- Home
- Conferences
- Conference Proceedings
- Conferences
IOR 2013 - 17th European Symposium on Improved Oil Recovery
- Conference date: 16 Apr 2013 - 18 Apr 2013
- Location: Saint Petersburg, Russia
- ISBN: 978-90-73834-45-3
- Published: 16 April 2013
73 results
-
-
Compositional Simulation of a Chemically Unconventional Oil Flooded by CO2
More LessCO2 flooding is considered as one of the most effective EOR processes when the miscibility can be achieved under reservoir conditions. The key point in this connection is the understanding and reproducing of the phase interactions between CO2 and reservoir oil. A challenging compositional simulation was performed to investigate the feasibility of CO2 flooding in a field in northern Germany having chemically unconventional oil. The usual steps of PVT simulation were applied. The grouping of the components was performed based on the chemical structure as well as on the distribution of K-values from CO2-oil flash experiments. Good agreements with the experiments were obtained at the end of the regression of the selected EOS parameters. The calibrated PVT set was further used to simulate the core flood experiments. Good matches with measured oil-water production were obtained after the fine tuning by parachor values of the pesudo components. A fully miscible process could not be achieved. On the other hand, the simulation using separator oil composition (lower C1 content) indicated the miscible/partially miscible displacement process with recoveries up to 70% of the remaining oil in place which fits well with observed results.
-
-
-
Effect of Connate Water Vaporization on Well Injectivity During Acid Gas Injection into an Oil Producing Reservoir
More LessEffect of connate water vaporization on well injectivity during acid gas injection into an oil producing reservoir Paola Ceragioli. Ivan Maffeis, Alice Tegami Having H2S high EOR capabilities like those more widely known of CO2, acid gas reinjection in sour reservoirs, is an attractive option for sour oil fields developments, able to combine environmental preservation requirements with higher oil recoveries. Moreover, even though Sulphur market has been recently forecasted in growing trend, nevertheless overall sulphur production increase suggests to consider also sour reservoir scenarios alternative or even parallel to the production of high quantities of elemental solid sulphur. However, because of the high risk and the severe difficulties in H2S transportation, any environmentally friendly solution for acid gas injection has to be realized in place. However a careful design of such development scenarios involves the inclusion of additional complex phenomena. In fact, unlike what is usually accepted for non-acid fluids, full immiscibility between water and gas may not be valid anymore. In fact when a sour/acid gas stream contacts the connate brine, significant amounts of H2O gradually transfer to the acid phase, possibly leading to following halite precipitation from the more salty concentrated brine. At the same time, acid components dissolving into the connate brine from the contacted acid gas, may give rise to geochemical reactions, possibly able to alter rock properties. Here the dynamic study has been first focused around the variations on the injection/production throughout a sour reservoir sector, by taking into account injection gases with different acid components concentrations. In fact, at least as far as no water mobilization is expected within a carbonatic sour reservoir, porosity and permeability variations due to salts precipitation or calcite dissolution, in a previous work were estimated not too relevant, while connate water vaporization had been highlighted as the additional phenomenon presenting the major impact on the reservoir development description. The study will focus also on the needed preliminary modelling extensions, both with regards to thermodynamics and relative permeabilities, to be adequately set in order to make it possible the execution of these extended simulations.
-
-
-
Effects of Oil on Foam Generation and Propagation in Sandstone Porous Media
More LessFoaming of nitrogen stabilized by C14-16 alpha olefin sulfonate in natural sandstone porous media, previously subject to water flooding, was studied experimentally. Foam was generated in-situ by co-injecting gas and surfactant solution at fixed foam quality. Effect of surfactant concentration on the foam strength and foam propagation was examined. X-ray CT scans were obtained to visualize the foam displacement process and to determine fluid saturation at different times. The experiments revealed that stable foam could be obtained in the presence of water-flood residual oil. CT scan images, fluid saturation profiles and mobility reduction factors demonstrated that foam exhibited a good mobility control in the presence of water-flood residual oil. This was further confirmed by a delay in the gas breakthrough. The experiments also proved that immiscible foam displaced additional oil from water-flooded sandstone cores, supporting the idea that foam is potentially an effective EOR method. Foam flooding provided an incremental oil recovery ranging from 13±0.5% of the oil initially in place for 0.1 wt% foam to 29±2% for 1.0 wt% foam. Incremental oil due to foam flow was obtained first by a formation of an oil bank and then by a long tail production due to transport of dispersed oil within the flowing foam. The oil bank size increased with surfactant concentration, but the dispersed oil regime was less sensitive to the surfactant concentration.
-
-
-
New Reduced Parameters for Flash Calculations Based on Two-parameter BIP Formula
Authors S.E.G. Gorucu and R.T.J. JohnsPhase equilibrium calculations constitute a significant percentage of computational time in compositional simulation, especially as the number of components and phases increase. Reduced methods address this problem by carrying out phase equilibrium calculations using a reduced number of independent parameters. These methods have shown to speed up flash calculations, decrease simulation times, and also improve convergence behavior. In this paper, we present new reduced parameters using the two-parameter binary interaction parameter formula originally proposed by Li and Johns [1]. The new reduced parameters are applied to solve two-phase flash calculations for five different fluid descriptions. The results show a significant reduction in the number of iterations required to achieve convergence compared to the Li and Johns original approach. The improved method is also more robust than all previous reduced methods. We also compare computational times with the new reduced approach to conventional flash calculations based on the minimization of Gibbs energy using optimized software.
-
-
-
Accelerated Deployment of Low Salinity Waterflooding in Shell
Authors T.G. Sorop, B.M.J.M. Suijkerbuijk, S.K. Masalmeh, M.T. Looijer, A.R. Parker, D. Dindoruk and S. GoodyearAccelerated Deployment of Low Salinity Waterflooding in Shell Low Salinity Waterflooding (LSF) is an emerging IOR/EOR technology that improves microscopic sweep efficiency by optimizing the injection water salinity. Although the exact microscopic mechanism is not yet fully understood, there is increasing evidence that in sandstones LSF improves the oil recovery by wettability alteration of the reservoir rock towards a more water-wet state. Typical field scale incremental oil recoveries are estimated to be up to 6% STOIIP. Despite these beneficial factors, LSF deployment can be a slow process. This paper discusses the key factors that help accelerate LSF deployment in Shell. A key enabler for technology deployment acceleration is Shell’s decision-driven opportunity realization process (ORP). Within this framework, the deployment starts with a portfolio screening using a consistent set of surface and subsurface screening criteria, to rank and prioritize the opportunities (according to probability of success). For each identified opportunity, a key next step is to perform reservoir condition SCAL tests, for which Shell has developed a comprehensive protocol to assess and quantify the LSF effect, while de-risking the potential for injectivity loss through clay swelling. These protocols have been standardized and incorporated into the general WF guidelines, so that any suitable new WF project conducts LSF SCAL. For mature waterfloods, this SCAL program also provides the operating units with reservoir condition relperm data, which helps to refine history matching and forecasting, enabling an optimal management of their waterfloods. While SCAL is started as early as possible in the ORP, it is accompanied, in parallel, by facilities design, production forecasting and project economics. In particular, the standardization of the facilities design, including cost models, for various offshore and onshore options, plays a key role in accelerating the deployment effort. In Shell, LSF is currently at different stages of deployment around the world and across the whole spectrum of WF projects, from the rejuvenation of brown fields to green field developments, both offshore and onshore assets. Integrated surface and subsurface technology teams are currently taking the lead, working in close cooperation with R&D and individual asset teams. While LSF is a natural extension of WF, this deployment effort is combined with screening for other EOR technologies, to identify where LSF may be able to unlock additional value by creating the appropriate conditions for subsequent chemical flooding.
-
-
-
Polymer Flooding with the Polysaccharide Schizophyllan - First Field Trial Results
Authors B. Leonhardt, M. Santa, A. Steigerwald and T. Kaeppler. For the first field trial an existing fermentation plant at BASF’s industrial compound at Ludwigshafen, Germany, has being expanded to include a pilot plant for the production of a sufficient amount of Schizophyllan. In this field trial Schizophyllan is being injected for the first time into a mature oil field in Northern Germany. New wells were drilled in the selected project area and surface facilities for polymer storage and mixing and oil transportation were constructed. One of the new wells was drilled as an observation well fairly close to the injection well, to provide quick information on the project progress. Microbiological surveillance, pressure monitoring using permanent down-hole gauges and frequent production tests are performed to monitor the progress of the polymer trial. The paper summarizes learnings from the implementation phase and provides first results of the biopolymer injection. The surveillance plan will be discussed, and the challenges posed by planning and executing a new technology trial in a mature oil field are highlighted.
-
-
-
Low Salinity Flooding - A Critical Review
By A. SkaugeLow Salinity flooding is an emerging technology to improve waterflood oil recovery for both sandstone and carbonate reservoirs. Extensive laboratory experiments investigating the effect of low salinity are available in the literature. To quantify the low salinity effect, either spontaneous imbibition and/or tertiary waterflooding experiments have been performed. In few cases, the experimental flooding data was interpreted using numerical simulation to derive relative permeability curves for both low and high salinity water to be used in field simulation. The field experience using change in brine salinity to improve oil recovery is yet very limited. The mechanisms suggested explaining low salinity effect (LSE) is very diverse. This paper will evaluate the different proposed mechanisms with focus on wettability alteration as the main mechanism. The paper will discuss 1- whether spontaneous imbibition experiments, which are often performed to demonstrate the change of wettability, are sufficient to demonstrate the potential of low salinity effect and 2- whether changing the rock to more water-wet will lead to reduction in residual oil saturation (Sorw) in light of the well-established fact that Sorw is higher for water-wet rock. Core flood results as a tertiary low salinity process is mostly reported in the literature, and these experiments often give a low increase in oil recovery smeared over a long production period. The question arise that possible a lot of the literature data is influenced by capillary end-effects. Some solid low salinity response is documented with stepping up the flow rate at the end of the primary waterflood, and still shows added recovery after change in injected brine salinity. An alternative approach to control capillary end-effects would be to use monitoring of in-situ saturation. Unfortunately, the low salinity literature lacks information about local saturation and thereby also on how additional oil is mobilized. The paper conclude on what we in our opinion find is the proven main low salinity mechanisms, best approach for core flooding studies of low salinity, and modeling approach for matching core floods and also estimate field response.
-
-
-
The Critical Parameter for Low Salinity Flooding - The Relative Importance of Crude Oil, Brine and Rock
Improved oil recovery by low salinity flooding (LSF) in sandstone reservoirs is hypothesized to be the result of a wettability change of the crude oil, brine, rock (COBR) system to a more water-wet state. The exact mechanism behind the wettability change upon lowering the ionic strength of the brine is, however, not yet fully understood. It is generally accepted that a strong low salinity effect requires the presence of clay minerals in the reservoir rock and preferably a high salinity of the formation water containing divalent cations. Still, COBR systems that obey these minimum requirements may give a highly variable response to low salinity flooding. To create enhanced understanding of the critical parameter(s) controlling the low salinity effect, crude oil, rock and brine from three different reservoir systems were varied in all possible combinations in a series of spontaneous imbibition tests. These tests show that, for the COBR systems analyzed here, the rock is the most critical parameter for a strong low salinity effect. Cross-correlation of the change in water saturation upon exposure to low salinity, ΔSw LS, with various rock parameters indicated the strongest correlation with rock zeta potentials.
-
-
-
Maximizing Oil Recovery - Developing and Piloting Offshore Facilities to Customize Water for CEOR and Low Salinity Injection
Authors L. Henthorne, C. Martin and F. Azhar Abd SatarThe growing popularity of water-based enhanced oil recovery (EOR) technologies, such as low salinity injection (LSI), chemical EOR (CEOR), and steam-flooding, has created new opportunities for the water treatment industry as a function of the unique requirements of equipment and systems in EOR projects. In some cases, the needed technologies have little to no history of application in the upstream oil and gas industry, therefore impacting EOR project budgets and schedules. These issues become particularly acute in offshore applications that are generally limited by footprint and weight, thereby further reducing suitable water treatment options. Two offshore projects in Southeast Asia are pioneering the use of customized water to maximize oil recovery in CEOR applications. In one project, two vastly different water qualities are being developed which correlate to two CEOR cocktails under consideration. The water treatment infrastructure must be capable of providing either water quality and be responsive to water quality impacts associated with produced water injection facilities such that the blended injection water quality maintains consistency. In the other project, an ultra-low hardness level is desired in the injection water, to prevent potential precipitation in the reservoir. This paper describes the results of pilot testing of reverse osmosis and unique nanofiltration membranes to produce a variety of water chemistries for CEOR and LSI applications, including ultra-low hardness, high salinity; and low hardness, low salinity injection water. The testing confirms the ability of new water treatment technologies to solve challenging issues that arise in EOR applications, particularly those in offshore applications that must respond to varying needs of reservoirs and footprint/weight limitations.
-
-
-
Low Salinity Polymer Flooding
Authors A. Skauge and B.S. ShiranLow salinity waterflooding has received increasing attention. However, the increased oil recovery by low salinity is in most cases very limited. Combining low salinity with other EOR methods has been our focus in recent years. The combined effect of brine chemistry and added surfactant on oil recovery was addressed by Alagic and Skauge in recent publications. Their results show incremental recoveries of 20-30% OOIP from low salinity surfactant (LS-S) injection. The low salinity surfactant solutions used showed type II- phase behaviour with the crude oil used in the tests. We have in this study made core flood experiments to study the combined effect of low salinity and polymer injection. The polymer used is HPAM and the concentration of polymer has been very low. The change in injection brine viscosity is therefore very small, but the impact on oil recovery is significant. The results also show the benefit of secondary low salinity flooding in combination with polymer injection compared to tertiary injection.
-
-
-
Fitting Foam Simulation Model Parameters to Data
Authors C.S. Boeije and W.R. RossenCheng et al. (2000) present a simple method to fit foam simulation parameters without oil to data for pressure gradient as a function of superficial velocities of gas and liquid. The key in this process is the identification of "high-quality" (high gas fraction) and "low-quality" foam regimes. The method is essentially the same for the foam model parameters in foam models in STARS, UTCHEM or ECLIPSE. Often, however, available data are more limited - pressure gradient for one scan of foam quality at fixed total superficial velocity. We show how to extend this method to the more limited data set. The transition in regimes occurs at the foam quality with the maximum pressure gradient. We illustrate the method by fitting parameters to several published data sets. Our approach is simple and direct. The model fit would be appropriate for an EOR process involving foam injection at finite water fraction, but not a SAG foam process involving large slugs of gas and liquid. For the latter process, model parameters should be fit to data relevant to that process, i.e. at extremely high foam quality. The approach assumes an abrupt transition between high- and low-quality foam regimes, i.e. a large value of epdry in the STARS foam model. If a smaller value is chosen for faster execution of the simulator this approach could underestimate pressure gradient near its maximum value at the transition between regimes. In that case the parameter values quickly obtained by this method could provide the initial guess for a computer-based least-squares fit of all parameters, including a smaller value of epdry, and a check on the parameters so obtained.
-
-
-
Multi-scale Pore-network Modelling of WAG in Carbonates
Authors C. Maier, Z. Jiang, A. Al-Dhahli, M.I.J. van Dijke, S. Geiger, G.D. Couples and J. MaCarbonate reservoirs have textural heterogeneities at all length-scales (triple porosity: pore-vug-fracture) and tend to be mixed- to oil-wet. The choice of an enhanced oil recovery process and the prediction of oil recovery require a sound understanding of the fundamental controls on fluid flow in mixed- to oil-wet carbonate rocks, as well as physically robust flow functions, i.e. relative permeability and capillary pressure functions. Obtaining these flow functions is a challenging task, especially when three fluid phases coexist, such as during water-alternating-gas injection (WAG). We have recently developed a method for integration of pore-networks derived from micro CT images at different length-scales, thus capturing pore structures from different types of porosity. The network integration method honours the connectivity between different pore types, including micro-fractures, and their spatial distribution. In this work, we use these multi-scale networks as input for our three-phase flow pore-network model, which comprises a novel thermodynamic criterion for formation and collapse of oil layers that strongly depends on the fluid spreading behaviour and the rock wettability. The criterion affects in particular the oil relative permeability at low oil saturations and the accurate prediction of residual oil saturations. We generate three-phase flow functions for gas injection and WAG from networks with carbonate pore geometries and connectivities and we demonstrate the impact on residual saturations of the different types of porosity and the interaction with different realistic wettability scenarios. We also show that the network generated three-phase flow relative permeabilities are distinctly different from traditional models, such as Stone’s. The flow functions will be used in a heterogeneous carbonate reservoir model and to demonstrate their impact on the sweep efficiency.
-
-
-
Modeling of Foam Flow Using Stochastic Bubble Population Model and Experimental Validation
More LessThe transient foam flow, forward movement of foam front until breakthrough in a one dimensional flow, in an oil-free porous medium was studied using the stochastic bubble population (SBP) model. The premise of this model is that foam flow in porous media is a complex fluid and bubble generation is a stochastic process. The SBP foam model describes the net bubble generation using three parameters: maximum bubble density and bubble generation and destruction coefficients. The corresponding governing equations, a system of non-linear partial differential equations in the saturation, pressure and bubble density, were solved using the IMPES method. The sensitivity to the main physical parameters was also analyzed. It was found that increase of the maximum bubble density leads to generation of stronger foam, characterized by a slower foam propagation rate and a larger foam mobility reduction. The bubble generation coefficient Kg mainly controlled the foam generation rate such that a higher Kg led to a more rapidly increasing bubble density. We also provided a comparison between the numerically obtained saturation and pressure data with those obtained from the experiments at which foam was generated by co-injecting nitrogen and C14-16 alpha olefin sulfonate surfactant in Bentheimer sandstone. X-ray CT scans were also obtained to visualize the foam displacement process and to determine fluid saturation at different times. A good match was obtained between the numerical and the experimental data which confirms that the SBP foam model is robust and reproduces the main features of the transient behavior of foam flow in a homogeneous porous media.
-
-
-
Pore Scale Modelling of Polymer Flow
Authors N. Zamani, R. Kaufmann, T. Skauge and A. SkaugePolymer flooding as an EOR method that has boomed in the last decade as oil prices have been rising, and new and larger polymer flood projects are being realized. Some milestones and examples are the large-scale viscoelastic polymer flood implementation at the Daqing field in China, polymer injection in Marmul field, Oman, and the Dalia offshore polymer project. Polymer flood is a mature EOR technology, but as the reservoir targets get more diverse and the field conditions harsher, the current understanding of polymer flood is stretched to its limits. In order to explain viscous fingering in inter-mediate to heavy oil reservoirs and viscoelastic mobilization of residual oil there is a need for a better understanding of polymer flow mechanisms on the pore scale. Pore scale polymer flow characterization is very complex and involves several flow phenomena like; adsorption, viscous fingering, depleted layers, hydrodynamic retention, bridging/flow-induced adsorption, viscoelastic effects, in-accessible pore volume and more. In this study we have developed a Navier-Stokes model to analyse polymer flow and to compare against Newtonian fluids. The aim has been to identify the key parameters for polymer displacement. Examples of obtained results are that the depletion layer plays a major role in study of rheological properties. Increased depleted layer thickness lead to lower velocity at the centre of the pore and more slip effect near the pore wall. When a higher degree of shear thickening is included a larger drag on fluids in side channels will occur, this is consistent with oil mobilisation and lowering of residual oil saturation.
-
-
-
Osmosis During Low Salinity Water Flooding
Authors K. Sandengen and O.J. ArntzenSeveral research groups have shown that injection of low saline water may yield an Enhanced Oil Recovery (EOR). The mechanisms underlying this “low salinity effect” are, however, still unclear. We believe that osmosis has been overlooked as a possible mechanism for the observed EOR effect. Osmosis is bound to occur in an oil/water/rock system when injecting low salinity water as the system is full of an excellent semi-permeable membrane, namely the oil itself. Hence we believe that this topic deserves more attention. In the present work oil droplets were observed to move under the influence of an osmotic gradient in a simple visualization experiment. The experimental setup consisted of two oil droplets in a ~1 mm diameter glass tube with salt water between them and distilled water on the outside. For a porous rock medium it is proposed that such osmotic gradients relocate oil by expanding an otherwise inaccessible aqueous phase.
-
-
-
The Impact of Common Reservoir Minerals and Temperature on the Low Salinity EOR-effect in Sandstone
Authors S. Strand, T. Austad, T. Puntervold, H. Aksulu, B. Haaland, K. Navratil, S. Storås and D. HåmsøThe mechanism of the low salinity EOR process in Sandstone reservoirs has been debated in the literature for more than a decade. We recently proposed a chemical wettability alteration mechanism for the process, well founded in experimental observations. Even though this main chemical understanding is quite well described, there are parameters/factors that could disturb the main process. Combinations of certain minerals, temperature, and salinity/composition of formation water could have impact on the low salinity EOR process. Plagioclase, a polysilicate mineral, is often present in sandstone reservoir rocks, and could have a significant effect on the initial pH of the formation water, which will influence the initial wetting conditions. In this experimental work it is shown that Plagioclase in reservoir rock and outcrop material responded differently on the low salinity effect. It is also verified that enhanced dissolution of anhydrite, CaSO4, in the low saline fluid suppressed the increase in pH, which is an important parameter for observing tertiary low salinity effects. A combination of high reservoir temperature, Tres>100 oC and very high salinity of the formation water, >200 000 ppm, resulted in too water wet conditions for observing tertiary low salinity EOR effects, even though the clay content was high, ≈20 wt%. The experimental results are in line and discussed in relation to the previously published chemical mechanism for the low salinity EOR process.
-
-
-
The Use of Polymer Injectivity Data for the Estimation of Porous Media Longitudinal Dispersion
By A.M. AlSofiCurrent dispersion estimation techniques rely on the measurement of a tracer concentration smearing either in-situ or at the outlet. We propose a much easier technique that does not require measuring concentrations. The technique involves the injection of a pure phase followed by the same phase saturated with a non-linear viscosifying agent (or vice versa). This transition in the viscosity of the injected phase will result in a pressure transition. Theoretically, without dispersion, the pressure transition is directly linear with respect to time. However, with dispersion and due to the non-linearity of the viscosity-concentration dependence this transition will further spread. Analyzing this additional smearing and delay of the pressure response would give a direct measure of dispersion. Adsorption of the viscosifying agent also can cause a similar effect where the pressure propagation is delayed. Nevertheless, we could decouple those effects. The proposed procedure of measuring pressures during a viscosity switch is already done in the industry. In the context of polymer flooding, injectivity tests are used to give indication of potential injectivity issues and, explicitly, provide estimates of the polymer solution resistance and residual resistance. Therefore, we can further use injectivity data to estimate water dispersion and polymer adsorption. Injectivity data measured for a polyacrylamide polymer in a limestone core was used to test the method. Our pressure analysis suggest the aqueous phase exhibits a longitudinal dispersivity of 0.02 ft while, at 0.2 wt. %, 10% of the polymer concentration is adsorbed. Both results fall within the ranges reported in the literature. Additional simulation sensitivity results were performed using UT-Chem. The results support the presented theory. The proposed method is simple and could prove helpful in eliminating experimental redundancy and in simplifying dispersion estimation.
-
-
-
Low Salinity Water Flooding: Retention of Polar Oil Components in Sandstone Reservoirs
Authors I.F. Fjelde, A.P. Polanska, F.T. Taghiyev and S.M.A. AsenInjection of low salinity water has been reported in the literature to improve oil recovery in some sandstone reservoirs, but some disappointing results have also been reported for other reservoirs. Different low salinity water flooding (LSWF) mechanisms have been proposed, but no mechanism has been widely accepted. These mechanisms are therefore still discussed. Understanding how the brine and oil components interact with the minerals in the reservoir rocks is necessary to establish more knowledge about the LSWF mechanisms. In the presented study the objective has been to investigate the retention of polar crude oil components onto minerals and reservoir rock (with high clay content) in equilibrium with brines of different salinities/compositions. The interactions between minerals/reservoir rock, oil and brine were then studied in both static and dynamic experiments. These results have been compared with results from core flooding studies carried out to study the effect of different brine compositions on the oil recovery in the same reservoir rock. The experiments have demonstrated that change of injection brine from high to low salinity/composition can significantly change the retention of polar oil components onto minerals and reservoir rocks. When the injection brine is changed, the amounts of divalent cations onto clay surfaces can depending on the compositions of these brines either increase or decrease. The wettability conditions of the rock can therefore either be altered to less water-wet or more water-wet. The results from the study of retention of polar crude oil components were in accordance with flow characteristics in the core flooding studies carried out in the same reservoir rock. It is concluded that the first evaluation of the potential for low salinity water flooding for improving oil recovery can be carried out by measuring the difference in retention of polar crude oil components for the high and low salinity brine compositions. The potential for different possible low salinity water compositions can also be evaluated by measuring the retention of oil components in the presence of these brines.
-
-
-
Foam for Mobility Control in EOR - a Microfluidic Approach
Authors N. Pannacci, M. Ryba, Y. Peysson, B. Herzhaft and J.F. ArgillierFoam injection is one of the processes that may be used for enhanced oil recovery, in particular for gas mobility control. The work we present is focussed on understanding foam formation and foam flow at small scale in very simple model geometries. To this purpose, a microfluidic device is used to accurately control diphasic flows confined at 10 to 100 micrometer scale. The microfluidic device is made of polydimethylsiloxane (PDMS), a transparent elastomer allowing simple and fast prototyping and easy observation of flows with optical microscopy. The experimental method is based on a microsystem that first permits formation of a dispersion of very monodisperse gas bubbles in water and surfactant at a flow-focusing geometry. The flow and the behaviour of the bubbles downstream is as well observed and measured in the model geometries including chamber, channels, etc. Complete phase diagram of the foam formed is shown, from very wet to very dry (small or high gas volume fraction) and with small or large bubbles according to pressures applied of both the gas and the aqueous phase. Image analysis is used to characterize the foam structure (quality, bubble size, bubble monodispersity). A simple analysis is done to give a criterion for the foam to be formed according to geometry, surface tension and pressures applied to the fluids. First results show that in a geometry modelling two permeabilities with simple large and small channels, fluid flow may be redirected from high permeabilities areas to small permeabilities ones. Even if obtained without any oil, this observation may be compared to what happen to foam flows in fractured rocks and may explain part of the complex phenomena involved for increase oil recovery. To conclude, microfluidic tool appears as an interesting technique to characterize the behaviour of foam at the micrometric scale.
-
-
-
Interfacial Tension and Contact Angle Determination in Water-sandstone Systems with Injection of Flue Gas and CO2
Authors N. Shojai Kaveh, E.S.J. Rudolph, W.R. Rossen, P. van Hemert and K.H. WolfCarbon capture and storage (CCS) has the potential for reducing CO2 emissions to the atmosphere. This option includes storage strategies such as CO2 injection into deep saline aquifers, depleted oil and gas reservoirs, and unmineable coal seams. This process is largely controlled by the interactions between CO2, the reservoir fluid and reservoir rock. In particular, the wettability of the rock matrix has a strong effect on the distribution of the injected CO2 into geological formations. In this study, the wetting behavior of Bentheimer sandstone slabs and CO2 and/or flue gas is investigated by means of contact-angle measurements. In addition, the interfacial tension between CO2 and/or flue gas and connate water was determined. The experiments were conducted in a pendant-drop cell, adapted to allow captive-bubble contact-angle measurements and performed at a constant temperature of 318 K and pressures varying between 0.2 and 15 MPa, typical in-situ conditions. The experimental contact angle measurements show that the Bentheimer sandstone/water system is (and remains) water-wet even at high pressures with CO2 and/or flue gas injection. The determined data of the contact angle of the water–sandstone system demonstrate a strong dependence on the bubble size and surface roughness with CO2 and flue gas injection.
-
-
-
New Method of Active Electromagnetic Induction and Seismic Monitoring in Oilsaturated Media
Authors O.A. Hachay, O.Y. Khachay and A.Y. Khachayor equal observation periods changing by the method of phase diagram state of many phase medium in the oil layer is developed. The developed method allows on quality level to classify the state of the polyphase medium, which is the oil layer, using data of many cycles influence. In that paper we suggest the algorithm of modeling of 2-d seismic field distribution in the heterogeneous medium with hierarchic inclusions. Using the developed earlier 3-d method of induction electromagnetic frequency geometric monitoring we showed the opportunity of defining of physical and structural features of hierarchic oil layer structure and estimating of water saturating by crack inclusions. That allows managing the process of drainage and steeping by water displacement the oil out of the layer. Reference 1.Geosciences: Making the most of the Earth’s resources. S-Petersburg 2 - 5 April 2012 Field Development & EOR C024 Reflection of No Equilibrium Two Phase Processes of Filtration in Heterogeneous Media in the Active Seism Acoustic Borehole Monitoring Data O.A. Hachay* (Institute of Geophysics UB RAS), V.V. Dryagin (Institute of Geophysics UB RAS), G.V. Igolkina (Institute of Geophysics UB RAS) & O.Y. Khachay (Ural Federal University)
-
-
-
Pore-scale to Core-scale Aspects of Capillary Desaturation Curves Using CT-scan Imaging
Authors R. Oughanem, S. Youssef, B. Bazin, E. Maire and O. VizikaSurfactant flooding is one of the effective technologies to enhance oil recovery of water flooded petroleum reservoirs. Several previous studies have demonstrated that the release of oil from a rock submitted to waterflood depends on the competition between displacing forces (viscous and buoyancy) and capillary forces. This competition is expressed by two dimensionless numbers, the Capillary number, defined as the ratio of viscous to capillary forces and the Bond number, defined as the ratio of gravity to capillary forces. At the core scale the evolution of the oil residual saturation as function of the capillary number is better known as the Capillary Desaturation Curve (CDC), which constitutes an important input parameter in EOR processes reservoir simulation. In this work we present a new experimental workflow to investigate the effect of rock structure on the CDC. This workflow combines core flood experiments and CT-scan imaging to accurately measure the mean residual oil saturation at different capillary number values as well as the local saturation distribution along the core plug. The CDC was measured on a set of water-wet sandstone with different permeability and degree of heterogeneity. The capillary number was varied by injecting a surfactant solution at different flow rates. Using this methodology, we first study the effect of core flood orientation (Horizontal injection and vertical downflow injection). The resulting local saturation curves show that in a horizontal configuration the oil migrates upwards in the sample inducing an oriented front strongly deviating from the piston like displacement, and very different from the one observed in the vertically placed sample. This behaviour is manly attributed to buoyancy forces that are no more negligible compared to capillary forces when surfactant is injected. This experiment shows that when measuring a CDC the capillary number needs to be corrected to take into account the buoyancy forces. In a second step we have investigated the effect of local heterogeneity of core plugs on the CDC with Clashach and Fontainebleau sandstones. Two samples of Clashash sandstone with equivalent mean properties were studied (mean permeability of 380 and 426 md and mean porosity of 13.4 % and 14.1% respectively). The resulting CDC curve exhibits almost two decades difference in the critical capillary number. This discrepancy is explained in terms of the local variation of the porosity that induces important differences in the local saturation profile.
-
-
-
Micromechanical Analysis of Relative Permeability Hysteresis
Authors A.M. Galechyan and V.V. KadetThis paper represents the model of relative permeability hysteresis in drainage and imbibition with help of percolation theory. The following processes are considered. First of all the hydrophilic core is totally saturated by water. Oil displaces water under the pressure gradient – this process is called drainage. During this process oil firstly goes to large pores, because they have small hydrodynamic resistance and small capillary pressure. After the core is maximally saturated by oil the displacing of this oil by water begins under the pressure gradient. This process is called imbibition. During drainage oil changes the surface properties of some part of capillaries through which it passed. The cause of it is formation of thin hydrocarbon film during drainage. So one part of capillaries (ӕ) has unchanged hydrophilic surface properties, and the other part (1-ӕ) has changed surface properties, which can become both hydrophobic and hydrophilic with another angel of contact (θ1 and θ2 – angles of contact before and after oil pass through, α=cosθ1/cosθ2). Different variants of ӕ and α are considered in this paper. The cubic lattice of capillaries is taken for the basic model of porous media which has lognormal density of radius distribution function. The received results of relative permeability calculations for drainage and imbibition demonstrate the availability of hysteresis. The closest to experiment results are for ӕ=0.75 and α=-1. This shows that in proposed model after drainage oil changed surface properties from hydrophobic to hydrophilic in 25% of capillaries that is 1/3 of capillaries, trough which oil passed. Represented model is rather universal and allows taking into consideration different mechanisms of changing the surface properties of porous media. The best accordance with represented experiment is achieved by choosing the hydrophobisation of porous media during drainage as the main mechanism. Comparing with the experiment allows to find the right ӕ and α. This method can be used instead long and difficult experiments for plotting the relative permeability. It’s necessary to use the mineral structure data and the experimental density of radius distribution function in the calculating algorithm of represented model and the relative permeability will be plotted.
-
-
-
Visualization of Pore-level Displacement Mechanisms During CO2 Injection and EOR Processes
Authors J. Gauteplass, H.N. Follesø, A. Graue, A.R. Kovscek and M.A. FernøMultiphase flow and fluid displacements at pore-level were visualized in two-dimensional micromodels retaining essential characteristics of porous rocks. Microvisual data during CO2 injection for enhanced oil recovery was obtained from high resolution images using UV-sensitive dye to improve contrast. The dominating mechanisms were piston-like displacement of one fluid by another, either by a stable moving interface or through Haines-like jumps. Film thickening, film drainage, snap-off mechanisms and capillary trapping of CO2 were also observed. Both stable and unstable flow regimes were identified as the front advanced through the network during two-phase flow. In the latter regime, instabilities in the displacements were manifested by capillary fingering perpendicular to the main flow direction. Oil was found to be spreading in the water-oil-gas system at the experimental conditions. This led to an efficient oil production at pore-level from CO2 gas injection, even at high water saturation. The injected gaseous CO2 contacted only oil in three-phase systems, and led to direct oil displacement, whereas water was displaced through double or multiple displacement events.
-
-
-
Polymer Flooding - Designing of a Pilot Test for Unusually High Salinity and Hardness Reservoir
Reservoir conformance problems render uneven the flow of the injected water making waterflooding inefficient due to poor mobility control. This paper describes a systematic approach taken for the designing of a polymer flooding pilot test for a reservoir with challenging characteristics such as unusually high salinity and hardness that complicate the selection of the candidate polymer. This work includes a description of the characterization of a pre-selected candidate polymer, its rheological evaluation, its adsorption performance onto porous media, and its mechanical stability. Together with rheological properties, emphasis is given to the evaluation of flow performance of the polymer onto porous media at reservoir conditions. The experimental results indicate that the selected polymer (acrylamide/ATBS/acrylic acid ter-polymer) shows proper performance especially in terms of tolerance to reservoir salinity, hardness and high temperature. Numerical simulation studies demonstrate that polymer flooding at the selected zone could render a favourable incremental oil recovery (16%) over waterflooding.
-
-
-
Impact of Polymer Mechanical Degradation on Shear and Extensional Viscosities
Authors D. Rousseau, I. Henaut, A. Dupas, P. Poulain, R. Tabary, J.F. Argillier and T. AubryField data from polymer flooding operations sometimes indicate a better-than-expected polymer injectivity below fracturing pressure. Current interpretations for this unexpected phenomenon are based either on geomechanical considerations (for unconsolidated sand formations) or on polymer mechanical degradation, potentially occurring in the injection facilities and the near wellbore area. In this paper, a new approach of polymer injectivity is suggested. It is based on the study of polymer mechanical degradation with respect to both shear and extensional viscosities. In the first part of this work, we have investigated the onset of mechanical degradation by submitting semi-dilute solutions of high molecular weight partially hydrolyzed polyacrylamide (HPAM) to extensional laminar flow created by an API capillary system. We have then measured both shear and extensional viscosity of the native and the degraded HPAM solutions. We consider the onset of mechanical degradation to be reached when shear viscosity loss is equal to 10%. At low degradation extensional rate, extensional viscosity decreases to the same extent as shear viscosity (10%), whereas, at high degradation extensional rates, the decrease reaches up to 60%. This means that degraded HPAM with weakly affected shear viscosity can develop much less resistance to extensional flow. In the second part, we have explored the influence of mechanical degradation on injectivity by determining resistance factors of native and degraded HPAM solutions. Solutions have been injected in reproducible unconsolidated sand packs. At low velocities, resistance factors were similar for both kind of solutions, as expected from their comparable shear viscosities. However, at high velocities, namely where flow in porous media implies high extensional deformations in the vicinities of the pore throats, rheo-thickening was much less marked for solutions degraded at high extensional rate. These results allow understanding why polymers which do not seem to be mechanically degraded according to their shear viscosity can show a very good injectivity, thanks to the reduction of extensional resistance in porous media. They could also lead to establish guidelines for designing new polymer pre-treatment methods aimed at improving injectivity while retaining the mobility control ability of polymers.
-
-
-
Application of Quantitative Structure-property Relationship (QSPR) Method for Chemical EOR
Authors F. Oukhemanou, A. Maldonado, P. Moreau and B. CretonThe selection of high performance surfactants for chemical EOR is a challenging and time consuming task. A surfactant formulation, typically a blend of at least two surfactants must be developed for each case study. A tool to pre-select suitable surfactants would thus be highly valuable. In this paper, we describe the development of a quantitative structure-property relationship applied to the selection of surfactants for chemical enhanced oil recovery. A correlation is drawn between surfactant structures and optimal salinities, i.e. the salinity which corresponds to a minimum in interfacial tension. A comprehensive and coherent database has been generated using a high-throughput screening robotic platform and industrial products belonging to different families of surfactants: olefin sulfonates, alkyl ether sulfates and alkyl glyceryl ether sulfonates. This database has been built for specific reference conditions (temperature, oil, brine hardness). Industrial surfactants, most often constituted of a variety of molecules, have been carefully analyzed in order to identify predominant species. The structures of these compounds have then been drawn using molecular design tools, and molecular descriptors were generated for the whole set of amphiphiles. Finally, various statistical approaches have been used to develop multi-linear regressions correlating combinations of the most relevant molecular descriptors with the experimentally determined optimal salinity of surfactant mixtures. Our results indicate that a strong correlation exists between the surfactant structure and its optimal salinity. A limited set of descriptors can be used to predict this critical property with predictive models. These models can then be used to select promising existing products as well as to identify candidate raw materials or products for industrial surfactants development. We also demonstrate the ability of our models to predict optimal salinity of surfactant blends typically used in chemical EOR. Future developments will be focused on extrapolation of these models to the prediction of other application properties for chemical EOR (e.g. interfacial tension value) and to broaden the application domain to a wide range of conditions (temperature, brine composition, type of oil).
-
-
-
Surfactant Flooding Evaluation for Enhanced Oil Recovery in Sandstones Reservoirs
Authors F.C. Bonilla and R.B.Z.L. MorenoThis research work considered surfactants for chemical oil recovery applications. Surfactant flooding is an EOR technique applied for decreasing capillary effects by molecular performance alterations on water-oil interface between injected water and displaced oil. In most situations, this method is implemented as a tertiary flood near of the end of waterflooding but it could be conducted after the initial stage of field production when oil saturations are high in the porous media. By an injector well, required volumes are introduced to the reservoir with the defined surfactant formulations for developing a new stabilized oil bank via ultralow interfacial tension between oil and water phases. The experimental methodology included Phase Behavior and Coreflooding tests for making comparative analyses between oil production responses of different configurations of surfactant flooding method. The phase behavior tests were conducted to select the best surfactant formulations through interfacial tensions and solubilization ratios determinations of different concentrations of five commercial surfactants: three anionic surfactants (Stepanol, sodium dodecyl sulfate and ammonium dodecyl sulfate) and two no-ionic surfactants (SPAN-20 and TWEN-20). Previously, it was performed surface tensions measurements to identify the critical micellar concentration (CMC), characteristic of each surfactant. The selected primary surfactant and co-surfactant formulations were tested for enhanced oil recovery using coreflood tests on high permeability sandstones from Bocatutu Formation. In these tests, the primary formulation solutions were followed by polymeric drive solutions injection. The tested formulations were also tested for porous media adsorption, evaluating surfactant losses during a surfactant flooding. The results are useful for running numerical simulation cases and single well field projects.
-
-
-
Experimental Investigations into the Effect of Heterogeneities on the Recovery of Heavy Oil by VAPEX
Authors A.H. Muggeridge, M. Al-Hadhrami and A. AlkindiVapour extraction (VAPEX) of heavy oil is a low energy alternative to Steam Assisted Gravity Drainage (SAGD). Nearly miscible vapour is injected into the formation instead of steam. It dissolves in the heavy oil, reducing its viscosity. The diluted oil is then produced via gravity drainage (in the same way that heated oil drains during SAGD). Although there are many reported numerical and experimental studies into VAPEX, very few have investigated the impact of heterogeneities on this process. None have compared the predictions of simulation with experiment. We report a series of laboratory studies into the effect of layering and discontinuous shales on oil rate and recovery from VAPEX. These were performed in well characterized glass bead packs using glycerol and ethanol as analogues of oil and solvent respectively. The permeability, porosity and fluid properties (including diffusion and dispersion) were measured independently. Numerical predictions of the experiments were performed, using these data as input, to determine whether conventional reservoir simulation can capture the flow processes observed in the experiments. We found that the observed oil drainage rates from the layered packs were between the rates observed in homogeneous packs formed of the lowest permeability beads (lower bound) and the highest permeability beads (upper bound). The numerical simulations tended to underpredict oil drainage rate although they correctly predicted the pattern of solvent and oil distribution seen in the experiments. The performance of the layered system could be predicted by a homogeneous system using the arithmetic average of the layer permeabilities. A single discontinuous shale had little impact on recovery unless it was directly between the injection and production wells or its length approached that of the reservoir. These results suggest that these types of heterogeneity have little impact on VAPEX performance except through their influence on effective permeability of the reservoir.
-
-
-
Secondary Polymer Flooding in Extra-heavy Oil - Core Experiments under Reservoir Conditions and Core Scale Simulation
More LessIn this work we present the results obtained from a coreflood experiment with polymer injection in secondary mode for extra heavy oil at 5500 cP viscosity. The work was carried out on a 30 cm length reconstituted core composed from cleaned reservoir sand. The core was packed using an in-house developed method, and then saturated with live oil partially degassed in PVT cell from initial reservoir conditions down to expected pressure at start of a field test (Pres). Saturation profiles were accurately measured by means of X-Ray scans on the core, enabling the visualization of flow instability development (viscous fingering). Effluents were collected in carbon cells under reservoir conditions with X-Ray production level measurements. The effluents were then flashed to atmospheric conditions, collected in test tubes and re-measured by X-Ray and UV measurements. The polymer flood carried out in secondary mode showed excellent results with a recovery of around 60% after 1.8 PV of polymer injected at 1 cc/h, even though viscosity ratio was highly unfavourable. The estimated apparent viscosity of the polymer was 60 cP at 7 s-1, corresponding to the frontal advancement rate achieved during the coreflood. This recovery is in the same order as that obtained in tertiary mode after water flood in outcrop cores ([9], [12]).
-
-
-
Selection of the EOR Methods for the Russkoe High-viscosity Oil Field Based on Laboratory and Field Experiments
Authors I. Edelman, A. Shandrygin, E. Severinov, L. Gaidukov and D. DubrovskiyThe paper presents an approach and the results of laboratory tests of the EOR methods on core samples of Russkoe gas and oil field, and the results of pilot works to the implementation of the recommended method. The field is unique in terms of both its huge hydrocarbon reserves and problems associated with its development. It is located above the Polar Circle and is characterized with a complex geological structure of highly permeable poorly cemented reservoirs saturated with high-viscosity oil. Significant factors making field development difficult include presence of tectonic faults, extensive gas cap, and underlying water. At the first stage of the research the following main EOR methods have been analyzed: injection of hot water, steam injection, injection of polymer solutions and thermo-alkali flooding. Experimental studies have been conducted on natural cores and bulk models. The complexity of the preparation and conduct of experiments was attributed to work with weakly consolidated core. At the initial stage of the pilot project one of the most effective methods, which performance has been proven by both experiments and simulations, has been recommended for implementation, - the displacement of viscous oil with hot water. Test injection of hot water in one of the pilot areas commenced in August 2010 and, in general, confirms the effectiveness of oil displacement observed in laboratory experiments. The results of field tests of EOR methods in the Russkoe field by injecting hot water are described in detail in the report. In the next stage of the pilot project, which is aimed at finding appropriate technologies for the development of this extremely complicated field, the continuation of laboratory testing of the EOR methods is planned using new core samples. Along with this, further laboratory testing of WAG and surfactants applicability is envisaged. To achieve this objective, a special program of laboratory and analytical studies is planned.
-
-
-
Performance of Associative Polymers in Porous Media
Authors A. Thomas, N. Gaillard, C. Favero, J. Bai, K. Green and F. WassmuthThe propagation of associative HPAM polymers in porous media is greatly dependent on the degree of hydrophobic modification. In this paper, the transport properties of several associative polymers with degree of association from none to high were investigated in Berea cores and silica sand-pack cores. The associative polymer solutions with customary bulk viscosities generated resistance factors that varied significantly, ranging from 10 to over 500. The increasing resistance factors were attributed to the higher level of polymer retention as the degree of association increased. On the other hand, two associative polymers, with a similar degree of association but different molecular weight and bulk viscosities generated similar resistance factors. Hence the effect of molecular weight and bulk viscosity is not as significant as hydrophobic modification in generating in-situ flow resistance. Linear coreflood tests were conducted to evaluate the potential of associative polymer flooding in recovering western Canadian heavy oil with viscosity of 18,700 mPa.s in 3-Darcy sandpacks. The properly selected associative polymer was able to propagate through the sandpack with no significant retention and generate in-situ apparent viscosity twice as high as the unmodified HPAM.
-
-
-
EOR Technologies for Permocarbonic Deposit of High-viscosity Oil in Usinskoye Oil Field - Experience and Prospect
Authors V.A. Kuvshinov, L.K. Altunina, A.A. Alabushin and S.O. UrsegovPresented are the results of laboratory research and field tests of physicochemical technologies intended to improve oil recovery of high-viscosity oil deposits developed by steam injection. To increase the efficiency of thermal-steam and cyclic-steam stimulations we proposed to combine them with physicochemical methods using thermotropic gel-forming and oil-displacing systems: the gels increase reservoir coverage by steam injection and oil-displacing systems, which at thermal stimulation generate СО2 and alkaline buffer solution, promote decrease in oil viscosity and additional oil displacement. In 2007-2011 154 wells located on Permocarbonic deposit in Usinskoye oilfield were stimulated using IPC SB RAS IOR technologies. Daily increase in oil production rate ranged from 3 to 24 tons per well and additional oil production amounted to more than 2000 thousand tons. A complex technology of alternating injections of steam, thermotropic gel-forming and surfactant-based oil-displacing systems was shown to be promising to provide increased reservoir coverage with steam injection and oil after-washing.
-
-
-
Polymer Flood Design for Displacement of Heavy Oil Analysed by 2D-imaging
Authors A. Skauge, P.A. Ormehaug, B.F. Vik, C. Fabbri, I. Bondino and G. HamonWaterflooding and polymer assisted waterflood in heavy oil reservoirs has recently gathered great attention. Enhanced water injection schemes represent an alternative in cases where thermal methods are either impractical or uneconomic. This study describes the frontal displacement and analyses the oil mobilization by use of 2D X-ray imaging. This study has investigated viscous instabilities, mechanisms for finger growth and water channeling at adverse mobility ratio during waterflood. Experiments have been made on Bentheimer sandstone slabs (30cm x 30cm x 2,5 cm) studying waterflooding and tertiary polymer injection in extra heavy oils (2000cp). The sandstone represents a relatively homogeneous and high permeability porous medium. The experiments utilize gamma and X-ray source for porosity and saturation measurements, and an X-ray imaging system to visualize displacements and thereby quantify the underlying flow mechanisms and oil recovery. The rock material was aged with crude oil to shift wettability and dampen the capillarity. The development of viscous fingers was detailed recorded by 2D X-ray imaging. This paper focuses on polymer slug design. The polymer slug will be influenced by polymer adsorption, inaccessible pore volume, dispersive mixing, and also chase water fingering into the polymer slug. The polymer slug mixing is studied using 2-D imaging by tagging each injected phase. Special focus has been on chase water mixing into the polymer slug. The oil recovery the waterflood was 39% OOIP, but more important a quick increase in oil cut was obtained by polymer injection. The oil recovery after polymer flooding reached final recoveries of more than 70% of OOIP.
-
-
-
Toe-to-Heel Air Injection - Effect of Oil Layer Thickness
Authors M. Greaves, L.L. Dong and S.P. RigbyA simulation study of a full-section of the first THAI field pilot, conducted in the Athabasca Oil Sands of Alberta, Canada, has investigated the effect of different oil layer thicknesses:; namely,8, 25 and 40 metres. The physical model description was an idealised representation of the WHITESANDS Conklin field pilot, having an homogeneous oil layer and no bottom water, or interbedded shale features. For a 6-year operating period, the oil production showed an increasing trend with increasing oil layer thickness, up to 80 m3/day. However, for the 8 m thick reservoir, the oil production profile showed a continuous decline, with oxygen breakthrough occurring after 1350 days. A significant Steam Zone developed in all three cases, advancing fastest in the 8 m thick oil layer. This latter case was accompanied by an increase of gas channelling, in the direction of the production well end of the reservoir. Peak combustion temperatures were highest for the 25 m oil layer, and lowest for the 8 m thick case.
-
-
-
Uncertainty Analyses for Thermal Development in Heavy Oil Fields
Authors R. Sabatino, I. Maffeis, F.M. Contento, A. Tegami and M. De SimoniThe main purpose of this work is to get an insight into thermal development strategies to be applied in an extra-heavy oil field. The goals of this study are: to study the feasibility of thermal EOR techniques; to perform a risk analysis highlighting the main uncertainties on reservoir development. Firstly, a general overview of the field is given. Steamflooding has been thoroughly investigated, by optimizing operating parameters and evaluating their effect on oil recovery and steam-oil-ratio (SOR). Similar sensitivity analyses have been performed for the down-hole electrical heating technique, focusing particularly on power input, and evaluating the propagation of heat in the reservoir. Risk analyses have been then performed in order to highlight the main uncertainties affecting the field development, in cold production as well as in steamflooding and electrical heating. Risk analysis was carried out by applying both the classic Monte Carlo workflow and the Experimental Design and Response Surface Modelling. This methodology becomes advisable when simulation runtime is excessive and a classic Monte Carlo workflow is too expensive. The last part of the paper covers basic pseudo-economic analysis to assist in the comparison between cost-benefits of steamflooding and electrical heating. The main outcomes of this work are the following: steamflooding proved to be an effective way to improve oil recovery, although for pessimistic scenarios (i.e. very high viscosity) its convenience should be properly evaluated; electrical heating can cheaply provide additional oil recovery. The performed analysis has highlighted the risk and the opportunities of the two thermal recovery techniques.
-
-
-
Detrimental Effect of Capillary Forces in Extreme Low Permeable Unconventional Gas Reservoirs
Authors I.J. Lakatos, T. Bódi, J. Lakatos-Szabó and G. SzentesIn the 21st century the global gas demand will be met only by extensive production and utilization of unconventional gases. Unfortunately, these kind usually have extremely low permeability, small average pore sizes and strongly, often absolute water-wet surface character. As a result, the residual water saturation and the critical capillary pressure needed to mobilize water from natural porous systems might also be unexpectedly high. Therefore, a detailed laboratory studies have been carried out with the aim at determining the detrimental effects of pore structure, wettability, capillary and imbibition forces in reservoirs having D permeability. Using natural cores, the capillary pressure was calculated as a function of pore size distribution and wettability. Spontaneous imbibition tests were carried out to demonstrate the effect of aqueous and organic fluids. Based on experimental results, it was found that extremely high threshold pressure, sometimes several hundred bars, was needed to start water drainage from natural cores. Consequently, due to the unusual capillary forces, the water proved to be a natural blocking phase in such systems, and hence, the water may cause serious formation damaging hard to cure when the reservoirs is or were ever contacted with water. As a result, the operators definitely face with difficulties when water-based fluids are used in drilling, well completion, fracturing, and production technologies. Therefore, the physico-chemical considerations suggest that application of water-free fluids should be used in any phases of field operations. In addition, the presence of water in tight sand gas and BCGA reservoirs has detrimental effect on gas transport. Since the mass transport is usually diffusion, non-Darcy flow characterizes the gas rate, viz. the driving force of gas production should be treated with weaponry of physico-chemical approach and thermodynamic calculations. Thus, new paradigms and theoretical approach are necessary in the future, and further fundamental and applied research seems to be indispensable to develop novel technologies for gas recovery from unconventional gas reservoirs including tight sand, shale and BCGA formations.
-
-
-
Comparison of Heating Methods for In-situ Oil Shale Extraction
Authors K.G. Hazra, K.J. Lee, C.E. Economides and G. MoridisOil shales are lamellar, non-porous, impermeable hydrocarbon bearing rocks that contain organic matter called kerogen which, when heated at pyrolysis temperature of approximately 650-700 oF, thermo-chemically decomposes to liberate hydrocarbons. They are at the base of the resource triangle because cutting edge technology and higher fuel prices are required to economically produce them. Technologies for oil shale production include surface and in-situ retorting. This study focusses on in-situ oil shale production methodologies. The process of heating oil shale to the pyrolysis temperature can be achieved by direct or indirect heating. Direct heating geometries include the Shell in-situ conversion process (ICP) using downhole electric heaters in vertical holes and the ExxonMobil approach using longitudinal vertical fractures created from horizontal wells and propped with electrically conductive material such as calcined coke. Indirect heating approaches propose injection and circulation of steam or a non-condensable gas like CO2. These include the Chevron concept of creating horizontal fractures in vertical wells or the Texas A&M concept using multiple vertical transverse fractures penetrated by horizontal wells. The objective of this paper is to compare energy and recovery efficiency of various in-situ retorting technologies using different heating schemes and well configurations as mentioned above. Thermo-physical parameters like thermal conductivity, specific heat capacity, porosity, permeability needed for the numerical simulation have been obtained by extensive literature survey of various oil shale deposits in Green river formation of USA. A sensitivity analysis of direct heating pattern and spacing reproduces previous work. Then the validated model is used to evaluate the size and fracture spacing sufficient to heat the oil shale in the direct and indirect heating approaches and to compare pressurized hot fluid circulation to heating elements. The use of the same wells for both heating and hydrocarbon production offer an economic edge for indirect heating approaches.
-
-
-
Alkali Surfactant Gas Injection - Attractive Laboratory Results in Carbonates under Harsh Salinity and High Temperature
Authors C. Cottin, D. Morel, D. Levitt, P. Cordelier and G. Pope(Alkali) Surfactant, Polymer injection is an attractive enhanced oil recovery technique that allows achieving almost zero residual oil saturation at the microscopic scale when properly designed. In this combination of chemicals, the role of polymer is to achieve the necessary mobility control of the microemulsion / oil fronts which are formed and propagated through the reservoir. Foam has been recently identified as an alternative to polymers to achieve such a mobility control. This paper describes the (A)SG laboratory results which have been obtained on carbonate core samples under harsh salinity and temperature conditions. The starting point was the development of a surfactants formulation to achieve ultra low interfacial tensions between the oil and injected solution, using the classical test tubes approach. The efficiency (in terms of oil recovery) of this chemical formulation in this particular S and T condition was demonstrated with SP core floods. The same chemical formulation was used for (A)SG; the polymer was replaced by nitrogen co-injected with surfactant to create foam. Although SP and ASP flooding has been studied and implemented for decades, there remain few applications in carbonates, and none in the particular case of high salinity and high temperature carbonate reservoirs. Even if adequate surfactants can be tailored to these conditions, the use of polymers for mobility control in low permeability formations, particularly at high temperatures and in the presence of calcium, is a significant challenge. These results demonstrate that (A)SG is an alternative that works at laboratory scale and might be the starting point of a potential future pilot implementation . Foam quality has to be optimized in order to achieve the best recovery, but keeping also in mind that it is possible that gas sourcing and recycling will be a predominant consideration at the field scale; low quality foam may be suitable. In some situations the same surfactants can contribute to ultra low interfacial tension and have good foaming properties. - ASG results are presented in high salinity and high temperature conditions. Replacement of polymers by foam can work and is particularly attractive if lower permeability and higher temperature are targeted - For the many carbonate fields where water injection is already implemented, (A)SG EOR is a new option to consider.
-
-
-
First Application in Russia of Bright Water™ Chemical for Waterflood Sweep Improvement in the Samotlor Field
Authors D.R. Thrasher, P. Denyer, A.S. Timchuk, Y.V. Zemtsov and D.V. AkininThe first pilot in Russia of Bright Water™ chemical (Thermally-Activated Particles or TAP) for improving waterflood sweep has been commenced in the Ust Vakh Satellite to the giant Samotlor Field in West Siberia in 2011. This field (the sixth largest in the world) has been under development since 1969. Water injection commenced in the early 1970s, and many wells now have very high watercut. However, large volumes of oil remain unrecovered in multiple reservoirs, and reservoir heterogeneity can have a significant impact on oil recovery by reducing reservoir sweep efficiency of the waterflood. A screening process was used to select the most suitable pilot candidate areas from a number of different fields which could potentially benefit from the technology. The Ust Vakh Satellite is a more recent development since early 2000s and possesses multiple wells completed in only a single zone, which is advantageous for pilot interpretation. Five wells in the Ust Vakh Satellite were selected on the basis of the number of good injectors, the presence of reservoir heterogeneity and high Water Oil Ratio wells despite the relatively short time under waterflood in this location. Another key criterion was selecting an area at the edge of the field with lowest interference possible in order to decrease the risk to interpreting a production response during the pilot. Tracer was injected in all wells prior to treatment which confirmed the lack of any high-rate fracture connectivity from the injectors to offset producers and validated the treatment design. The 5 wells were treated with a total of more than 400 tonnes of TAP over a period of 23 days. This paper describes aspects of candidate screening, treatment design, surveillance, implementation of the pilot and early response from the treatment. Note - Bright Water™ is a trademark of Nalco Company
-
-
-
Recent Progress in Surfactant Flooding in Carbonate Reservoirs
Authors E. Chevallier, P. Moreau, S. Renard, R. Tabary, B. Bazin, F. Douarche and F. OukhemanouSurfactant Polymer (SP) flooding in carbonate reservoirs is still considered as a considerable challenge today. Indeed, adsorption of anionic surfactants onto carbonate rocks is known to be much higher than onto sandstone rocks. This limits drastically the efficiency of the process. We develop here new methods on reducing surfactant adsorption in carbonate reservoirs using new additives: adsorption inhibitors. First we illustrate the impact of lithology (dolomite, limestone) on surfactant adsorption. We demonstrate how high adsorption clearly limits chemicals flooding performances in carbonate rocks under realistic conditions, i.e. moderate amount of injected chemicals at reservoir flowrates. Then, static adsorption tests show that careful selection of additives can significantly decrease surfactant adsorption onto carbonate rocks. This is further confirmed by dynamic adsorption tests. These laboratory results clearly demonstrate that surfactant flooding can be successfully applied in matrix carbonate reservoirs but it is crucial to consider lithology as it plays a significant role on final process performances, showing high variabilities in porous medium. The use of adsorption inhibitors appear as a significant advance for surfactant flooding in carbonate reservoirs, opening new opportunities for surfactant flooding in these challenging conditions.
-
-
-
Microemulsion Rheology and Alkaline-surfactant-polymer Flooding
Authors K. J. Humphry and M. van der LeeWorkflows to assess the technical and economic suitability of an enhanced oil recovery (EOR) technique for a particular field generally involve laboratory testing, such as core flooding experiments, and field-scale reservoir modelling. When building these field scale models and interpreting laboratory experiments it is important to understand the flow properties of all phases present in the particular EOR process. In alkaline-surfactant-polymer flooding (ASP) flooding, surface-active molecules decrease the interfacial tension between water and crude oil, increasing the capillary number, and recovering oil trapped in the reservoir pores. The ultra-low interfacial tensions needed for ASP flooding occur when the surface active molecules are equally soluble in the brine and oil phases. Under these conditions, in addition to the brine and oil phases, a third thermodynamically stable phase is formed. This third phase is known as a microemulsion. While the flow properties of crude oil and polymer-enriched brine are well understood, little has been done to characterize the microemulsion phase, particularly with respect to rheology in porous media. In this study, larger volumes of microemulsion, with and without polymer, are generated using a model ASP system. These microemulsions are studied using conventional shear rheology. Additionally, an in situ, or apparent, viscosity is recovered from core flooding experiments in Berea sandstone, where pressure drop across the core is recorded as a function of the flow rate of the microemulsion through the core. The implication of these results for ASP flooding is discussed.
-
-
-
Methodology of Selecting Pilot Development Areas for Application of BrightWater™ Technology
Authors D.V. Akinin, A. Timchuk, Y.V. Zemtcov and O.Y. BochkarevAt present, development of unique and reserves-rich fields is characterized by declining oil production rates and increasing portion of residual recoverable reserves in reservoirs with high current watercut. Conventional tools to recover such reserves are rather inefficient. Therefore, application of flow-diverging techniques of enhancing oil recovery is becoming more and more important. In the recent time, there has been a growing interest to a new EOR technology BrightWaterТМ. Since 2004, the commercial use of this method has expanded from single pilot applications to several dozens of wells, and has been implemented at oil fields in Alaska, Argentina, Azerbaijan, Brazil etc. The key feature of this technology, which makes it different from its analogs, is the formation of a barrier diverging the flow of water within the formation rather than in the bottomhole area. To select the most appropriate areas at the Company’s oilfields and test BrightWaterТМ technology, a number of fields have been assessed and analyzed for feasibility of such application. This paper describes the main criteria of applying BrightWaterТМ technology and the algorithm of selecting pilot development areas for this purpose.
-
-
-
Laboratory and Field Tests of Component-wise Gel Injection Technology for EOR
Authors I.V. Kuvshinov and V.V. KuvshinovThis work presents the results of computer modeling, laboratory research and field tests of component-wise gel injection technology for EOR. Now standard methods of gel injection imply using of homogeneous gel-forming composition, with component mixing on a surface just before injection, or even earlier, at a stage of chemicals production. It is not always acceptable, because the gelation process can start inside or near the wellbore, e.g. in a hot steam injection well, but the technology requires the formation of a gel shield at a certain distance from the well. Component-wise injection technology is based on fluid dispersion during filtration through a porous media, when the solutions of each reagent are sequentially injected into the well, and their mixing occurs due to dispersion at a certain distance from wellbore. The computer model of the component-wise injection process, which enables to estimate the required volumes of reagent and their mixing conditions in situ, is presented. Modeling results for different laboratory experiments and injection schemes for field tests are shown. The specially constructed laboratory setup for studying fluid dispersion, with test column length up to two meters, is described. Experimental data obtained were used for computer model verification. In special series of the experiments, test column configuration was varied, with “dead zones” modeled, to estimate its effect on fluid dispersion process. The results of the first successful field test of the technology, performed on injection well in one of the Western Europe oilfields, are also presented. These results prove the adequacy of the model, and the technology effectiveness.
-
-
-
From Lab to Pilot Design of ASP Flooding in High Temperature Reservoir of Limau Field Indonesia
Authors I.P. Suarsana, A. Badril and I. WijayaHigh temperature is considered the most handicaps in the process of chemical selection, Laboratory analysis, core flooding process, and lab verification of government authority. When we get the best fluid selection then the price will control the pilot project. This paper will present the chemical selection, lab analysis and pilot design of Limau Field, section P&Q, located in South Sumatera Indonesia. Limau Field is one of the oil field located in the working area of PT. Pertamina EP Sumatera Region, Limau is a mature field began produced since 1930. Tertiary Recovery stage (EOR) target implementation in block P, Q-22 and Q-51. This three block has been selected since they have highest potential of remaining oil in place, and have been implemented secondary recovery phase with water injection and got a positive response from this activity. Primary peak oil production was achieved at 46,000 BOPD with 5 % of Water Cut in 1960, Activities of secondary recovery (water injection) stage conducted in 1991 with water injection using a staggered line drive and peripheral pattern with the main d in Soutin 1994 from the previous condition of 1,222 BOPD in 1989. From the results of successful secondary recovery stage, Pertamina EP and partner plan to implementation tertiary recovery stage with chemical injection (ASP Flooding),. To propose a chemical flooding project, there several regulation has to be follow before the pilot implementation. There are some activities to convincing EOR stage include : screening chemical flooding, chemical flooding laboratory study (fluid-fluid analysis & rock fluid analysis) in accordance with the conditions of the reservoir at temperature of 1050 C, GGRPF (geophysical & Geology, Reservoir, Production and facilities) study for the determination of the pilot area until full scale development. The challenges facing the stage screening chemical use is high reservoir temperatures in the range 1050 C, the results core flooding conducted and chemical flooding (ASP floding) who has been getting incremental recovery of 13,84% conducted in SURTEK lab USA and Lemigas Lab for verification is 9.94% of the OOIP. From the laboratory stage and studies that have been successfully carried out, will continue with ASP flooding pilot with 6 spot inverted pattern, where the results of reservoir simulation production response to injection will be felt in the 4 month with an annual increase of 2400 bopd from the previous condition of 225 bopd in production wells.
-
-
-
Impact of Difficult Environments on Chemical Flooding Performance
Authors B. Bazin, R. Tabary, F. Douarche, P. Moreau and F. OukhemanouSurfactant flooding processes become challenging when one of the following criteria is met: hard brines, high temperature, low permeability rock and high clay content. This paper illustrates how we overcome those difficulties combining appropriate formulations with the right injection strategy (slugs design). A particular emphasis is set on solutions that can be applied in the field. High performances solutions first rely on selecting appropriate surfactants from an extended portfolio representative of industrial products. We describe how ultra-low interfacial tension formulations are designed while maintaining a good solubility at high temperature (>100°C) and in hard brines (high divalent ion concentration). Various reservoir cases will then be reviewed: In hard brines chemical adsorption is known to be significantly higher than in soft brines. Surfactant adsorption is drastically reduced (<0.2 mg/g) when using appropriate adsorption inhibitors. This results in a very high oil recovery (>90 %) with performances comparable to the one obtained in soft brine conditions. High temperature (> 70-80°C) raises thermal stability issues with losses of effectiveness and possible plugging. New surfactants and polymers are available to address this situation. Successful oil recovery experiments done up to 120°C will be discussed. Low permeability sandstone, usually associated with high clay levels has an impact on both injectivity and chemical adsorption. In most challenging conditions alkaline cannot be used and an optimized salinity gradient combined with adsorption inhibitors is requested. The paper will demonstrate how surfactant flooding can be successfully applied in challenging reservoir conditions to open new opportunities for chemical EOR.
-
-
-
Injectivity Errors in Simulation of Foam EOR
Authors W. Rossen, T.N. Leeftink and C.A. LatooijInjectivity is a key factor in the economics of foam EOR processes. Poor injectivity of low-mobility foam slows the production of oil and allows more time for gravity segregation of injected gas. The conventional Peaceman equation, when applied in a large grid block, makes two substantial errors in estimating injectivity: it ignores the rapidly changing saturations around the wellbore and the effect of non-Newtonian mobility of foam. When foam is injected in alternating slugs of gas and liquid ("SAG" injection), the rapid increase in injectivity from changing saturation near the well is an important and unique advantage of foam injection. Foam is also shear-thinning in many cases. We use the method-of-characteristics approach of Rossen et al. (2011), which for the first time resolves both changing saturations and non-Newtonian rheology with great precision near the wellbore, and compare to conventionally computed injectivity using the Peaceman equation in a grid block. By itself, the strongly non-Newtonian rheology of the "low-quality" foam regime makes a significant difference to injectivity of foam. Thus for continuous injection of foam in this regime, the Peaceman equation underestimates injectivity by a factor of two even for grid blocks as small as 10 m wide, and by a larger factor for realistic grid-block sizes. However, one could estimate this effect using the equation for injectivity of power-law fluids, i.e. without accounting for changing water saturation near the well, without much error. In SAG processes, however, non-Newtonian rheology is less important than accounting for foam collapse in the immediate near-wellbore region. Averaging water saturation in a large grid block misses this dryout very near the well and the Peaceman equation grossly underestimates the injectivity of gas. We illustrate with examples using foam parameters fit to laboratory data.
-
-
-
CO2 Injections for Enhanced Oil Recovery Visualized with an Industrial CT-scanner
Authors Ø. Eide, M.A. Fernø, Z. Karpyn, Å. Haugen and A. GraueThe effect of micro-scale heterogeneities on front instabilities during secondary, liquid CO2 injections for enhanced oil recovery in standard-sized chalk core plugs was investigated. The rock structure and displacement process was imaged in an industrial CT-scanner to probe the effect of micro-scale heterogeneities on the flow patterns and development of plume and CO2 fingers during injections. Heterogeneities in the chalk samples include fractures, healed shear bands and remnants of burrows. A one-component mineral oil was placed in contact with CO2 at the experimental conditions to promote reproducibility between repeated tests. The chalk is considered homogeneous on a standard-sized plug level, and varies only slightly in porosity and permeability within a large number of cores. The high spatial resolution CT scanning revealed sub-mm healed shear bands running through the length of the core which potentially can cause a permeability decrease or diversion of the injected fluid. Total oil recovery from CO2 injection was around 90% regardless of heterogeneities, and there was no visible difference in CO2 arrival at the outlet. With no permeability contrast through the length of the core, the production of oil took place with less than one pore volume (PV) of CO2 injected. With a permeability contrast through the length of the core, more than one PV of CO2 was required to reach end-point oil saturation. Imaging the dynamic properties of a CO2 flood in the industrial CT showed how micro scale heterogeneities impact the flooding characteristics of a small core sample, as the healed shear bands diverted flow to a certain degree. It is also demonstrated how a larger permeability contrast will make the recovery more dependent on diffusion, which is a slower process than viscous displacement. The results demonstrate the need for characterization of micro-scale heterogeneity, because high permeability streaks and fractures will dominate flow during CO2 injection for EOR.
-
-
-
History Match and Polymer Injection Optimization in a Mature Field Using the Ensemble Kalman Filter
Authors S. Raniolo, L. Dovera, A. Cominelli, C. Callegaro and F. MasseranoThe paper focuses on a Chemical EOR study for a mature field. The field was selected due to its volume in place and good petrophysical properties. Indeed, the preliminary screening gave indication that polymer injection could be a promising EOR technique. New core data, SCAL and PLT were acquired and a high resolution model of the pilot area was built to integrate such new data and to properly capture the behaviour of the chemicals. The sector modelling was challenging due to the complexity of the history match and polymer injection optimization. The field has been producing for 60 years. Moreover, due to the complex structural settings, the sector model is not completely isolated from the full field model and dummy wells were introduced to mimic the flow interaction with the rest of the reservoir. A Computer Assisted History Matching (CAHM) was carried out by the means of the Ensemble Kalman Filter (EnKF). The EnKF is a Monte-Carlo method that automatically updates an ensemble of reservoir models by production data integration. The EnKF is capable of providing a set of matched models that preserve the geological coherence which can be used to quantify uncertainty in forecast production. In this paper, we present the application of the EnKF to history match the sector model and the consequent optimization for polymer injection. EnKF was used to calibrate petrophysical properties, relative permeability and faults transmissibility integrating measurements, shut-in pressures and rates, of 14 wells including the dummy wells. The final output is a set of 100 alternative models that properly match production data which were used to set up and optimize the forecast development strategy through polymer injection. This application provides evidence that the EnKF is effective and efficient for history matching. Moreover, dealing with multiple models put the basis for a conscious estimation of future production and a more realiable risk evaluation on EOR strategy.
-
-
-
Results and Lessons Learned from an Extended Single-well Tracer Campaign Performed in the Handil Field, Indonesia.
Authors A. Mechergui, C. Romero, N. Agenet, J. Batias, M. Nguyen and L. HeidariHandil is a mature oil and gas field in the Mahakam Delta, Indonesia. It was discovered in 1974 and developed since 1975. It was firstly produced by natural depletion and then by waterflooding. From 1995 gas injection was implemented as tertiary recovery mechanism. In 2007 a first Single-well tracer test (SWTT) campaign was carried out in the field showing a low Remaining Oil Saturation (ROS) that was confirmed by coring technique in the selected reservoir. Uncertainty existed on the origin of such low ROS (12-14%), thus in 2011 an ambitious SWTT campaign was launched to assess the ROS distribution in different reservoirs under waterflood and simultaneous water and gas flood strategies. The objective was to better understand EOR mechanisms prevailing in the field and help assess ROS under different flooding strategies. The challenging campaign consisted of a program of consecutive SWTT trials performed in a mature and offshore field environment. This paper focuses on the operations and results of the SWTT campaign obtained from three tests out of five that were performed in different reservoirs. The interpretation of these tests was challenging and numerical simulation was compulsory for a reliable ROS estimation. In reservoir A, we suspected that the tested zone have been invaded by the gas cap. Therefore, in order to get an uncertainty range of ROS in presence of gas, the partitioning coefficient of primary tracer (Ethyl Acetate) between gas and water was measured at reservoir conditions. Results indicate that even with high trapped gas saturation, the ROS is in the order of 22%. For the second test in Reservoir B, the mass balance was excellent but profiles showed non ideal behavior due either to drift or a wellbore effect. The two hypotheses were investigated and numerical simulations helped identify that wellbore effect was the main non-ideality. This was included and a reliable ROS value of ~30% was determined. The third SWTT was performed in Reservoir C and showed an excellent tracer recovery with low scattering data. However production phase was characterized by an unstable flow regime which required the use of instantaneous production rate during numerical simulation. Matching of tracer profiles indicates an average ROS in this reservoir of 20%. These ROS values that range between 20-30% allow us today to move forward in the identification of potential EOR candidates and they will help us advance in the location of future pilot zones for different EOR processes.
-
-
-
Injection Fall-off Interpretation from Fractured Injectors
More LessWe performed numerical simulations of injection fall-off (IFO) testing for both water and (non-Newtonian) polymer in which the gradual closure of the induced fracture is explicitly included. A large variety of induced fracture sizes and shapes was included in this study. Results show that half-slope and quarter-slope ranges will only occur very exceptionally in the early-time pressure derivative curves. On the other hand, the unit slope (storage flow dominated) occurs very often at early time. In principle, both half-slope / quarter-slope and unit slope can be used for IFO test analysis to estimate the dimensions (length, height) of the induced fractures. However, based on the above, we conclude that fracture dimensions in IFO tests can only be reliably interpreted from the unit slope part. This point is further illustrated by a two IFO test examples from the field, where it is shown that interpretation of half-slope or quarter-slope can often result in unrealistically large fractures.
-
-
-
Continuous Land Seismic Reservoir Monitoring of Thermal EOR in the Netherlands
Authors J. Cotton, L. Michou and E. ForguesA continuous reservoir monitoring system has been installed for Shell, on a heavy-oil onshore field situated in the Netherlands, to re-develop oil production by Gravity-Assisted Steam Drive. The challenge was to continuously monitor using seismic reflection the expansion of the steam chest injected in the reservoir during production. The main problems for onshore time-lapse seismic are caused by near-surface variations between base and monitor surveys which affect the seismic signal coming from the reservoir. In our system, a set of permanent shallow buried sources and sensors has been installed below the weathering layer to both mitigate the near-surface variations and minimize the environmental footprint. The very high sensitivity of our buried acquisition system allows us to track very small variations of the reservoir physical properties in both the spatial and calendar domains. The 4D reservoir attributes obtained from seismic monitoring fit the measurements made at observation, production, and injector wells. A daily 4D movie of the reservoir property changes allows us to propose a scenario that explains the unexpected behavior of the production and confirms that the steam does not follow the expected path to the producer wells but rather a more complicated 3D path within the reservoir.
-
-
-
Experiments and Analysis of Imbibition in Carbonates
Authors R.A. Anderson, N.A. Al-Ansi and M.J.B. BluntWith around half the world's remaining conventional oil contained in fractured carbonate reservoirs, it is important that the fundamentals of the transfer of fluids from fracture to matrix are understood. We present the results of an extensive series of spontaneous imbibition ambient-condition experiments on three carbonate cores of different length, designed to test recent theoretical models of imbibition. We study the displacement dynamics, from an initial square-root-of-time recovery to an exponential relaxation to residual saturation as the wetting from reaches the end of the core. We also quantify the effect of pore structure in highly heterogeneous systems. The scaling models presented by Ma et al. (1995), Li and Horne (2004), and Schmid and Geiger (2012) were tested on the experimental data. Schmid and Geiger’s correlation was found to be the most reliable. The recovery, as a function of dimensionless time, could be fitted with the mass transfer function proposed by Aronofsky et al. (1958) and the analytical oil recovery solution presented by Tavassoli et al. (2005). The work suggests that recent correlations for transfer rates in the literature, combined with benchmark experimental results, can be used as a reliable technique to help predict field-scale recovery rates in fractured reservoirs.
-
-
-
Integrated Laboratory and Numerical Investigations Towards a MEOR Pilot
Authors H.K. Alkan, E. Biegel, A. Herold and F. VisserA project on the application of MEOR in one of the Wintershall candidate fields has been initiated. The project aims mainly at developing nutrient formulations for stimulating microbial activity in terms of oil recovery and defining reservoir and process parameters for the selected field leading to a field trial. The project is structured with a workflow consisted of 5 work packages. The sampling activities were extended with a sub-surface sampling in one of the candidate fields to investigate the effect of pressure on bacterial activity. The works on the determination of growth rates and metabolite activities of microbial consortia derived from one field is continuing with batch tests and micromodels. Dynamic screening experiments are going on in sandpacks and cores under sterile and anaerobic conditions. Numerical works are performed in two parallel ways. On one hand, an analytical model is being applied to evaluate relevant process parameters. On the other hand, a numerical simulator is being tested and validated to implement it into a reservoir simulator. The recent results both in experimental and numerical parts are presented and discussed in the paper.
-
-
-
An Integrated Laboratory Workflow for the Design of a Foam Pilot in Malaysia
An integrated laboratory workflow for the design of a foam pilot in Malaysia. Max Chabert (Rhodia), Lahcen Nabzar (IFPEN), Siti Rohaida, Pauziyah Hamid (Petronas PRSB). We present the laboratory feasibility study dedicated to the design of an enhanced water alternating gas (EWAG) process for a Malaysian oilfield. The field is currently submitted to produced gas injection, mainly consisting of CO2. We focus here on the design of a water soluble foaming surfactant formulation using advanced characterization methods and the evaluation of this formulation in corefloods experiments. On-field conditions make the design of a surfactant formulation particularly challenging, with a reservoir temperature of 100°C and only sea water available for foaming formulation injection. The ultimate goal of this design study is thus to obtain an industrially realistic formulation yielding stable foams in reservoir conditions (including in presence of oil) at an affordable price. We set-up a specific laboratory workflow to design a foaming surfactant formulation adapted to reservoir settings. An automated screening routine based on robotics was used at ambient and reservoir temperature to pre-select the most performing formulations for foam stabilization among more than 400 binary and ternary mixes. Formulations solubility maps were obtained using automated image analysis. Only formulations perfectly soluble in the window defined by injection and production waters salinities were retained for further testing. Selected formulations were then characterized for foam stabilization in reservoir pressure and temperature conditions using a high pressure variable volume view cell. Adsorption of the selected formulations on reservoir crushed rock was optimized by exploiting synergistic effects between surfactant families. A formulation yielding over 2 hours foam half-life in reservoir conditions with a static adsorption below 1 mg/g was obtained. This formulation was further characterized in petrophysics application tests using analog Berea sandstones and reservoir rocks. These tests were designed to mimic potential pilot conditions in terms of injection strategy, injection rate and gas composition. High values of mobility reduction factors were obtained, including in presence of residual oil. This set of results is a first step toward application of an enhanced WAG foam process.
-
-
-
Dynamic Interactions between Matrix and Fracture in Miscible Solvent Flooding of Fractured Reservoirs
Authors A. Ameri Ghasrodashti, R. Farajzadeh, M. Verlaan, V.S. Suicmez and H. BruiningMiscible solvent injection has received increasing attention in recent years as an efficient method to improve oil recovery from fractured reservoirs. Due to the large permeability difference between fracture and matrix, the success of this method depends to large extent on the degree of enhancement of the mass exchange rate between the solvent flowing through the fracture and the oil residing in the matrix. A series of experiments have been conducted to investigate the mass transfer rate between the fracture and the matrix. Different scenarios have been considered to examine the effect of flow rate, matrix permeability, fracture aperture, and oil properties. To this end a porous medium (fully saturated with oil) is placed in a vertical core holder that can be used in a CT scanner, to simulate the matrix. A small slit between the porous medium and the core holder simulates the fracture. The interaction between the matrix and fracture is visualized for solvent flooding by means of CT-Scanning, which can be used to validate theories of enhanced transfer in fractured media. The experimental data are compared with a simulation model that takes diffusive, gravitational and convective forces into account.
-
-
-
Enhancing Recovery from the Oil-Rim Using Energy from the Gas Cap
Authors N.N. Ivantsov and A.S. TimchukIn the environment of constant deterioration of resource base, stability of oil production in the nearest decades will depend on the prospects of development of geologically complicated fields. In Western Siberia significant part of undeveloped reserves is represented by highly viscous oil fields with gas cap. Such are Russkoye, Messoyakhskoye, Van-Yoganskoye, Severo-Komsomolskoye and other, having reserves over 4 bln. tons. Development of such assets is hindered by adverse geological and physical conditions. Presence of a gas cap and a fine oil rim leads to early gas breakthroughs. Viscous oil and poorly consolidated reservoir contribute to the risk of premature water breakthroughs (matrix breakthrough events), reducing the efficiency of injection. Permafrost and reservoir clay swelling limit the deployment of thermal techniques. The fields were discovered over 40 years ago and massive pilot work is being carried out only in Russkoye field, however, an efficient development technique has not yet been found. In such an environment it seems relevant to look into unconventional solutions. The authors propose an oil rim development technique using the energy of the gas cap. In this technique the design and the trajectory of horizontal wells allow for simultaneous controllable oil production from the oil saturated zone and gas production from the gas cap. This allows for enhancement of oil flow rate, reduction of gas coning and extends the period of stable well operation. The earlier achieved results of calculations made for Russkoye field have shown that while depletion recovery factor equals 6%, enhancement could provide up to extra 3%. In this work the authors, using modeling results, have determined optimal geo-technical conditions for deployment of this technique. Efficiency evaluation has been performed for operations at injection scheme. Particular features of this technique enable it to be viewed not only as an EOR technique, but also as a tool to prevent the main risks for similar fields, i.e. gas breakthroughs and reservoir damage. Based on the results of the study proposals were elaborated for pilot work in Russkoye field.
-
-
-
Pelican Lake Polymer Flood - First Successful Application in a High Viscosity Reservoir
Authors E. Delamaide Inc., A. Zaitoun, G. Renard and R. TabaryThe Pelican Lake heavy oil field located in northern Alberta (Canada) has had a remarkable history since its discovery in the early 1970s. The reservoir formation is thin (less than 5m) and as the oil is viscous (from 600 to over 40,000cp), initial production using vertical wells was poor. Several methods were used in order to improve production and recovery, including an air injection scheme in the 1990’s. However it is only with the introduction of horizontal drilling that the field began to reach its full potential; indeed Pelican Lake was one of the first fields worldwide to be developed with horizontal then multi-lateral wells. With primary recovery around 5-7% and several billion barrels OOIP, the prize for EOR is large; polymer flood had never been considered in such high viscosity oil until 1995, when the idea of combining polymer flood and horizontal wells gave way to a polymer flood pilot in 1997. This was the first step on the way, and today the field is in the process of being fully converted to polymer flood, with several hundred injection wells already in action. Polymer flooding has the potential to increase recovery to over 20%OOIP at relatively low cost. Pelican Lake is the first successful application of polymer flood in a high viscosity oil reservoir (1,000-2,500cp). This paper presents the history of the field then focuses on the polymer flooding aspects. It describes the preparation and results of the first polymer flood pilots as well as the extension to the field.
-
-
-
ASP Pilot in West Salym Field - Project Front-end Engineering
Authors Y.E. Volokitin, J. Nieuwerf, V. Karpan, M. Shuster, W. Tigchelaar, D. van Batenburg, M. Shaymardanov, I. Chmuzh, I. Koltsov and R. FaberSalym Petroleum Development N.V. (SPD) is a 50/50 Joint Venture of Shell and Gazpromneft. SPD is the License holder and operator of the Salym Group of fields in Western Siberia (Upper Salym, West Salym and Vadelyp Work on maturation of Enhanced Oil Recovery option for Salym Petroleum Development (SPD) has began in 2007 and after initial screening, the ASP (Alkaline-Surfactant-Polymer) technology has been chosen for further work. Follow-up work involved laboratory and field tests, subsurface modelling and surface high-level concept design. High-level assessment demonstrated production potential of 30+ mln tones additional oil and a significant potential value to be shared between SPD and Russian Government. At that stage work began on Production Pilot as a Separate Project with Pilot Concept selected and Front-End Engineering work completed in 2012.Construction and opperation is expected in 2013-2014. The chosen concept for the Pilot involves a single 100x100m square pattern with 4 injectors and one producer. Since the primary objective of the Pilot is to demonstrate technology and to collect data for further optimization, 2 additional observation wells will be drilled within the pattern to provide information about the effectiveness of the process. Wells will be drilled from a dedicated well pad in the Northern area of West Salym field. The same location will host standalone mixing and production facilities. Produced fluids will be collected in the tank farm at the well pad and analysed. Logistics and planning for assurance of quality control of chemical mix has provided a separate challenge, also exacerbated by remoteness of location, but also by rheology properties of viscous surfactnat concentrates. In addition all storage and mixing facilities have to survive harsh Siberian conditions with temperatures ranging from -50 to +40 deg C. The paper describes some subsurface, chemical and engineering solutions for Salym pilot that might be of value for other groups contemplating cEOR pilots and small-scale production in a similar area
-
-
-
Effect of Nonionic Surface-active Substances on Paraffin Crystallization in the System
Authors L.K. Altunina, L.A. Stasyeva and V.A. KuvshinovPresented are physicochemical and rheological properties of viscous paraffinic oils recovered from the south of West Siberia, Russia, Germany and Mongolia in the temperature range of 20-90 °C at different shear rates and interactions with oil-displacing systems based on surfactants and alkaline buffer solutions. The systems were determined to have demulsifying effect on the viscous paraffinic oils under study, regardless of surfactants composition and structure. Temperature dependence of paraffin crystallization point on a preheating temperature is extreme. At the same time maximum paraffin crystallization points correspond to preheating temperatures of 50-60 °C. We studied the ability of non-ionic surfactants – oxyethylated alkylphenols with different degrees of oxyethylation, from 12 to 90, to exhibit depressant properties with respect to paraffinic oils, reduce the viscosity of crude oils and the paraffin crystallization point. Optimal degree of oxyethylation of non-ionic surfactants was determined equal to 50, at which the decreases in oil viscosity and paraffin crystallization point were maximal. One can use the proposed compositions to develop EOR technologies for high-viscosity paraffinic oils.
-
-
-
Geological Factors in Acidizing Design
Authors N.A. Misolina and I.M. NasibulinField experience and laboratory tests indicate that the effective result of the use of acid solutions is "wormholes".This article studied the effect of the geological features of reservoir rocks in the acid treatment and the ability to influence the acid compositions to specific lithotypes limestone.The complex technology of the tests for acid stimulation of wells in carbonate reservoirs consisted of five stages: filtration studies using three different acid compositions, the microscopic method (thin sections), the electron microscope, X-ray tomography.Founnd that when exposed to different types of carbonate reservoir acid compositions, all other things being equal, the structure formed dissolving the following types: surface, tapered, dominant, even.Using modern methods of X-ray tomography, assured the visualization of inhomogeneities of the core sample, and scanning electron microscopy was used to answer questions related to the change of the internal structure, the structure of the pore space limestone after exposure to acidic agents. It has been shown that the decisive role in the choice of the method of intensification is the material composition of sediments and reservoir type.
-
-
-
Harmonic Testing of Hydraulically Fractured Wells
By P.E. MorozovHydraulic fracturing is an effective technique for increasing productivity of damaged wells and wells producing in low permeability formation. Various methods have been proposed to estimate reservoir and fracture properties from transient pressure and flow rate data. The basic concept of harmonic testing is the use of a sinusoidal flow rate variation instead of a step change as in conventional well testing. When a pseudo-steady flow regime is achieved after a few periods, both flow rate and wellbore pressure exhibit a sinusoidal behavior. It is then possible to identify the modulus of the response and phase shift between the two signals. These data are used to evaluate the reservoir parameters. In this study, new analytical solutions are presented for analyzing amplitude- and phase-frequency characteristics of fractured wells in homogeneous or double-porosity reservoirs. The influence of wellbore storage effect, fracture storage and conductivity on the pressure modulus and phase shift is investigated. In case of high dimensionless frequencies a set of asymptotic solution is derived. These solutions can be used to solve the inverse problems for obtaining the formation and fracture properties.
-
-
-
Chemical EOR in High Salinity-High Temperature Reservoir - Experimental Coreflooding Tests and Numerical Simulation
Authors V. Parasiliti Parracello, C. Callegaro, A. Dato, F. Siliprandi, P. Albonico and M. MatteiRecent developments in chemical EOR technologies make now possible to operate in severe environments, characterized by high-temperature conditions and by high salinity and hardness of reservoir brine. A feasibility study was conducted on a field operated by Eni, in order to design a surfactant injection under these challenging conditions. Laboratory studies and simulations were performed to evaluate the potentiality of the technique to increase the oil recovery. Two surfactant formulations presenting good phase behaviour and conferring low interfacial tension between brine and reservoir oil were tested. The dynamic performance of the chemicals was screened with a series of coreflooding tests, carried out using Berea sandstone. Sea water injection was followed by the chemical flooding, so that the additional recovery factor was evaluated. Surfactant adsorption was then measured to select the most suitable formulation. Moreover, core experiments were history matched through numerical simulation to validate the model and obtain scaling parameters of the chemical process for future forecast previsions of surfactant flood benefits at sector scale.
-
-
-
Applying the Probabilistic Collocation Method to Surfactant-polymer Flooding
Authors A. Alkhatib and P. KingEnhanced oil recovery has achieved great attention during the past few years. However, broad scale implementation requires greater understanding of the relevant uncertainties and their effect on performance. Quantifying this uncertainty is very important for designing these processes, yet traditional methods which are usually based on Monte Carlo simulations require a large number of realizations to produce convergent results. We propose the use of a non-intrusive approach known as the Probabilistic Collocation Method (PCM) to quantify parametric uncertainty for surfactant-polymer flooding. The quantification of uncertainty was performed for surfactant/polymer related state variables such as adsorption rates and residual saturations. The PCM is performed on two reservoir models: a modified section of the SPE10 model and the PUNQ-S3 model. The random input variables PDFs are first approximated using polynomial chaos expansions and then probabilistic collocation is used to produce approximations of the reservoir model using the collocation points obtained via Gaussian quadrature and Chebyshev extrema. These approximations can then be used to produce PDFs for output variables such as the recovery factor. Results show that PCM produces similar results to those obtained via Monte Carlo simulation, which requires a large number of simulations, while requiring significantly lower number of simulation runs.
-
-
-
Optimization of Polymer Flooding with a Tapered Concentration Slug
Authors A. Behr, L. Olie, F. Visser and B. LeonhardtThis paper provides hints and guidelines towards a better understanding of the correlation between the polymer injection schedule and the project profitability. In the optimization study, the polymer slug will be represented by three parameters: the slug length, which is the effective duration of polymer injection at maximal polymer concentration, the maximal injected polymer concentration itself and the tapering (in terms of slope of polymer concentration profile versus time). This last factor is often ignored due to the complex problems of parameterisation in numerical models. The polymer flood model and inverse problem formulation were adapted to be solved by CMG’s tools and a special method was introduced to account for the effect of varying the optimization parameters on the rheological properties of the water phase (combining viscosity dependence on shear-thinning and concentration) and on the polymer injectivity. The injectivity issue was treated by introducing an additional negative well skin factor which corrects the well inflow model for non-Newtonian polymer solutions. The Net Present Value was used as an objective function during the optimisation phase to estimate the economic benefit. The method was applied to a North-German mature oil field where a polymer project is at the stage of pilot testing.
-
-
-
Design of Foam-assisted Carbon Dioxide Storage in a North Sea Aquifer Using Streamline-based Simulation
Authors A.M. Al Sofi, S. Vitoonkijvanich and M.J. BluntCarbon capture and storage (CCS) − the collection of CO2 from industrial sources and its injection underground − could potentially contribute to the reduction of atmospheric emissions of greenhouse gases. In this paper, we investigate the sequestration of CO2 in aquifers with the co-injection of surfactants for foam generation, to allow increased storage capacity. This is equivalent to the use of foam for conformance control in enhanced oil recovery applications. To study foam-assisted sequestration, we extend an in-house streamline-based simulator. We use two foam models: Hirasaki and Lawson (1985) and Rossen et al. (1999). In both models foam hinders gas mobility through increasing its apparent viscosity. The modified simulator is validated by comparison to analytical solutions. We then investigate the performance of CO2 sequestration with the co-injection of surfactants. We look at CO2 sequestration in a North Sea aquifer. We study both simultaneous and alternating surfactant-gas injection at different fractional flows (i.e. water:gas ratios). For cases where a seal provides a reliable trapping mechanism, the simulation results suggest that the use of surfactants to generate foam significantly improves the storage efficiency at a marginal increase in water consumption. In this setting, CO2/surfactant simultaneous injection at a 0.5 CO2 fractional flow was found to be the optimum injection strategy for the case investigated. If the seal is unreliable or absent, CO2/brine simultaneous injection at a 0.85 CO2 fractional flow was found to be the optimum injection strategy. Although foam-assisted sequestration in this case furthers improve the storage efficiency, it does so at a significant increase in water consumption. This is since, although foam generation improves the sweep during the sequestration phase, it significantly hinders the sweep during the chase brine injection phase. Based on that, having a design where the surfactant will degrade just before or during the chase brine injection phase would provide the optimum sequestration strategy—without reliance on the presence or integrity of the seal.
-
-
-
WAG-CO2 Light Oil Recovery from Deep Offshore Carbonate Reservoirs
Authors S.F. Mello, E.L. Ligero, H.F.A. Scanavini and D.J. SchiozerBrazilian pre-salt reservoirs are constituted by carbonate rock and light oil with some CO2 and high solution gas ratio. A sustainable production of oil from pre-salt reservoirs requires a destination for the produced CO2 to mitigate its emission into the atmosphere. CO2 has been used to improve oil recovery when combined with water injection in the water-alternating-gas process (WAG). WAG-CO2 is an Enhanced Oil Recovery (EOR) method that modifies the fluid and rock-fluid properties. This injection process is associated to hysteresis of relative permeability and capillary pressure. Before implementation of the WAG injection in a field, the use of the reservoir simulation is required, a tool used to predict the oil recovery. A more rigorous way to simulate this process is by using a compositional reservoir simulator, given that an Equation of State (EOS) must be used to represent the pressure, volume, temperature (PVT) data that is different from the representation considered in conventional Black-Oil models. An EOS obtained from conventional PVT experiments and swelling tests must be employed to adequately represent the phase behavior resulting from the CO2 dissolution in the oil. Changes in relative permeability and capillary pressure resulting from hysteresis associated with the alternation between the injected fluids in the WAG process must be considered in the simulation model, avoiding a non-realistic oil recovery prediction. The impact of changes in oil properties and the hysteresis effect are considered in the prediction of WAG-CO2 oil recovery from a reservoir with petrophysical properties similar to a real carbonate reservoir constituted by light oil (about 8% molar of CO2). Reservoir simulation results give an indication of the expected oil recovery from a reservoir with pre-salt characteristics, enabling one to decide if the WAG-CO2 process is indicated for implementation in practice.
-
-
-
Optimization of Water Flooding in Stratified Formations or Multiple Reservoirs
Authors A.I. Ermolaev, L.M. Surguchev, A.A. Khrulenko, R.A. Berenblyum and A.A. ShchipanovWater flooding of stratified reservoirs often resulted in non-uniform oil displacement and fast water breakthrough in high permeability layers. Increase in oil recovery may be achieved by improvement of oil displacement in different layers and getting simultaneous water breakthrough in production wells. A similar problem may arise when water flooding multiple reservoirs with constrains on total injection / production. Control of injection rate allocation may provide uniform oil displacement in a layered formation or multiple reservoirs. Constrains on local (per layer) and total (per formation) injection / production rates and on production period for each layer may be accounted for. In this study optimization algorithms have been developed to determine an optimal strategy enabling maximum possible oil production with minimum possible water cut from a group of non-communicating layers or reservoirs. A solution of the optimization problem was found using linear and discrete programming methods under an assumption of two-phase piston-like incompressible flow in the reservoir. An optimal strategy with maximum oil recovery is defined under constrains on local and total production rates, injection start-up time and duration of production period for each layer or reservoir. An analytical solution was also found for a partial statement of the problem, where injection rates remain constant over the whole production period, which in turn is the same for all layers. The general problem statement has flexible constrains available, while the analytical solution for the partial statement may be easily implemented and used without dimension (number of layers or reservoirs) limitations. Both solutions were coded and further tested at mechanistic reservoir models to confirm applicability and efficiency of the developed algorithms in the reservoir simulation practice. A two-dimensional cross-sectional model with non-communicating layers was set up to test efficiency of the optimization algorithms for a typical reservoir simulation problem where fluid / rock compressibility and relative permeability effects are accounted for. The reservoir simulation results have confirmed that the optimal solution remained in force and therefore the optimization algorithms may be successfully integrated in reservoir simulation workflow.
-
-
-
Tensor Characteristics of Filtration and Capacity Properties for Anisotropic Reservoirs.
Authors A.N. Kuzmichev, V.V. Kadet and N.M. DmitrievIn recent years while determining filtration and capacity properties in cores greater attention is paid for considering the anisotropy, in particular, not only for identifying of the lateral anisotropy, but also for obtaining the tensor coefficients of absolute and relative permeability, relative phase permeabilities. At the same time many other characteristics such as tensor characterizing linear dimensions (pore radius), capillary pressure, Leveret`s function and etc. also have a tensor nature. It`s necessary to have methodology and theoretical concepts for determining these tensors. The results of comprehensive researches carried out in the real full-sized core from the North field of Samara region are presented in this paper. The presence of lateral anisotropy and the directions of the principal axes of the permeability coefficients were established in full-sized core with using the author`s technique. As a result of complex laboratory tests for each of the samples the absolute and relative permeability, the distribution of pore radius and the capillary pressure curves were obtained. The experimental results were computed with using the authors' theoretical formulas. After comparing the experimental and theoretical results the obtained filtration and capacity properties proved to have tensor nature.
-
-
-
Experimental and Mathematical Workflow in Modeling In-situ Combustion Processes for Unconventional Resources Recovery
The development of new technologies to increase oil recovery and the improvement of old ones has become increasingly important in the world. One of such methods is based on in-situ combustion, which in reference to light oils is termed as High Pressure Air Injection – HPAI. There are a number of projects of air injection into light and heavy oil fields described in literature. Some of them are successfully operated for many years and up to this day. The in-situ combustion process is attended with CO and CO2 formation as well as thermal decomposition processes resulting in hydrocarbon gases output and fuel formation. The improvement in oil recovery is caused by contribution of several processes – rise of reservoir pressure and temperature, oil density and viscosity reduction under heating, evaporation-condensation of water, nitrogen and fuel gases displacement, dilution of oil due to dissolution of carbon dioxide, and many others. Nowadays there is no systematic and comprehensive approach to all the mentioned phenomena. That causes considerable risks in project’s efficiency and total oil recovery estimation. The present work includes theoretical and experimental study of the processes associated with HPAI. The first stage includes calorimetric study of oxidation process in differential scanning calorimeter (DSC) and kinetic parameters estimation (activation energy, pre-exponential factor, reactions’ rate and order etc.), which are then applied for in situ combustion modeling. In term of theoretical investigations the mathematical model of in-situ combustion based on experimental data is formulated. The model includes heat- and mass-transfer in three-phase multi-component system in porous medium. The mathematical model is also constructed to make the attempt to investigate some transition processes – in-situ ignition, attenuation and re-igniting. Set of dimensionless parameters is formulated which allow predicting the quality of in-situ-combustion of oil. Large number of geological and physical parameters responsible for the in-situ-combustion is reduced to the analysis of two dimensionless parameters. The conditions for development of self-sustained oxidation reaction in porous medium are obtained that is summarized in a form of ignition-combustion diagram for in-situ-combustion process. The modeling results will be calibrated with combustion tube experimental data, as well as the results will be used to perform some combustion cases with the tube. The main goal of the project is to enhance predictability of the modeling and reduce risks associated with HPAI.
-
-
-
Enzymatic Generation of Oil-displacing Systems
Authors L.K. Altunina and L.I. SvarovskayaThe main method for the development of low-temperature reservoirs on viscosity oil deposits – thermal-steam stimulation. To improve oil recovery from low-temperature reservoirs we have developed and apply combined technologies based on steam injection into a reservoir followed by the injection of oil-displacing compositions based on surface-active substances. Besides surfactants such oil-displacing compositions contain nitrogen compounds including carbamide. At a high reservoir temperature carbamide is subjected to hydrolysis to yield СО2 and ammonia. Dissolving in water СО2 decreases oil viscosity and ammonia forms an alkaline buffer system with рН=9.0 10.0. It improves detergency of the system thereby improves oil recovery. To improve oil recovery from low-temperature reservoirs without thermal treatment we have developed a combined physicochemical and microbiological method based on simultaneous injections of the solution of oil-displacing system and urease enzyme catalyzing carbamide hydrolysis with the release of ammonia and СО2. Thus the effective oil-displacing system is generated in situ; it is capable to increase the oil-displacement factor of low-temperature oil deposit without thermal stimulation.
-
-
-
Wormlike Micelles for Mobility Control - A Comparison with Different EOR Techniques
Authors H. Bertin, E. Tognisso, M. Morvan and A. ColinPolymers can be used for EOR operations to improve the mobility, however a major problem is its sensitivity to shear stress. An alternative method could be wormlike micelles, which are self assembled surfactant molecules, that show a similar behaviour than polymers in term of viscosity increase and have the advantage of breaking and reforming in the porous medium when shear stress is modified. We started this study by a complete characterization of a wormlike micelles solution prepared with betaine molecules. Micellar characterization, for different surfactant concentration, salinities and temperatures showed that that the kraff point decreases when the salt and surfactant concentration increase. This means that this system stability increases with temperature. Rheological experiments showed a classical shear thinning behavior. Experiments in porous media consist in one phase and two phase flow in sandstone cores. One phase flow has been performed to determine surfactant adsorption and permeability reduction. Two phase flow displacements were conducted to show the ability of wormlike micelles to improve oil recovery. Experimental data obtained with wormlike micelles displacement are compared with standard reference experiments using polymer and Alkaline Surfactant Polymer. Results show that, despite adsorption, wormlike micelles have a positive effect on mobility control.
-
-
-
Forecasting IOR/EOR Potential Based on Reservoir Parameters
Authors A.A. Khrulenko, E.V. Babushkina, V.S. Rusakov, S.V. Rusakov, A. Shchipanov and R.A. BerenblyumThe oil and gas industry has accumulated significant experience in carrying out improved/enhanced oil recovery (IOR/EOR) projects. The outcome of different IOR/EOR methods applied to the fields world wide is available in open data sources as well as internal databases of oil companies. Open data typically include general information about oil field, average reservoir and fluid properties (reservoir parameters), and efficiency of an IOR/EOR method applied. Statistical analysis of such data may be applied to evaluate IOR/EOR potential of a particular field. Since such analysis requires small amount of information on a field, it is suitable for screening of large number of fields or evaluation of new discoveries or acquisitions. A new statistical approach to predict efficiency of different IOR/EOR methods for particular reservoir parameters has been developed and tested on actual filed data. The approach utilizes multi-dimensional statistical analysis based on data clustering. The K-means clustering is used to partition a filed case database into clusters based on reservoir parameters. A set of six representative parameters (porosity, permeability, depth and oil density, viscosity and temperature) has been chosen based on parameter correlation studies described in literature. Visualization of the cluster analysis results is performed via projection of six-dimensional vectors into two-dimensional space using the principal component method. IOR/EOR potential for a new field case is evaluated into two steps: (1) association of the case with a nearest cluster utilizing the discriminant analysis and (2) multi-dimensional interpolation of recovery factor for different methods within the cluster. A quality control is carried out at all stages of the statistical analysis to confirm its reliability. A list of potential methods with an estimation of recovery factor classified according to the confidence index (a measure of reliability) is outputted as a result of the analysis performed. Described algorithm was coded and tested on actual field case databases. The tests have shown good quality and reliability of the results obtained at all stages of the analysis. The testing has also revealed that reliable evaluation of IOR/EOR potential is possible for databases containing at least ten field cases with a particular method. Application of the new approach may serve as an IOR/EOR compass when potentially efficient methods have to be identified. A database containing actual field data and/or results of laboratory experiments and reservoir simulations may be used as an input for such analysis.
-