bluuebunny/crossref_metadata_2025 huggingface dataset:
Understanding Foam Flow with a New Foam EOR Model Developed from Laboratory and Field Data of the Naturally Fractured Cantarell Field
Authors: Skoreyko Fraser , Villavicencio Antonio Pino , Prada Hector Rodríguez , Nguyen Quoc P.
Published: April 2012

As much of the oil in the Akal field of the Cantarell complex is contained in the low permeability oil wet matrix, foam injection has been proposed as a method to control fluid mobility in the fracture, with the possible added benefit of transporting surfactant into the matrix so that additional oil could be liberated through a reduction of interfacial tension between oil and water (if this effect is significant for the surfactant in question). Presented in this paper is the work flow undertaken during an extensive study of all available laboratory experiments and pilot single well foam injection tests. Laboratory experiments ranged from simple water plus surfactant imbibition tests and surfactant flooding tests, to more complex foam flooding in split core experiments and co-injection of surfactant and gas for generation of foam in-situ. There were three field pilot single well foam injection tests that were included in this analysis that were of the huff-and-puff design. This extensive analysis was done with the aid of numerical simulation that resulted in the development of a novel foam model that handles both mobility control and interfacial tension reduction effects, and is capable of simulating foam degradation, foam regeneration, and trapped foam phenomena. Previous foam models available in commercial numerical simulators were not capable of simulating all of these foam effects together. It is shown that with identical foam parameters, this model matches all laboratory core flood studies as well as the field pilot tests, showing that this foam model is capable of predicting foam performance in both laboratory and field settings. The foam components can be chosen to be defined as either gaseous or aqueous components and this choice is shown to affect the impact of capillary pressure on foam flow into the matrix.

Also discussed in this paper are details of how the foam behaves when injected into a gas saturated zone where the foam combines with in-situ gas, resulting in higher foam qualities than was injected. It is demonstrated that foam mobility control as a function of foam quality is an important aspect for matching field performance. The significance of correct foam density calculations is also discussed using field scale models.

The work done to match the many laboratory and field scale foam tests resulted in a significant improvement of the understanding of foam degradation, regeneration, permeability blockage, and flow in porous media and the phenomena responsible for generating incremental oil.
Surfactant-Mediated Spontaneous Imbibition in Carbonate Rocks at Harsh Reservoir Conditions
Authors: Chen Peila , Mohanty Kishore K.
Published: April 2012

The goal of this work is to pursue strategies to improve oil recovery in highly fractured carbonate reservoirs by altering the wettability from oil-wet to preferentially water-wet at high temperature (100°C or above), high salinity, and especially high hardness environments. Cationic surfactants and anionic surfactants were investigated for their compatibility with hard brine and thermal/hydrolytic stability. Sequestration agents were added to improve aqueous solubility. The performance of surfactant formulations was evaluated by measuring contact angles on calcite plates and spontaneous imbibition in originally oil-wet dolomite cores. Cationic surfactants altered the wettability of oil-aged calcite plates towards a more water-wet state in the presence of hard brines; oil recovery by spontaneous imbibition from dolomite cores was 50–65% OOIP. Anionic surfactant formulations changed the carbonate wettability to strongly water-wet only when the brine salinity and divalent ion concentration were reduced. The wettability could be altered in hard brines if a sequestration agent (e.g. EDTA) is added to anionic surfactant formulations; up to 45% OOIP was recovered by spontaneous imbibitions. EDTA provides alkalinity, saponification, chelation of divalent ions, and dissolution of dolomite; these mechanisms are responsible for the increase in imbibition rate and ultimate oil recovery in fractured carbonates.
A New Class of Viscoelastic Surfactants for Enhanced Oil Recovery
Authors: Siggel L. , Santa M. , Hansch M. , Nowak M. , Ranft M. , Weiss H. , Hajnal D. , Schreiner E. , Oetter G. , Tinsley J.
Published: April 2012

A new class of viscoelastic surfactants for chemical enhanced oil recovery is presented. The triphenoxmethanes (TPM) show promise under harsh conditions of high salinity and high temperatures. The TPM's are viscoelastic at low concentrations (<0.5%w/w), show good stability in highly saline brine (18.6% TDS) that contains high concentrations of divalent cations at elevated temperatures (>70°C). Static adsorption measurements show acceptable values for the harsh conditions under study. Rheological measurements demonstrate that the viscoelasticity is not from formation of wormlike micelles and displays non-Maxwell behavior. We propose a novel supramolecular structure that explains the laboratory and rheological observations to date. The compounds show good injectivity into 2 Darcy Gildehaus sandstone

The development of this class of compounds combines the efforts of a team comprised of synthesis, analytics, rheology, core lab and computational chemistry. The goal is to develop an understanding the system's behavior from the molecular level in-silico via computational chemistry, through coreflood tests -and beyond- for a future field pilot. The structure- property-relationships that are being developed will lead to further refinement and targeted development of next generation molecules with improved properties.
Adsorption-Desorption of an Amphoteric Surfactant onto Permeable Carbonate Rocks
Authors: Zhou Xianmin , Han Ming , Fuseni Alhasan B. , Yousef Ali A.
Published: April 2012

The loss of surfactant from aqueous solutions during the propagation in the reservoirs, especially carbonate reservoirs, is one of the major concerns with chemical oil recovery processes. This is due to the loss of effectiveness of the chemical solution to reduce the oil-water interfacial tension and thus renders the process economically unfeasible. This paper presents, in detail, 10 runs of core flooding tests on dynamic adsorption and desorption of an amphoteric surfactant (OCT-1) onto permeable carbonate rocks, which were conducted in natural carbonate core plugs at reservoir temperature of 100°C and pore pressure of 3100 psi. The surfactant solution was continuously injected into the core plug until the effluent surfactant concentration approached that of the injected surfactant solution, followed by seawater injection until no surfactant was present in the effluent. The effluent surfactant concentrations were analyzed by means of titration technique. Amount of dynimc adsorption and desorption of surfactant solutions was calculated using a new definite integral method. The results showed that the adsorption of the surfactant decreases with increase in the value of the pore geometry parameter, (K/Ф)0.5. The adsorption ranges from 0.223 mg/g-rock to 0.597 mg/g-rock for the rocks with permeabilities from 688 md to 110 md. For surfactant concentration of 0.2 wt% OCT-1 in seawater that was used in the study, this level of adsorption implies the surfactant is applicable from adsorption point of view. It was also observed that the adsorption varied with the initial surfactant concentration, as well as relationship between dynamic adsorption and despersion. The value of dispersion, mechanical mixing coefficients and matching adsorption were obtained using dispersion/adsorption equations to match experimental data. This paper presents insights into the adsorption and desorption of the amphoteric type of surfactant on carbonate rocks which could help the application design for a chemical flooding process.
Snorre In-Depth Water Diversion Using Sodium Silicate - Single Well Injection Pilot
Authors: Skrettingland Kjetil , Giske Nils Harald , Johnsen Jan-Henrik , Stavland Arne
Published: April 2012

In-depth water diversion has been evaluated as a measure for increased oil recovery at the Snorre field, offshore Norway. The waterflood sweep efficiency can be potentially increased by in-depth placement of a blocking agent.

From a comprehensive qualification program presented in a previous work (SPE 143836) in-depth formation plugging was demonstrated in realistic core flood experiment using sodium silicate.

This paper highlights key results obtained from a single well pilot injection of sodium silicate in an offshore well at the Snorre field at NCS. The injection pilot was carried out successfully in June 2011 with the goal to confirm the ability of generating an in-depth permeability restriction approximately 40 m away from the wellbore. Fluids mixing and injection were performed from a vessel linked up to the platform in order to minimize the operational interference with the ongoing work on the platform.

The chosen pilot design was aimed to (a) soften the formation water by a KCl preflush, (b) control the gelation kinetics using HCl acid mixed into the diluted silicate solution, and (c) displace the silicate solution by a KCl postflush.

The in-depth permeability reduction was interpreted from injectivity measurements and from repeated pressure falloff-tests before and after the sodium silicate injection. The quality of the response measurement data was very good, and the in-depth permeability reduction was demonstrated with kinetics similar to predictions derived from laboratory experiments. The size of spacer slug applied in front of the sodium silicate was, however, on the low side. A larger spacer slug would probably be more optimal.
Review of Gas Injection Projects in BP
Authors: Brodie James , Jhaveri Bharat , Moulds Tim
Published: April 2012

BP has developed a range of innovative techniques to maximize economic oil recovery from its global miscible gas floods and the results have been reported in a series of publications over the past three decades. The purpose of this paper is to provide an overview of BP's experience of establishing, managing and optimizing a miscible gas flood.

Prudhoe Bay (Alaska) is the world's largest miscible gas project. Conventional and unconventional methods have been applied in a variety of different settings. An extensive surveillance program has facilitated a good understanding of the processes operating at field scale and surveillance data are used to optimize the flood. In 2000, a large-scale gas cap water injection project was implemented to slow the decline in field pressure. This project has made the vaporization process more efficient at higher pressure, resulting in additional recovery. Miscible gas injection has been extended to numerous other fields on the North Slope of Alaska.

BP has two active miscible gas projects in the North Sea: Magnus and Ula. Tertiary miscible water-alternating-gas (WAG) flooding in Magnus field started in 2002 and its impact on reservoir performance is significant and well understood. Tertiary miscible WAG injection in Ula field started in 1998 and has played a key role in arresting production decline. The WAG scheme in Ula is currently being expanded. In addition to these projects, BP operates a CO2 injection and storage project at In Salah, Algeria, where more than 3.2 million tonnes of CO2 have been stored since 2004.

Miscible gas injection has generated considerable benefits for BP over the past three decades and will continue to do so. The potential availability of large sources of CO2 in the future, supplied by carbon capture, could help maintain a leading role for miscible gas injection for years to come.
Research and Application on Nitrogen and Dissolver Assisted Horizontal Well Steam-Injection to Develop Shallow Thin Super Heavy Oil Reservoirs
Authors: Sun Jianfang , Yang Yong , Wu Guanghuan , Jiang long , Cao Qiuying , Zhao Yanbin
Published: April 2012

Chun-feng heavy oil field is located in Junggar Basin, western China. Dead oil viscosity is commonly more than 5×104mPa•s. The depth of the heavy oil play ranges from 400 to 500m underneath with net pay of 2 to 7m. Porosity is about 30% and permeability ranges from 5000 to 6000 md. Traditional development techniques such as steam-injection using vertical well are not effective due to tremendous heat losses, limited heat radius with thin netpay and low drainage energy.

Chun-feng oil field is developed integrally and successfully by using N2 and Dissolver Assisted Horizontal well Steam-injection technology. Peak oil production rate is up to 32t/d, which is 3 times more than that of wells using traditional technologies, and oil-steam ratio is 0.47.

In order to improve steam quality and enhance steam sweep efficiency, new techniques combing horizontal well assisted steam injection with N2 and dissolver are proposed to develop this kind of heavy oil reservoirs. Study also shows that high efficient dissolver may decrease the viscosity of the heavy oil around wellbore and increase injection steam quality; meanwhile, N2 assisted steam injection may increase the volume of injection steam, enhance the drainage energy, and decrease heat losses around wellbore effectively. By the means of plug injection of dissolver and N2 assisted by horizontal wells, super heavy oil may be recovered effectively.

Techniques mentioned above are proved to be very effective for the development of shallow thin super heavy oil reservoirs. Moreover, it is of practical significance which has been proved by successfully applying those techniques to Chun-feng oil field with over 3000* 104t proven oil reserve.
Accurate Modelling of Pore-Scale Film and Layer Flow for Three-Phase EOR in Carbonate Rocks with Arbitrary Wettability
Authors: Al-Dhahli Adnan R. , Geiger Sebastian , van Dijke Marinus I.
Published: April 2012

Three-phase flow is a key to many EOR techniques such as Water Alternating Gas (WAG) injection. Predicting oil recovery during three-phase EOR in carbonates requires a sound understanding of the fundamental flow physics in mixed- to oil-wet rocks to derive physically robust flow functions, i.e. relative permeability and capillary pressure. In this work we use pore-network modelling, a reliable and physically-based simulation tool, to predict the flow functions. We have developed a new pore-scale network model for rocks with variable wettability, from mixed to oil-wet. It comprises a constrained set of parameters that mimic the wetting state of a reservoir. Unlike other models, it combines three main features: (1) A novel thermodynamic criterion for formation and collapse of oil layers. The new model hence captures wetting film and layer flow of oil adequately, which affects the oil relative permeability at low oil saturation and leads to accurate prediction of residual oil. (2) Multiple displacement chains, where injection of one phase at the inlet triggers a chain of interface displacements throughout the network. This allows accurate modeling of the mobilization of many disconnected phase clusters that arise during higher order (WAG) floods. (3) The model takes realistic 3D pore-networks extracted from pore-space reconstruction methods and CT images as input, preserving both topology and pore shape of the rock. We validated our network model by comparing 2D network simulations with published data from WAG floods in oil-wet micromodels. This demonstrates the importance of film and layer flow for the continuity of the various phases during subsequent WAG cycles and for the residual oil saturations. A sensitivity analysis has been carried out with the full 3D model to predict three-phase relative permeabilities and residual oil saturations for WAG cycles under various wetting conditions with different flood end-points.
Multiple Foam States and Long-Distance Foam Propagation in EOR Displacements
Authors: Ashoori E. , Marchesin D. , Rossen W. R.
Published: April 2012

Foam reduces gas mobility and thereby improves sweep in enhanced-oil-recovery processes. The "strength" of foam describes the degree of gas-phase mobility reduction. Experiments show that foam can exist in three different states (weak foam, intermediate foam, and strong foam) at the same injection rate. Strong foam with fine bubbles achieves better sweep efficiency than weak foam with coarse bubbles. In experiments, creation of strong foam is triggered by an increase in superficial velocity; thereafter injection rate can be reduced to lower values and strong foam remains at velocities at which weak foam was previously observed.

It is important to determine whether strong foam created near an injection well can propagate to large distances from the well, where superficial velocity is much smaller. Here, we study strong-foam propagation with finite-difference simulations and Riemann solutions, applying a population-balance foam model that represents the multiple steady states of foam.

Our simulations show that strong foam cannot directly displace the initial high-water-saturation bank initially in the reservoir at low superficial velocities; it pushes a weak-foam state with lower velocity that in turn displaces the bank ahead. Our traveling-wave solutions show that strong foam propagates more slowly as superficial velocity decreases and stops propagating at yet lower superficial velocities, in agreement with experiment. Failure of propagation occurs at superficial velocities greater than that at which the strong-foam state disappears; it raises concerns for long-distance propagation of strong foam created near injection well. In the context of the model, it is not extraordinary destruction of foam at the front that slows the propagation of strong foam, but failure of foam (re-)generation at the front. Our model also represents for the first time a process where strong foam is created near the exit of a core and then propagates upstream, as seen in some experiments.
Case Study of Polymer Flood Pilot in a Low Permeability Mannville Sand of the Western Canadian Sedimentary Basin Using Produced Water for Blending
Authors: Irvine Randy , Davidson John , Edwards Scott , Kingsbury Jennifer , Hui-June Park , Tardiff Cara
Published: April 2012

Polymer flooding is well established using fresh waters for polymer hydration. These waters can be difficult and expensive to acquire in some regions and environmental concerns make produced waters attractive alternatives. This case study will summarize the operation of the polyacrylamide polymer pilot using produced water in the Viking Kinsella Wainwright B pool. Particular focus will be put on the treatment of the produced water to make it suitable for polymer hydration.

The pilot has clearly demonstrated that it is possible to generate a stable polymer fluid with the produced water given the high salinity and iron content. The paper will discuss the removal of undesirable elements, control of bacterial growth, compensation for the salinity and handling of the polymer injection fluid to preserve stability.

The target reservoir while having high porosity has low permeability. The permeability to oil averages 95 md which is on the lower end of the traditionally accepted range for polymer flooding. The response of the flood is not definitive but directionally is encouraging. Injectivity challenges have delayed the formation of an oil bank. Production data suggests that the oil bank is starting to develop. The economic viability of the project is indeterminate at this time.
CO2 Injection and CO2 WAG in Dipping Gas Condensate and Oil Reservoirs
Authors: Soroush Mansour , Hoier Lars , Kleppe Jon
Published: April 2012

In this study, different scenarios of CO2 injection in dipping gas condensate and oil reservoirs are investigated through reservoir simulations. Both miscible and immiscible flooding conditions were investigated for a range of different injection gas mixtures, and geological realizations.

We find particularly interesting results for miscible flooding of gas condensate systems below dewpoint pressure. Here, dropped out condensate is the prime target for enhanced recovery projects and multi-contact miscibility could develop through the combined condensing/vaporizing mechanism.

Different patterns of permeability variation with depth in layering scenarios with dip angle showed distinct different responses on produced condensate. CO2 WAG in partially depleted gas condensate reservoirs seems to have the same value of oil recovery in early times, but ultimate recovery is different according to layering heterogeneity. In the case of pure CO2 injection, both up-dip and down-dip, it was found that homogeneous layering showed highest recovery. Here developed multicontact miscible oil-bank is able to move and sweep condensate above it easier. Applying various gas injection mixtures of CO2 and C1 combinations, the effect on ultimate recovery were studied. In this case CO2 injection is above minimum miscibility pressure (MMP) resulting in high recoveries.

CO2 WAG in dipping oil reservoir was also studied extensively, based on injection pattern, MMP values and various layering systems. CO2 WAG in scenarios with increasingly trend of permeability with depth had the highest value of recovery. This is because of prevention from early gas breakthrough in upper layers and good sweep efficiency in lower layers. Pure CO2 injection with total same injection volume showed lower recovery. This may verify that gravity in WAG water injection period is the most effective parameter in the case of down-dip WAG.
Improved/Enhanced Oil Recovery from Carbonate Reservoirs by Tuning Injection Water Salinity and Ionic Content
Authors: Yousef Ali A. , Al-Saleh Salah , Al-Jawfi Mohammed
Published: April 2012

Improved/enhanced oil recovery by tuning the ionic composition of the injection water is currently deemed as new emerging recovery method. In the recent years, extensive research on oil/brine/rock systems has shown that injecting low salinity brines has a significant impact on oil recovery from sandstone reservoirs. Although, the potential for carbonates has not been carefully investigated, some reported studies have excluded carbonates from this effect.

In view of research results for the last three years, we demonstrated in previous reports (SPE 137634; SPEREE Journal, vol. 14(5), pp. 578-593, SPE 143550, SPE 141082) that substantial oil recovery beyond conventional waterflooding from carbonates can be achieved by optimizing ionic composition of field injection brine. Also, research confirmed that the driving mechanism is wettability alteration. In this paper, we present the results of new reservoir condition laboratory coreflooding studies, conducted using composite rock samples from different carbonate reservoir, to investigate the impact of ionic content on oil recovery at both secondary and tertiary recovery modes. Also, we report a broad range of laboratory studies addressing role of water ions. In addition, we briefly disclose the results of first-ever field application conducted in a carbonate reservoir to demonstrate the SmartWater Flood potential.

The experimental results revealed that substantial tertiary oil recovery beyond conventional waterflooding can be achieved by altering the ionic content of field injection water. Similar potential has been confirmed also in the secondary recovery mode. For recovery mechanisms, the new results confirmed that wettability alteration is the main cause for the substantial increase in oil recovery. Compared to previous reported work, the variation in oil recovery from two different carbonate reservoirs is attributed to the variations in reservoir temperature and also the chemistry of initial formation water. For field application, two field trials confirmed that injection of SmartWater achieved ∼7 saturation units reductions in residual oil beyond conventional seawater flooding. Considering these field trials are the first-ever applications in carbonate reservoirs, they further provided another confirmation that SmartWater Flood is emerging recovery method targeting carbonate reservoirs.
Coupling of Stress Dependent Relative Permeability and Reservoir Simulation
Authors: Ojagbohunmi Samuel , Chalaturnyk Rick , Leung Juliana
Published: April 2012

Geomechanics is increasingly being considered for inclusion in reservoir simulation, since conventional simulators do not honor deformation resulting from the interaction between stress and fluid flow response in a porous medium.

When a reservoir responds to changes in effective stress, the bulk volume adjusts, changing the pore geometry and dependent parameters like porosity, absolute permeability and effective permeability, and phase saturations. Most of the recently developed sequentially coupled approaches for coupling flow and geomechanics have focused on updating porosity and absolute permeability while changes in relative permeability (due to geomechanics) is ignored. For multiphase flow systems, relative permeability functions are one of the most influential parameters controlling fluid movement and distribution. To examine how geomechanically-influenced relative permeability may impact flow, a sequentially coupled reservoir geomechanical simulation study was conducted. The simulation workflow incorporated automatic updates of the relative permeability table for each grid block in the model at every time-step. Data for populating the geomechanical relative permeability tables was extracted from recent experimental test results reported in the literature.

Results from the simulation studies showed a significant difference in recovery factors when the impact of geomechanics on relative permeability functions was integrated into coupled simulation compared to when only changes in porosity and absolute permeability were used.

Coupled models which incorporate not only the change in permeability and porosity but also the changes in relative permeability can lead to more realistic production forecast especially for reservoirs under improved or enhanced oil recovery scheme as found in heavy oil and oil sands projects.
Mobility and Conformance Control for CO2 EOR via Thickeners, Foams, and Gels - A Literature Review of 40 Years of Research and Pilot Tests
Authors: Enick R. M. , Olsen D. , Ammer J. , Schuller W.
Published: April 2012

Carbon dioxide (CO2) has been used commercially to recover oil from geologic formations by enhanced oil recovery (EOR) technologies for over 40 years. The U.S. Department of Energy Office of Fossil Energy and its predecessor organizations have supported a large number of laboratory and field projects over the past decades in an effort to improve the oil recovery process including investments to advanced reservoir characterization, mobility control, and conformance of CO2 flooding. Currently, CO2 EOR provides about 280,000 barrels of oil per day, just over 5 percent of the total U.S. crude oil production. Recently CO2 flooding has become so technically and economically attractive that CO2 supply, rather than CO2 price, has been the constraining developmental factor. Carbon dioxide EOR is likely to expand in the United States in upcoming years due to "high" crude oil prices, natural CO2 source availability, and possible large anthropogenic CO2 sources through carbon capture and storage (CCS) technology advances. Despite its well-established ability to recover oil, the CO2 EOR process could be improved if the high mobility of CO2 relative to reservoir oil and water can be effectively and affordably reduced. The CO2 EOR industry continues to use water-alternating-with-gas (WAG) as the technology of choice to control CO2 mobility and/or mechanical techniques (e.g., cement, packers, well control, infield drilling, and horizontal wells) to help control the CO2 flood conformance. If the "next generation" CO2 EOR target of 67 billion barrels is to be realized, new solutions are needed that can recover significantly more oil than the 10–20% of the original oil in place associated with current flooding practices. A recent literature review [Enick and Olsen, 2011] concentrates on the history and development of CO2 mobility control and profile modification technologies in the hope that stimulating renewed interest in these chemical techniques will help to catalyze new efforts to overcome the geologic and process limitations such as poor sweep efficiency, unfavorable injectivity profiles, gravity override, high ratios of CO2 to oil produced, early breakthrough, and viscous fingering. This paper is a concise overview of the recent, comprehensive literature review available on the NETL website entitled "Mobility and Conformance Control for Carbon Dioxide Enhanced Oil Recovery (CO2-EOR) via Thickeners, Foams, and Gels – A Detailed Literature Review of 40 Years of Research" [Enick and Olsen, 2011] that focuses on attempts to enhance carbon dioxide mobility control (in-depth, long-term processes that cause CO2 to exhibit mobility comparable to oil) and profile modification/conformance control (near-wellbore, short-term process primarily intended to greatly reduce the permeability of a thief zone) using CO2 thickeners and CO2 foams. In particular, this paper focuses on the history of CO2 thickeners.
Numerical Simulation of Electromagnetic Driven Heavy Oil Recovery
Authors: Bogdanov Igor , Torres Jose Antonio , Corre Bernard
Published: April 2012

This work presents a feasibility study of a heavy oil recovery process driven by electromagnetic heating (EMH). Previously EMH has been subject of many research works on heavy oil recovery, including laboratory, theoretical and numerical simulation studies. These works have demonstrated that EMH constitutes a promising recovery process; however the simulations of this challenging coupled multi-physics phenomenon were not straightforward and required special efforts in model development.

The major part of previous theoretical and numerical models has been based on simplifications of the Maxwell equations for the EMH source description. The advantage of such a model is its simplicity which helps to gain a conceptual knowledge via order of magnitude estimations at reasonable computational expenses. A typical example is the use of conventional constitutive relation for the EMH source, i.e. the so-called Beer-Lambert-Bouguer law which, strictly speaking, can be applied to a limited number of practically valuable cases. Other models are required, for instance, to estimate the influence of water evaporation and resulting multiphase flow on EMH driven oil recovery.

Taking advantage of a coupled numerical simulation tool recently developed in our group, a few instructive EMH application cases capturing the effects of EM wave propagation in a non-homogeneous medium, on one side, and thermal multiphase flow in a heavy oil reservoir, on the other, are presented and analyzed in this paper.

Major attention is paid to the production efficiency. Conventional criteria adopted for such an IOR method may not be always applicable, so a comparison to known methods like SAGD or recovery by conductive heating is provided for analysis purposes. Although a number of process scenarios and options are possible, in our current study we chose for the base case a horizontal SAGD-like well pair, the upper well being equipped with an EM wave emitting facility (the EM well). Different process stages (preheating, steam chamber offset and development, and production) are considered in detail and the critical analysis of heating zone and oil flow configurations is done to find out conditions of improved recovery. In particular, the results indicate that while the preheating period can be successfully modeled using the BLB law, starting from the steam chamber offset a more realistic electromagnetic model is to be applied to adequately describe EMH heating source and production dynamics.

The EMH assisted recovery process is a promising IOR method especially for unconventional oil reservoirs. The results obtained in this work via coupled EMH/reservoir flow simulations provide an improved understanding on this challenging multi-physics problem.
Low Salinity Water Flooding Experiments and Interpretation by Simulations
Authors: Fjelde Ingebret , Asen Siv Marie , Omekeh Aruoture
Published: April 2012

Even though the proposed screening criteria for low salinity water flooding (LSWF) are fulfilled, improve recovery is not always obtained. The LSWF mechanisms are therefore still discussed. The objective for the study was to describe the brine-rock interactions at high and low salinity. Reservoir core plugs were flooded either by formation water, sea water and low salinity waters in succession or by low salinity water directly from initial water saturations. Effluent samples were analyzed for ionic concentrations and pH. Relative permeability (kr) and capillary pressure (Pc) curves were obtained at the core scale by history matching the experimental production and differential pressure across cores using a simulation tool. A developed two-phase model was used to predict the release of divalent cations from the rock during LSWF, and to relate this to the oil recovery.

The high salinity water flood with formation water was found to give close to piston-like displacement, while the oil was produced over much longer periods in LSWF. The estimated kr- and Pc-curves indicated that the rock was water-wet in the high salinity floods and mixed-wet in the low salinity floods. The experimental results were in accordance with the modeling of the brine-rock interactions. When the formation water was replaced with the low salinity water, increase in the concentrations of divalent cations onto clay surfaces was predicted for the selected brine compositions. Higher concentrations of polar oil components can then be bonded to the clay surfaces by the divalent cations and make them less water-wet. It is concluded that the low salinity water altered the wetting state of the rock. The direction of alteration can be explained by ion exchange taking place on the clay surface. The low salinity water potential for improving recovery should be considered on a case by case basis based on the interactions between the formation brine, injected brines, oil components, and rock type.
Modeling of Ion-Exchange and Solubility in Low Salinity Water flooding
Authors: Omekeh Aruoture , Friis Helmer André , Fjelde Ingrebet , Evje Steinar
Published: April 2012

The potential of low salinity water flooding (LSWF) to improve oil recovery in sandstone cores has been well documented. The objective of this paper is further development and examination of a one-dimensional mathematical model for the study of water flooding laboratory experiments. The model describes how dissolution/precipitation of various carbonate minerals and multiple ion-exchange (MIE) will have an impact on the water-oil flow function. The model is formulated such that the total release of divalent cations from the rock surface will give rise to a change of the relative permeability such that more oil is mobilized. The combined effect of MIE and dissolution/precipitation was modelled to determine how this will affect pH and the total release of divalent cations

The effects of solubility of carbonate minerals on the ion exchange process during the LSWF have been studied. Dynamic experiments were carried out using brines with different compositions and reservoir rocks. The ion concentrations and pH in effluent samples were determined.

In experiments, pH was found to increase during the interaction between low-salinity brine and reservoir rocks. The ion composition of the low salinity brine was also found to change due to interaction with the reservoir rocks. The model developed successfully matched the experimental results. The simulation results show that dissolution of carbonate minerals can occur and this will then alter the composition of the injected low-salinity brine, the concentration of divalent ions on the rock surface and hence the potential of low salinity to improve recovery.

It is important during the evaluations of the potential for LSWF to take into account that dissolution of minerals can change the composition of the injected low salinity brine. The potential should be evaluated using the composition that the brine will have in the main part of the reservoir.
Chemical EOR Pilot in Mangala Field: Results of Initial Polymer Flood Phase
Authors: Pandey Amitabh , Kumar M. Suresh , Jha Manish Kumar , Tandon Rohit , Punnapully Brennan S , Kalugin Mavriky , Khare Ashish , Beliveau Dennis
Published: April 2012

The Mangala field in the Rajasthan state of western India was the first major oil discovery in the Barmer Basin. It contains over 1 billion bbls of paraffinic oil with average viscosity of ~15cp and wax appearance temperature only ~5°C less than reservoir temperature. The initial development plan is a hot waterflood to prevent in situ wax deposition; however, chemical EOR methods are expected to play an important role in the ultimate field development strategy.

EOR assessment was part of the initial field development planning process. Screening studies were conducted soon after discovery followed by comprehensive laboratory evaluations of chemical flood potential which had been identified as the most suitable process. The laboratory evaluation along with parametric simulation studies indicated significant chemical EOR potential. A closely spaced normal 5-spot pilot was designed to test chemical EOR processes in the early part of the field development. Logging observation wells are strategically placed in the pilot to periodically monitor changes in oil saturation.

The initial waterflood phase in the pilot has been completed and injection of the polymer slug is in progress. Comprehensive monitoring and quality control procedures are being followed to ensure smooth operations. Extensive PLTs, time-lapse saturation and resistivity logs, pressure surveys, tracer surveys, detailed produced fluid analyses and tests for monitoring the quality of injected fluids are all performed routinely. Dynamic reservoir modeling has been a critical part of the analysis to understand polymer flood behavior. The initial polymer flood phase in the pilot will be followed by ASP (alkaline-surfactant-polymer) injection for further evaluation of chemical EOR potential.

This paper discusses the operational aspects of polymer flood facilities, quality control and monitoring program followed, challenges faced, polymer injection results and plans for future ASP injection.
CO2 Injection in Porous Media: Observations in Glass Micromodels Under Reservoir Conditions
Authors: Robin M. , Behot J. , Sygouni V.
Published: April 2012

CO2 injection process is of high interest in applications such as CO2 storage in reservoir rocks, enhanced oil recovery or soil remediation. The optimization of such a process requires a detailed reservoir petrophysical description but also representative three-phase transport properties in porous media. Imbibition and drainage processes are dominated by interfacial phenomena. The displacement mechanisms are affected by wettability and interfacial tensions.

A series of experiments were conducted in glass micromodels of varying wettability, aiming at describing three phase displacements involving brine, oil and CO2. They have been conducted under various conditions of pressure and temperature.

Experiments under varying thermodymic conditions (gaseous, liquid and supercritical CO2) were conducted on porous media of different wettabilities. Fluids distribution within the porous medium under reservoir conditions was visualized and conclusions concerning important parameters such as the spreading coefficient which plays a major role in oil recovery were drawn. These observations were confirmed by core scale experiments such as capillary pressure curves and displacements at the core scale.

Additionally, we observed the in situ formation of CO2 foams generated from surfactants dissolved in the aqueous phase. These foams (or emulsions) were also formed from gaseous, liquid or supercritical CO2. CO2 and surfactant solutions were co injected in the porous media. Foam formation and evolution from the inlet to the outlet of the porous medium was followed.
Pore-Scale Evaluation of Polymers Displacing Viscous Oil – Computational Fluid Dynamics Simulation of Micromodel Experiments
Authors: Clemens Torsten , Tsikouris Kostas , Buchgraber Markus , Castanier Louis , Kovscek Anthony
Published: April 2012

Recovery of viscous oil can be significantly improved by injecting polymer solutions. The processes leading to increased oil production occur on a large scale – improving vertical and areal sweep efficiency – but they begin on a micro scale.

Micromodels with realistic pore geometries have been created. These micromodels were saturated with viscous oil and the displacement of the oil by water and polymer solutions investigated experimentally. Polymer injection reduced fingering compared with water injection and increased sweep efficiency accordingly.

The micromodel pore network geometry was digitised using Scanning Electron Microscopy (SEM). The digitised model was used to perform Computational Fluid Dynamics Simulations (CFD) of the displacement processes.

The displacement efficiencies and displacement patterns of the CFD simulations using water, polymer solutions, and polymer solutions after water breakthrough at the outlet end to displace oil were very similar to the results of the micromodel experiments.

Then, the CFD simulations were used to investigate the displacement at the pore scale. Water injection leads to creation of fingers along slightly more permeable flowpaths. The number and length of the fingers decreases if polymer solution is injected. Even for polymer injection after water breakthrough, the fingering is reduced, polymer solutions are diverted into less favourable flow paths and sweep efficiency is increased.

CFD simulations can also be used to look into nonNewtonian fluid behaviour at the pore scale. The polymers injected in the micromodel experiments exhibited shear-thinning behaviour. On a pore scale, CFD simulations showed that the shear stress and viscosity of the polymer solutions accordingly are significantly lower in the pore throats than in the pores. Hence, the displacement efficiency of the polymer solutions is impacted by the shear-thinning behaviour.

The CFD simulations are in remarkable agreement with the micromodel experiments and can be used to quantify the displacement processes at pore scale.
Gravity-Enhanced Transfer between Fracture and Matrix in Solvent-Based Enhanced Oil Recovery
Authors: Kahrobaei S. , Farajzadeh R. , Suicmez V. S. , Bruining J.
Published: April 2012

Solvent injection has been considered as an efficient method for enhancing oil recovery from fractured reservoirs. If the mass transfer would be solely based on diffusion, oil recovery would be unacceptably slow. The success of this method therefore depends on the degree of enhancement of the mass exchange rate between the solvent residing in the fracture and the oil residing in the matrix.

A series of soak experiments have been conducted to investigate the mass transfer rate between the fracture and the matrix. In a soak experiment, a porous medium containing oil is immersed in an open space containing the solvent to simulate the matrix and the fracture respectively. We use a CT scanner to visualize the process. The experimental data are compared with a simulation model that takes diffusive and gravitational forces into account.

We find that the initial stage of all experiments can be described by a diffusion-based model with an enhanced "effective diffusion coefficient". In the second stage enhancement of the transfer rate occurs due to the natural convection of solvent in the fracture. The experiments are quantitatively modeled by numerical simulations. We find that transfer rates depend on the properties of the rock permeability, the viscosity and the density of solvent and oil. The gravity enhanced transfer is quantified by comparison of experimental and simulated results.
Surfactant Flooding in Heterogeneous Formations
Authors: Lohne Arild , Fjelde Ingebret
Published: April 2012

The potential for surfactant flooding of oil fields can be obtained using field-scale surfactant simulation model with capillary number (Nc) dependent relative permeability, kr. Typically, kr(Nc) is solely based on core flood experiments. In this paper, surfactant recovery mechanisms in presence of heterogeneities smaller than the field simulation grid block are investigated. Effects of reducing the interfacial tension, IFT, are investigated in various models by numerical simulation of the displacement process and by steady-state upscaling. It is demonstrated that measured core-scale results should go through appropriate averaging before they are used in a field-scale surfactant model.

Macro-scale effects of IFT in presence of small-scale heterogeneities are examined separately. Capillary trapping of oil in heterogeneous formations depends on the geometric distribution of permeability and wettability and on IFT. In general, reduced IFT has little or possibly negative effect on production from water-wet, low-permeability inclusions embedded in a mixed-wet background. Production from mixed-wet, low-permeability inclusions will in general be increased at reduced IFT.

The IFT level needed to mobilize capillary trapped oil is proportional to the heterogeneity scale. At normal field flow rates, it was found that oil recovery was sensitive to variation in IFT at scales less than approximately 10 m. IFT reduction down to 1 mN/m was found sufficient for heterogeneities of length scale 10 cm. It is shown that the effect of capillary trapping in heterogeneous formations can be represented as Nc-dependent relative permeability function at the larger scale and that the larger-scale functions can be obtained from rate dependent steady-state upscaling. The macro-scale effects described here comes in addition to the measured core-scale effects, and may increase the potential for surfactant flooding.