decrease of rock permeability once the rock contacts water. The pores filled during spontaneous imbibition are mainly the nanopores from NMR spectra. Full understanding of the mineralogical effect and sample heterogeneity benefits the selection of segments to fracturing. The fast flow-back scheme is applicable in this reservoir to minimize the damage. Because lots of water imbibed into the nanopores, the main flow channels become larger, which are beneficial to the permeability recovery after flow-back of hydraulic fracturing. This is helpful in understanding the APT autoremoval after certain shut-in time. Also, Keeping the appropriate production differential pressure is very important in achieving the long term efficient development of volcanic gas reservoirs.

Experimental Study on the Saturation Model of Volcanic Rock Based on Fluid Distribution

2021 ◽  
Vol 62 (4) ◽  
pp. 422-433
Author(s):  
Baozhi Pan ◽  
◽  
Weiyi Zhou ◽  
Yuhang Guo ◽  
Zhaowei Si ◽  
...  
Keyword(s):  
Volcanic Rock ◽  
Oil And Gas ◽  
Water Saturation ◽  
Early Stage ◽  
Evaluation Model ◽  
Acoustic Velocity ◽  
Distribution Model ◽  
Fluid Distribution ◽  
Water Drainage ◽  
Gas Reservoirs

A saturation evaluation model suitable for Nanpu volcanic rock formation is established based on the experiment of acoustic velocity changing with saturation during the water drainage process of volcanic rock in the Nanpu area. The experimental data show that in the early stage of water drainage, the fluid distribution in the pores of rock samples satisfies the patchy formula. With the decrease of the sample saturation, the fluid distribution in the pores is more similar to the uniform fluid distribution model. In this paper, combined with the Gassmann-Brie and patchy formula, the calculation equation of Gassmann-Brie-Patchy (G-B-P) saturation is established, and the effect of contact softening is considered. The model can be used to calculate water saturation based on acoustic velocity, which provides a new idea for the quantitative evaluation of volcanic oil and gas reservoirs using seismic and acoustic logging data.

Predicted Liquid Water Saturation in Unstructured Pore Networks Based on PEMFC GDL Porosity Profiles

2010 ◽  
Author(s):  
J. Hinebaugh ◽  
Z. Fishman ◽  
A. Bazylak
Keyword(s):  
Liquid Water ◽  
Water Saturation ◽  
Pore Space ◽  
Polymer Electrolyte Membrane ◽  
Gas Diffusion ◽  
Pore Network Model ◽  
High Porosity ◽  
Pore Networks ◽  
Electrolyte Membrane ◽  
Capillary Pressures

An unstructured, two-dimensional pore network model is employed to describe the effect of through-plane porosity profiles on liquid water saturation within the gas diffusion layer (GDL) of the polymer electrolyte membrane fuel cell. Random fibre placements are based on the porosity profiles of six commercially available GDL materials recently obtained through x-ray computed tomography experiments. The pore space is characterized with a Voronoi diagram, and invasion percolation-based simulations are performed. It is shown that water tends to accumulate in regions of relatively high porosity due to the lower associated capillary pressures. It is predicted that GDLs tailored to have smooth porosity profiles will have fewer pockets of high saturation levels within the bulk of the material.

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