Mahmoud Jamiolahmady

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.

A Mechanistic Model of Gas-Condensate Flow in Pores

Recent experimental results reported in the literature indicate that the relative permeability of gas-condensate systems increases with rate (velocity) at some conditions. To gain a better understanding of the nature of the flow and the prevailing mechanisms resulting in such behaviour flow visualisation experiments have been performed, using high pressure micromodels. The observed flow behaviour at the pore level has been employed to develop a mechanistic model describing the coupled flow of gas and condensate phases. The results of the model simulating the observed simultaneous flow of gas and condensate phases have been compared with reported core experimental results. Most features of the reported rate effect are predictable by the developed single pore model, nevertheless, its extension to include multiple pore interaction is recommended.

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

Positive Effect of Flow Velocity on Gas-Condensate Relative Permeability: Network Modelling and Comparison with Experimental Results

Positive velocity dependency of relative permeability of gas–condensate systems, which has been observed in many different core experiments, is now well acknowledged. The above behaviour, which is due to two-phase flow coupling in condensing systems at low interfacial tension (IFT) conditions, was simulated using a 3D pore network model. The steady-dynamic bond network model developed for this purpose was also equipped with a novel anchoring technique, which was based on the equivalent hydraulic length concept adopted from fluid flow through pipes. The available rock data on the co-ordination number, capillary pressure, absolute permeability, porosity and one set of measured relative permeability curves were utilised to anchor the capillary, volumetric and flow characteristics of the constructed network model to those properties of the real core sample. Then the model was used to predict the effective permeability values at other IFT and velocity levels. There is a reasonable quantitative agreement between the predicted and measured relative permeability values affected by the coupling rate effect.

Direct observation of CO2 transport and oil displacement mechanisms in CO2/water/oil systems

As the concern over the greenhouse gas effects of carbon dioxide (CO2) increases, its injection into oil and gas reservoirs for enhancing hydrocarbon recovery and in saline aquifers for storage is on the rise. Variation of reservoir pressure and temperature affects the properties of CO2 and its interaction with reservoirs resident phases. Although in most cases CO2 would be in supercritical state at reservoir conditions, however, it is necessary to understand the flow and displacement mechanisms of CO2/water/ oil systems in porous media under various reservoir conditions.

A Thorough Investigation of Clean-up Efficiency of Hydraulic Fractured Wells Using Statistical Approaches

Hydraulic fracturing is considered as one of the most effective stimulation techniques to improve recovery especially from unconventional low permeability reservoirs. However this promising stimulation technique sometimes does not respond as expected. Significant amount of work has been dedicated to this topic with ineffective fracturing fluid (FF) clean-up considered as one of the main reasons for this underperformance. However there are still great deals of uncertainties in this area primarily due to large number of parameters affecting FF invasion and its back flow. This work presents results of 10 different sets of numerical simulations consisting of injection, soaking and production periods for 40960 runs. Each set consists of 4096 runs and investigates the simultaneous impact of 12 pertinent parameters (fracture permeability, matrix permeability (km), end points and exponents of Corey gas and FF relative permeability curves in both matrix and fracture and matrix capillary pressure (Pcm) (depending on interfacial tension (IFT), km and pore size index). Two-level full factorial experimental design and linear response surface statistical approaches were used to sample the variables domain, covering a wide practical range determined with the support of our 11 industrial sponsors, and generate output response. Results indicate that improvement in FF mobility inside the fracture is the major factor affecting FF cleanup efficiency. In line with this finding, maintaining high Pcm, by retaining high IFT, results in cleaner fracture (lower gas production loss, GPL). That is, increasing IFT retains FF within the matrix and allows more gas to flow freely inside the fracture. This was confirmed by the corresponding saturation map of FF distribution. The effect of Pcm was more pronounced when drawdown was very low and/or soaking time was extended. At very low drawdown and when km was reduced, in a set within its variation range, the effect of the resultant increase of Pcm on GPL was more pronounced than that of the resultant decrease in FF mobility. Generally when injected FF volume increased, larger GPL was observed and reduction of GPL (cleanup) was also slower. As fracture length decreased, cleanup was faster and the effect of fracture pertinent parameters on GPL, compared to those of matrix, decreased. This works findings allows better evaluation of benefits of this costly operation leading to an optimized design and more efficient ways to improve its performance. For instance, sometimes aiming for a longer fracture, due to its FF poor cleanup performance, is not practically attractive and use of IFT reducing agents to produce more FF during the back flow period, would not have the intended impact to bring back its performance to the desired ideal level. Copyright © 2014, Society of Petroleum Engineers.

A Study of Hydraulic Fracturing Clean-up Efficiency in Unconventional Gas Reservoirs Using Statistical Approaches

Hydraulic fracturing is widely used to improve well productivity especially in unconventional reservoirs. This costly operation, however, sometimes underperforms. One of the main reasons for this poor performance is poor clean-up efficiency of injected fracturing fluid (FF). In this work, a parametric study of FF clean-up efficiency of hydraulic fractured vertical wells was performed with 49152 simulations (in 12 sets) consisting of injection, soaking and production periods. Due to the large number of required simulations, that were conducted using a commercial reservoir simulator, a developed computer code was used to automatically read input data, run simulations and creates output data. In each set (consisting of 4096 runs), simultaneous impacts of 12 parameters (fracture permeability, matrix permeability and capillary pressure, end points and exponents of Corey gas and FF relative permeability curve in both matrix and fracture)were studied. To sample the variables domain and analyse results, two-level full factorial experimental design and linear surface model describing dependency of gas production loss (GPL), compared to 100% clean-up, to pertinent parameters at three production periods (10, 30 and 365 days) were considered and supported by the tornado charts of fitted equations, frequency of simulations with given GPL and FF saturation maps. Results indicate that generally parameters controlling FF mobility within fracture had greatest impact on GPL reduction. However in sets with very low matrix permeability especially when applied pressure drop during production is low, the effect of fluid mobility in the matrix on GPL is more pronounced, in other words, it is important how gas and FF flow within matrix rather than how fast fracture is cleaned. In tighter gas formations, generally more GPL and slower clean-up was observed. The effect of matrix capillary pressure on GPL reduction was more pronounced when drawdown was very low and/or soaking time was extended. This observation was more profound in tighter formations, i.e. for these formations, the effect of a change in drawdown and/or soaking time on matrix capillary pressure and GPL was more pronounced. These findings can be used to make better decisions on the performance and optimised design of hydraulic fracturing, which is a costly but widely used stimulation technique for unconventional low permeability gas reservoirs.

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.

An integrated study of cleanup efficiency of short hydraulic fractured vertical wells using response surface methodology

In tight gas reservoirs, gas well production is impaired after Hydraulic fracturing, that is mostly due to fracturing fluid (FF) invasion into matrix and fracture and poor clean-up efficiency. The scope of this study is to investigate the clean-up efficiency in short hydraulic fracture vertical wells and observe how the effect of pertinent parameters on gas production loss (GPL) changes with the hydraulic fracture length. The impact of 12 parameters including fracture permeability, matrix permeability, End point and Exponent of Corey gas and FF relative permeability curve in both matrix and fracture, and Interfacial Tension and Pore Size Index (capillary pressure) have been studied by developing a computer code. Interactive linear surface model describing the dependency of GPL to the pertinent parameters was used. The results indicate that as fracture length decreased the effect of fracture parameters (fracture permeability and End point and Exponent of Corey gas and FF relative permeability curve in fracture) on GPL decreased and the effect of those relevant parameters in matrix on GPL increased. The effect of capillary pressure in reducing GPL is less pronounced in shorter fractures. In shorter fractures, faster fracture clean-up was observed compare to the one for longer fracture.

Decline curve analysis for two-phase flow in tight gas condensate reservoirs

Summary Traditionally, decline curve analysis (DCA) has been used by reservoir engineers to estimate hydrocarbon-in-place and expected ultimate recovery. Most modern DCA type curve techniques, which make it possible to determine reservoir and well productivity parameters such as permeability and skin, were originally developed for the analysis of single-phase flow. The presence of two-phase conditions in a gas condensate reservoir (GCR) operating below dew point pressure introduces severe non-linearities in the diffusivity equation, which make the use of single-phase techniques debatable. Effective linearization requires the use of pseudo-pressure and pseudo-time functions, which account for the multi-phase conditions. In this study, synthetic production data, generated using a fine-grid GCR simulation model, with a permeability of 0.1md, was analysed with the widely-used Blasingame type curves. An “equivalent phase” approach is introduced in the calculation of the pseudo-variables for two-phase conditions. The results demonstrate that when DCA type-curve techniques are used in GCRs where operating conditions result in significant condensate saturations (more than 15%, as observed in this study), the use of two-phase pseudo-pressures and an equivalent-phase-based material balance pseudo-time help to improve reservoir and well productivity parameter estimations.