bluuebunny/crossref_metadata_2025 huggingface dataset:
Katz (Strawn) Unit Miscible CO2 Project: Design, Implementation, and Early Performance
Authors: Smith David J , Kelly Troy R , Schmidt David L , Bowden Cindy E
Published: April 2012

A miscible CO2-solvent flood has commenced at the Katz (Strawn) Unit (KSU) located in Stonewall County, Texas, on the Eastern Shelf of the Permian Basin. The reservoir is comprised of three distinct Pennsylvanian-age Strawn fluvial deltaic sandstones. CO2 injection into the KSU began in December 2010 with definitive flood response seen seven months later. Project design was challenged by severely limited geologic, production, injection, and wellbore data. The following paper is a summary of the methods used to evaluate, design, and implement this miscible CO2 project. This project is significant in that it provides a lengthy extension of the CO2 pipeline network outside of the Permian Basin which creates an entirely new basin for CO2 projects.

Limited data sets will become more prevalent as tertiary recovery projects extend from major producing basins to next tier targets. Typical parameters usually provided by reservoir simulation, such as total recovery, WAG ratios, slug sizes, etc. were determined using analog data and analytical techniques due to the lack of subsurface data and detailed performance information.

The design techniques presented in this paper provide a means to implement tertiary recovery with limited data sets from smaller target lower tier assets which remain in the Permian Basin. Many other assets may be plagued by a lack of data (production/injection, petrophysical, geophysical, wellbore), and present a significant challenge to engineers and geoscientists. The discussion outlines a methodology used and the results generated.
A Successful Pilot of Dilute Surfactant-Polymer Flooding in Shengli Oilfield
Authors: Li Zhenquan , Zhang Aimei , Cui Xiaohong , Zhang Li , Guo Lanlei , Shan Liantao
Published: April 2012

The first pilot of dilute surfactant-polymer flooding in the world was carried out by Shengli Oilfield Company in Ng54‒61 reservoir of West 7 Block, Gudong oilfield in Sep. 2003, the daily oil production increased and the water cut decreased significantly. The daily oil production in Central Block increased to 11.3 times, from 127.5 t/d to 10.4 t/d,; the water cut decreased by a factor of 37.9%, from 98.3% to 60.4%. Up to Dec. 2011, the oil recovery increased by a factor of 16.7%. The estimated ultimate oil recovery can be up to 18% of OOIP. The performance on the pilot was analyzed. The results showed that the flow resistance and the swept volume increased due to the polymer while the displacement efficiency was improved due to the surfactant. The amplitudes of water cut decrease and daily oil production increase during dilute surfactant-polymer flooding in the pilot area were higher than single polymer flooding.
Thermally Activated Particle Treatment to Improve Sweep Efficiency: Pilot Test Results and Field Scale Application Design in El Borma Field (Tunisia)
Authors: Galli Giuseppe , Morra Daniela , Ghaddab Fethi , Sitep Marcello Tesconi , Manrique Eduardo , Tiorco Glyn Freeman
Published: April 2012

El Borma is a mature oil field located onshore in the Northern Sahara Desert, Tunisia. Oil production commenced in 1966 and is currently supported by water injection; the high water cut (96%) and permeability contrast in the main reservoir (Level "A") indicated thief zones with less than optimum sweep efficiency prompting the evaluation of a tertiary method for improved oil recovery. In January of 2010 a pilot project (injector-producer) was implemented to evaluate a thermally activated particle (TAP) system as a strategy to improve the sweep efficiency of ongoing water injection program.

This paper will summarize TAP pilot implementation and will describe methodology and results of project monitoring and injection-production performance. The evident good results of this TAP application (decrease in water cut with consequent increase in oil recovery up to 55%) in the last fourteen months justified a larger scale application in the field.

The field scale application design was performed in two different steps: 1) Comprehensive production-injection data analysis of injectors based on the number of connected (offset) producers and channel volume estimations and; 2) The numerical simulation studies of most promising patterns calibrated with information generated during the first TAP pilot. Screening of patterns candidates and simulation approach of TAP will be also presented.

El Borma pilot results validate the potential of TAP as an in-depth conformance strategy that can improve sweep efficiency of mature waterfloods. El Borma workflow to screen and rank patterns candidates combined with pilot project implementation, monitoring and evaluation can be used as a reference to evaluate the benefits of TAP technology in waterflooded oil reservoirs.
Improving Heavy Oil Recovery Using an Enhanced Polymer System
Authors: Fletcher P. , Cobos S. , Jaska C. , Forsyth J. , Crabtree M. , Gaillard N. , Favéro C.
Published: April 2012

This paper introduces the benefits of a hybrid polymer system for enhanced heavy oil recovery (EOR) that contains viscosifying anionic polyacrylamides (HPAM) and a recently developed, low toxicity, low molecular weight, dispersing polymer (LMwDP).

Conventional EOR polyacrylamides increase sweep efficiency, but are not thought to mobilize residual oil since they have limited effect on wettability and interfacial tension. To improve displacement efficiencies, costly concentrations of surfactants are added to polymer solutions to increase capillary numbers. These surfactant concentrations are designed to accommodate the high level of adsorption within the porous medium. Surfactant dosage can be reduced from 0.5% to 1% down to 0.05% to 0.2% using alkalis, but this often requires expensive water softening systems and higher polyacrylamide concentrations to reach the required viscosity.

The LMwDP in the hybrid polymer system mimics the surfactant role without some of their disadvantages, at concentrations between 0.2% and 0.5%. Indeed, the LMwDP affects neither the viscosity of the HPAM solution, nor the injection and production facilities. The system is particularly beneficial to the recovery of medium to heavy oil, i.e., above 200 cP. Several HPAM chemistries have been tested at concentrations between 0.03% and 0.2%.

This paper presents experimental oil recovery factors, using HPAM and 20,000 g/mol LMwDP, in 9 to 12 darcy sandpacks with porosities of approximately 40%. The oil viscosity was 3,000 cP at 50°C, 16,400 cP at 30°C and 40,700 cP at 20°C.

In these reported studies, oil recovery factors with the hybrid polymer system were 70% higher than a brine alone baseline and 20% higher than brine plus HPAM. Trends in recovery factors indicated that each polymer in the formuation mutually enhances the performance of the other, i.e., there is a synergy between the components. The sand pack results generated essential data required for history matching, which then allowed up-scaling using an industry standard reservoir simulator.

Additional studies are in progress to optimize the dosages, and the cost of this hybrid polymer system, for a field implementation of this EOR technology to the recovery of medium to heavy oil.
Stabilization of Interfacially-Active-Nanohybrids/Polymer Suspensions and Transport through Porous Media
Authors: Baez Jorge L. , Ruiz M. Pilar , Faria Jimmy , Harwell Jeffrey H. , Shiau Ben , Resasco Daniel E.
Published: April 2012

Novel amphiphobic nanoparticles based on functionalized carbon nanotubes (CNT) have shown promising applications for enhanced oil recovery, by lowering the water/oil interfacial tension upon adsorption or chemical reaction catalyzed by these nanoparticles. Challenges for this novel approach include a) stabilizing aqueous suspensions of the nanoparticles in the presence of brine, b) propagating these suspensions through a porous media, c) conducting reactions at the interface.

It is well-known that it is difficult to suspend CNT in liquids since they are amphiphobic. Thus, surfactants or polymers are needed to create stable suspensions. Here, several polymers have been tested to disperse CNT in water. Even though some of them produced very stable nanohybrid suspensions in deionized water, when brine was present in the medium, in most cases the suspension destabilized and the nanohybrids settled out.

We were successful in stabilizing nanohybrids suspensions in brine, by using polyvynil-pyrrolidone (PVP). However, in propagation experiments of these suspensions through a porous media (crushed Berea sandstone, 75-250 μm particle size, k = 4.2 D, Φ = 35%), it was observed that the PVP strongly interacted with the sand in the presence of elevated brine (10% solution), leading to low particle recoveries (< 10 %). Conversely, with PVP in deionized water, the particle recovery was higher than 90 %. After trying to get a good particle recovery of brine nanohybrid suspensions, we discovered an effective binary polymer combination that produced very stable nanohybrid suspensions that propagated through the Berea sand, with a particle recovery of 80 %. This polymer combination consisted of a sequential addition of PVP and a proprietary high salinity-resistant polymer, which reduces the rock/polymer interaction.

We envision these engineered nanoparticles having a great impact in the characterization of the reservoir and enhancement of oil recovery.
Optimization of Viscosifying Surfactant Technology for Chemical EOR
Authors: Morvan M. , Degré G. , Beaumont J. , Dupuis G. , Zaitoun A. , Al-Maamari R S. , Al-Hashmi A R. , Al-Sharji H H.
Published: April 2012

Recent publications indicate injection of polymer solutions at concentration larger than conventional polymer flooding can result in higher recovery at field scale. Typically more than 20% OOIP compare to waterflooding have been reported (Wang et al; 2011). However injectivity issues have to be considered when injecting such concentrated polymer solutions. This work describes an alternative approach based on surfactant-based fluids. The technology we have developed matches the rheological properties of polymer solutions in a broad range of reservoir conditions (temperature & salinity) without any injectivity limitation even when considering very viscous surfactant solutions (ie up to 1000 cps) and low permeability cores.

Average first normal stress difference measurements have been used to compare the elastic properties of surfactant and high molecular weight polymer solutions. The Degrée of non linearity in the mechanical properties for both fluids has been expressed by Weissenberg number. The surfactant solution has much larger Weissenberg number than the polymer solution at a shear rate corresponding to the fluid propagation in the reservoir.

The potential of this surfactant-based technology is illustrated through a specific reservoir case involving heavy oil. A series of core-flood experiments has been performed in reservoir cores. The surfactant slug can be combined with a conventional low-concentration polymer flooding to further improve the process. Reduction in residual oil saturation in the range of ΔSw = 10-15% has been obtained. Complementary simulation study giving rise to economic analysis have been performed.
CO2 Mobility Control With Dissolved Polymers: A Core-Scale Investigation Of Polymer-Rock and Polymer-Oil Interactions
Authors: Rousseau David , Renard Stéphane , Prempain Benoît , Féjean Christophe , Betoulle Stéphane
Published: April 2012

CO2-dissolved polymers could be used as mobility control agents for CO2-EOR. Unlike classical CO2 mobility control techniques, using polymers would involve a single thermodynamically stable CO2 phase and would not require water injection, which would eliminate difficulties linked to well acidification. Developing an industrial "CO2-polymer" EOR method implies three challenges. i) Suitable polymers must be evaluated in terms of solubility in CO2 under reservoir conditions and thickening ability. ii) Polymer-oil and polymer-rock interactions must be understood. Their consequences in terms of effective polymer transport far from the injection wells and potential mobility or permeability impairment must be physically modeled. iii) Reservoir scale simulations must be carried out to determine an economically optimal scenario (with parameters such as viscous slug size and polymer concentration).

Although the first of the abovementioned topics has received some attention from researchers in the past years, the two others have not been studied yet. In this paper, we report, for the first time, an investigation of polymer-oil and polymer-rock interactions from coreflood experiments involving polymer-thickened CO2. We have studied polydimethylsiloxane-based model systems whose solubility in CO2 and viscosity enhancement ability have been previously evaluated in the literature. The coreflood tests were carried out with an experimental setup designed to enable on-line viscosity measurements downstream the cores and quantitative compositional analysis of the effluents. Results show that part of the injected polymer is immobilized in the porous media, and that this phenomenon originates not only from adsorption/retention in the rock surface/matrix but also from polymer dissolution in residual oil. We have also observed that polymer immobilization had moderate impact in terms of injectivity degradation and no impact in terms of irreversible permeability reduction. These insights could be used as input data for reservoir simulation.
Controlled Hydrophobe Branching to Match Surfactant to Crude Oil Composition for Chemical EOR
Authors: Barnes Julian R. , Groen Khrystyna , Dubey Sheila , Reznik Carmen , Buijse Marten A. , Shepherd Andrew G.
Published: April 2012

In this paper an innovative structure/property approach is used to evaluate several commercially available surfactants in tests relevant to both alkaline-surfactant-polymer (ASP) and surfactant-polymer (SP) floods, in order to gain an understanding of how hydrophobe structure is related to surfactant performance and crude oil composition. The surfactant structural elements considered here include relative branching level and carbon chain length. This has application to chemical EOR implementation in fields over a range of reservoir temperatures and salinity. Phase behavior (giving interfacial tension), and micro-emulsion viscosity tests were carried out for internal olefin sulfonates and mixtures with alcohol propoxy sulfates to identify those that perform well while minimizing or eliminating the use of costly co-solvents. Hydrophobe branching and carbon chain length, characterized by gas chromatography, were used to match surfactants to certain crude oil properties such as natural surfactants, including total acid number (TAN) and asphaltenes, and the ratio of saturates/aromatics. The paper also examines how crude oil sampling influences crude properties and surfactant performance. The approach used and associated data contribute to cost reduction of formulations through a) better matching of commercially produced surfactants to the reservoir and crude oil properties to improve oil recovery efficiency, and b) minimizing or eliminating the use of co-solvents to reduce formulation and logistics costs. In addition, the study demonstrates how binary blends from a few core surfactants can match formulations across regionally different crude oils thereby simplifying formulation selection, and reducing uncertainty and cost.
Field Scale Application of the SOS-FR (Steam-Over-Solvent Injection in Fractured Reservoirs) Method: Optimal Operating Conditions
Authors: Naderi K. , Babadagli T.
Published: April 2012

Heavy oil reserves are considered to be the upcoming hydrocarbon resource. Yet, more efficient methods are needed as there are substantial economical and environmental drawbacks to sole injection of steam and solvents. A combined application of these yielded promising results in the laboratory experiments. But, optimal application conditions and cost lowering options need to be determined.

Steam-over-solvent injection in fractured reservoirs (SOS-FR) is a recently proposed method which consists of an alternate injection of steam and hydrocarbon solvents to improve oil recovery over steam injection and accelerate the solvent retrieval rate. The initial tests were done for hot-water conditions instead of steam and liquid solvents for simplicity (Al-Bahlani and Babadagli, 2008; 2009a-b; 2011b). In our modification to this method, we introduced CO2 as an alternative to hydrocarbon solvents for only one pressure and temperature condition (Naderi and Babadagli, 2012). Initial results out of this study showed a moderate recovery of 50% OOIP in average for unfavorable matrix conditions (oil wet).

In the present study, the SOS-FR applications with CO2 were tested at various conditions numerically and with different timings to improve the recovery. First, the effect of different parameters was studied to obtain the best match between the simulation and experimental results. This exercise not only provided data for field scale simulations (relative permeability and diffusion coefficients) but also clarify the impact of different rock and fluid properties on the mechanics of the proposed EOR technique.

Finally, an optimization scheme was suggested for field scale applications. In this exercise, a field scale numerical model of experiments was performed based on experimentally validated core scale model and the optimal conditions (solvent type, application pressure and temperature, duration of cycles) were determined to maximize the recovery.
A New Formulation For Decoupling of Large and Small Scale Heterogeneities in Multi Layered Reservoirs
Authors: Moghanloo Rouzbeh Ghanbarnezhad
Published: April 2012

This paper examines decoupling of the small-scale heterogeneity and permeability variation in multi-layered reservoirs. Here, the growth of vertically averaged concentration is formulated through incorporating dispersivity and the permeability variation; hence, unrealistic large dispersivity values, needed otherwise, are avoided to match the concentration distribution in time-distance domain.

A simulation approach is used to verify the analytical solution derived in this study. The simulation models consist of a vertical injection well and a producer located at the ends of two-dimensional (2D) heterogeneous reservoirs. The vertically averaged concentration from simulation is compared with the average concentration obtained from the analytical solution. The simulation results match the analytical solution.

It is concluded that scale-dependent dispersivity in the field-scale represents the lack of knowledge about the heterogeneity involved in the system. The results suggest that the effects of permeability heterogeneity that are ignored while using the one-dimensional (1D) solution of the convection-diffusion (CD) equation manifest themselves as an apparent scale-dependent dispersivity. Furthermore, the impact of heterogeneity and dispersivity on the length of the mixing zone within each layer of 2D reservoirs is evaluated in this study. From that, I determine the fraction of layers in which the mixing zone grows faster than that 1D dispersive flow as a function of the Koval factor and input dispersivity. The transition between channeling and dispersive flow regimes is clearly shown in the examples studied here.
Evaluation of a Vietnam Offshore CO2 Huff "n" Puff Test
Authors: Uchiyama Tadao , Fujita Yusuke , Ueda Yoshiaki , Nishizaki Aiko , Okabe Hiroshi , Takagi Sunao , Mitsuishi Hiroshi , Kawahara Yohei , Huy Le , Trung Phan Ngoc , Trung Nguyen Huu , Van Toan Nguyen , Hoan Nguyen Ngoc
Published: April 2012

First CO2-EOR application to the offshore oil field in Vietnam has been investigated through an international joint study scheme between Japan and Vietnam since 2007 and a preliminary study outcome indicated feasibility to some extent. To reduce and mitigate uncertainties/risks in the field scale EOR implementation, a CO2-EOR pilot test was executed in Vietnam offshore oil field in 2011.

The test was conducted as a single-well Huff ‘n’ Puff. CO2 was injected into the well and the well was flowed after soaking. In order to confirm the CO2-EOR effect the following items were monitored during the test: 1)CO2 Injection Performance2)Real Time Bottom-hole Pressure/Temperature3)Oil/Gas/Water/CO2 Production Performance4)Fluids' Saturation Change before and after CO2 Injection5)Produced Fluid Property & Composition on-site

Over 100 tons of CO2 were successfully injected into the well. Bottom-hole pressure was kept higher than MMP (Minimum Miscibility Pressure) during the injection period, thus miscible condition was considered to be achieved in the reservoir at least near the wellbore. The vertical contrast of CO2 injectivity and oil saturation change in the reservoir were confirmed by saturation logs and production logs. Clear increment of oil rate, reduction of water cut and oil composition change were observed after CO2 injection. Simulation study for matching pilot test performance was carried out and its result was in good agreement with the monitored data.
A Dimensionless Capillary Pressure Function for Imbibition Derived from Pore-Scale Modelling in Mixed-Wet Rock Images
Authors: Zhou Y. , Helland J. O. , Hatzignatiou D. G.
Published: April 2012

It has been demonstrated experimentally that Leverett's. J-function yields almost unique dimensionless drainage capillary pressure curves in relatively homogeneous rocks at strongly water-wet conditions, whereas for imbibition at mixed-wet conditions, it does not work satisfactorily because the permeability dependency on capillary pressure has been reported to be weak. The purpose of this study is to formulate a new dimensionless capillary pressure function for mixed-wet conditions, based on pore-scale modeling, which could overcome these restrictions. We simulate drainage, wettability alteration and imbibition in 2D rock images using a semi-analytical pore-scale model which represents the identified pore spaces as cross-sections of straight capillary tubes. The fluid configurations occurring during drainage and imbibition in the highly irregular pore spaces are modeled at any capillary pressure and wetting condition by combining the free energy minimization with an arc menisci-determining procedure that identifies the intersections of two circles moving in opposite directions along the pore boundary. Circle rotation at pinned contact lines accounts for mixed-wet conditions. Capillary pressure curves for imbibition are simulated for different mixed-wet conditions in Bentheim sandstone samples, and the results are scaled by a newly proposed improved J-function that accounts for differences in formation wettability induced by different initial water saturations after primary drainage. At the end of primary drainage, oil-wet pore wall segments are connected by many water-wet corners and constrictions that remain occupied by water. The novel dimensionless capillary pressure expression accounts for these conditions by introducing an effective contact angle which depends on the initial water saturation and is related to the wettability measured at the core scale by means of a wettability index.

The accuracy of the proposed J-function is tested on 36 imbibition capillary pressure curves for different mixed-wet conditions that are simulated with the semi-analytical model in SEM images of Bentheim sandstone. The simulated imbibition capillary pressure curves and the reproduced curves, based on the proposed J-function, are in good agreement for the mixed-wet conditions considered in this study. The detailed behavior is explained by analyzing the fluid displacements occurring in the pore spaces. It is demonstrated that the proposed J-function could be applied to mixed-wet conditions to generate a family of curves describing different wettability conditions induced by assigning different wetting properties on the solid surfaces or by varying the initial water saturation after primary drainage. The variability of formation wettability and permeability could be described more accurately in reservoir simulation models by means of the proposed J-function, and hence allow for improved evaluation of core-sample laboratory experiments and reservoir performance.
Towards a New Theory for Improved Oil Recovery from Sandstone Reservoirs
Authors: Sunde E. , Lillebø B.-L. , Torsvik T.
Published: April 2012

As discoveries of large new oilfields become a thing of the past, the residual oil in old oilfields becomes an increasingly important oil resource. Significant research and development efforts on increasing recovery have however yielded low results. We believe that the main reason for this is that the current models for how residual oil is trapped and mobilized are wrong. Several field observations have shown that mobilized residual oil moves more rapidly through the reservoir than the injected water assumed to be pushing it. This is not possible within the framework of current reservoir simulation models. We here present a new theory for the behaviour of residual oil in sandstone reservoirs.

Based on field cases and a laboratory study we argue that the residual oil is collected in continuous oil strands extending from injector to producer and blocked only by water in a pore close to the producer. The blocking water of that pore throat can be removed by applying a pressure pulse to the oil strand or by reducing the capillary force that makes the water adhere to the wall of the pore throat.

In a flooding experiment where the flow rate of oil and water was followed with oil and water soluble tracers, the results showed that oil moved 1000 times faster than the injection water through the core. Field observations involved oil fields, where analysis of H2S concentration at the producers showed that H2S had been transported with the oil and moved faster than the water through the reservoir. In an MEOR pilot increased oil production ceased almost immediately after the microbial activity was stopped, showing a continuous oil phase from injector to producer even under residual oil concentration.

Applying this new knowledge can considerably increase the recovery from most oil fields.
Advanced Screening Technologies for the Selection of Dense CO2 Foaming Surfactants
Authors: Chabert M. , Morvan M. , Nabzar L.
Published: April 2012

Injection of dense supercritical CO2 (sc-CO2) represents today more than half of the EOR projects carried out in USA. While sc-CO2 flooding is very effective in mobilizing trapped oil at the microscopic (pore-scale) level, this technology is usually limited by unfavorable mobility ratio and gravity segregation issues. In that context, use of dense CO2 foams (emulsions) may be one of the most robust methods for improving sc-CO2 flooding efficiency and maximizing oil recovery at reservoir scale. However, surfactant screening for dense CO2 foams has until now been extremely time consuming and limited to a few products due to strong technical constraints (high pressure equipments). Here, we report an original set of high throughput screening for optimizing dense CO2 foams formulations. The formulation yielding the best results is further characterized in corefloods experiments.

We use a proprietary high pressure jet-drop transition technique to screen interfacial properties of molecules at the dense CO2 / brine interface. The surfactants showing significant interfacial activities between aqueous solution and sc-CO2 are selected for the next steps. We use an autoclave to generate highly sheared foam with low cell sizes and study generated foam stability in a high pressure variable volume view cell. Structure/properties relationships are extracted from our numerous screening experiments and complement existing design rules for dense CO2 foam formulations.

A surfactant formulation yielding superior sc-CO2 foam stability is tested for mobility reduction in low-permeability carbonate cores. Using a CO2/aqueous solution co-injection scheme, we observe various flow regimes for different fractional flows. We confront these first results to the existing theories of foam flooding in porous media.
Experimental and Numerical Investigation on the Performance of Gas Oil Gravity Drainage at Different Miscibility Conditions
Authors: Ghasrodashti A. Ameri , Farajzadeh R. , Verlaan M. , Suicmez V. S. , Bruining J.
Published: April 2012

Gas oil gravity drainage is an effective oil recovery process, which has been proven in the field. Under favorable conditions the displacement is stable and for the right surface tension combinations the residual oil saturation is low. In the absence of gas dissolution, the recovery after gas injection is usually low as a large amount of oil remains capillary trapped in the matrix blocks. However, when the main gas constitutes is soluble in the oil, the dissolution leads to mixing and interfacial tension (IFT) reduction, which cause gravity enhanced transfer between matrix and fracture. Therefore, a study of the mechanisms that control the interactions between fracture and matrix (e.g. capillarity, gravity, phase behavior and flow behavior) can help to optimize recovery. This paper concerns an experimental study to investigate whether gravity drainage is also an effective recovery process in fractured reservoirs. In this study, we describe six gas injection experiments conducted at different miscibility conditions, i.e., immiscible, developed miscible and first contact miscible (FCM), using CO2, nitrogen and flue gas. In addition, the impact of switching from an immiscible (Nitrogen, Flue gas) injection gas to non-equilibrium and fully miscible CO2 injection is investigated. In one of the experiments, we study the effect of a permeability barrier on the recovery efficiency from the matrix block when CO2 is injected in the fracture at immiscible and miscible conditions. Accurate modeling for the transfer between fracture and matrix is also essential for accurate recovery predictions. In this study, a numerical model is developed to perform compositional simulations of gas injection for different miscibility scenarios. Results revealed that ultimate oil recovery increases considerably once miscibility is reached. Miscibility can usually be achieved at high pressures only. High pressure gas injection has two disadvantages, viz., (1) one may need a larger mass of gas to fill the pore space from where the oil is recovered and (2) the density of injected gas increases significantly, which reduces the density difference between the gas and oil. This leads to less effective gravity mediated recovery. Even if the impermeable layer impairs the performance of the gas oil gravity drainage (GOGD) process for immiscible gas injection, it improves the recoveries for first contact miscible gas injection.
Optimization of a Mature CO2 Flood — From Continuous Injection to WAG
Authors: Zhou Dengen , Yan Meisong , Calvin Wm. Marc
Published: April 2012

Although CO2 EOR is a well-accepted technology with 30+ years' field history, the optimization in its design and operation is historically constrained by the oil price – trying to minimize the cost especially when oil price is low. When we enter a high oil price regime, CO2 becomes a valuable commodity and its supply starts to limit the flood operation and design.

This paper will first review the industrial practice of CO2 design and optimization and the current status of CO2 projects within Chevron. We then focus on a case study to demonstrate the impact of reservoir heterogeneity on flood design. The field was originally designed as crestal gravity stable CO2 injection based on the excellent water flood performance. Good initial oil response was observed but followed by high gas recycling and complicated operational issues. The simulation study suggests that the existence of high permeability, vertical conduits causes the CO2 flow rates in the reservoir significantly higher than the critical gravity-stable flow rate resulting in high gas recycling. Therefore balancing recovery efficiency and project economics is a challenge for gravity stable injection design. A tapered WAG design is proposed to improve operational flexibility and recovery efficiency in this mature field. The case study also demonstrates that it is critical to include proper characterization of flow barriers and channels for a successful CO2 flood design.
Oil Recovery by Sequential Waterflooding: the Effects of Aging at Residual Oil and Initial Water Saturation
Authors: Loahardjo Nina , Xie Xina (Sheena) , Winoto Winoto , Buckley Jill , Morrow Norman R.
Published: April 2012

Sequential waterflooding refers to cycles of flooding for which initial water saturation is re-established after a waterflood by flow of crude oil followed by further waterflooding. In previously reported examples of sequential waterflooding, cores were neither cleaned nor re-aged at high crude oil saturation between floods. Numerous core floods with different rock types showed significant decrease in residual oil saturation from one flood to the next (Loahardjo et al. 2010a). Systematic decrease in residual oil saturation by sequential waterflooding was confirmed by nuclear magnetic resonance imaging measurements of in-situ saturations (Loahardjo et al. 2010b).

In this work, sequential waterflooding has been demonstrated for outcrop Berea sandstones of medium and low permeability: both showed reduction in residual oil saturation with each sequential flood. The tests have been extended to include aging periods at either residual oil saturation or initial water saturation. Aging at residual oil saturation (high water saturation) resulted in an increase in oil recovery for the subsequent flood, with larger increases observed for extended aging times. After an extended period of aging at initial water saturation (high oil saturation), decreased oil recovery was observed. The variations in oil recovery are consistent with changes in wettability that depend on oil saturation during displacement and subsequent aging conditions.
Fundamental investigations into wettability and low salinity flooding by parameter isolation
Authors: Suijkerbuijk B. M. , Hofman J. P. , Ligthelm D. J. , Romanuka J. , Brussee N. , van derLinde H. A. , Marcelis A. H.
Published: April 2012

Improved oil recovery by low salinity waterflooding (LSF) represents an attractive emerging oil recovery technology, as it is relatively easy to implement and low-cost compared to other Improved and Enhanced Oil Recovery (IOR and EOR, respectively) processes. Even though LSF leads to extra oil recovery in most laboratory experiments and some promising data from the field have been presented, the mechanism underlying LSF is still unclear. Therefore it is difficult to predict a favorable performance of LSF in one field a priori, while dismissing others.

This paper describes a series of spontaneous imbibition experiments on Berea outcrop core plugs, and some reservoir rock core plugs, that were designed to determine the impact of formation water, imbibing water and crude oil composition on wettability and on wettability modification by LSF. The data presented in this paper lead us to conclude that: Spontaneous imbibition experiments with formation brine and low salinity brine executed on Berea outcrop material aged with a crude oil show excellent reproducibility;An increasing concentration of divalent cations in the formation brine makes a Crude Oil/Brine/Rock system more oil-wet;The extent of wettability modification towards more oil-wet upon aging also depends on the types of cations in the formation brine;Improved oil recovery by exposure of the aged plugs to NaCl brines occurred when the imbibing phase was either higher or lower in salinity than the formation brine;Aging of the same brine/rock system with different crudes having diverse physico-chemical properties led to:○A spread in wettabilities after aging○A crude oil-dependent low salinity effect

These results are discussed within the context of several mechanisms that have been put forward previously as an explanation for the low salinity effect.
Secondary and Tertiary Recovery of Crude Oil from Outcrop and Reservoir Rocks by Low Salinity Waterflooding
Authors: Winoto Winoto , Loahardjo Nina , Xie Xina (Sheena) , Yin Peigui , Morrow Norman R.
Published: April 2012

A wide range of outcrop sandstones and carbonates have been tested for waterflood response to one twentieth dilution of synthetic seawater, using a single crude oil that gave high response to low salinity flooding for a reservoir rock. The tested outcrop rocks included 17 sandstones and 6 carbonates. Gas permeabilities ranged from 1.49 to 7,187 mD and porosities from 10 to 39%. The average reduction in residual oil for tertiary response was only 1.5% OOIP with the highest being 5.8% OOIP; some rocks showed no response. After testing, three of the outcrop rocks that responded to injection of low salinity brine were restored by cleaning and re-aging with crude oil using procedures comparable to those commonly used in restoration of reservoir cores. When re-tested, the response to low salinity flooding was eliminated for two of the cores and significantly reduced for the third core. Companion plugs for 6 of the sandstones and 3 carbonates were tested for increased oil recovery using low salinity connate and injected brine; this data provided comparison with the measurements for high salinity connate and injection brine. Six of the plugs showed increase in recovery for the low salinity waterfloods, and three showed decrease. Results are also summarized for the effects of reduction in salinity for 11 sandstone cores taken from five reservoirs and 8 carbonate cores all taken from the same reservoir. Comparison between results for outcrop and reservoir cores, including literature data, indicates that overall response to low salinity flooding is significantly higher for the reservoir cores.
A Texas MEOR Application Shows Outstanding Production Improvement Due To Oil Release Effects On Relative Permeability
Authors: Akintunji Folami , Marcotte Brian , Sheehy Alan , Govreau Bradley
Published: April 2012

A Microbial Enhanced Oil Recovery (MEOR) application in the Big Wells Field located in Dimmit County, Texas has shown a significant improvement in production—both oil rate and water cut performance. As a result of a specific nutrient injection designed in the laboratory to stimulate in situ, naturally occurring microbes, for this San Miguel sandstone reservoir and its microbial ecology, a marked improvement was seen in the two producing wells to which the treatment was applied. The water cut in one well improved from fifty per cent to fifteen percent. The water cut in a second well improved from fifty-five to thirty-five percent.

Although previous field applications of this MEOR process had shown increases in oil production and decreases in water production, water production in this application was completely stopped for a brief time as a result of the treatment. This paper reviews the Big Wells producing well treatments and their results. A specific look at the oil release mechanism of this MEOR process offers an explanation as to how the oil released by these treatments impacts the relative permeability of fluids in the reservoir near the treated wellbores as demonstrated in the field producing well treatments. Similar benefits are seen during the treatment of water injection wells related to performance in adjacent producing wells.

The significance of this application is that field evidence supports that production improvements result from the release of oil in sufficient quantities to change the near wellbore relative permeability to both oil and water. Also, it demonstrates that this MEOR technology can be successfully applied to reservoirs in this geographical area and extends the lower threshold for formation permeability suitable for treatment. Having been successfully applied in other parts of North America, this is an important application of this MEOR technology in Texas.
Modeling of Foamed Gas Mobility in Permeable Porous Media
Authors: Balan H. O. , Balhoff M. T. , Nguyen Q. P.
Published: April 2012

In mechanistic modeling of foam in porous media, reduced gas mobility is attributed to viscous resistance of flowing foam lamellas to gas flow, while gas trapping significantly modifies relative permeability. By using pore-network models representative of real porous media, we previously developed a relationship between flowing gas fraction and pressure gradient for strong foam (high lamella density). In this study, we expand our model to describe the effects of foam strength and pore-scale apparent gas viscosity models on both relative gas permeability and effective gas viscosity. Dimensional analysis in scaling of these two rheological quantities with pressure gradient and lamella density is discussed.

One of our important findings is that relative gas permeability is poorly sensitive to total lamella density while it is a strong non-linear function of flowing gas fraction, opposing to most of the existing theoretical models describing the effect of gas trapping on relative gas permeability. This is consistently observed for all the pore-scale apparent gas viscosity models. It is also found that effective gas viscosity increases exponentially with flowing lamella density. This result implies that the use of the commonly used apparent gas viscosity model for straight capillary tubes is not accurate for foam flow in porous media. In addition, shear thinning foam flow is more obvious at high flowing lamella density while Newtonian flow becomes significant at relatively low flowing lamella density. Furthermore, scaling of effective gas viscosity with flowing lamella density depends on how the later quantity is defined. Both empirical and mechanistic pore-scale apparent gas viscosity models give almost the same functional relationship between flowing gas fraction and pressure gradient. This would facilitate scaling of flow rate with pressure gradient and testing a range of shear-thinning and yield-stress behavior in a simple format. Our results necessitate the need for further improving the existing mechanistic foam modeling methods with focus on process upscaling.
Low Salinity Waterflood at Reduced Capillarity
Authors: Spildo Kristine , Johannessen Annette Meland , Skauge Arne
Published: April 2012

A new generation EOR methods comes from combining techniques to make the overall process more efficient and minimize the retention or loss of chemicals. One of the hybrid EOR methods we are investigating combines low salinity brine and reduced capillarity by surfactants, which has potential to increase EOR oil and cost efficiency.

It is well documented that low salinity waterflooding may give improved recovery. Judging from published data, it is likely that more than one mechanism is contributing to the observed oil recovery. We have summarized that two of the main effects are destabilization and mobilization of oil layers, and fines migration due to destabilization of clays. The latter is believed to contribute to increased oil recovery by pore blocking and microscopic diversion. If capillary forces are high, the oil mobilized by either of these two mechanisms is easily re-trapped. However if the capillary forces are lowered by adding surfactant, re-trapping may be avoided.

The effect of decreasing interfacial tension was investigated in a series of constant rate, low salinity floods performed on crude oil aged Berea sandstone cores. The purpose is to explore the added benefit of the low salinity surfactant process over low salinity brine injection, and to investigate to which extent the capillary forces needs to be reduced to take advantage of the incremental recovery that may be obtained by combining the two processes. The results show that reduction of interfacial tension in low salinity waterfloods gives an increase in oil recovery which exceeds the expected performance of injecting a solution with the same reduction in interfacial tension but without the low salinity contribution.

The combined effect of low salinity brine and surfactant injection may have the potential to improve the economy of EOR operations. The desalination cost and logistic involved may in some cases limit the possibility for low salinity waterflood, but enhanced oil recovery by simultaneous lowering of interfacial tension giving a much higher additional oil recovery may improve the overall economy.
Development of a Novel and Computationally-Efficient Discrete-Fracture Model to Study IOR Processes in Naturally Fractured Reservoirs
Authors: Moinfar Ali , Varavei Abdoljalil , Sepehrnoori Kamy , Johns Russell T.
Published: April 2012

Many naturally fractured reservoirs around the world have depleted significantly and improved oil recovery (IOR) processes are necessary for further development. Hence, the modeling of fractured reservoirs has received increased attention recently. Accurate modeling and simulation of naturally fractured reservoirs is still challenging owing to permeability anisotropies and contrasts. Non-physical abstractions inherent in conventional dual porosity and dual permeability models make them inadequate for solving different fluid-flow problems in fractured reservoirs. Also, recent technologies of discrete fracture modeling suffer from large simulation run times and the industry has not found applications for them yet, even though they give more accurate representations of fractured reservoirs than dual continuum models.

We developed a novel discrete fracture model for an in-house compositional reservoir simulator that borrows the dualmedium concept from conventional dual continuum models and also incorporates the effect of each fracture explicitly. In contrast to dual continuum models, fractures have arbitrary orientations and can be angled or vertical, honoring the complexity of a typical fractured reservoir. Likewise, the new discrete fracture model does not need mesh refinement around fractures and offers computationally-efficient simulations compared to other discrete fracture models. Examples of water-flooding and gas injection are presented in this paper to demonstrate the accuracy, robustness, and applicability of the developed model for studying IOR processes in naturally fractured reservoirs. Simulations show that favorable rock wettability along with capillary pressure contrasts between matrix and fractures causes noticeable incremental oil recovery in water floods. Likewise, simulations of gas injection demonstrate that high-permeability fractures not only expedite gas breakthrough, but also increase segregation of gas towards the top of the reservoir, leading to very low sweep efficiency. Furthermore, oil recovery from naturally fractured reservoirs is found to be sensitive to the fracture inclination angle.