Water-alternating-gas Experiments Research Articles

A Systematic Experimental Study to Understand the Performance and Efficiency of Gas Injection in Carbonate Reservoirs

Summary Gas injection is the most widely applied recovery method in light, condensate, and volatile oil carbonate reservoirs. Gas has high displacement efficiency and usually results in a low residual oil saturation in the part of the reservoir that is contacted with gas. The displacement efficiency increases when the injected gas is near-miscible or miscible with the oil. In addition to nitrogen and hydrocarbon gas projects, carbon dioxide (CO2) enhanced oil recovery (EOR) has been the dominant gas EOR process. Gas-based EOR has been implemented in both mature and waterflooded carbonate reservoirs. In this paper, we present the results of a detailed experimental study aimed at understanding the performance and efficiency of gas injection in carbonate reservoirs. A series of immiscible and miscible gas injection coreflood experiments were performed using limestone reservoir cores under different injection strategies. To minimize laboratory artifacts, long cores were used in the experiments, and to observe the effect of gravity, both 2 in. diameter and 4 in. diameter (whole core) were used. The experiments were performed under reservoir conditions using live crude oil. The core wettability was restored by aging the core in crude oil for several weeks under reservoir temperature. Hydrocarbon gas (methane) was used as the immiscible injectant, and both CO2 and a mixture of 50% C1 and 50% CO2 were used as miscible injectant. All gas injection experiments were performed using vertically oriented cores, and the gas was injected from the top unless it is stated otherwise. The main parameters investigated in this study are as follows: The effect of miscibility on oil recovery for both continuous gas injection and water alternating gas (WAG). The effect of gravity on gas sweep efficiency compared to waterflooding. The effect of gas-oil interfacial tension (IFT) on oil recovery when using the same oil. The effect of oil type on oil recovery using the same injected gas at miscible and immiscible conditions. The effect of immiscible gas injection on subsequent miscible gas injection performance. Impact of CO2 cycle length on ultimate oil recovery. The impact of the order of fluid injection where multiple WAG injection cycles were performed in separate experiments after water or gas injection. The main conclusions of this study are as follows: As expected, miscibility has a significant impact on displacement efficiency and oil recovery where miscible gas recovered more than 20% extra oil compared to immiscible gas. A significant variation in oil recovery is observed for miscible gas injection (i.e., more than 10 saturation units difference) depending on the minimum miscibility pressure (MMP) between the injected gas and crude oil, even when both experiments are performed at miscible conditions using the same injected gas. The performance of tertiary CO2 flood was adversely affected by the slug of immiscible gas injected. Therefore, it is not recommended to have immiscible gas injection before miscible gas injection. Regardless of injected gas type, gas injection with similar IFTs achieved similar oil recovery. During WAG experiments, starting the injection cycles with water or gas did not have any impact on the ultimate oil recovery for both miscible and immiscible cases for one of the reservoirs, while WAG_G (WAG starting with gas injection) recovered more oil for another reservoir. Gravity has a significant impact on oil recovery for both miscible and immiscible gas injections. A significant difference is observed in oil recovery when comparing CO2 injection on 2-in.- and 4-in.-diameter core samples or when comparing horizontal vs. vertical immiscible gas injection and WAG experiment. The longer the CO2 slug size, the higher the oil recovery observed in gas injection experiments. The results of this study provide a rich and rarely available set of experimental data that can help improve and optimize gas and WAG injection in oil-wet carbonates.

Three-Phase Fluid Flow Interaction at Pore Scale during Water- and Surfactant-Alternating Gas (WAG/SAG) Injection Using Carbon Dioxide for Geo-Sequestration and Enhanced Oil Recovery

Sequestration of CO2 in geologic formations such as depleted oil reservoirs has emerged as one of the lead solutions to tackle greenhouse gas emissions to reduce pollution and global warming. Supercritical CO2 (sc-CO2) injection in oil reservoirs has proven to be useful as an enhanced oil recovery (EOR) technique along with the benefits of CO2 sequestration. In this study, a tortuous microscopic pore scale model was used to study and investigate the phenomena of water-alternating gas (WAG) and surfactant-alternating gas (SAG) with sc-CO2. The study scrutinizes the dynamics of the pore-level phenomenon in the multiphase WAG and SAG flows at the pore level in detail. Transient computational fluid dynamics (CFD) analysis was used to study the fluid flow characteristics of oil, water, and sc-CO2 at different reservoir pressure and temperature conditions in oil-wet conditions. Governing equations were coupled with EOS (Helmholtz free energy equation) to capture the viscous and intrinsic properties of sc-CO2 due to variations in pressure and temperature conditions. It was found that higher oil recovery does not necessarily indicate higher sc-CO2 sequestration and that temperature harms the displacement mechanism due to unfavorable mobility ratios. Comparing WAG and SAG for the first injection cycle, SAG showed a more diffused interface between displaced and displacing fluid. The additional oil recovery produced in patches was a result of pressure oscillations near the blind pores. Moreover, high vorticity promotes greater intermixing between the displacing and displaced fluid by increasing the rate of interface length. In SAG cases, faster sc-CO2 breakthroughs were observed due to reduced shear stress along the fluid interfaces, which resulted in higher sequestration values in a given time frame. The CO2 sequestration volume in SAG cases was found to be approximately 40% more than in WAG experiments. The study confirms that lower values of oil–water interfacial tension aids in faster and more efficient sequestration of sc-CO2 along with additional oil gain from a given reservoir.

Generalised model for simulation of two- and three-phase cycle-dependent hysteresis in sandstones

Many Enhanced Oil Recovery (EOR) processes involve injecting multiple slugs to improve the volumetric sweep efficiency in the reservoir, such as Water-Alternating-Gas (WAG), polymer flood, surfactant flood, and steam injection. Precise estimations of hysteresis phenomenon in relative permeability (kr) and capillary pressure (Pc) plays a crucial role in conducting accurate prognosis of oil production, reliable decision making, and feasibility assessment of EOR plans. Over the years, abundant high-quality experimental data revealed limitations of existing hysteresis models in the literature and highlighted the necessity of introducing a reliable hysteresis model.This paper presents a new hysteresis model for accurate estimation of ultimate oil recovery and pressure drop in coreflood experiments. In contrast to the existing models, all required parameters are directly calculated from experimental data, eliminating the tuning procedure, and reducing the associated uncertainties. This study also includes a detailed discussion of estimating trapped gas saturation and application of Land’s trapping model in cyclic systems, considering their importance in CO2 sequestration and non-aqueous contaminant flow in soil. The presented model also benefits from a new procedure for estimating final saturations during a WAG experiment based on common observations of WAG experiments. A comprehensive set of cyclic two- and three-phase experiments performed on a homogenous sandstone over a wide range of injection scenarios, fluid, and rock properties were successfully used to validate the model. The detailed analysis and comparison of various cyclic experiments herein provide an excellent benchmark for future validation and development of hysteresis models.

Experimental investigation of CO2 in continuous and water alternating gas injection

CO2 injection and water-alternating-gas injection are EOR methods for improving oil recovery. This paper shows Water alternating gas (WAG) and continuous gas injection experiments with CO2 in secondary recovery. Experiments were performed in sand-packed-model. The continuous gas injection experiments were conducted at 3800, 4200, 4600 and 5000 psi, then two WAG experiments was completed at 3800 psi. Also temperature was 190 °F (the reservoir temperature) in all experiments. Six tests were conducted to investigate continuous CO2 and WAG injection under the reservoir condition. In the first test, 1.2 PV (pore volume) of CO2 was injected into sand-packed-model at pressure of 3800 psi and temperature of 190 °F. Amount 1.2 PV of CO2 was injected into sand-packed-model at 4200 psi in the test 2. In third one, 1.2 PV of CO2 was injected at 4600 psi and 1.2 of PV CO2 was injected at 5000 psi in forth one. Water alternating gas injection experiments with CO2 were including two tests. In the first one, 0.3 PV of CO2 and 0.9 PV of brine were injected consecutively into model. In the second one, 0.3 PV of CO2 and 0.3 PV of brine were injected respectively into model and this test was completed in two cycles. The results indicate that increase of injection pressure enhances oil recovery in continuous CO2 injection and increase of injected CO2 increases oil recovery in WAG process. Also WAG injection increases oil recovery more than CO2 continuous injection.

Estimation of Flow and Hysteresis Parameters Applicable to WAG Experiments

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 183321, “An Improved Approach for Estimation of Flow and Hysteresis Parameters Applicable to WAG Experiments,” by Pedram Mahzari and Mehran Sohrabi, Heriot-Watt University, prepared for the 2016 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 7–10 November. The paper has not been peer reviewed. Water-alternating-gas (WAG) injection has demonstrated encouraging results for improving oil recovery. However, numerical simulation of three-phase flow and the associated hysteresis effects are not well-understood. In the complete paper, a new assessment of the WAG-hysteresis model, which was developed originally for water-wet conditions, was carried out by automatic history matching of two coreflood experiments in water-wet and mixed-wet conditions. The results indicate that history matching the entire WAG experiment would lead to a significantly improved simulation outcome. Introduction Using an optimization software, the authors have carried out a series of history-matching exercises on coreflood experiments to evaluate the performance of the WAG-hysteresis model and to simulate WAG experiments conducted on mixed-wet and water-wet cores at near-miscible conditions. The main difference here compared with previous work is the tuning of the parameters relevant to the WAG-hysteresis model on entire WAG experiments (rather than on individual cycles of one experiment) with a new methodology to estimate more-representative two-phase relative permeability curves from the WAG experiments. Coreflood Experiments and History-Matching Method There are numerous coreflood experiments in the literature that can be used for studying pure WAG-related interactions at near-miscible conditions. The unique advantages of this data set are gravity-segregation effect has been excluded by rotating the core while the fluids were being injected and all the fluids (water/oil/gas) were thermodynamically pre-equilibrated to minimize the effect of mass transfers at near-miscible conditions. Therefore, the processes taking place in the coreflood experiments can be attributed solely to multiphase flow and hysteresis effects. The following coreflood tests were selected from the data set to investigate the behavior of flow functions with respect to fluid saturation, injection scenario, and initial wettability: Continuous gas injection in the water-wet core saturated with oil at irreducible water saturation, used to estimate two-phase gas/oil relative permeabilities Continuous gas injection in the mixed-wet core saturated with oil at irreducible water saturation, used to estimate two-phase gas/oil relative permeabilities WAG experiment performed at low-gas/oil-interfacial-tension (near-miscible) conditions in a mixed-wet core, with the starting water-injection displacement used to obtain water/oil-flow functions WAG experiment performed at near-miscible conditions in a water-wet core, with the starting water-injection displacement used to obtain water/oil-flow functions

A Robust Methodology To Simulate Water-Alternating-Gas Experiments at Different Scenarios Under Near-Miscible Conditions

Summary Three-phase flow in porous media during water-alternating-gas (WAG) injections and the associated cycle-dependent hysteresis have been subject of studies experimentally and theoretically. In spite of attempts to develop models and simulation methods for WAG injections and three-phase flow, current lack of a solid approach to handle hysteresis effects in simulating WAG-injection scenarios has resulted in misinterpretations of simulation outcomes in laboratory and field scales. In this work, by use of our improved methodology, the first cycle of the WAG experiments (first waterflood and the subsequent gasflood) was history matched to estimate the two-phase krs (oil/water and gas/oil). For subsequent cycles, pertinent parameters of the WAG hysteresis model are included in the automatic-history-matching process to reproduce all WAG cycles together. The results indicate that history matching the whole WAG experiment would lead to a significantly improved simulation outcome, which highlights the importance of two elements in evaluating WAG experiments: inclusion of the full WAG experiments in history matching and use of a more-representative set of two-phase krs, which was originated from our new methodology to estimate two-phase krs from the first cycle of a WAG experiment. Because WAG-related parameters should be able to model any three-phase flow irrespective of WAG scenarios, in another exercise, the tuned parameters obtained from a WAG experiment (starting with water) were used in a similar coreflood test (WAG starting with gas) to assess predictive capability for simulating three-phase flow in porous media. After identifying shortcomings of existing models, an improved methodology was used to history match multiple coreflood experiments simultaneously to estimate parameters that can reasonably capture processes taking place in WAG at different scenarios—that is, starting with water or gas. The comprehensive simulation study performed here would shed some light on a consolidated methodology to estimate saturation functions that can simulate WAG injections at different scenarios.

Relative Permeability Characterization for Water-Alternating-Gas Injection in Oil Reservoirs

Summary Large quantities of oil usually remain in oil reservoirs after conventional waterfloods. A significant part of this remaining oil can still be economically recovered by water-alternating-gas (WAG) injection. WAG injection involves drainage and imbibition processes taking place sequentially; therefore, the numerical simulation of the WAG process requires reliable knowledge of three-phase relative permeability (kr) accounting for cyclic-hysteresis effects. In this study, the results of a series of unsteady-state two-phase displacements and WAG coreflood experiments were used to investigate the behavior of three-phase kr and hysteresis effects in the WAG process. The experiments were performed on two different cores with different characteristics and wettability conditions. An in-house coreflood simulator was developed to obtain three-phase relative permeability values directly from unsteady-state WAG experiments by history matching the measured recovery and differential-pressure profiles. The results show that three-phase gas relative permeability is reduced in consecutive gas-injection cycles and consequently the gas mobility and injectivity drop significantly with successive gas injections during the WAG process, under different rock conditions. The trend of hysteresis in the relative permeabilty of gas (krg) partly contradicts the existing hysteresis models available in the literature. The three-phase water relative permeability (krw) of the water-wet (WW) core does not exhibit considerable hysteresis effect during different water injections, whereas the mixed-wet (MW) core shows slight cyclic hysteresis. This may indicate a slight increase of the water injectivity in the subsequent water injections in the WAG process under MW conditions. Insignificant hysteresis is observed in the oil relative permeability (kro) during different gas-injection cycles for both WW and MW rocks. However, a considerable cyclic-hysteresis effect in kro is observed during water-injection cycles of WAG, which is attributed to the reduction of the residual oil saturation (ROS) during successive water injections. The kro of the WW core exhibits much-more cyclic-hysteresis effect than that of the MW core. No models currently exist in reservoir simulators that can capture the observed cyclic-hysteresis effect in oil relative permeability for the WAG process. Investigation of relative permeability data obtained from these displacement tests at different rock conditions revealed that there is a significant discrepancy between two-phase and three-phase relative permeability of all fluids. This highlights that not only the three-phase relative permeability of the intermediate phase (oil), but also the three-phase kr of the wetting phase (water) and nonwetting phase (gas) are functions of two independent saturations.

Efficient Experimental-Data Acquisition for Miscible CO2 Water-Alternating-Gas-Injection Corefloods in Carbonate

SummaryUnderstanding the physics behind which carbon dioxide (CO2) and water displace oil in the porous medium is of the utmost importance for the success of any miscible CO2 water-alternating-gas (WAG) -injection project. This involves estimating parameters such as remaining oil saturation, trapped gas saturation, and three-phase relative permeability by carrying out and by interpreting several CO2 WAG experiments representative of flows inside the reservoir (i.e., pressure and temperature conditions, fluids, capillary number). This paper presents an experimental design, an apparatus, and a procedure to carry out such experiments at reservoir conditions with extensive and up-to-date data-acquisition techniques.Two CO2/water cyclic injections were performed at reservoir conditions, on horizontal carbonate cores with light oil from a Middle East field, far above minimum miscibility pressure (MMP). Great care was given to the data-acquisition systems set for the experiments. Produced volumes were monitored to provide material balance of each phase at both reservoir and laboratory conditions with a clear separation of flashed oil, condensate, and gas. A full compositional analysis of the fluids produced was then conducted, with gas chromatography (GC) and liquid analysis of flashed oil and condensate. Differential pressure across the core was monitored for relative-permeability estimation. Finally, a dual-energy X-ray scanner was used to measure three-phase in-situ saturations, cross check material-balance results, highlight gravity segregation, and ensure that laboratory artifacts (end effects) do not influence interpretation conclusions.Several material-balance methods were investigated to accurately calculate the average saturations and the recovery factor in the presence of strong CO2/oil interactions. With our experimental design, we were able to decouple thermodynamic effects (stripping) from three-phase flow effects (sweeping) in the raw-production data. Several hysteresis features were observed, such as reduction in gas relative permeability and variation in land-trapping parameter.

Modeling of Cyclic Hysteresis of Three-Phase Relative Permeability During Water-Alternating-Gas Injection

Summary Multiphase flow takes place in many petroleum reservoirs—in particular, mature fields and reservoirs under fluid [e.g., gas, water-alternating-gas (WAG)] injection. The numerical simulation of such reservoirs requires knowledge of flow functions (i.e., relative permeability and capillary pressure). Because experimental measurement of fluid permeabilities (in particular) under three-phase-flow conditions is very time-consuming and difficult, many correlations and models were developed and these are widely used instead of measured data. In this study, we have used the results of a comprehensive set of WAG-injection coreflood experiments performed under different wettability conditions and core-permeability values to obtain relative permeabilites of oil, water, and gas under reservoir pressure and temperature. Three-phase relative permeability of each phase was obtained by history matching the measured production and differential pressure obtained in the laboratory. The results of the experiments revealed significant cyclic hysteresis effects in gas and oil relative permeability. We proposed new formulations and methodology for the modeling of cyclic hysteresis of three-phase relative permeability during WAG injection. This technique is a direct method that uses measured three-phase kr data obtained from the first cycle of WAG injection to predict the relative permeability of the subsequent cycles. The integrity of this technique was validated against the three-phase kr data obtained from our WAG experiments. We also assess the validity of the WAG-injection hysteresis model available in reservoir simulators against our three-phase relative permeability data to evaluate its performance.

Experimental Investigation of Near-Miscible Water-Alternating-Gas Injection Performance in Water-Wet and Mixed-Wet Systems

Summary Laboratory data on water-alternating-gas (WAG) injection for non-water-wet systems are very limited, especially for near-miscible (very low IFT) gas/oil systems, which represent injection scenarios involving high-pressure hydrocarbon gas or CO2 injection. Simulation of these processes requires three-phase relative permeability (kr) data. Most of the existing three-phase relative permeability correlations have been developed for water-wet conditions. However, a majority of oil reservoirs are believed to be mixed-wet and, hence, prediction of the performance of WAG injection in these reservoirs is associated with significant uncertainties. Reliable simulation of WAG injection, therefore, requires improved relative permeability and hysteresis models validated by reliable measured data. In this paper, we report the results of a comprehensive series of coreflood experiments carried out in a core under natural water-wet conditions. These included water injection, gas injection, and also WAG injection. Then, to investigate the impact of wettability on the performance of these injection strategies, the wettability of the same core was changed to mixed-wet (by aging the core in an appropriate crude oil) and a similar set of experiments were performed in the mixed-wet core. WAG experiments under both wettability conditions started with water injection (I) followed by gas injection (D), and this cyclic injection of water and gas was repeated (IDIDID). The results show that in both the water-wet and mixed-wet cores, WAG injection performs better than water injection or gas injection alone. Changing the rock wettability from water-wet to mixed-wet significantly improves the performance of water injection. Under both wettability conditions (water-wet and mixed-wet), the breakthrough (BT) of the gas during gas injection happens sooner than the BT of water in water injection. Ultimate oil recovery by gas injection is considerably higher than that obtained by water injection in the water-wet system, while in the mixed-wet system, gas injection recovers considerably less oil.

Three-phase relative permeability and hysteresis effect during WAG process in mixed wet and low IFT systems

There is significant uncertainty associated with the selection of three-phase relative permeability in particular for the numerical simulations of water-alternating-gas (WAG) injection. Generally, three-phase relative permeabilities are calculated from empirical correlations, which are based on two-phase relative permeabilities. Water alternating gas injection involves drainage and imbibition processes taking place sequentially. Therefore, accurate prediction of the relative permeability ( k r) functions and their hysteresis effects applicable to WAG are extremely complex. The problem of 3-phase k r selection becomes even more difficult for three-phase systems involving mixed-wet rocks and low gas–oil IFT (interfacial tension) fluids (nearly-miscible fluids). We use the results of coreflood experiments carried out on two different cores (one water-wet and one mixed-wet) using a low IFT gas–oil system to generate two-phase and three-phase relative permeability data by using an in-house three-phase coreflood simulator. The results show that water and gas three-phase k r values depend on two independent saturations, contrary to the inherent assumption in most of the existing empirical k r models. Three-phase water, oil and gas k r values were all significantly lower than their corresponding two-phase values. This reduction in k r was more profound for the gas where the three-phase k rg was an order of magnitude lower than its corresponding two-phase k rg. Using the laboratory derived three-phase k r data, the performance of some of the existing three-phase k r models was evaluated by comparing the results of the WAG experiments with predictions made by a commercial reservoir simulator. In general, considerable discrepancies between the measured and the predicted k r values were observed. Some models performed better than others but no single model was capable of matching all experimental results adequately.

Slug Water Alternating Gas Flow Processes Behavior in the Vicinity of Discontinuous Shales

Gas injection is the second largest enhanced oil recovery process practiced in the world. To increase the macroscopic sweep efficiency, the gas is generally injected intermittently with water either simultaneously or as slugs. This mode of injection, called water alternating gas (WAG), is being widely used in the oil fields. This experimental and numerical study is aimed at understanding mechanisms of oil recovery following slug first-contact miscible WAG (FCMWAG) injection in the presence of discontinuous shales. A particular objective is to quantify the accuracy of numerical simulation when modeling slug FCMWAG displacements in these heterogeneous systems. A series of well-characterized laboratory experiments in two-dimensional heterogeneous bead packs were carried out. Slug FCMWAG displacement experiments were performed in the porous media containing discontinuous shale. Slug injection was carried out at a WAG ratio of 1:1 with slug sizes of 5 and 50% PV. All experiments were then modeled using IMPES finite difference simulator without using history matching (all simulations used directly measured porous media properties as inputs) to quantify the accuracy of the simulation when modeling the slug FCMWAG displacements in a porous media with a discontinuous shale. The large water slug (50% PV) displacement outperformed the 5% PV slug process because the large water slug injected ahead of solvent significantly reduced the extent of fingering and the bypassed oil around the shale barrier. Simulation of the slug WAG experiments showed good agreement for the oil recovery. However, a discrepancy in the physics of the fluid flow during the displacements, especially downstream and upstream of the shale barrier, was observed in the fluid cut curves. Simulation predicted less fingering and fewer breakdowns of the injected slugs.