bluuebunny/crossref_metadata_2025 huggingface dataset:
A Novel Ultra-low Interfacial Tension Foam Flooding Agent to Enhance Heavy Oil Recovery
Authors: Kang Wanli , Liu Shuren , Meng Lingwei , Cao Dongqing , Fan Haiming
Published: July 2010

Foam as a mobility control agent in enhanced oil recovery is becoming more and more attractive. Recently, ASP foam flooding method was proposed, which was based on the mechanism of both lowering interfacial tension to an ultra-low value (10−3mN/m grade) and improving sweep efficiency of displacing fluid. However, the alkali (NaOH or Na2CO3) in the ASP system will bring about scaling in the reservoir and pipelines if the formation water contains a large number of divalent cations such as Ca2+ and Mg2+. Therefore, it is necessary to develop a non-alkali foam flooding system to improve oil recovery.

A novel ultra-low interfacial tension foam agent is developed by the combination of surfactant and additives to lower oil-water interfacial tension and the addition of polymer to improve foam stability. Firstly, the concentration of surfactant and non-alkali additives used as the foam agent was determined by interfacial tension contour diagram. Then, the molecular weight and concentration of HPAM to enhance foam stability in the reservoir was screened. The foamability of the formula was measured using airflow method. Furthermore, the effects of temperature, salinity and shearing on the interfacial property and foamability were investigated to know the adaptability of this method to different oilfields. The heavy oil displacement experiments showed that the final oil recovery could be improved approximately 23% initial-oil-in place over waterflood recovery for the heterogenous core model of which permeability variation coefficient is 0.65, more than that of alkaline-surfactant-polymer flooding.
Well Bore Heat Loss - Options & Challenges for Steam Injector of Thermal EOR Project in Oman
Authors: Wang Jianshe (James) , Macfadyen Ross , Zhang Eamon , Mukhaizna Occidental
Published: July 2010

Wellbore heat loss is an important factor in steam flooding. It influences the magnitude and form that heat energy is injected into the reservoir, which impacts final recovery and project economics as well as flooding conformance in the context of viscous fingering of the liquid phase. Sufficient down hole steam quality is critical for the success of steam flooding projects. Heat loss can be measured by steam quality change from wellhead to bottom hole. Many factors affect down hole steam quality, such as completion design and injection rate. It is a reservoir management and production surveillance challenge to obtain quantifiable down hole steam quality values. Unfortunately, reliable down hole steam quality measurement is still effectively unavailable.

This paper introduces a study and practice for steam injection wellbore heat loss modeling for Mukhaizna steam flood project in Oman. A state-of-the-art numerical thermal well model is used, supported by some empirical data calibration. Important influencing factors are discussed in the paper including completion design, injection rate, reservoir pressure, etc. The findings of this study strengthen and enhance the knowledge and understanding of steam injector behavior. Some useful practical guidelines for injection well design and field operation are recommended.
Designing Alcohol-Free Surfactant Chemical Flood for Oil Recovery
Authors: Shiau B. J. , Harwell Jeffrey H. , Dinh Anh V. , Roberts Bruce L. , Hsu Tzu-Ping , Anwuri Ovinuchi I.
Published: July 2010

This work shows a unique method for determining the composition of an aqueous solution for chemical EOR using surfactants, salts, and polymer without the addition of a co-solvent. Phase behavior studies composed of reservoir brine, alkali, surfactants, salts, polymer and reservoir crude oil are evaluated as a function of time for onset of phase equilibrium and middle phase formation at ambient temperature and pressure. The optimal surfactant formulation was confirmed by a fast coalescence rate of formation of middle-phase microemulsion and ultra-low interfacial tension. Optimum formulations from phase behavior studies are further evaluated in 1-D sand-pack using crushed sandstone, reservoir oil, and brine at reservoir temperature. One half of a pore volume (PV) of the selected surfactant/polymer (SP) or alkali/surfactant/polymer (ASP) solution is used to flood the column and is followed with reservoir brine until no more oil is produced. The optimum SP and ASP compositions for oil mobilization from the sand pack studies are then investigated in a core flood apparatus. Residual oil saturation was first established in a Berea core at the targeted reservoir temperature and pressure. The core is then flooded with 0.5 PV of the optimum SP or ASP formulation, followed by reservoir brine until no more oil is produced. A unique aspect of this work is that the packed column studies predict core flood results. Packed bed studies are much faster, the apparatus is much less complex and much less expensive, relative to a core flood apparatus. The level of surfactant loading is 0.51% to 0.55% with 2.1% salt. The alcohol-free surfactant loading is lower that previously reported levels. Core floods show oil recoveries ranging from 55% to 64% of the residual oil after waterflooding.
Quantifying Geochemical Interactions When Injecting into a Sour Oil or Gas Field
Authors: van Putten Sascha , Gupta Arjit , Oraimi Mahmood , Abri Ali
Published: July 2010

In this paper the study results for gas and/or water injection into sour fields located in the South Oman Salt Basin (SOSB) is presented. The hydrocarbons in the fields are contained in carbonate “stringer” reservoirs, which are slabs of carbonates floating within salt. The fields in this area are typically high pressure, high temperature sour (H2S and CO2) reservoirs.

The typical development concept for these type of fields in general follows a staged approach: (1) An appraisal phase, (2) An early production phase from primary depletion, followed by (3) a miscible gas flood (or a water flood), and ultimately (4) a gas blow down phase. The objective of this phasing is to allow for optimal learning and economies of scale.

This paper presents a part of the work done in preparation of the third development phase with a specific focus on quantifying the interaction of an injectant with the reservoir rock. In other words due to geochemical reactions of the injected gas (or water) with the host rock or formation water, mineral dissolution or precipitation can occur. As a result, the reservoir properties in the reservoir are altered that could potentially result in well injectivity and/or productivity issues (either through pore plugging or fine migration).

The development of reactive flow simulation tools that are capable of modeling the relevant process (e.g. fluid flow, geochemistry, rock behavior) is currently an active research topic in industry. In this paper we will present a modeling workflow to improve our fundamental understanding taking into account some of the current limitations of the modeling tools. The workflow will be described through presenting several modeling examples using different simulation tools (e.g. geochemical modeling tools, PVT modeling tools).
Effect of Clay, Brine and Chemical Treatment in the Wettability Alteration of Berea Rock
Authors: Wu Stanley , Firoozabadi Abbas
Published: July 2010

Alteration of wettability from liquid wetting to intermediate gas wetting has great potential in improving gas well productivity from water-blocking and condensate blocking in gas reservoir. Presence of some salt ions such as Na+ even in small quantities in the initial water in the rock has detrimental effect on the alteration of wettability. Berea cores are usually used in laboratory flow studies including in the alteration of wettability. In this work, we present a comprehensive study on the use of Berea, both unfired and fired, in single and two-phase flow with a focus on salt effect on wettability alteration. Three fluoro-chemicals are used in the treatment. We find that one of the three, a nonionic polymeric surfactant is very effective in the alteration of wettability in fired Berea with and without initial salt presence in the rock. The treatment efficiency of ionic surfactants is reduced at the presence of initial salt.
Integrated Evaluation of Surfactant-Polymer Floods
Authors: Gao P. , Towler B. , Li Y. , Zhang X.
Published: July 2010

This paper proffers some guidelines for using a surfactant-polymer (SP) flooding operation so that the feasibility and profit can be optimized. Many successful projects have shown that surfactant-polymer flooding is an effective means to improve oil recovery after or during water-flooding. Here, the guidelines for evaluating whether a surfactant-polymer flood is suitable for a given field are developed and the procedure for a full implementation is summarized. These guidelines cover primary screening, laboratory measurements, reservoir simulation, economic analysis, pilot testing, and field application. Detailed methods also are presented for the optimization of chemicals (including compatibility tests between chemicals and reservoir fluids and rock), well pattern and spacing preparation, and slug and injection process design. The correlations between the above phases of operation are also emphasized. The work offers reservoir engineers a reference for decision-making in SP flooding.
A Drilling Rate Model for Roller Cone Bits and Its Application
Authors: Hareland G. , Wu A. , Rashidi B.
Published: July 2010

Modeling bit performance is a scientific approach to optimizing drilling performance. Drilling rate or rate of penetration (ROP) is one of bit performance indexes. Several ROP models for roller cone bits have been developed over the years. However, there exist errors to some extent between these models and the field. This is because of the technical complexity of the bit-rock interaction. This paper introduces a new ROP model based on the interaction mechanism between drill bit and rock. The ROP model takes into account bit structure, especially cutting structure, and drilling parameters, such as WOB, RPM, and bit wear. The paper then focuses on applications of the ROP model in predicting drilling rate and rock compressive strength with drilling well data from Western Canada.

Simulations were carried out using the ROP model for roller cone bits with two sets of offset well drilling data. The predicted ROP and rock strength when the model is used in an inverted mode were compared with field data or results from log rock strength data respectively. The comparison shows the ROP model can predict drilling operational ROP and rock compressive strength well.

The ROP model is different from others in that it takes into account the bit cutting structure in more detail. The model can reflect the effects of different number of inserts and insert shape on ROP.

The model is especially useful when selecting a roller cone bit with same IADC code but with different insert features and designs, and can be used in optimizing the drilling parameters in a planning mode and predicting the unconfined compressive strength in an inverted mode.
CO2 Based VAPEX for Heavy Oil Recovery in Naturally Fractured Carbonate Reservoirs
Authors: Gul Ali , Trivedi Japan J
Published: July 2010

With the increasing demand for energy production and environmental concerns, the focus has been shifting towards new green recovery techniques for heavy oil complex reservoirs such as naturally fractured carbonate reservoirs (NFCRs). After the success of VAPEX as an alternate to SAGD for heavy oil recovery, it has been studied for fractured reservoirs in recent years. Moreover, CO2 has been a successful EOR agent in fractured light-medium oil reservoirs and thus can be used as a higher soluble, low cost, and environment friendly alternate to solvent. Our aim is to show that CO2 with VAPEX could be a feasible choice for NFCRs. This work is focused on investigating the applicability and optimization of CO2 based solvent extraction process for heavy oil recovery and greenhouse gas sequestration from NFCRs.

A series of numerical experiments were performed to study the role of a) solvent type, b) operating condition, c) oil and gas diffusion, and d) extraction process; in various single/multiple fracture configurations while injecting CO2 - solvent in different ratios. The optimal injection rate and CO2 - solvent concentration ratio were obtained considering maximum oil recovery and CO2 storage. A parametric study was also performed to analyze the influence of various operational and reservoir parameters such as fracture properties, fracture configurations, oil viscosity, solvent type, and injection/production constrains. The results suggested that CO2 or conventional VAPEX alone may not be able to achieve higher recovery in high pressure NFCRs, but CO2 based VAPEX can provide efficient technique to recover heavy oil with emphasis on sequestration.
Exciting New Technology for Monitoring HT Wells
Authors: Shanks David
Published: July 2010

It has historically been difficult to permanently monitor steam flood operations and also HPHT wells as the gauges available have short life spans and also give erroneous results. This project demonstrates a new, unique, robust, and available technology which will enable reliable monitoring of high temperature oil wells in the future. The ability to reliably monitor steam floods and HPHT wells will alter production and completion strategy and improve reservoir drainage.

This paper is outlining a new technology which allows us to monitor well pressure and temperatures up to 500 Celcius

The paper gives a description of a brief history of high temperature downhole gauges, a description of the development of the HT and XT technology and an outline of the first well installations.

This paper details the testing and results in the lab and also achieved results from the first field installations. Some test results are shown and early technology blockers discussed, as well as field installation problems and how they have been overcome. The paper has photographs of equipment and the installations, as well as graphical presented results.

We outline the state of maturity of this technology and the industry uptake. The results demonstrate a powerful new tool available to operators, previously thought unattainable.
In-situ Estimation of Relative Permeability from Resistivity Measurements
Authors: Li K. , Shapiro M. , Horne R. N. , Ma S. , Hajari A. , Mudhhi M.
Published: July 2010

Relative permeability is one of the key parameters governing fluid flow through porous media. Determination of relative permeability is traditionally conducted in the laboratory using either recombined reservoir oil or laboratory oil at simulated reservoir conditions or simply at laboratory room conditions. This is because it is expensive to sample representative uncontaminated reservoir fluids and extremely difficult to cut reservoir cores without altering their surface properties. Restoring rock properties to their original reservoir conditions has been a technical challenge to the industry. Upscaling laboratory special core analysis data to reservoir scale is also a concern. Consequently, the industry has been researching new methods to extract relative permeability in-situ including using specially designed permanent downhole electric resistivity array measurements.

In this study, a different approach was taken. A semianalytical model, developed to infer relative permeability from resistivity, was verified using experimental and field data. Relative permeability and resistivity were measured simultaneously in the laboratory. The results demonstrated that relative permeability derived from measured resistivity were close to the measured relative permeability. Relative permeability calculated from resistivity logs in two wells was compared to measured relative permeability with encouraging results. With this approach, it would be possible to obtain a distribution of relative permeability characteristics throughout an entire reservoir for enhanced reservoir engineering studies.
Investigating Productivity of Vertical and Horizontal Wells in One of the Persian Oil Fields
Authors: Mirzaei Paiaman Abouzar , Karimi Mohammad Rahim , Safian Gholam Abbas
Published: July 2010

First horizontal well in Iran was drilled in July 1992 in Marun oil field. Since then, most of the Persian giant oil fields have experienced horizontal drilling. This can be considered as a step towards improved recovery.

In this paper we try to compare the productivity of vertical and horizontal wells in a particular field. This field is located in the Southern part of Iran, with two separate carbonate reservoirs, R1 and R2. R1 is on the top and R2 in the bottom. An impermeable layer separates the two reservoirs. In this field about 50% of drilled wells are horizontal. Production results from horizontal wells are not satisfactory, and in most cases productivity index of horizontal wells is equal or even less than vertical wells, therefore the reasons should be investigated.
Control of Numerical Dispersion in Simulations of Augmented Waterflooding
Authors: AlSofi Abdulkareem M. , Blunt Martin J.
Published: July 2010

Augmented waterflooding is where a component is co-injected for the purpose of modifying the fractional flow curve: examples include polymer flooding, surfactant injection, low salinity waterflooding and carbonated water injection (including applications related to carbon dioxide storage). The numerical simulation of these processes is a challenge for several reasons: the appropriate physical behavior needs to be incorporated consistently into empirical models of the fractional flow, while the solutions should minimize numerical dispersion, allowing the correct and accurate tracking of compositional variations.

Traditional numerical simulations of these processes give excessive front smearing, requiring many thousands of grid blocks in one dimension to resolve the fronts adequately, rendering the predictions from three-dimensional simulations dubious at best. These erroneous predictions are not caused by phase dispersion (the improper prediction of water velocity), as in black-oil simulation, where the effect is less significant, but occurs because of the coupling of compositional dispersion with fractional flow. Small errors in composition alter the fractional flow, causing the development of incorrect wave speeds. The same effect is also seen in compositional simulation of gas injection.

We propose a simple method, based on the assumption of segregated flow within a grid block, that substantially reduces numerical dispersion. After comparing numerical and analytical results in one dimension, we implement the method into a three-dimensional streamline-based simulator of polymer flooding that also incorporates a physically-based model of the fluid rheology. We demonstrate that traditional simulation methods can vastly over-estimate recovery, potentially leading to poor injection design and management decisions. We demonstrate the utility of our approach by suggesting optimal strategies for the design of polymer injection based on our improved simulation technique. We also discuss extensions of the method to fully compositional displacements involving many chemical components.
Mechanistic Modeling of Chemical Transport in Naturally Fractured Oil Reservoirs
Authors: Abbasi-Asl Yousef , Pope Gary A. , Delshad Mojdeh
Published: July 2010

Surfactants both change the wettability and lower the interfacial tension by various degrees depending on the type of surfactant and how it interacts with the specific oil. Ultra low IFT means almost zero capillary pressure, which in turn indicates little oil should be produced from capillary imbibition when the surfactant reduces the IFT in naturally fractured oil reservoirs that are mixed-wet or oil-wet. The question is then what is the transport mechanism for the surfactant to get far into the matrix and how does it scale with distance in a matrix block of a fractured reservoir?. Recent dynamic laboratory data suggest that the process is faster when a pressure gradient is applied compared to static imbibition tests. A mechanistic chemical compositional simulator was used to study the effect of pressure gradient on chemical oil recovery from naturally fractured oil reservoirs for several different chemical processes (polymer, surfactant, surfactant-polymer, alkali-surfactant-polymer flooding). The fractures were simulated explicitly by using gridblocks with fracture properties. Both homogeneous and heterogeneous matrix blocks were simulated. Microemulsion phase behavior and related chemistry and physics were modeled in a manner similar to single porosity reservoirs. The simulations indicate that even very small pressure gradients (transverse to the flow in the fractures) are highly significant in terms of the chemical transport into the matrix and that increasing the injected fluid viscosity greatly improves the oil recovery. Large-scale simulations show that the transverse pressure gradients promote transport of the surfactant into the matrix at a feasible rate even when there is a high contrast between the permeability of the fractures and the matrix. These simulations indicate that injecting a chemical solution that is viscous (because of polymer or foam or microemulsion) and lowers the IFT as well as alters the wettability from mixed-wet to water-wet, produces more oil and produces it faster than static chemical processes. These findings have significant implications for enhanced oil recovery from naturally fractured oil reservoirs and how these processes should be optimized and scaled up from the laboratory to the field.
Coning Control and Recovery Improvement Using In-situ Water Drainage/Injection in Bottom - Water - Drive Reservoir
Authors: Jin L. , Wojtanowicz A. K.
Published: July 2010

Technology that directly controls water coning employs in-situ water drainage using oil wells with downhole water sink (DWS) bottom completions. With DWS, the well's oil productivity dramatically improves as oil can be recovered from a thin pay zone underlain by bottom water – an impossible undertaking for conventional wells. However, concurrent drainage of large volumes of water depresses water drive – particularly in the reservoir systems with small aquifers.

A natural extension of the water sink technology for small aquifers is the concept of returning the drained water to the same aquifer using triple-completed wells with downhole water loop (DWL). DWL technology retains all benefits of water coning control without depleting energy of water drive. However, DWL well completions have to be properly spaced to avoid pressure interference and the drained water must be oil-free to be injected in-situ into the same well.

The reported simulation study compares recovery performance of conventional, DWS and DWL wells in variety of oil reservoirs with bottom water coning from aquifers of different size and strength. The results show increasing superiority of DWL over conventional and DWS wells in reservoirs with decreasing aquifer strength. For example, when the aquifer is big, the DWL well recovery is similar to that for conventional and DWS wells but is 5-fold slower than that for DWS. However, when the aquifer is small, DWL recovers 60 percent more oil with 43 percent less water in 10 percent shorter time comparing to conventional well, while DWS fails to perform at all due to the fast depletion of reservoir pressure.

Also, the simulation experiments demonstrate operational flexibility of DWS and DWL wells. For conventional wells, a small improvement in recovery requires reduced production rate and extended producing time. In contrast, the recovery process of DWS and DWL wells can be optimized for maximum recovery, minimum production time or minimum produced water by seeking the best combination of the oil production and water drainage/injection rates.
Scale Dependence of Diffusion in Naturally Fractured Reservoirs for CO2 Injection
Authors: Alavian S. A. , Whitson C. H.
Published: July 2010

Based on detailed compositional simulations of matrix/fracture systems, we present results of the impact of diffusion on oil recovery by CO2 injection for small-scale laboratory experiments and field-scale systems. We consider reservoir conditions that lead to a range of recovery mechanisms from clearly immiscible to near-miscible.

Laboratory experimentation is a desirable approach to understanding the recovery mechanism of CO2 injection in fractured oil reservoirs because an unusual combination of complex physical phenomena exists. A fundamental problem with this approach is scaling the results to field conditions, and particularly matrix block size which is often many (5–100) times larger than laboratory cores. Molecular diffusion is clearly affected by matrix block dimensions, and any affect of diffusion on the recovery mechanism would also be scale dependent. In this paper we provide guidelines and computational examples of laboratory tests to study CO2 recovery processes, including diffusion. We also study the change in recovery processes as matrix/fracture dimensions approach field scale.

We recommend using reservoir core or outcrop samples similar to the actual reservoir rock, with dimensions (5–25 in2 horizontal area and 10–30 in high). A synthetic model oil can be constructed to mimic PVT properties of the actual reservoir oil, and in particular the minimum miscibility pressure (MMP) as defined by a traditional 1D multi-contact displacement process – MMP1D, reduced gas-oil interfacial tensions (IFT) and oil-gas density differences. The core should be placed in a container with annular space representing the fracture. CO2 is injected at various rates into the annular space, at relevant reservoir pressures both above and below the MMP1D.

In this work, the effect of several key parameters are studied – matrix permeability, matrix block size, CO2 injection rate and reservoir pressure. One of the key results is the effect of diffusion on oil recovery, and how it varies with matrix block size and CO2 injection rate. We show that diffusion has a dominant effect on recovery mechanism in experimental tests, except at very low CO2 injection rates. For field-scale matrix/fracture systems, diffusion has a significant effect on the rate of recovery, the effect becoming noticeable for low reservoir pressures and/or high fracture densities.

Compared with earlier studies on the Iranian Haft-Kel reservoir considered in this paper, our current work shows that the rate of high recoveries by CO2 injection reaches more than 90% 2–10 years with diffusion, versus >100 years in the absence of diffusion, for an 8x8-foot matrix grid.
Comparison of Methods for Drainage Relative Permeability Estimation From Displacement Tests
Authors: Hussain F. , Cinar Y. , Bedrikovetsky P.
Published: July 2010

This paper compares classical and contemporary methods used to obtain relative permeability from dynamic experiments. We apply a variety of analytical, semi-analytical and history matching methods to analyze experimental data of oil-water unsteady-state drainage displacements. The analysis involves two types of error: bias and variance errors. The bias error in the resultant relative permeabilities mainly comes from the smoothening and differentiation of the experimental data while the variance error represents statistical uncertainty in measurements. We elect to use our own experimental data to minimize the variance error. We compare the numerical and functional fitting methods proposed for the differentiation and apply spline and Gaussian functions for fitting production and pressure data, respectively. We use spline fitting improved by time-domain data sampling to achieve a more effective history match. This approach minimizes the effects of non-uniqueness and shape dependency of relative permeability curves. We present a modification of the semi-analytical method of Civan and Donaldson (1989).

Comparison of different methods shows that analytical methods are in agreement with each other but differ from the semi-analytical and history matching methods. The modified semi-analytical approach agrees well with the improved history matching. The spline and Gaussian functions for fitting experimental data are capable to preserve the data shape and yield less bias error. The function fitting methods are more effective than numerical methods in differentiation/integration of experimental data, preserving the features of the data and minimizing the errors. Semi-analytical methods provide a better first guess for history matching. Use of the cubic spline curves for relative permeability makes the relative permeability curve more flexible and any shape of the curve can be produced. There is a trade-off between the simplicity of the conventional Corey-type power law function and the accuracy of the cubic splines.
Impact of Distillation on the Combustion Kinetics of High Pressure Air Injection (HPAI)
Authors: Barzin Y. , Moore R. G. , Mehta S. A. , Ursenbach M. G. , Tabasinejad F.
Published: July 2010

During the last two decades HPAI (High Pressure Air Injection) has proven to be a successful recovery method in deep light oil reservoirs. Distillation, flue gas drive and thermal front effects are the most dominant mechanisms associated with oil recovery in HPAI processes. This paper describes the results and observations of an experimental study conducted to characterize distillation, not only as a recovery mechanism but moreover as a phenomenon that impacts the kinetics of light oil combustion in HPAI.

Distillation or vaporization-condensation of light fractions of oil in thermal processes, more frequently in steam flooding and in-situ combustion, has been studied since its first recognition in 1960. Compositional effect of distillation on phase behavior of light oils, through stripping, and displacement of light ends through vaporization-condensation has been recognized as important. However, certain aspects of distillation such as the latent heat associated with vaporization of hydrocarbons, type of residual fuel remaining in the liquid phase after progression of an evaporation front, and more importantly the type of fuel transferred to the vapor phase through vaporization, all of which impact the kinetics of light oil combustion, has been missing in HPAI studies.

This study aims to shed light on the impact of distillation on formation and progression of the thermal front and reaction kinetics associated with the vapor phase oxidation/combustion. For the purpose of this study, oxygen and nitrogen injection experiments were performed on a recombined light oil core sample in a 45cm long, ramped temperature oxidation (RTO) reactor. This paper concentrates on selected tests which highlight the distillation behavior.

The presence of an endothermic vaporization front accompanying the exothermic thermal front in the RTO experiments was observed in this research. The nature of the thermal front depends on whether the concentration of hydrocarbon in the vapor phase falls in the flammable range.
MEOR From Lab to Field
Authors: Thrasher D. , Puckett D. A. , Davies A. , Beattie G. , Gordon Pospisil G. , Boccardo G. , Vance I. , Jackson S.
Published: July 2010

Progression of Microbial EOR (MEOR) technology from the laboratory towards field trial is described. An overview is provided of evaluation steps and field trial risk management through laboratory testing and numerical simulation, together with assessment of operational factors which could impact a long-duration field trial.

Previously MEOR has often been applied in onshore operations which carry relatively low risk. Where MEOR is to be applied in high value wells or higher risk environments such as the arctic or offshore deepwater, a higher degree of assurance is necessary to mitigate technical risks and maximise economic value. It is also essential to have sufficient understanding of base performance to ensure appropriate application and interpretation of the EOR process. To ensure success of an MEOR process, there needs to be a sufficient understanding of the performance of the microbes and the relevant MEOR mechanisms operating in the specific reservoirs.

Multiple processes have been characterised and represented to enable improved understanding of a microbial technology and its potential field implementation.

This paper will focus on screening of candidate reservoirs, and the methodology adopted to upscale core-scale results to prediction of performance in the field. This will include the choice of simulation models used for mechanistic understanding at the core scale and prediction of performance at the reservoir scale. It will also discuss some of the field operational aspects which need to be considered for well selection for field trial, including injectivity and surveillance requirements. Potential constraints on application of MEOR in the field have been identified, assessed and mitigated where possible in order to maximise chances of success.

MEOR technologies are often poorly understood, which creates uncertainty and apprehension around their use. The approach described here has been used to reduce uncertainty in progressing towards field application of a novel MEOR technology.
Effect of Wettability and Interfacial Tension on Microbial Improved Oil Recovery with Rhodococcus sp 094
Authors: Afrapoli M. Shabani , Alipour S. , Torsaeter O.
Published: July 2010

Results of coreflooding experiments with Rhodococcus sp. 094 species have already revealed that the bacterium is able to increase oil recoveries up to 9 %. Subsequent investigations have been carried out in order to recognize the complex mechanisms. Although published results proposed wettability changes in core plugs and favourable changes in the flow pattern as the active mechanisms but the potential of interfacial tension (IFT) and contact angle parameters was not fully understood in an aerobic process.

The present paper is a continuation of a series of laboratory experiments and consists of interfacial tension and contact angle measurements by an automated pendant drop goniometer. A refined hydrocarbon as the drop and two variants of bacteria suspended in brine as the continuous phase were employed. IFT and contact angle experiments were conducted in a static and a dynamic condition and quartz plates with two initial wettabilities were used. A certain volume of the bacterial solution and a short observation time is used in the static condition and the measurements show that by using bacteria, IFT is lowered from 18.3 mN/m (brine) to 13.6 mN/m (bacteria) and the contact angle changes slightly. However, our hypothesis is that the bacteria are capable of forming very stable emulsions of oil in brine and the real IFT value is much lower and the contact angle changes significantly. In the static condition, metabolic activities that lead to reduction of interfacial tension or contact angle changes are stopped due to the lack of nutrients and oxygen during the short observation period.

Therefore a constant flow of fresh bacterial suspension with enough nutrients and oxygen is ensured in the dynamic status. The IFT and the contact angle values obtained are presented in both conditions. The results show that the interfacial tension in the case of continuous flow of fresh bacteria is close to 5 mN/m. It is also observed that the contact angle is lower in the dynamic system compared to the static system. The new experimental procedure is more suitable for investigation of IFT reduction mechanisms in aerobic microbial improved oil recovery processes.
Limitations of Current MOC (Method of Characteristic) Methods to Predict MMPs for Complex Gas/Oil Displacements
Authors: Ahmadi Kaveh , Johns Russell T. , Mogensen Kristian , Noman Rashed
Published: July 2010

An accurate minimum miscibility pressure (MMP) is one of the key factors in miscible gas flood design. There are a variety of experimental and analytical methods to determine the MMP, but the most reliable methods are slim-tube experiments, 1-D slim-tube simulations, mixing-cell models, and the key tie-line approach using method of characteristics (MOC). Direct comparisons of all these methods generally agree well, but there are cases where they do not. No explanation has yet been given for the anomalies, although the MMP is critically important to recovery.

The focus of this paper is to explain when current MOC results may not be reliable and how to identify when this is the case. We demonstrate using fluid characterizations from Middle Eastern oils that the MMPs using the MOC method can be over 6500 psia greater than those calculated using a recently developed mixing-cell method. The observed differences in the MMP increase substantially as the API gravity of the oil decreases. We show that the key tie lines determined using MOC methods do not control miscibility for such cases. We explain the reasons for these differences using simplified pseudo-ternary models and show how to determine when an error exists. We also offer several ways to correct the MMP predictions using the MOC for these complex gas/oil displacements.
Interpreting Single Well Chemical Tracer Tests
Authors: Jerauld Gary R. , Mohammadi Hourshad , Webb Kevin J.
Published: July 2010

Single Well Chemical Tracer Tests (SWCTT) are widely used to estimate the remaining oil saturation after waterflooding (Sorw) and enhanced oil recovery including low salinity waterflooding. SWCTT have the advantage of being a more direct measure of Sorw than logs and unlike cores do not have the uncertainty of maintaining or restoring wettability and samples more reservoir rock. Interpretation of the test is often superficial, lacking a full description of physical processes involved and proper uncertainty analysis. This paper analyses SWCTTs from high and low salinity waterflooding, explains what is necessary to model the tests, demonstrates rigorous uncertainty analysis, and shows the value of designing tests with simulation.

Simulation procedures involve finding multiple history matches to the observed tracer production. Parameters affecting tracer production such as Sorw, mechanical dispersivity, hydrolysis reaction rate, number of layers and the amount of fluid injected and produced for each layer are adjusted to get the best fit. Nonstandard aspects of SWCTT must also be modeled. Because Sorw is sensitive to the ester partitioning coefficient which in turn is sensitive to salinity and temperature, injection of water with a lower temperature than the reservoir impacts interpretation. In one example, if the temperature variation is not accounted for the error in Sorw is 3 su.

Each SWCTT has its own characteristics which often appear to be different even in repeat tests on the same well. Apart from the common variables, other variables often must be introduced to get a good history match. In most cases, the shape of the tracer profiles cannot be satisfactorily matched with a single layer and layers with different levels of irreversibility must be added to match the shape. The well bore volume is sometimes varied. In repeat tests on the same well, constraining the interpretations to have the same layering and not increasing Sorw can reduce uncertainty and improve interpretation. In one case, a one-layer analysis shows no benefit but more detailed analysis with 3 layers indicates an incremental recovery of 12% PV, depending on the assumptions about well bore volume; the best fit overall indicated 2% PV.
Multiphase Fluid Flow Simulation of Heavy Oil Recovery by Electromagnetic Heating
Authors: Carrizales Maylin A. , Lake Larry W. , Johns Russell T.
Published: July 2010

Electromagnetic (EM) heating, also called high-frequency heating, generates EM waves through an antenna located inside a wellbore and parallel to the reservoir sand-face. The EM energy heats the reservoir from within, causing oil viscosity to lower and oil production to increase. Recent studies (Carrizales et al. 2008) showed that oil rate can be increased with the application of EM heating for single-phase radial flow. No simulations results or detailed modeling studies have yet been published that completely model the complex interactions of EM energy and multiphase flow.

This paper presents a multiphase, two-dimensional radial model that describes the three-phase flow of water, oil, and steam and heat flow in a reservoir within confining formations. The model accounts for the appearance and/or disappearance of a phase, and uses the variation in temperature and water saturation to continuously update the EM heating rate. A single well is used to locate the EM source, and also to produce oil. Gravity effects and vertical heat loss into the confining layers are included. This model allows determining the temperature distribution and the productivity improvement from EM heating when multiple phases are present. This model will be useful to predict the recovery of heavy oil by EM heating where conventional steam injection is not attractive.

To solve the model we used Lagrange-quadratic finite elements in the environment provided by COMSOL Multiphysics and its partial differential equations (PDE) application. Several simulations were made for hypothetical reservoirs with different fluid and rock properties. Special attention is on reservoirs with characteristics for which steam injection does not look attractive or feasible. Results show the feasibility of conducting EM heating based on the power source and frequency used to maintain an optimum absorption coefficient and to obtain higher production rates avoiding excessive power consumption. Also, a comparison shows that cumulative oil production and recovery factor obtained by EM heating is better than what is achieved by cyclic steam stimulation (CSS), especially for thin payzones.
Experimental Study of Foam Flow in Fractured Oil-wet Limestone for Enhanced Oil Recovery
Authors: Haugen Å. , Fernø M. A. , Graue A. , Bertin H. J.
Published: July 2010

The use of foam to increase oil recovery by reducing the gas mobility during gas injection in heterogeneous reservoirs with permeability variations is a proven EOR technology. The use of foam for fracture permeability reduction in fractured reservoirs is less studied. In this work laboratory experiments using foam to reduce fracture transmissivity and improve the matrix sweep in highly fractured, low permeable, oil-wet limestone are reported. Oil recovery either by individual water-, surfactant-, or gas injection exhibited low recovery, less than 10%OIP, with oil recovered predominately from the fractures. Oil recovery was significantly improved by simultaneous injection of surfactant and gas to generate foam in the fracture network and thus divert flow to the oil saturated matrix. Two foam injection schemes were tested: 1) co-injection of surfactant and gas in the fracture for in-situ foam generation, and 2) pre-generated foam injection. In-situ foam generation in the smooth-walled fractures was weak and not sufficient to divert fluids from the fractures and into the matrix. Injection of stable, pre-generated foam caused an increase in the differential pressure and diverted fluid to the matrix, yielding a significant increase in oil recovery, 80% OIP was receverd at high pore volumes injected.
Squeeze Related Well Productivity Impairment Mechanisms & Preventative/Remedial Measures Utilised: Norwegian Continental Shelf
Authors: Fleming N. , Ramstad K. , Mathisen A.-M. , Selle O. M. , Tjomsland T. , Fadnes F. H.
Published: July 2010

Squeezing is routinely employed by Statoil as a means of maintaining well productivity and avoiding safety issues related to downhole safety valve scaling. In the majority of cases, squeezing maintains well production through minimisation of scale related downtime. However, it has been observed occasionally by Statoil that the benefits of scale prevention by squeezing can be outweighed by the detrimental impact on well productivity. While there have been several articles covering specific elements of a squeeze operation that have affected well productivity, little has been published that attempts to completely describe squeeze related, production impairment mechanisms. This paper will aim to address this gap by demonstrating how squeezing, in some cases, can have an adverse impact on well productivity and highlight the remedial or preventative methods that have been utilised.

A review of the squeeze related, production impairment mechanisms from Statoil operated fields show that they can be related to near wellbore formation, alteration in the reservoir production characteristics or completion design. Physical formation damage mechanisms include Squeezing of sensitive reservoirs (fines mobilisation and clay swelling)Scaling of production intervals due to incorrect inhibitor placementViscosified inhibitor formation damageDamage related to precipitation squeezesIncreased sand production after squeezing

Liquid formation damage mechanisms include Squeeze related relative permeability alteration causing increased water cut and reduced oil rates.Water blocks and emulsion formation due to squeezing of an aqueous treatment into an oil producing or water sensitive interval.

Other examples of squeeze related productivity impairment are screen and gravelpack blockage while an indirect effect are lift problems after squeezing in wells with depleted reservoir pressure. In all instances, the economic costs of lost production can far exceed those of actually performing the squeeze. Case histories will be used to illustrate the productivity impairment mechanisms and methods used to overcome these along with lessons learned.
Chemical Mechanism of Low Salinity Water Flooding in Sandstone Reservoirs
Authors: Austad Tor , RezaeiDoust Alireza , Puntervold Tina
Published: July 2010

Both laboratory and single well field tests have documented that enhanced oil recovery can be obtained from sandstone reservoirs by performing a tertiary low saline waterflood. Due to the complexity of the crude oil-brine-rock interactions, the mechanism behind the low saline EOR process has been debated in the literature for the last decade. Both physical and chemical mechanisms have been proposed, but it appears that none of the suggested processes has so far been generally accepted as the main contributor to the observed low salinity EOR effect. Based on published data and new experimental results on core flooding, effects of pH and salinity on adsorption of acidic and basic organic components onto different clay minerals, clay properties like ion exchange capacity and selectivity, and oil properties, a new chemical mechanism is suggested, which agrees with documented experimental facts. At reservoir conditions, the pH of formation water is about 5 due to dissolved acidic gases like CO2 and H2S. At this pH, the clay minerals, which act as cation exchange material, are adsorbed by acidic and protonated basic components from the crude oil, and cations, especially divalent cations from the formation water, like Ca2+. Injection of a low saline fluid, which promotes desorption of Ca2+, will create a local increase in pH close to the brine-clay interface because Ca2+ is substituted by H+ from the water. A fast reaction between OH- and the adsorbed acidic and protonated basic material will cause desorption of organic material from the clay. The water wetness of the rock is improved, and increased oil recovery is observed.

To observe low salinity EOR effects in sandstones, a balanced initial adsorption of organic components and Ca2+ onto the clay is needed. Both the adsorption capacity and the pH-window for adsorption/desorption of organic material is somewhat different for various types of clay minerals. A detailed knowledge of the chemical mechanism behind the low saline EOR process together with information on formation brine composition, oil properties and type of clay material present, will make it possible to evaluate the potential for increase in oil recovery by a low salinity waterflood.