Combined Effect Of Salinity And Ionic Composition Biology Essay

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This research work will be based on current field practice in ASAB field and will implement the combined effect of tuning both the ionic composition and salinity of the injected water to ascertain what has been reported in the literatures.

The experiments will consist of the following;

X-Ray Diffraction Analysis / Thin section analysis to determine the mineralogy of the core sample.

X-Ray Computed Tomography (CT) / Scanning Electron Microscopy (SEM) Analysis will done pre and post experiment to verify any change in pore structure, maybe due to rock dissolution (Hiorth et al., 2008) and selecting composite cores from single cores of the same rock properties

IFT measurement will be done to evaluate the influence of the combined effect on the brine-oil (Liquid-liquid) interaction.

Wettability monitoring will be used to evaluate the wettability alteration caused by the injected fluid.

Spontaneous imbibition will check for the effect of dilution and roles of Mg2+/SO42- (Yousef et al., 2010; Fathi et al., 2010)

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Coreflooding experiments will be done sequentially on both single and composite cores in order to get an optimized brine composition for improved oil recovery.

Ionic composition analysis will check for the concentration of the potential determining ions and the non-active salts in the effluent against the concentration in the injected brine.

Zeta potential is the potential difference that exists within the double layer which is the degree of repulsion between adjacent, similarly charged particles. Zeta Potential measurements will evaluate the effect of injected brine on the surface charge of the cores.

Surface reactivity studies will be done to evaluate the affinity of each potential determining ion on the surface of the cores.

Lastly, the 1-D simulation will be done using the relative permeability curve to match the experimental data and consequently, upscale to field data.

With all these experiments conducted, an optimized brine composition will be developed to improve oil recovery in our tight carbonate reservoir and also, add to the literatures on mechanism of smart waterflooding.

CONTENTS

Cover page …………………………………........................................................................1

Summary............................................................................................................................2

Contents.............................................................................................................................3

List of tables.......................................................................................................................4

1.0 Introduction.................................................................................................................5

1.1 Background...................................................................................................................5

1.2 Motivation.....................................................................................................................7

1.3 Objectives…………………............................................................................................8

1.4 Significance……………………......................................................................................9

1.5 Scope of Study...............................................................................................................10

3.0 Methodology………………………………..………........................................................12

3.1 Materials .......................................................................................................................12

3.1.1 Core plugs.........................……….…………………….....................................12

3.1.2 Fluid properties.................….………………………….....................................12

3.1.2.1 Brines...............…………………………….........................................12

3.1.2.2 Reservoir Oil Samples…………………………………………………..13

3.1.2.3 Additional chemicals for solvent cleaning..........................................13

3.2 Apparatus.......................................................................................................................14

3.2.1 Air minipermeameter........................................................................................14

3.2.2 Digital tensiometer............................................................................................14

3.2.3 Coreflooding apparatus.....................................................................................14

3.3 Experimental Procedure…...............................................................................................15

3.3.1 Core Samples Selection and Preparation..............................................................15

3.3.2 Fluid Preparation...............................................................................................17

3.3.3 IFT Measurements............................................................................................17

3.3.4 Wettability monitoring.........................................................................................18

3.3.5 Spontaneous Imbibition Experiments...............................................................19

3.3.6 Coreflooding Experiments................................................................................19

3.3.7 Ionic composition analysis....................................................................................20

3.3.8 Zeta potential measurements.................................................................................21

3.3.9 Chromatographic studies/surface reactivity...........................................................21

3.4 Simulation Studies ……………………………………......................................................25

4.0 Project Task and Time Frame ......................................................................................26

References....................................................................................................................................27

LIST OF TABLES

Table 3.1 Geochemical analysis of field formation water samples....................................13

Table 3.2 Geochemical analysis and the corresponding chemicals concentration…….....22

Table 3.3 Composition of brines used in the chromatographic tests and zeta studies……24

INTRODUCTION

1.0 BACKGROUND

Carbonate reservoirs contain about 60% of the world's oil reserves and about 90% of these reservoirs are described as neutral to oil-wet (Akbar et al. 2001). Yet experts believe that over 60% of the oil trapped in carbonate rocks is not recovered because of factors relating to reservoir heterogeneity, produced fluid type, drive mechanisms and reservoir management (Sun and Sloan, 2003).

Reservoir oil recovery is typically executed in three stages throughout the life cycle of the field. Primary recovery is by using the natural energy of the reservoir; secondary recovery is by mainly injecting water (waterflooding) and gas for pressure maintenance; and tertiary recovery or enhanced oil recovery (EOR) is by using an injectant (Yousef et al. 2010). Due to the potential for EOR, different techniques have been applied in order to improve oil recovery from carbonate formations. There are five categories of EOR processes: mobility-control (polymers, foams), chemical (surfactants, alkaline agents), miscible (hydrocarbon solvents, CO2), thermal (steam, in-situ combustion) and other processes, such as microbial EOR, immiscible CO2 etc., (Green and Willhite, 1998). Smart waterflooding (Low salinity) should perhaps be categorized under other processes. Waterflooding has been the most widely used oil recovery method for many decades.

Waterflood is dominant among fluid injection methods and has been used since 1865 as a result of accidental water injection in Pithole City, Pennsylvania (Lewis, 1961). The target of any waterflood reservoir management is principally to maximize the ultimate oil recovery. Historically, the quantity of the water was given more consideration rather than the water quality. However, people later realized that it was important to monitor water quality as well as the quantity. Good quality water should be free from the solids suspension and organic matters, compatible with formation water and chemically inactive with compounds and elements present in the injection system. It is well known that aquifer water and seawater are the two main water sources for waterflooding (Alotaibi and Nasr-El-Din, 2009).

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Because waterflooding has been viewed as a physical process to maintain reservoir pressure and drive oil towards the producing wells, less attention has been given to the role of the chemistry of the injection water and its impact on oil recovery. In recent years, extensive research has shown that tuning salinity and ionic composition of the injected water can favorably affect Crude oil/brine/rock (COBR) interactions, alter rock wettability, enhance microscopic displacement efficiency, and eventually improve waterflood oil recovery chemistry both for sandstone and carbonate reservoirs (Yousef et al. 2010). However, water chemistry is an important factor that may help in improving oil recovery due to the interactions of COBR.

The idea of injecting smart water into petroleum reservoirs has been addressed since the 1960s. Researchers (Martin, 1957; Bernard, 1967) began injecting fresh water into core samples almost a half century ago. Bernard observed increased oil recovery in Coreflood experiments when injecting fresh water and attributed the improvement to improved microscopic sweep efficiency induced by clay swelling and plugging of pore throat by migrating fines, however this work did not capture the attention of the petroleum industry.

Considerable interest in low salinity waterflooding was generated in the 90's by researchers at the University of Wyoming (Jadhunandan, and Morrow, 1991; Yildiz and Morrow, 1996; Tang. and Morrow, 1997) studying the effect of brine, crude oil, mineralogy and experimental procedure on wettability. Tang and Morrow noticed that injecting low salinity brine improved recovery in clay rich core but not in clay free cores. They observed fines in the effluent during successful low salinity waterfloods. Extensive research work in sandstone reservoirs (Jadhunandan and Morrow, 1995; Tang and Morrow 1999; Tang and Morrow 2002; Zhang and Morrow 2006; Zhang et al., 2007) has developed this idea into an emerged trend.

Low salinity water has proved its high potential for improving oil recovery compared to high salinity waterflooding. Laboratory waterflood (Yildiz and Morrow, 1996; Zhang and Morrow, 2006; James et al. 2008; Morrow and Buckley, 2011) and successful field tests (Webb et al. 2004; McGuire et al. 2005) have showed that low salinity waterflooding can improve the oil recovery in sandstone reservoirs. However, the low salinity effect has not been thoroughly investigated for carbonates. One argument for why low salinity is not expected to work in carbonates is that clay minerals play a key role in the low salinity effect, and clays are lacking in most carbonates (Lager et al. 2008a). RezaeiDoust et al. (2009) reported another argument that different chemical mechanism may be responsible for difference in the low salinity effect: it is the crude oil adsorption onto positively charged calcite surface and negatively charged quartz surface.

Even after few research, (Austad et al., 2005; Strand et al., 2008; Yousef et al., 2010; Gupta et al., 2011; Yousef et al. 2011; Yousef et al., 2012; Romanuka et al., 2012; Zahid and Shapiro, 2012; Winoto et al., 2012) smart waterflooding in carbonates remains quite controversial. Great success in oil recovery was made by injection of seawater into the highly fractured mixed-wet Ekofisk chalk field (Sulak, 1991). Zhang et al. (2006) reported the impact of potential determining ions as one of the factor responsible for wettability alteration. Another report was made by Yousef et al. (2010) but a contrary report was given by Zahid and Shapiro (2012). The mechanism(s) responsible is poorly understood, the reproducibility of published results is doubted and the technology's scalability to the field is questioned. However, optimization of waterflooding by manipulating water salinity is not feasible due to the lack of understanding the primary mechanisms and all factors that might affect the oil recovery.

1.2 MOTIVATION

Previous experiments conducted on chalk show a higher recovery than limestone because chalk is pure biogenic material, and it has a much larger surface area compared to limestone (≈ 2 m2/g compared to ≈ 0.3 m2/g for limestone). Even though the chemical composition of chalk and limestone is similar, CaCO3, the response against the potential determining ions present in seawater may be different with regard to wettability modification. Subsequently, similar interactions behavior (improvement in oil recovery and reduction in residual oil saturation) have been reported with limestone rocks (Strand et al., 2008). Many reports have shown additional oil recovery by tuning the salinity and ionic composition of the injection water. The initial results are promising. While many recovery mechanisms are proposed, still many uncertainties remain with respect to the mechanism and the roles of the water chemistry. This work will therefore contribute to the understandings of impact of potential determining ions on oil recovery by smart waterflooding.

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Nonetheless, smart waterflooding is appealing because it could offers considerable recovery benefit, is relatively low cost and is relatively simple compared to other chemical EOR techniques. This question arises "how is injection of seawater into the Ekofisk chalk such a tremendous success in oil recovery, which is now estimated to approach 55%?" Ekofisk is mixed wet, highly fractured, it has low matrix permeability, about 2 mD, and the reservoir temperature is high at 130oC. For the ASAB field which has reached the waterflooding maturity stage, a considerable amount of oil is still left in the formation. Critical examination of the field properties with previous experiments conducted (Strand et al., 2006a; Zhang and Austad, 2006; Zhang et al., 2006; Yousef et al., 2010; Gupta et al., 2011; Yousef et al. 2011; Yousef et al., 2012; Romanuka et al., 2012; Zahid and Shapiro, 2012; Winoto et al., 2012) has made smart waterflooding a promising EOR methods for this very tight Carbonate reservoir field.

1.3 OBJECTIVES

It has been verified by a number of papers (Strand et al., 2006a; Zhang and Austad, 2006; Zhang et al., 2006) that seawater can act as a "smart water" to improve oil recovery from chalk by wettability alteration towards more water-wet conditions by both spontaneous and forced imbibition and a mechanism has been suggested (Zhang et al., 2007). In a very preliminary study, Strand et al. (2008) showed that the surface reactivity of reservoir limestone cores towards Ca2+, Mg2+ and SO42- had a similar trend as that of the chalk surface.

This research study is aimed at evaluating the impact of brine salinity and composition to enhance oil recovery. It will also present a systematic procedure for analysis of the potential of smart waterflooding so as to reflect the reservoir conditions and current field injection practices, including reservoir pressure, reservoir temperature, salinity and ionic content of initial formation water and current types of injected water.

The main objectives of this study include:

Investigate the reported mechanism for oil recovery by tuning the chemistry of injected water.

Study the surface chemistry of carbonate core and investigate the affinity of potential determining ions (especially Mg2+ and SO42-) in injected water towards carbonate core at reservoir conditions.

Investigate potential of diluting injected water salinity while varying the potential determining ions for improving oil recovery in carbonate formation (single and composite) by analyzing coreflooding results, ionic/chromatographic analysis conducting contact angle and IFT measurements.

Build a mechanistic reservoir simulation model to access the possible effect of water chemistry on oil recovery.

Correlate the coreflooding experiments with the simulation results.

1.4 SIGNIFICANCE OF STUDY

Until very recently, EOR by Low Salinity was a phenomenon allocated to sandstone and not observed for carbonates. Yousef and co-workers (Yousef et al., 2010) increased the oil recovery from composite limestone cores by successively flooding the cores with Gulf SW and diluted Gulf SW: 2, 10, and 20 times. A significant increase in oil recovery was observed as the injected SW was diluted. On the other hand, no effect was observed when outcrop chalk cores were imbibed or flooded with diluted SW. In fact, the oil recovery was decreased drastically as SW was diluted due to the decrease in active ions (Fathi et al., 2010a).

Several works done on chalk cores by Austad and co-workers have shown tremendous increase in oil recovery. One of their observation is that seawater contains reactive ions SO42-, Ca2+ and Mg2+ towards chalk surface that can act as potential determining ions since they can change the surface charge of CaCO3 (Zhang and Austad, 2006). They have also shown that increasing the SO42- in seawater can serve as a wettability modifier. Fathi et al., (2010a) even suggested that depleting seawater in NaCl concentration should be even smarter water than ordinary seawater. Zhang et al. (2007) investigated the effect of Ca2+ and Mg2+ at the chalk surface and noticed that at high temperature, the affinity of Mg2+ was higher than Ca2+. It was observed that without Mg2+ present, the solubility of CaSO4 is drastically decreased and will precipitate at a temperature of 100oC which will block the porous system.

Also, a set of comprehensive tests done by Zhang and Hemanta (2012) using UAE carbonate rock to estimate displacement efficiency, assess wettability variation through wettability monitoring and optimize brine composition at varying temperature of 700C, 900C and 1200C showed that lowering water salinity or increasing sulfate concentration of the injected water can lead to much higher oil recovery.

Considering these reports, this study will be based on accessing the combined effect of seawater and diluted seawater on oil recovery while tuning the concentration of Mg2+ and SO42- with/without NaCl on a carbonate core at a high temperature, i.e. reservoir temperature. This study is new and will likely add to literature on the mechanism of oil recovery as observed in the laboratory experiments.

1.5 SCOPE OF STUDY

Coreflood Experiments

Core flood experiments will be performed using reservoir cores and live crude oil under reservoir conditions and current field injection practices, including reservoir pressure, reservoir temperature, representative wettability, salinity and ionic content of initial formation water and current types of injected water. To quantify the level of oil recovery by water flooding using brines with different salinities and ionic compositions, a series of coreflooding experiments will be carried out on both single and composite cores. Modification of injection water in terms of both salinity and ionic composition would be based on gulf water. Basically, smart water coreflood experiments will be performed in the following two scenarios:

Waterflood with different salinities

Waterflood with different ionic compositions

The results of these tests will quantify the level of oil recovery by using different injection water and help define the most favourable brine salinity and composition for improving oil recovery. Furthermore these tests will also generate data for calculating water/oil relative permeability for the above scenarios, which would be used in simulation study.

Mechanistic study on LSW study

In order to better understand relevant mechanisms for smart waterflooding in carbonates, ionic composition analysis, surface charge potential measurement, chromatographic studies (adsorption analysis), contact angle and IFT measurements will be carried out under full reservoir conditions. In these measurements, the combined effect of brine salinity and ionic composition will be considered as variables.

Simulation study

By adopting the Kr data from 1-D simulation match on Coreflood results and reservoir static model, reservoir simulation will be conducted to evaluate the performance of different injection scenarios on laboratory scale. In addition, based on mechanistic study, simulation method could be proposed for LSWF in carbonates.

METHODOLOGY

3.1 MATERIALS

3.1.1 Core plugs

Limestone core plugs will be used in this work. These cores will be collected from a very tight zone (permeability range of 0.01 to 5 md) of a UAE carbonate reservoir. All the cores used in this work will be measured and preferably 1.5 inches in diameter and around 2 inches in length will be cut from whole cores and composite cores (1.5 inches and 30 cm long) will be arranged.

3.1.2 Fluid Properties

3.1.2.1 Brines

Different brines will be used in this study, including formation water (Table 3.1) to establish initial or irreducible water saturation (Swi) for cores and seawater, SW, for base injection, and different salinity slugs of injection seawater to displace oil. All brines will be prepared from distilled water and reagent grade chemicals, based on geochemical analysis of field water samples. Table 3.2 depicts the geochemical analysis and the corresponding chemicals concentration for each type of brine. For the experiments described below, seawater had a salinity of about 43,619 ppm, and initial connate water is very saline with salinity of 252,923ppm by weight.

Other dilute versions of seawater will also be prepared by mixing with different volumes of deionized water and addition/removal of salts (Sulfate and Magnesium). This includes:

10 times diluted seawater as DSW

Seawater containing twice the usual magnesium and sulfate ion concentration as SW X 2Mg2+ X 2 SO42-

Seawater without NaCl and containing four times the usual magnesium and sulfate ion concentration as SW X 4Mg2+ X 4 SO42- X 0NaCl

10 times diluted seawater containing twice the usual magnesium and sulfate ion concentration as DSW X 2Mg2+ X 2 SO42-

10 times diluted seawater without NaCl and containing four times the usual sulfate ion concentration as DSW X 4 SO42- X 0NaCl

3.1.2.2 Reservoir Oil Samples

Reservoir oil samples will be used in this study.

3.1.2.3 Additional chemicals for solvent cleaning

Toluene: Used for the cleaning of the limestone reservoir cores.

Methanol: Used for the removal of Toluene and water in the limestone reservoir cores during the cleaning process.

Table 3.1: Geochemical analysis of field formation water samples

Formation Water

kppm

Mol/L

Ionic Strength

Na+

74.969

3.260

3.2595

Ca2+

18.972

0.474

0.2250

Mg2+

3.432

0.143

0.5720

SO42-

0.267

0.003

0.0111

HCO3-

0.04

0.001

0.0059

Cl-

155.236

4.373

4.3728

4.2232

TDS

252.916

SO42-/Ca2+

0.014

SO42-/Mg2+

0.078

Solubility product

Kc

0.0013

Kd

0.0004

Total

0.0017

APPARATUS

3.2.1 Air Minipermeameter

Air permeability will be measured using a minipermeameter which measures flow rate and inlet pressure.

3.2.2 Digital Tensiometer

The main parts of the instrument are the IFT chamber cell, the hand pump for injection, a vibration free table, needle, temperature control system, lamp, transfer cells, pressure transducers with digital display, and a fully automated imaging system. The imaging system allows a direct digitization of the drop image with the aid of a video frame grabber of a digital camera

3.2.3 Core Flooding Apparatus

The coreflooding apparatus to be used in this research work is custom designed to perform experiments with both normal and composite core plugs to evaluate oil recovery using waterflooding at reservoir conditions. The main components of the apparatus are oven, core holder, fluid accumulators, differential pressure transducers, two pumps, back pressure regulator (BPR), confining pressure module, and three phase separator (Yousef et al., 2010).

The flooding system is capable of handling temperatures up to 150 °C, pore pressures up to 9,500 psi, and overburden pressures up to 10,000 psi. Volumes of oil and different salinity brines are supplied from high-pressure floating piston accumulators, operated by external high-pressure pumps. Oil and brine injection will be accomplished through a pump connected by a set of valves ahead of the core holder. System pressure is maintained by a back pressure regulator (BPR) at the core outlet, and measured by absolute and differential pressure transducers; and these data are registered by a computer based data acquisition and control board. The coreflooding apparatus is equipped with a three-phase separator, used to measure the recovered oil during waterflooding. The separator is placed inside the oven in a mounting bracket and operates at reservoir pressure and temperature. The three phase separator with a two-bore pattern is primarily used for phase level measurement of the oil/water and gas/oil interfaces at test pressure and temperature.

Three separate software programs that can be run in a manual, semi-automated or automated mode, allows the user for full mode control on most aspects of the system from the main screen. This feature includes valve toggling, reading pressures and temperatures, control the status of the pumps, and confining pressure pump settings.

3.3 EXPERIMENTAL PROCEDURE

3.3.1 Core Samples Selection and Preparation

The cores might had some contamination during coring and cutting processes, they will first be subjected to solvent cleaning using Dean-Stark extraction and dried at 230 °F for about 24 hours before carrying out petrophysical measurements and wettability restoration steps.

Solvent cleaning

The cores will be cleaned by flooding the cores at room temperature with toluene in Dean-Stark apparatus until the effluent became colorless (Thomas et al., 1993). Thereafter, the cores will be flooded with several PVs of methanol to remove toluene and water. Then the core was dried out at 230 °F to evaporate methanol.

Different laboratory tests will be exercised to select a consistent core composite in terms of petrophysical properties as well as rock types; this includes routine core analysis, XRD analysis (to check the mineralogy of the rock) and X-ray Computerized Tomography (CT) scan. Routine core analysis will be first conducted to measure the dimensions, air permeability, porosity, and pore volume of core plugs. The core plugs will then be CT scanned to screen out any core with fractures or permeability barriers.

Permeability Measurement

The absolute permeability for selected cores is calculated from Darcy's law based on the observed pressure drop across the brine saturated core after steady-state is achieved by injecting formation water through the core sample. The oil permeability at the initial water saturation will also be measured. Darcy's law (equation 3.1) for single-phase, steady-state, incompressible, horizontal flow in laboratory units of cc/min, md, cm2, psi, cp and cm:

The relative permeability measurement will done using unsteady state waterflooding procedure. After the measurement of the brine permeability, the core will be flooded by the reservoir oil to the connate water saturation and oil permeability will be measured. At the initial stages of waterflooding before water breakthrough, during the water breakthrough, during the production of oil and water and at the end of water flood, i.e. residual oil saturation, the effective permeability to oil and water will be measured and their saturations will be recorded (equation 3.2).

Effective permeabilites for each phase will be normalized to 100% brine permeability for relative permeability calculations (equation 3.3).

Air permeability was measured using the minipermeameter described above. Compressed nitrogen is injected into the prepared cores at a range of flowrates. An analog pressure dial is used to measure pressure drop. Air permeability will be calculated accounting for Klinkenberg effect.

Pore Volume and Initial Water Saturation

The pore volume of cores, original oil in place, and initial water saturation of selected core plugs will be determined using a centrifuge apparatus. The dry weight of the core sample will be measure. Then the core plug will be saturated by vacuum for 10 days with formation water to achieve ionic equilibrium with the core samples. The wet weight of the sample will be measured. The pore volume will be calculated by weight difference and the density of formation water at the reservoir temperature. Each core plug will be centrifuge at 2,000 rpm to drain the water in the pores and establish the connate water saturation. Then weight of centrifuged core sample will be measured to determine weight difference of the original oil in the core and the initial water saturation - before and after centrifuge.

Afterwards, saturation cores with formation water will be analyzed to sort some core samples into composites with similar rock types. Based on a review of the conventional core analysis & CT scan (before and after experiment), one composite core will be selected for this study. The aim of this is to examine the effect of different wettability states on oil recovery.

3.3.2 Fluid Preparation

Brine

The water and salts will be mixed in the appropriate proportions. Every brine sample will be filtered with the using porous media for any unexpected particles removal. The impact of salinity and ion composition, on the physical properties (density and viscosity) of prepared waters will be studied. The density and viscosity properties will be measured at reservoir temperature of 230 °F.

Crude oil

Every oil sample is filtered with the organic filter paper to remove solids and contaminants to reduce any (asphaltene particles and fines) experimental difficulties during coreflood experiments. The oil analysis data, viscosity and density measurement at reservoir condition are taken.

3.3.3 IFT Measurements

IFT measurements will be conducted using reservoir oil and different diluted brine at reservoir conditions. The experiment is conducted to address the effect of fluid-fluid interaction in wettability alteration in improving oil recovery. A high temperature/high-pressure pendent drop instrument (max 10,000 psi and 392oF) will be used to measure IFT values between the crude oil and injected brines.

After thorough cleaning of the apparatus (first by hexane, acetone, dry air and lastly, deionized water) to remove any trace amounts of contamination which might alter the result, a calibration test is first run by placing the stainless steel ball inside empty an IFT cell and the image system to be set ready to take a picture.

The ball will be removed from the IFT cell and the position of the camera fixed. The formation water will be injected into the IFT cell while the temperature is set to reservoir value to obtain temperature equilibrium inside the whole cell. More formation water is injected into the cell to increase the pressure inside the cell to reservoir pressure.

Reservoir oil will be injected through the bottom needle to get a stable oil drop on the top of the needle inside the cell. Then a digital photograph will be taken and the image drop program will be run to calculate IFT values. The same procedure will be done with regular SW, SWX2Mg2+X2SO42-, SWX4Mg2+X4SO42-X0NaCl, DSW, DSWX2Mg2+X2SO42- and DSWX4SO42-X0NaCl.

3.3.4 Wettability monitoring

Contact angle is one of the most versatile methods to quantify wettability of rock. The aim is to evaluate the impact of chemistry of the diluted seawater on carbonate rock wettability. The general conventional classification of contact angle is (Anderson 1986): water-wet, 0° - 75°; intermediate-wet, 75° - 115°; and oil-wet, 115° - 180°.

To obtain an insight on the driving mechanisms for additional oil recovery observed in coreflood experiments, it is critical to measure contact angle values using the same flood sequence at which the coreflood experiments is conducted. For the same rock sample, the measurements will be conducted in both singular and sequential mode:

FW, SW and DSW

FW, SWX2Mg2+X2SO42 and DSWX2Mg2+X2SO42

FW, SW, SWX2Mg2+X2SO42- and SWX4Mg2+X4SO42-X0NaCl

FW, DSW, DSWX2Mg2+X2SO42- and DSWX4SO42-X0NaCl

The same procedure of cleaning of rock samples will be done and to restore rock wettability, core is first aged in formation water for 1 week, and then aged in the field oil for more than six weeks. Mount the core to the upper needle using epoxy and place it inside the chamber cell at a suitable position to be seen in the image system. Formation water will be injected into the contact angle cell. Both the temperature and pressure of the cell will be set to reservoir conditions. The bottom needle will be raised close to the core and an oil droplet will be placed on the surface of the rock plate. Run the program on contact angle measurement mode and the contact angle between the oil-brine-solid interfaces will be monitored over 7 days

3.3.5 Spontaneous Imbibition Experiments

Spontaneous imbibition experiments will be conducted to check the wettability alteration potentials of the diluted brine samples with different water chemistry. The Spontaneous imbibition experiments are conducted as follows:

After the initial water saturation has been established in the cores. The cores will be aged for 20-30 days to restore wettability and then they will be placed in convectional glass Amott cells in an oven at 230oF. The cores will be surrounded by the seawater and oil production by spontaneous imbibition will be recorded as a function of time. Once the oil production stops, the surrounding seawater will be replaced with one of the diluted brines (SWX4Mg2+X4SO42-X0NaCl, DSWX4SO42-X0NaCl).

3.3.6 Coreflooding Experiments

A coreflooding study is conducted to investigate the impact of tuning the salinity and ionic composition of the injection water on oil recovery. The experimental parameters and procedures will be designed to reflect the initial conditions usually found in carbonate reservoirs, as well as the current field injection practices.

Single core flooding

The experimental procedure followed is described below:

All accumulators of the coreflooding apparatus is first filled with injected fluids including reservoir oil and brines.

The three phase separator is checked and calibrated to accurately determine the oil production during waterflooding.

The core plugs are loaded into the core holder.

Confining pressure of 4,500 psi is maintained on the core plugs by filling the core holder confining annulus.

The pore pressure is initiated by setting up the back pressure regulator at 200 psi.

Reservoir oil is flushed through the cores at back pressure conditions to displace gas and ensure complete fluid saturation.

Reservoir oil flushing is maintained until the pressure drop across the cores is stabilized. This process takes 1-2 weeks.

The oven is switched on and the temperature is set to the reservoir temperature of 230 °F.

The core is aged at reservoir temperature with repeated reservoir oil flushes. This process takes 4weeks and it ends when the pressure drop across the core is stabilized.

The pore pressure of the core is set at reservoir pressure through the back pressure regulator.

Conduct seawater flooding while monitoring the amount of oil produced, the pressure drop across the core, pH and the injection rate of the seawater as a function of time.

Water will be injected at a constant rate of approximately 0.1cc/min until no more oil liberation.

The injection rate will be increased to 0.2cc/min, and then to 0.5cc/min to ensure all mobile oil is produced and avoids capillary end effect.

The diluted water will then be injected into the core sample following the same injection procedure as described above.

The same process goes for composite coreflooding. The composite must be assembled, wrapped with Teflon®, placed into a rubber sleeve, and in order to increase the capillary number, the flooding rate will be increased in steps.

3.3.7 Ionic composition analysis

Effluent collected at constant time intervals will be analyzed. An ion-exchange chromatograph and inductive coupled plasma will be used to analyze the ionic concentrations of Na2+, Ca2+, Mg2+ and SO42-.

3.3.8 Zeta potential measurements

The zeta potential indicates the degree of repulsion between adjacent, similarly charged particles in dispersion. For molecules and particles that are small enough, a high zeta potential will confer stability, i.e., the solution or dispersion will resist aggregation. When the potential is low, attraction exceeds repulsion and the dispersion will break and flocculate (Hanaor, 2012).

Sample preparation: The rock materials will be wet-milled with methanol using a planetary ball mill and dried at 230 °F. In order to investigate the affinity of potential determining ions towards the rock surface, the aqueous rock powder suspension will be prepared by mixing representative solution (100% pure NaCl) with milled rock powder. The suspension will then be stirred for 24 hours before use.

Zeta potential: Zeta potential will be measured using a Colloidal Dynamics Acousto Sizer II that worked based on electro-acoustic and ultrasonic attenuation measurements.

The effect of divalent ions in the representative solution, (selectively SO42- and Mg2+) at different concentrations on the charge of carbonate surface will be analyzed.

For each single divalent ion, a new batch will be prepared. The carbonate powder suspension in a representative solution will be stirred for 24 hours. Then the surface charge will be measured at different molar concentration of each single divalent ion. For each measurement, the pH will be kept constant, equal to 8 by adjusting with small amounts of concentrated HCl or NaOH. The carbonate suspensions will be stirred for 15 minutes after new chemicals were added in order to achieve a new equilibrium before the measurement. Then the measurement will be repeated with SW and DSW.

3.3.9 Chromatographic studies/surface reactivity

A 100% water-saturated carbonate core will be mounted in a Hassler core holder, with a confining pressure of 4,500 psi. A back pressure of 200psi will be used to ensure constant pore pressure, and to prevent the fluid from boiling at high temperatures. The core will be flooded at constant rate. Samples of the effluent will be taken using a fraction collector and the ionic compositions will be analyzed.

Affinity of SO42-: Affinity of SO42- towards the surface of core samples at reservoir temperature will be studied using SW1/2T, seawater with half equal amounts of SCN- and SO42- and DSW1/2T, ten times diluted seawater with half equal amounts of SCN- and SO42-. This will be done to check the effect of sulfate at the seawater salinity and ten times dilution (table 3.3). Before the test, the core will be flooded with at least 5 PV's of seawater without SCN- and SO42- (SW0T).

Substitution of Ca2+ by Mg2+: Due to the increase in reactivity of Mg2+ at Temperature above 90 °C, it has been observed that Mg2+ is able to displace Ca2+ from the carbonate surface lattice, by a substitution reaction. In the presence of SO42-, Mg2+ is also able to act as a wettability modifier. Thus, the substitution of Ca2+ by Mg2+ is believed to be part of the wettability alteration process (Zhang et al., 2007). Different diluted water - SW, SWX2MgX2SO4 and DSW, DSWX2MgX2SO4 - will be flooded through the cores at a rate of 0.1cc/min and the concentration of Ca2+, Mg2+, and SO42-will be plotted versus the PV injected.

Table 3.2: Geochemical analysis and the corresponding chemicals concentration

Seawater Water

kppm

Mol/L

Ionic Strength

Diluted Seawater Water

kppm

Mol/L

Ionic Strength

Na+

13.7

0.5957

0.5957

Na+

1.37

0.0596

0.0596

Ca2+

0.521

0.0130

0.0002

Ca2+

0.0521

0.0013

1.70E-06

Mg2+

1.62

0.0675

0.2700

Mg2+

0.162

0.0068

0.0270

SO42-

3.31

0.0345

0.1379

SO42-

0.331

0.0034

0.0138

HCO3-

0

0.0000

0.0000

HCO3-

0

0.0000

0.0000

Cl-

24.468

0.6892

0.6892

Cl-

2.4468

0.0689

0.0689

0.8465

0.0846

TDS

43.62

TDS

4.362

SO42-/Ca2+

6.35

SO42-/Ca2+

6.353

SO42-/Mg2+

2.04

SO42-/Mg2+

2.043

Solubility product

Solubility product

Kc

0.0004

Kc

4.49E-06

Kd

0.0023

Kd

2.33E-05

Total

0.0028

Total

2.78E-05

SWx2Mgx2SO4

kppm

Mol/L

Ionic Strength

Diluted SWx2Mgx2SO4

Kppm

Mol/L

Ionic Strength

Na+

13.7

0.596

0.5957

Na+

1.37

0.0596

0.0596

Ca2+

0.521

0.013

0.0002

Ca2+

0.0521

0.0013

1.70E-06

Mg2+

3.24

0.135

0.5400

Mg2+

0.324

0.0135

0.0540

SO42-

6.62

0.069

0.2758

SO42-

0.662

0.0069

0.0276

HCO3-

0

0.000

0.0000

HCO3-

0

0.0000

0.0000

Cl-

24.468

0.689

0.6892

Cl-

2.4468

0.0689

0.0689

1.0504

0.1050

TDS

48.55

TDS

4.855

SO42-/Ca2+

12.71

SO42-/Ca2+

12.706

SO42-/Mg2+

2.04

SO42-/Mg2+

2.043

Solubility product

Solubility product

Kc

0.0009

Kc

8.98E-06

Kd

0.0093

Kd

9.31E-05

Total

0.0102

Total

1.02E-04

SWx4Mgx4SO4x0NaCl

kppm

Mol/L

Ionic Strength

Diluted SWx4SO4x0NaCl

kppm

Mol/L

Ionic Strength

Na+

0

0

0

Na+

0

0

0

Ca2+

0.521

0.013

0.0002

Ca2+

0.0521

0.0013

1.70E-06

Mg2+

6.48

0.270

1.0800

Mg2+

0.162

0.0068

2.70E-02

SO42-

13.24

0.138

0.5517

SO42-

1.324

0.0138

5.52E-02

HCO3-

0

0

0

HCO3-

0

0

0

Cl-

0

0

0

Cl-

0

0

0

0.8159

0.0411

TDS

20.24

TDS

1.538

SO42-/Ca2+

25.41

SO42-/Ca2+

25.413

SO42-/Mg2+

2.04

SO42-/Mg2+

8.173

Solubility product

Solubility product

Kc

0.0018

Kc

1.796E-05

Kd

0.0372

Kd

9.309E-05

Total

0.0390

Total

1.111E-04

Table 3.3: Composition of brines used in the chromatographic tests and zeta studies

SWx0T

kppm

Mol/L

Ionic Strength

DSWx0T

kppm

Mol/L

Ionic Strength

Na+

13.7

0.5957

0.5957

Na+

1.370

0.0596

0.0596

Ca2+

0.521

0.0130

0.0002

Ca2+

0.052

0.0013

1.70E-06

Mg2+

1.62

0.0675

0.2700

Mg2+

0.162

0.0068

0.0270

SO42-

0

0.0000

0.0000

SO42-

0.000

0.0000

0.0000

HCO3-

0

0.0000

0.0000

HCO3-

0.000

0.0000

0.0000

Cl-

24.468

0.6892

0.6892

Cl-

2.447

0.0689

0.0689

SCN-

0

0

0.0000

SCN-

0

0

0.0000

 

 

 

0.7775

 

 

 

0.0777

TDS

40.309

 

 

TDS

4.0309

 

 

SO42-/Ca2+

0

 

 

SO42-/Ca2+

0

 

 

SO42-/Mg2+

0

 

 

SO42-/Mg2+

0

 

 

Solubility product

 

 

Solubility product

 

 

 

Kc

 

0

 

Kc

 

0

 

Kd

 

0

 

Kd

 

0

 

Total

 

0

 

Total

 

0

 

 

 

 

 

 

 

 

 

SWx1/2T

kppm

Mol/L

Ionic Strength

DSWx1/2T

kppm

Mol/L

Ionic Strength

Na+

13.7

0.5957

0.5957

Na+

1.37

0.0596

0.0596

Ca2+

0.521

0.0130

0.0002

Ca2+

0.0521

0.0013

1.70E-06

Mg2+

1.62

0.0675

0.2700

Mg2+

0.162

0.0068

0.0270

SO42-

1.655

0.0172

0.0690

SO42-

0.1655

0.0017

0.0069

HCO3-

0

0.0000

0.0000

HCO3-

0

0.0000

0.0000

Cl-

24.468

0.6892

0.6892

Cl-

2.4468

0.0689

0.0689

SCN-

1.655

0.0285

0.0285

SCN-

0.1655

0.0029

0.0029

 

 

 

0.8120

 

 

 

0.0812

TDS

43.62

 

 

TDS

4.362

 

 

SO42-/Ca2+

3.18

 

 

SO42-/Ca2+

3.177

 

 

SO42-/Mg2+

1.02

 

 

SO42-/Mg2+

1.022

 

 

Solubility product

 

 

Solubility product

 

 

 

Kc

 

0.0002

 

Kc

 

2.25E-06

 

Kd

 

0.0012

 

Kd

 

1.16E-05

 

Total

 

0.0014

 

Total

 

1.39E-05

 

 

 

 

 

 

 

 

 

SWxT

kppm

Mol/L

Ionic Strength

DSWxT

kppm

Mol/L

Ionic Strength

Na+

13.7

0.596

0.5957

Na+

1.370

0.0596

0.0596

Ca2+

0.521

0.013

0.0002

Ca2+

0.052

0.0013

1.70E-06

Mg2+

1.62

0.068

0.2700

Mg2+

0.162

0.0068

0.0270

SO42-

3.31

0.034

0.1379

SO42-

0.331

0.0034

0.0138

HCO3-

0

0.000

0.0000

HCO3-

0.000

0.0000

0.0000

Cl-

24.468

0.689

0.6892

Cl-

2.447

0.0689

0.0689

SCN-

3.31

0.057

0.0571

SCN-

0.331

0.0057

0.0057

 

 

 

0.8465

 

 

 

0.0846

TDS

46.93

 

 

TDS

4.693

 

 

SO42-/Ca2+

6.35

 

 

SO42-/Ca2+

6.353

 

 

SO42-/Mg2+

2.04

 

 

SO42-/Mg2+

2.043

 

 

Solubility product

 

 

Solubility product

 

 

 

Kc

 

0.0004

 

Kc

 

4.49E-06

 

Kd

 

0.0023

 

Kd

 

2.33E-05

 

Total

 

0.0028

 

Total

 

2.78E-05

 

3.4 SIMULATION STUDIES

Computer modeling group, CMG will be used to model the one dimensional simulation solution. The model's formulation will incorporate known mechanisms under reservoir scale for simulating smart water processes. Homogenous models will be required to make use of the derived laboratory data (the relative permeability curve) and match the simulation results with experimental results.

4.0 PROJECT TASK AND TIME FRAME

The whole proposed research is divided into six subtasks as:

Task 1: Extensive relevant literature review and literature review summary;

Task 2: Experimental materials collection and setup preparation for experiments;

Task 3: Spontaneous imbibition experiments, Contact angle and IFT measurements using different brines for LSW;

Task 4: Coreflood experiments for smart waterflooding;

Task 5: Ionic composition analysis, Zeta potential and Surface reactivity measurements using different brines;

Task 6: Reservoir simulation study;

The GANTT CHART is shown below.