Mehran Sohrabi

Coreflooding studies to investigate the potential of carbonated water injection as an injection strategy for improved oil recovery and CO2 storage

Carbonated water injection (CWI) is a CO2-augmented water injection strategy that leads to increased oil recovery with added advantage of safe storage of CO2 in oil reservoirs. In CWI, CO2 is used efficiently (compared to conventional CO2 injection) and hence it is particularly attractive for reservoirs with limited access to large quantities of CO2, e.g. offshore reservoirs or reservoirs far from large sources of CO2. We present the results of a series of CWI coreflood experiments using water-wet and mixed-wet Clashach sandstone cores and a reservoir core with light oil (n-decane), refined viscous oil and a stock-tank crude oil. The experiments were carried out to assess the performance of CWI and to quantify the level of additional oil recovery and CO2 storage under various experimental conditions. We show that the ultimate oil recovery by CWI is higher than the conventional water flooding in both secondary and tertiary recovery methods. Oil swelling as a result of CO2 diffusion into the oil and the subsequent oil viscosity reduction and coalescence of the isolated oil ganglia are amongst the main mechanisms of oil recovery by CWI that were observed through the visualisation experiments in high-pressure glass micromodels. There was also evidence of a change in the rock wettability that could also influence the oil recovery. The coreflood test results also reveal that the CWI performance is influenced by oil viscosity, core wettability and the brine salinity. Higher oil recovery was obtained with the mixed-wet core than the water-wet core, with light oil than with the viscous oil and low salinity carbonated brine than high-salinity carbonated brine. At the end of the flooding period, an encouraging amount of the injected CO2 was stored in the brine and the remaining oil in the form of stable dissolved CO2. The experimental results clearly demonstrate the potential of CWI for improving oil recovery as compared with the conventional water flooding (secondary recovery) or as a water-based EOR (enhanced oil recovery) method for watered out reservoirs.

Visualisation of Oil Recovery by Water Alternating Gas (WAG) Injection Using High Pressure Micromodels - Water-Wet System

The use of WAG (water alternating gas) injection can potentially lead to improved oil recovery compared to injection of either gas or water alone, however the physical process is not well understood. Using high pressure glass micromodels, a series of WAG tests have been conducted using equilibrated fluids, with high quality images of the oil recovery processes operating during alternate WAG cycles being recorded. The tests were conducted using both water-wet and oil-wet micromodels. In this paper results of a typical water-wet test is presented (results of the oil-wet and mixed wet tests will be presented in a subsequent paper). Water-wet micromodels were initially fully saturated with water and then displaced with oil to establish the connate water saturation. The micromodels were then flooded with water to observe the process of establishing the waterflood residual oil saturation (S orw ). Alternate cycles of gas and water injection were then conducted to observe three-phase flow and its associated oil recovery. The experiments were performed within the capillary dominated flow regime. The results highlighted the importance of corner filament flow of water in the recovery process, with the initial waterflood residual oil saturation being trapped mainly in the centre of the majority of pore space surrounded by layers of water, and not in only large pores. The successive WAG cycles redistributed the oil in a way which resulted in improved oil recovery, hence, the oil which otherwise would not have been mobile under either gas or water injection alone was mobilised and produced. It was identified that a limited number of WAG cycles were required to approach maximum oil recovery, after which additional recovery was minimal. All recovery processes were filmed and electronically stored using high resolution imaging, with oil recovery at the end of each flooding cycle being measured using image analysis techniques.

Variations of gas/condensate relative permeability with production rate at near-wellbore conditions: a general correlation

It has been demonstrated, first by this laboratory and subsequently by other researchers, that the gas and condensate relative permeability can increase significantly by increasing rate contrary to the common understanding. There are now a number of correlations in the literature and commercial reservoir simulators accounting for the positive effect of coupling and the negative effect of inertia at near wellbore conditions. The available functional forms estimate the two effects separately and include a number of parameters, which should be determined using measurements at high velocity conditions. Measurements of gas-condensate relative permeability at simulated near wellbore conditions are very demanding and expensive. Intruduction The process of condensation around the wellbore in a gascondensate reservoir, when the pressure falls below the dew point, creates a region in which both gas and condensate phases flow. The flow behaviour in this region is controlled by the viscous, capillary and inertial forces. This along with

Oil Recovery by Near-Miscible SWAG Injection

Many of current oil reservoirs are approaching the end of their waterflooding life. At this stage a significant quantity of oil (40-60%) will still remain in the reservoir. It is known that using the Water- Alternating-Gas (WAG) injection some of that oil can be produced. The WAG scheme is a combination of two traditional techniques of improved hydrocarbon recovery: waterflooding and gas injection. In many reservoirs, injectivity during WAG cycles has been lower than expected. In many cases the low injectivity rates prolong injection time and play havoc with project economics. Therefore, injectivity loss is a crucial limiting factor in many projects involving WAG injection. In an example, the pre-WAG water injection rate of 286 m3/d (1800 BPD) was not pressure-limited, while after a couple of WAG cycles the gas and water injection rates were limited by pressure to about 160 and 130 m3/d (1000 and 800 BPD), respectively. Currently, there are no clear explanations of the factors influencing injectivity loss during WAG injection, nor methods available to mitigate this problem. In this paper we report results of an experimental study that was carried out to directly visualize the pore-scale events taking place during WAG injection in porous media. We show that, in the absence of other relevant causes, gas trapping causes relative permeability reduction and injectivity loss.

Novel Insights Into Mechanisms of Oil Recovery by Use of Low-Salinity-Water Injection

The underlying mechanism of oil recovery by low salinity water injection (LSWI) is still unknown. It would, therefore, be difficult to predict the performance of reservoirs under LSWI. A number of mechanisms have been proposed in the literature but these are controversial and have largely ignored crucial fluid/fluid interactions. Our direct flow visualization investigations have revealed that a physical phenomenon takes place when certain crude oils are contacted by low salinity water leading to a spontaneous formation of micelles which can be seen in the form of micro-dispersions in the oil phase. In this paper, we present the results of a comprehensive study that includes experiments at different scales designed to systematically investigate the role of the observed crude oil/brine interaction and micelle formation in the process of oil recovery by LSWI. The experiments include; direct flow (micromodel) visualization, crude oil characterization, coreflooding, and spontaneous imbibition experiments. We establish a clear link between the formation of these micelles, the natural surface active components of crude oil, and the improvement in oil recovery due to LSWI. We present the results of a series of spontaneous and forced imbibition experiments carefully designed using reservoir cores to investigate the role of the micro-dispersions in wettability alteration and oil recovery. To further assess the significance of this mechanism, in a separate exercise, we eliminate the effect of clay by performing a LSWI experiment in a clay-free core. Absence of clay minerals is expected to significantly reduce the influence of the previously proposed mechanisms for oil recovery by LSWI. Nevertheless, we observe significant additional oil recovery compared to high salinity water injection in the clay-free porous medium. The additional oil recovery is attributed to the formation of micelles stemming from the crude oil/brine interaction mechanism described in this work and our previous related publications. Compositional analyses of the oil produced during this coreflood experiment indicates that the natural surface active compounds of the crude oil had been desorbed from the rock surfaces during the LSWI period of the experiment when the additional oil was produced. The results of this study present new insights into the fundamental mechanisms involved in oil recovery by LSWI and new criteria for evaluating the potential of LSWI for application in oil reservoirs. The fluid/fluid interactions revealed in this research applies to oil recovery from both sandstone and carbonate oil reservoirs.

Smart Water Injection for Heavy Oil Recovery from Naturally Fractured Reservoirs

Enhanced Oil Recovery (EOR) from carbonate reservoirs can be a great challenge. Carbonate reservoirs are mostly oil-wet and naturally fractured. For this type of reservoirs, primary production is derived mainly from the high permeability fracture system which means that most of the oil will remain unrecovered in the low permeability matrix blocks after depletion. Further difficulties arise under high pressure and high temperature conditions. Oil recovery from carbonated rocks may be improved by designing the composition and salinity of flood water. The process is sometimes referred to as smart water injection. The improvement of oil recovery by smart water injection is mainly attributed to wettability modification in the presence of certain ions at high temperature. The resultant favourable wettability modification is especially important for naturally fractured reservoirs where the spontaneous imbibition mechanism plays a crucial role in oil recovery. The objective of the work presented here was to experimentally investigate the performance of smart water injection for heavy oil recovery from carbonate rocks under high reservoir temperature. A series of coreflood experiments were performed using a group of carbonate cores in which smart water injection was tested under both secondary and tertiary injection conditions. The experiments were conducted at 92 o C using an extra-heavy oil. Seawater from Gulf of Mexico (GOM) was used in the seawater injection experiments and the smart water used in the tests was obtained by 10 times dilution of the seawater. Although concentration of SO4 2is lower in the smart water, the occurrence of SO4 2as anhydrite in carbonates may be sufficient to stimulate a similar reaction between the carbonated rock and the injected water with lower salinities at high temperatures. Seawater injection resulted in oil recovery ranging between 30% and 40% whereas smart water injection resulted in 60% oil recovery from the same system. Additionally, analyses of brine composition before and after coreflood experiments confirmed that the effluent concentrations of SO4 2- , Mg 2+ and Ca 2+ changed compared to its original values in the injected water. The results indicated that, for some cases, the source of these ions was dissolution from the rock surface. The reactivity of the rock increased when lower salinity water was used.

Non-equilibrium Based Compositional Simulation of Carbonated Water Injection EOR Technique

Carbonated water injection (CWI) is an augmented water injection strategy, which has great potentials for EOR and CO2 storage purposes. When carbonated water, CO2 enriched water, is injected into oil reservoirs, due to higher CO2 solubility in oil compared to that in water, CO2 migrates from carbonated water into oil. This improves oil mobility, due to swelling and viscosity reduction, which consequently increases oil production. Our core flood experiments show that during CWI, CO2 is transferred and distributed between water and oil gradually and thermodynamic equilibrium is not reached. Available compositional reservoir simulators, which are based on the instantaneous equilibrium assumption, do not capture the actual physics of CWI. In this work, a non-equilibrium based compositional simulator was developed to simulate the performed core flood CWI experiments more realistically. The developed two-phase flow simulator is currently suitable for one dimensional core experiments. It includes a mass transfer term to capture the kinetics of CO2 transfer between phases. Governing equations were derived based on the water, oil and CO2 components balance, and solved using the fully implicit finite difference technique. Black-oil (without mass transfer) and compositional (with mass transfer) modes of the simulator can be used for simulation of conventional water injection (WI) and CWI, respectively. A genetic algorithm based optimization software was also developed that can be linked to the simulator to history match the available production data and obtain the unknown parameters of the model. The simulator was used to model WI and CWI coreflood experiments conducted on a water-wet sandstone core fully saturated by Decane (with well-defined fluid properties). First, the WI experiment was simulated when an oil-water relative permeability (kro-w) was obtained by history matching of WI production data. The WI test was re-simulated by ECLIPSE100 (E100) commercial simulator using optimized kro-w. E100’s predictions of production data reasonably matched model’s results, which verify its integrity. Next, the obtained kro-w was used for simulation of CWI. Mass transfer coefficient, as the only remaining unknown parameter, was tuned to match the available CWI production data leading to an acceptable match. The simulator shows promising potentials for simulation and better understanding of CWI for practical field applications. Moreover, the structure of this simulator offers a solid foundation for other EOR methods where kinetics of mass transfer is important.

A Comprehensive Experimental Study of Pore-Scale and Core-Scale Processes During Carbonated Water Injection Under Reservoir Conditions

Enriching the injection water with CO2 has demonstrated promising results as a method for improving oil recoveries and securely storing CO2 in oil reservoirs. However, the mutual interactions taking place between carbonated water and reservoir oil at elevated reservoir conditions are not fully understood. Here we present the results of a thorough investigation of the processes leading to additional oil recovery through integrating pore-scale visualisations and coreflood experiments. Four pore-scale visualization (micromodel) experiments were performed at reservoir conditions using the recombined live oil under different injection scenarios (tertiary and secondary). Having identified the underlying dynamic interactions at pore-scales, the performance of different injection scenarios for carbonated water injection (CWI) was investigated using carbonate reservoir rocks. Five coreflood experiments were carried out using both fully and half-saturated carbonated water to sensitise the impact of CO2 content of injection water on the performance of CWI. In-situ liberation of gaseous phase was identified (from direct visualisations) as the predominant mechanism controlling the performance of carbonated water injection. The gas phase formation would bring about higher degrees of oil swelling, and it would also create a three phase flow regime which leads to further reduction of residual oil saturation. The observations confirm that the performance of CWI should be investigated under reservoir conditions using multi-components live oil and reservoir cores. Any simplification, e.g. one components make-up gas or reduced pressure/temperature, of the reservoir conditions would misleadingly change the pore-scale event and hence, the performance of CWI. From the core displacement tests, it was observed that secondary CWI could recover a significant amount of additional oil, which was 26% compared to plain seawater injection. The tertiary carbonated water would effectively mobilise 15.3% of the residual oil (after seawater injection). When CO2 content of injected CW (carbonated water) was halved, the oil recovery dropped by 1/3. The results revealed that the oil recovery would be lower if CO2 concentration is reduced but the extent of oil recovery reduction would be much less than the level of reduction in CO2 concentration. The unique and integrated research approach employed here enables us to produce a more complete and reliable set of findings and understandings at realistic reservoir conditions. During CWI under reservoir conditions, an “in-situ WAG-type” three-phase flow would be generated with more effective sweep efficiency and pore-scale advantages.

Co-history Matching: A Way Forward for Estimating Representative Saturation Functions

Core-scale experiments and analyses would often lead to estimation of saturation functions (relative permeability and capillary pressure). However, despite previous attempts on developing analytical and numerical methods, the estimated flow functions may not be representative of coreflood experiments when it comes to predicting similar experiments due to non-uniqueness issues of inverse problems. In this work, a novel approach was developed for estimation of relative permeability and capillary pressure simultaneously using the results of “multiple” corefloods together, which is called “co-history matching.” To examine this methodology, a synthetic (numerical) model was considered using core properties obtained from pore network model. The outcome was satisfactorily similar to original saturation functions. Also, two real coreflood experiments were performed where water at high and low rates were injected under reservoir conditions (live fluid systems) using a carbonate reservoir core. The results indicated that the profiles of oil recovery and differential pressure (dP) would be significantly affected by injection rate scenarios in non-water wet systems. The outcome of co-history matching could indicate that, one set of relative permeability and capillary pressure curves can reproduce the experimental data for all corefloods.

An improved methodology for estimation of two-phase relative permeability functions for heavy oil displacement involving compositional effects and instability

In heavy oil recovery by immiscible gas injection, adverse mobility ratio and gravity segregation along with influential mass transfer are the most crucial factors controlling displacement efficiencies. Obtaining relative permeability functions using conventional techniques that are based on a stable displacement front could be highly misleading. In this work, an improved methodology was proposed for estimating relative permeability curves under simultaneous effects of frontal instability and mass transfer using history-matching techniques. The compositional analysis of produced oil from a coreflood experiment was employed, which represents dynamic interactions more realistically. For the history matching, an optimum, high-resolution, two-dimensional core model was used, as opposed to the industry standard use of a one-dimensional model. The results of the simulation were then verified by a semi-empirical approach using the Koval model, which was then used to predict a similar experiment but in a vertical orientation. A good match was obtained between the forward simulation and the experiment. To highlight the effect of mass transfer on the shape of relative permeabilities, the simulation results from two immiscible gas injection corefloods were compared: CO2 injection with mass transfer and N2 injection without mass transfer. The results showed that the two estimated functions were quite similar, indicating that instability levels would determine the displacement pattern rather than local mass transfer. This integrated approach, therefore, highlights the importance of employing the right fluid model and an appropriate 2D-grid model in estimating relative permeabilities in displacement with instability and mass transfer against the current industry practice.