Injection Of Water Into An Oil Reservoir Biology Essay

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Waterflooding is the injection of water into an oil reservoir to recover more petroleum from it, is a common oil industry practice. The technique is one of several used to sustain and prolong oil production in the province. The application of scientifically based systems of oil field development with wide use of artificial methods of oil productive beds stimulation played in practice an important role for this increase of oil production. Water injection into oil productive beds became a matter of special importance. It is known in the case of oil displacement by water that a comparatively high degree of oil recovery is attained. In most oil productive regions of the country there are dispensable sources of water which after simple treatment can be used for injection into oil productive beds. The water injection itself encounters no serious technical difficulties and its cost is comparatively not high. Finally, most oil reservoir rocks can usually take a sufficient quantity of water at the requisite pressures. It is sufficient to say that at present about 75 per cent of oil is produced in the field developed by means of water flooding methods. The wide practical use of peripheral and internal water flooding allowed a considerable decrease in the number of production wells and greatly increased their flow rate. This in its turn provided a considerable decrease of expenditure for each ton of oil produced. Secondary or enhanced oil recovery (EOR) methods are needed because only a small fraction of the oil in a reservoir can be produced by primary means (the reservoir's natural drives). Initial recovery ranges from only about 5 per cent up to about 20 per cent. These methods must, naturally, also be both economic and effective, or companies may not bother trying to coax more oil from the reservoir.

Grain size, sorting and mineralogy are closely interrelated. As grain size increases, sorting decreases and the proportion of readily soluble detrial grains increases.Sandstone samples were subdivided into tow subgroups in which relationshiops among grain size, porosity and permeability are significantly different: Sandstones with less than 13% porosity are strongly influenced by carbonate cement which controls porosity and permeability, independently of variations of grain size and sorting. Sandstones having porosity greater than 13% have undergone extensive carbonate dissolution, and coarse-grained sandstones have more secondary porosity than the finer-grained due to dissolution of unstable constituents. Both porosity and permeability are positively correlated with grain size in these samples.

Initial (connate) water saturation increases with grain size because of the strong correlation between increasing grain size and polycrystalline grains which have intra-grain microporosity. Increasing heterogeneity with increasing grain size is thought to contribute to higher residual oil saturations in coarser-grained, more poorly sorted sandstones. A decrease in oil recovery efficiency with increasing grain size and permeability may be predicted for other sandstone reservoir rocks deposited in similar types of environments.

In an extremely water-wet rock, the surface is covered with water. In that case oil (or gas) will be located in the centre of the pores. In the laboratory, when water-filled water-wet rock is brought to irreducible or connate water saturation (Scw) by oil flooding, this water will remain a continuous phase covering the pore walls. Therefore, in theory, by ongoing oil flooding of a perfect water-wet rock it is possible to "scratch-out" the last bit of water, albeit at infinitely long displacement time, so that Scw=0 for a perfect water-wet system. Consequently, for reservoir rock, a general feature of water-wetness is that Scw is low, say 10% or so of the pore space. During a subsequent water-drive to produce the oil, a significant amount of oil eventually will remain capillary trapped, floating as disconnected blobs in the centre of the pores. The residual oil saturation Sor is determined by the topology of the pore space and is usually higher than Scw: around 30% and up. In an oil-wet system, water and oil can be thought to exchange places when compared with a water-wet system. Therefore, in oil-wet rock, the residual oil saturation Sor is low, about 10% of the pore space, and Scw will be higher. As is demonstrated by the simulations, in the laboratory it is difficult to attain connate water and residual oil saturations in actual experiments. In practice, only remaining saturations are reached, due to a capillary end-effect or due to an extremely small mobility of the displaced phase.

1.2 Problem statemaent

The factor that must be known prior to initiation if enhanced oil recovery technique is a reservvoir that has reached the economic limit of production is the remaining (or resedula) oil saturation. This oil saturatiom must be known accurately to evaluate the economic feasibility of any enhanced oil recovery tecnique that maybe considerd. The rmaining oil saturation must be equal to the true resedual oil saturation. More frequently, however the remaining oil saturation is greater than resedual oil saturation of the rock. This is due to the production well damge that restricts oil production near the wellbore, or bottom water conning or extentive fracture prosity or the reservoir heterogenity. Thus, the term remaining oil saturation here is define the existing oil sturation of a reservoir at any time after production was initiated, whereas the resedual oil saturation defines the oil saturation of rock that cannot be reduaced further by normal waterflood.

Average primary recovery factor ar usually low. For example for the solution gas drive is 5% to 30% and water drive is about 35% to 70%. Secondry recovery project may be also behave disapointingly due to overall poor sweep and displcement efficiencies,reservoir stratification, directional or drastic vertical and lateral permeability variation.

Major reserves of proven but yet unrecovered oil, left behind after primary and secondry recovery, exist. Based on conservative estimates aplication of tertiary recovery methods to already known oil reservoir could recover from 55 bilion additional barrels of oil in teh U.S alone.

1.3 Objective

To start this project, a few objective have been made to make sure this researh can be proceed smoothly. The objective are ;

To conduct researh about effect of grain size on residual oil saturation after waterflooding.

To conduct researh about grain geometry on residual oil saturation after waterflooding

1.4 Scope of researh

Scope of research are important to make sure the expriment will follow through the procedure and no mistake is taken during experiment.

simple sand pack model was developed

linear displasment system was set in the experiment

flow rate of brine with 20,000 ppm were set at 11ml/minute

experiment was set at standard temperature and standard pressure

crude oil was used as the displaced fluid with 0.82g/ml

the experiment was conducted at ambient temperature and ambient pressure

0.5 until 2.0 pore volume (PV) of fluid was injected within the range of practical waterflooding.



Residual oil saturation is a basic item of data for many aspects of reservoir engineering. This number is required for normal material-balance calculations. Residual oil saturation is also extremely important in determining the economic attractiveness of a planned waterflood or a proposed tertiary recovery operation. Finally, in some areas proration is related to attainable residual oil saturation. Core analysis and well logging, the two most widely used methods for measuring residual oil saturations, are subject to a variety of well known limitations. The residual oil saturation measured represents an average over as much as several thousand barrels of pore space.

Water injection as a means of secondary recovery and as a technique for pressure maintenance to energize the reservoir is one of the oldest techniques used in the petroleum industry. Over the years there has been tremendous advancement in this field, and in waterflood design, development, and surveillance. Waterflooding is accepted worldwide as a reliable and economic recovery technique; almost every significant oil field without a natural water drive or with a partial water drive has been, is being, or will be considered for waterflooding. Waterfloods need to be initiated at an optimal time to enhance field recovery and maximize profits. The primary waterflooding objective is to maximizing oil recovery.


In many sandstone reservoirs, plots of core data show that the logarithm of permeability (k) is linearly proportional to porosity. Porosity and permeability are measured routinely on small plugs cut from core. When data from a given rock formation are plotted, the result often are used to conclude permeability from porosity, which is more easily determined from welllogs than permeability. But data from different rock formations form trends at different positions on a log(k) and porosity plot. The correlation between permeability and grain size has been recognized by many authors such as Nelson (1994) who have made a summary of grain size model. In pore space models, permeability is proportional to the square of pore throat size whereas in grain size models, permeability is proportional to the square of grain diameter. This strong dependence is present in newly deposited sands and its imprint remains throughout the course of compaction and diagenesis.

Figure 2.1

2.3 Sieve analysis

Sieves analysis for tabulated to show the mass fraction of each measuring grain size distribution screen increment as a function of the mesh (Bjorlykke 1989).

Figure 2.2 : Sieve analysis (McCabe, Smith, and

Harriott, 1993)

Table 2.1

The classification of the sand into sand, silt, clay, or subdivision into coarse sand, medium sand, fine sand. Another scale that is sometimes. used rather than grain diameter in mm is the phi scale or the negative of the logarithm base 2 of the diameter in mm. This scale subdivides the different sand grain sizes between -1 to +4. The base 2 is because the Tyler mesh sizes sorts grain sizes by factors of 2. Also, it is convenient to use a logarithmic scale because the distributions are usually approximately a log normal distribution. The simplest way to present the grain size distribution from a sieve analysis is to plot the weight retained on each tray as a histogram A histogram shows what percentage by weight of the grains fall within a particular size range. This type of presentation gives a good visual impression of the distribution of grains in the various size categories. In particular, it is easy to see how well sorted the sediments are, and whether the distribution of grain sizes are symmetrical, or perhaps bimodal.

2.4 Grain Size distribution Parameters

The parameters of a millimeter plot or a phi plot can be determined from the following formulas (after Folk and Ward 1957 and Jorden and Campbell,1984.). φ x is a grain size expressed in phi(φ) units such that x% of the sample is larger than this grain size. (Note: There are also other formulas to calculate the same quantity. Also, the definition of sorting does not appear to be consistent. Note: The mean with the φ scale is the geometric mean grain diameter.)

Table 2.2

2.5 Pore Shape

The quantity of direct interest in the flow through porous media is not the properties of the matrix (e.g. grain size distribution) but rather the properties of the pores (e.g. pore size distribution). When we observe a porous medium, what we see is the matrix such as the beadpacks. cross sectional dimensions of the pore space will in general not be uniform as one moves through the pore space. In particular, there may be narrow passages called pore throats separated by wide passages called pore bodies. The pore space in rocks are much more complex than that of spherical bead packs. Important parameters of the pore space that relate to the trapping of fluids include the number of pore throats that branch out from a pore body and ratio of pore body diameter to the pore throat diameter.

Ahmed Reda and Abdel Hakim Hashem from Melrose Petroleum Companyhave develope a New Method for Predicting the Average Pore Diameter which is Using the NMR Data Calibrated to Core Analysis in a Clastic Reservoir. The Nuclear Magnetic Resonance (NMR) logging is one of the most efficient technologies in reservoir evaluation and characterization due to its wide range of applications. The efficiency of this technology comes from the mineralogical independent acquisition that is only measuring and reflecting the formation fluids but not the rock matrix. This advantage differentiates NMR measurements from conventional wireline electric logging where their measurements, which are affected by the rock matrix and fluid-filled pores and are more sensitive to the rock matrix than to the pore fluids.

Such NMR applications are porosity, permeability, saturations, fluids identification as well as pore size distributions reflecting the corresponding grain size of the rock. The NMR T2 bins distribution reflect the pore sizes distribution of the rock in the presence of only a single fluid in the pores i.e. 100% water saturated rock of water wet nature. In a short inter echo spacing experiment is used, the surface relaxation becomes dominant and then the NMR T2 decay becomes directly proportional to pore size. By assuming the similarity of shape geometries, the largest pores should have the highest T2 values and lowest S/V ratio, and as the pores become smaller, the T2 values become lower and the S/V ratio increases. Therefore, the average pore diameter can be predicted from the measured NMR T2 values, S/N ratio and the rock relaxivity.

Their research explores an efficient and accurate method for determining the average pore size of rock using the NMR data of both the Halliburton-MRIL and Schlumberger-CMR tools calibrated to core analysis. The method is based on identifying the pore shape using the thin sections core chips and using the shape geometry in mathematical approach for determining the average pore diameter based on the reservoir relaxivity and the NMR decay time logarithmic mean. Their paper also detail the application of this method in three different reservoirs, where two are gas-bearing, located in the deep water of the Mediterranean Sea and the third light oil-bearing reservoir located in the Nile Delta depositions.

2.5.1 Pore Size Distribution

Mercury porosimetry or mercury/air capillary pressure curves are commonly used

to measure the distribution of pore throat sizes. A clean rock sample that may be

irregular in shape is placed in a high pressure vessel and is

evacuated. Mercury is introduced into the vessel with small increments of pressure.

The volume of mercury that goes into the vessel is precisely measured. The first

volume of mercury fills the void space in the vessel. This will determine the bulk

volume of the sample. Some mercury volume will then enter with increasing pressure

to fill the surface roughness of the sample. The first volume of mercury to enter the

rock will be at a pressure called the capillary entry pressure or displacement

pressure. This is the pressure required for the mercury to enter the largest pores in the

rock. The relation between the mercury pressure and the pore size that it will enter is

illustrated by the following equation.

This equation treats a pore throat as having an equivalent pore radius. The mercury

pressure is increased in small increments and the volume of mercury that enters is

recorded. As the mercury pressure is increased, mercury enters pores that are

accessible via smaller pore throats. The curve of mercury pressure versus mercury

volume is called the mercury/air capillary pressure. The mercury volume may be

normalized by the bulk sample volume to be expressed as a saturation. Usually, 1-SHg

is plotted on the abscissa to represent the saturation of the wetting phase (, i.e. so the

curve will have the same shape as when plotted as a function of the water saturation

from a capillary diaphram or centrifuge measurement). These measurements are

automated and are done on a routine basis.

Figure 2.3 : Mercury intrusion-withdrawal curves(Stegemeier, 1977)

2.5.2 Pore Diameter Measurement Method

Theoretically, the pores can have three distinctive types of shape, which are sphere, tube or sheet. As there is no available data regarding the pore shape of the present study, the pore shapes will be generally assumed to be from the sphere and tube like pore shape according to the pore shape distribution in the thin section core chip in which the dominant pore shapes are sphere and tube like, (Figure 10). The tube like pore is almost considered here in the present study as a connected chain of spheres.

The volume of the sphere V can be obtained from equation (1)

V = 4/3 * Л * r3 (Equation 1)

Where r is the radius of the pore,

In addition, the surface S can be obtained from equation (2)

S = 4 * Л * r2 (Equation 2)

By dividing equations (1) and (2), equation (3) is resulted

S/V = 3/r (Equation 3)

Because, D = 2 * r (Equation 4)

Where D is the diameter of the pore

S/V = 6/D (Equation 5)

From, 1/T2 = ρ2 * S/V (Equation 6)

Where ρ2 is the rock relaxivity in micron/second (μm/s), (Hurlimann, et al., 1994; Kenyon

and Kolleeny, 1995)

And T2 is the logarithmic mean from the CMR in millisecond (ms)

Therefore 1/T2 = ρ2 * 6/D (Equation 7)

D = 6 * ρ2 * T2 (Equation 8)

From the previous equation the pore size can be directly measured from the NMR tools measurements .Because the T2 value at one depth reflects different pore sizes at that depth, the calculated pore diameter can be defined as the average pore size Dav., (equation 9).

Dav = 6 * ρ2 * T2 (Equation 9)

2.6 Residual Oil Saturation

A reduction in oil saturation occurs as reservoirs are depleted during primary and secondary recovery programs.  However even the most effective secondary recovery programs still may not reduce oil saturation to the unrecoverable oil saturation point of the reservoir.  In order to continue to reduce residual oil saturation and recover oil at economic rates a program must be done to increases the mobility of the displacement medium by increasing the viscosity of the water or decreasing the viscosity of the oil and also Reduces interfacial tension between the oil and water

Chang, M.M. and N.L, Tomutsa, L. from Natl. Inst. for Petroleum and Energy Research says the amount and distribution of residual oil saturation (ROS) are critical parameters for determining whether to apply an EOR process to a reservoir. In their reseach, the include the available ROS techniques and indicating advantages, limitations, problems, and possible improvements of each technique. They also summarized advantages and disadvantages of each ROS-determination technique.

ROS is the oil saturation remaining in the reservoir after extraction by conventional recovery methods, such as waterflowing. The amount and distribution of residual oil in a reservoir are significapt factors in deciding whether EOR methods are suitable for economic exploitation of a reservoir. Variation of ROS may be caused by heterogeneities in the rock or by recovery processes such as waterflooding. Many different ROS measuring techniques are available, but they do not necessarily produce the same results. Therefore, understanding the limitations, accuracies, and sources of error of the different measurement techniques is important in selecting a technique to measure ROS.

Because there is no absolute, correct method of measuring ROS, and because every method is subject to some errors. a comparison of results from different ROS techniques is an alternative for ROS evaluation

ROS values determined by conventional core analysis are substantially less than in-situ values obtained from logging methods. The most severe change in oil saturation is caused by expulsion (bleeding) and associated shrinkage of the quantity of oil in the core as pressure decreases when the core is lifted to the surface. Attempts have been made to correct oil-saturation measurements obtained by conventional coring analysis, but with unreliable results.

2.6.1 Determination of residual oil in a formation

A method has been created by S.B. Coskun, Department of Geology and Geophysics, The University of Calgary for determining the amount of residual oil remaining in an oil bearing formation after primary production which includes the sequential steps of:

1 . logging the formation to obtain logging data measurements of the relative quantities of residual oil and formation water present in the formation;

2. injecting a sufficient amount of an oil miscible solution through the bore hole into the formation to displace substantially all of the residual oil in the formation surrounding the bore hole;

3. injecting a sufficient amount of water into the formation through the bore hole to displace substantially all of the oil miscible solution thereby rendering the formation being tested substantially 100 per cent water saturated; and

4. logging the formation for a second time to obtain logging data measurements which, when compared with the logging data measurements of the initial log indicate the amount of residual oil present in the formation, wherein said logging data measurements are obtained by employing a reservoir property logging apparatus selected from the group consisting of resistivity logging apparatus, sonic logging apparatus and density logging apparatus.

2.7 Water flooding

Waterflooding is usually the first secondary method applied to a reservoir. In most situations it will help recover a significant portion of the oil in the reservoir. Capital costs, mainly for surface facilities to handle the injection and production water, are relatively inexpensive compared with those of most other EOR methods. Operating costs for a waterflood are typically lower than for other EOR techniques. A common misconception is that oil companies use valuable surface water and, by injecting it into an oil formation, render it dirty and salty. While a limited number of projects do use some surface water, those practices are disappearing. Most projects use water from an underground aquifer that is similar to the oil formation's native water, usually quite salty and not suitable for human or animal consumption. Usually all of the injected water is produced with the oil. The two fluids are separated on the surface, the oil content remaining in the water is removed, and then the water is reinjected. So in fact most of the water gets repeatedly recycled and only a small amount of 'new' water, roughly equal to the amount of oil produced, is required on a daily basis, Water fractions in the produced fluids can be as high as 99 per cent before water handling costs make the practice uneconomic.

Waterflooding already has its advantages as a proven technology, but there is still room to improve. Waterflooding enhancements will be crucial to the continued productivity of a large number of reservoirs throughout Saskatchewan. While other EOR technologies will certainly recover more of the oil from a given reservoir, the economics may not be that favorable to their application in the province. The science behind waterflooding must be advanced to sustain the oil industry. Work is already underway to improve waterflooding technology and also to extend its application to heavy (more viscous) crudes, once thought impractical. One method involves the addition of a small amount of soap-like chemicals to the water which helps to free the oil attached to the reservoir rock. Researchers expect that this technique could recover an additional 10 to 20 per cent of a reservoir's original oil. This can be as good as discovering a new reservoir.

Other approaches are being developed to control where the water goes in the reservoir. In most applications, water is less viscous than the reservoir oil, and so tends to flow along the easiest path through the reservoir, missing a large amount of the remaining oil. There are ways to raise the water's viscosity and get it to flow into areas where there are higher oil concentrations. One of these methods involves creating and injecting micro-bubble solutions. It was recently "tested" by over a thousand school children in "Canada's Largest Science Experiment," held in Regina and Saskatoon. Oil producers and researchers are working hard to find the best waterflooding practices to increase recovery and to achieve quicker success. Many investment opportunities compete for oil companies' attention. For Saskatchewan's reservoirs to be a part of their production strategy, effective and relatively low-cost technology must be "on tap".

Kantzas from University of Calgary and TIPM Laboratory have made a research about Mechanisms Of Heavy Oil Recoveryby Low Rate Waterflooding. The Canadian deposits of heavy oil and bitumen are some of the largest in the world. As mention above, waterflooding is a common technique for secondary oil recovery in conventional oil reservoirs. In heavy oil systems, the extremely high oil viscosities lead to adverse mobility ratio conditions; thus, water will tend to "finger" through the oil, and recoveries are expected to be extremely low. Despite the poor recoveries predicted theoretically, there have been numerous reports of heavy oil waterfloods performed in the literature. All of these studies report poor sweep efficiencies and low overall recovery. However, it is significant that in all cases some oil was still recovered, despite the highly adverse mobility ratios in the waterfloods. Laboratory studies of waterflooding in heavy oil systems also demonstrate that some oil can be produced by controlled injection of water. Although heavy oil waterflood responses cannot be readily predicted through theory , waterfloods have still been carried out in heavy oil reservoirs in Alberta and Saskatchewan for the past 50 years.

Although heavy oil waterfloods are performed regularly in western Canada, there is a surprising lack of information regarding the mechanisms by which water can recover viscous oil. Adams, D.M. (1982) lists examples of field waterfloods in Lloydminster heavy oils, with viscosities ranging between 950 - 6,500 mPaâ‹…s. More recently, Miller, K.A. (2006) proves an overview of some of the laboratory and field data available for heavy oil waterfloods. The major conclusion drawn from this work is that sweep efficiency of these waterfloods is poor, and recovery can be improved through innovative well and production patterns. Smith, G.E. 1992 had lists several mechanisms as potentially being responsible for oil recovery: pressure support, multi-phase expansion of fluids, water imbibition and gravity drainage. However, there is little data provided as direct evidence of these mechanisms.

Several forces could be present during an immiscible waterflood. Viscous forces (i.e., flow according to Darcy's Law) are commonly used to represent the fractional flow of oil and water. Prior to water breakthrough, water is injected into continuous oil channels, and higher-rate waterfloods generally tend to be more unstable. Thus water breaks through quickly, with most of the oil still being continuous at this stage. Pressure then declines quickly because the injected water can easily flow through the low-resistance water fingers and bypass the remaining oil. In this condition, even if the oil relative permeability values are very high compared to those of water, the pressure gradient in the system is very low and there is little driving force remaining to induce flow of oil. For this reason, models of relative permeability developed for conventional oil systems fail to properly describe heavy oil waterfloods. Previous studies have considered the significance of capillary forces in heavy oil systems by performing fixed injection rate waterfloods into unconsolidated sandpacks containing dead (gas-free) heavy oil of varying viscosity. It was demonstrated that improved oil recovery after water breakthrough could be achieved at reduced injection rates, under lower applied pressure gradients. By reducing the injection rate (i.e., the viscous force contribution) the significance of capillary forces could be enhanced, and this allowed more water to access the bypassed regions of the porous medium instead of channeling through the water fingers. Normalized oil rates were lower under fast injection rates, despite the higher pressure gradients induced in these cores. In this manner, it was demonstrated that viscous forces are not responsible for oil production after breakthrough, but in fact they may be detrimental to the efficiency of the waterflood. High rate waterfloods will recover oil more quickly, but at much higher water cuts. Although production will be slower in low rate waterfloods, these floods will be more efficient because of the increased influence of capillary imbibition.

The first experiment this reseacher done was Primary Waterfloods.The rate of oil recovery is high at early times [less than 1 pore volume (PV) injected]. This corresponds to the pre-breakthrough time. Water fingers through this viscous bitumen and breaks through early in the life of the waterflood, and Figure 2.4 shows that additional oil can still be recovered after breakthrough. In the first PV injected, high pressure gradients were developed in the cores and pressure was highest for the fastest injection rate. However, there is no strong monotonic relationship evident between the injection rate and the recovery at the point of breakthrough. Breakthrough recovery was identified as the oil recovery factor at the time when the slopes of the recovery curves in Figure 2.4 begin to decline.

Figure 2.4

After the first water flooding, the reseacher have done the secondry waterflooding, In a secondary waterflood, the oil recovery prior to water breakthrough may be much lower because of the presence of free gas pockets that evolved during primary production. Therefore, experiments were performed in secondary waterflooding systems to investigate if the same recovery mechanisms would apply. The fact that pressure initially increased during the secondary waterfloods is an indication that although the gas saturation was high all along the core, the gas was not continuous. The significant difference between primary and secondary waterflooding, however, was that breakthrough of water occurred with essentially no oil production. Therefore, although the gas pockets were discontinuous, the high gas saturation allowed for redistribution of fluids and the development of a continuous water pathway without production of oil. In these conditions, any oil that is recovered will be at high water cuts, under post-water breakthrough.