King Saud University College of Engineering Petroleum and Natural ...

PGE 363 :Reservoir Engineering Laboratory Manual

King Saud University College of Engineering Petroleum and Natural Gas Engineering Department

PGE 363: Reservoir Engineering Laboratory

Compiled by Dr.Mostafa Mahmoud Abdel Latief Kinawy

March 2009

Dr.Eng.Mostafa M.Kinawy

1

King Saud University College of Engineering Petroleum and Natural Gas Engineering Department PGE 363: Reservoir Rock and Fluids Characteristics Laboratory

Preface This laboratory manual is designed to serve the following objectives: 1) Providing the students of the department of petroleum and natural gas engineering with the knowledge about the basic laboratory equipment and procedures used in core analysis and the theoretical aspects of the parameters. 2) The detailed description of laboratory exercises suitable for student work. 3) Knowledge of petrophysical and hydrodynamic properties of reservoir rocks 4) Give the students some details about the analysis of cores and review the nature and quality of the information that can be deduced from cores. 5) knowledge of the physical properties of reservoir fluids and their practical application in conducting a field study . These fluid properties are usually determined by laboratory experiments performed on samples of actual reservoir fluids. The following topics will be covered

during this course for reservoir engineering

laboratory : 1-introduction explaining course contents, grading criteria,safety issue to be followed in the reservoir engineering laboratory. The theory , objectives,equipment, measurement procedure and calculation methods will be presented. 2-The group of experiments will dealing with Rock sample preparation ,porosity measurement by saturation method and helium porosimeter , permeability measurement by using liquid ,permeability measurement by using gas fluid saturations measurement by extraction method, retort method, capillary pressure measurement by porous plate method and mercury injection method , electrical properties of rock saturated sample , grain size and pore size distribution of formation ,bubble point pressure ,oil formation volume factor and gas formation volume factor ,oil viscosity and finally gas viscosity


PGE 363: Reservoir Engineering Laboratory

COURSE LEARNING OUTCOMES MAPPING

Outcome 3 Outcome 4 Outcome 5 Outcome 6 Outcome 7 Outcome 8 Outcome 9 Outcome10 Outcome11

Outcome 2

Topics Related to Course Learning Outcomes

Outcome 1

Topic addresses Course learning outcome: (0) Not at all (1) slightly (2) moderately (3) considerably

Safety issues

2

0

Rock sample preparation.

3

1

3

1

3

1

3

1

3

1

3

1

Grain size and pore size distribution

3

1

Bubble point pressure Oil formation volume factor

3

1

3

1

Gas formation volume factor

3

1

Oil viscosity

3

1

Gas Viscosity

3

1

76%

24%

Porosity by saturation method and helium porosimeter Permeability by liquid and gas methods Fluid saturations by extraction and retort methods. Capillary pressure by porous plate and mercury injection methods Electrical properties

Average weight


3


Course Learning Outcome: 1. Apply the knowledge of mathematics, geology, physics, chemistry as well as other engineering sciences. (Corresponds to ABET Outcome "a"). 2. Conduct experiments safely and accurately and to be able to correctly analyze the results. (Corresponds to ABET Outcome "b"). 3. Design an engineering process or system to meet desired needs. (Corresponds to ABET Outcomes "c"). 4. Work in a team environment. (Corresponds to ABET Outcome "d"). 5. Identify, formulate and solve engineering problems. (Corresponds to ABET Outcome "e"). 6. Understand professional and ethical responsibilities. (Corresponds to ABET Outcome "f"). 7. Communicate successfully and effectively. (Corresponds to ABET Outcome "g"). 8. Understand the impact of engineering solutions in a global, economic, environmental and societal contest. (Corresponds to ABET Outcome "h").

9. Recognize of the need for, and an ability to engage in life-long learning. (Corresponds to ABET Outcome "i"). 10. Knowledge of contemporary issues. (Corresponds to ABET Outcome "j"). 11. Understand the use of modern techniques, skills and modern engineering tools necessary for petroleum and natural gas engineering practice. (Corresponds to ABET Outcome "k").


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Table of contents Preface ……………...…………………………………………………….…..2 Course Outcomes Learning Mapping ……………………………………..….3 Table of Contents………….………….………………………………….…....5 Introduction to petroleum reservoir engineering rock and fluids properties….6 Experiment #1: Rock sample preparation………………………………………...11 Experiment #2: Porosity by saturation method and helium porosimeter………………..16 Experiment #3: Permeability measurement by using liquid …………………………….34 Experiment #4: Permeability measurement by using gas ……………………………….37 Experiment #5: Fluid saturations measurement by extraction method………………….39 Experiment #6: Fluid saturations measurement by retort method………………...…43 Experiment #7: Capillary pressure by porous plate method ………………………..47 Experiment #8: Capillary pressure by mercury injection method…………………...52 Experiment #9: Electrical properties ……………………………………………………55 Experiment #10: Grain size and pore size distribution………………………………….57 Experiment #11: Bubble point pressure…………………………………………62 Experiment #12: Oil formation volume factor and Gas formation volume factor…….65 Experiment #13: Oil viscosity ……………………………………………………. …..69 References ………………………………………………………...………..75


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1. INTRODUCTION Knowledge of petrophysical and hydrodynamic properties of reservoir rocks are of fundamental importance to the petroleum engineer. These data are obtained from two major sources: core analysis and well logging. In this book we present some details about the analysis of cores and review the nature and quality of the information that can be deduced from cores. Cores are obtained during the drilling of a well by replacing the drill bit with a diamond core bit and a core barrel. The core barrel is basically a hollow pipe receiving the continuous rock cylinder, and the rock is inside the core barrel when brought to surface. Continuous mechanical coring is a costly procedure due to: - The drill string must be pulled out of the hole to replace the normal bit by core bit and core barrel. - The coring operation itself is slow. - The recovery of rocks drilled is not complete. - A single core is usually not more than 9 m long, so extra trips out of hole are required. Coring should therefore be detailed programmed, specially in production wells. In an exploration well the coring can not always be accurately planned due to lack of knowledge about the rock. Now and then there is a need for sample in an already drilled interval, and then sidewall coring can be applied. In sidewall coring a wireline-conveyed core gun is used, where a hollow cylindrical “bullet” is fired in to the wall of the hole. These plugs are small and usually not very valuable for reservoir engineers. During drilling, the core becomes contaminated with drilling mud filtrate and the reduction of pressure and temperature while bringing the core to surface results in gas dissolution and further expansion of fluids. The fluid content of the core observed on the surface can not be used as a quantitative measure of saturation of oil, gas and water in the reservoir. However, if water based mud is used the presence of oil in the core indicates that the rock information is oil bearing. When the core arrives in the laboratory plugs are usually drilled 20-30 cm apart throughout the


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reservoir interval . All these plugs are analyzed with respect to porosity, permeability, saturation and lithology. This analysis is usually called routine core analysis. The results from routine core analysis are used in interpretation and evaluation of the reservoir.

1-The objectives and outcomes of the course : 1) Providing the students of the department of petroleum and natural gas engineering with the knowledge about the basic laboratory equipment and procedures used in core analysis and the theoretical aspects of the parameters. 2) The detailed description of laboratory exercises suitable for student work. 3) Knowledge of petrophysical and hydrodynamic properties of reservoir rocks 4) Give the students some details about the analysis of cores and review the nature and quality of the information that can be deduced from cores. 5) knowledge of the physical properties of reservoir fluids and their practical application in conducting a field study . These fluid properties are usually determined by laboratory experiments performed on samples of actual reservoir fluids. By the end of this course , the student should be able to conduct experiments and analyze results of the different properties of rock and fluid properties mentioned previously.

2-Grading Criteria: i- Course work : including how to perform the experiments accurately and safely in a team work environment (reports, attendance and participation) : 60 Marks. ii- Final examination (oral +written): 40 Marks

3-Safety Instructions: Safety in the laboratory must be of vital concern to all those engaged in experimental work. It is therefore the responsibility of everyone to adhere strictly to the basic safety precautions provided and to avoid any acts of carelessness that can endanger his life and that of others around him. It is equally important to always abide by all the instructions for conducting the experimental work during the laboratory sessions. Below are some guidelines for general laboratory safety and procedures:


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1-All students must be familiar with the locations and operational procedures of the emergency shower, fire extinguishers, gas masks and fire blankets. 2-Laboratory coats, safety glasses and safety shoes must be worn at all times during the laboratory session. no open sandals are allowed during the laboratory sessions. 3-Eating and drinking are strictly prohibited in the laboratory at all times. Laboratory glassware should never be used for drinking purpose. 4-Report any injury immediately for first aid treatment, no matter how small. 5-Report any damage to equipment or instrument and broken glassware to the laboratory instructor as soon as such damage occurs. Emergency shower fire blankets, gas mask and fire extinguisher 6-Carefully handle chemicals, acids, mercury, HP-HP equipments, etc. 7-Clean any water or oil spill from laboratory floor. 8-Distinguish between 110V and 220 V appliances to avoid equipment damage. 9-Don't attempt to work in the laboratory alone at any time.

4-Report Format: Each student must submit a report within one week from the time of performing the experiment. The report will be evaluated and returned back to the student. The report must cover the following parts: Cover page. Objectives. Theory (Introduction). Apparatus. Procedure. Observations and Experimental raw data. Results and Discussion. Conclusions and Recommendations. References.


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All students must use the cover page format shown below in their weekly reports: .

King Saud University College of Engineering Petroleum and Natural Gas Engineering Department PGE 363: Reservoir Rock Characteristics Laboratory

Experiment No.: ……………………………………….. ………………………………………… …………………………………………

Student Name: ……………………........ Student ID Number:…………………....

Submission Date:…………………….


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5-Course syllabus: The following experiments will be performed during this course for reservoir engineering rock and fluid properties:

Experiments

Week

Rock sample preparation.

1

Porosity by saturation method and helium porosimeter

2

Permeability by using liquid

3

Permeability by using gas

4

Fluid saturations by extraction method.

5

Fluid saturations by using retort method.

6

Capillary pressure by porous plate method.

7

Capillary pressure by mercury injection method.

8

Electrical properties

9


10

Bubble point pressure

11

Oil formation volume factor and gas formation volume factor

12

Oil viscosity

13

Team work environment

week

Porosity by saturation method

2

Permeability by using liquid

3

Permeability by using gas

4


10


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Experiment #1 Rock sample preparation 1. Cleaning and Saturation Determination: 1.1.Objectives: Cleaning and drying the core samples

1.2. Introduction and Theory: Before measuring porosity and permeability, the core samples must be cleaned of residual fluids and thoroughly dried. The cleaning process may also be apart of fluid saturation determination.

1.3.Laboratory Methods 1.3.1 Direct Injection of Solvent The solvent is injected into the sample in a continuous process. The sample is held in a rubber sleeve thus forcing the flow to be uniaxial.

1.3.2 Centrifuge Flushing A centrifuge which has been fitted with a special head sprays warm solvent onto the sample. The centrifugal force then moves the solvent through the sample. The used solvent can be collected and recycled.

1.3.3 Gas Driven Solvent Extraction The sample is placed in a pressurized atmosphere of solvent containing dissolved gas.


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The solvent fills the pores of sample. When the pressure is decreased, the gas comes out of solution, expands, and drives fluids out of the rock pore space. This process can be repeated as many times as necessary.

1.3.4 Soxhlet Extraction

A Soxhlet extraction apparatus is the most common method for cleaning sample, and is routinely used by most laboratories. As shown in Figure (1.1a), samples to be cleaned are placed in a porous thimble inside the Soxhlet.

Electric or gas heaters are used to vaporize the solvent. The hot vapors meet the samples in the thimble and dissolve the oil and water. Vapors are condensed and cover the sample until over-flown back to the solvent flask. The extraction process continues for several hours and is terminated when no more oil remains in the samples. This is recognized when the condensing vapors remain clean because no oils is left in the cores to be dissolved.

After the extraction, samples are dried in an electric oven. Sometimes vacuum may also be applied to the oven. A complete extraction may take several days to several weeks in the case of low API gravity crude or presence of heavy residual hydrocarbon deposit within the core. Low permeability rock may also require a long extraction time.The dried samples are kept in a desiccator sealed with grease and has some moisture absorbents at its bottom .


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Figure(1-1-a): Soxhlet Extraction Apparatus

1.3.5 Dean-Stark Distillation-Extraction

The Dean-Stark distillation provides a direct determination of water content. The oil and water area extracted by dripping a solvent, usually toluene or a mixture of acetone and chloroform, over the plug samples. In this method, the water and solvent are vaporized, recondensed in a cooled tube in the top of the apparatus and the water is collected in a calibrated chamber (Figure 1.1b). The solvent overflows and drips back over the samples. The oil removed from the samples remains in solution in the solvent. Oil content is calculated by the difference between the weight of water recovered and the total weight loss after extraction and drying.


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Figure(1-1-b): Dean-Stark Distillation-Extraction

1-4-Conclusions and Recommendations. The direct-injection method is effective, but slow. The method of flushing by using centrifuge is limited to plug-sized samples. The samples also must have sufficient mechanical strength to withstand the stress imposed by centrifuging. However, the procedure is fast. The gas driven-extraction method is slow. The disadvantage here is that it is not suitable for poorly consolidated samples or chalky limestones. The distillation in a Soxhlet apparatus is slow, but is gentle on the samples. The procedure is simple and very accurate water content determination can be made. Vacuum distillation is often used for full diameter cores because the process is relatively rapid. Vacuum distillation is also frequently used for poorly consolidated cores since the process does not damage the sample. The oil and water values


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are measured directly and dependently of each other. In each of these methods, the number of cycles or amount of solvent which must be used depends on the nature of the hydrocarbons being removed and the solvent used. Often, more than one solvent must be used to clean a sample. The solvents selected must not react with the minerals in the core. The commonly used solvents are: - Acetone - Benzene - Benzen-methol Alcohol - Carbon-tetrachloride - Chloroform - Methylene Dichloride - Mexane - Naphtha - Tetra Chloroethylene - Toluene - Trichloro Ethylene - Xylene


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Experiment #2 Porosity Measurement by saturation method and helium porosimeter Porosity 2-1-Introduction: One of the essential properties of a reservoir rock is that it must be porous. Porosity is therefore an important property and its accurate determination is relevant to reserve estimates and other petroleum engineering calculations. The porosity of a material defined as the fraction of the bulk volume occupied by pores. Thus porosity is a measure of the storage capacity of the rock. The more porous is the rock, the more is its capacity to store fluids (oil, gas and water) in its pores. By definition Porosity

)

pore volume Vp bulk volume Vb

(2-1)

It is sometimes convenient to express porosity in percent. So % Porosity

Vp Vb

x 100

(2-2)

Since a rock is composed from pores and grains or rock matrix, it is obvious that Bulk volume = grain volume + pore volume

Vb = Vg + Vp

(2-3)

Vp = Vb – Vg

(2-4)

and

It is clear from the above relations that any two of the three values V p, Vg and Vb are sufficient to determine the value of porosity .


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i)

Porosity from pore and bulk volumes = Vp / Vb

ii)

Porosity from pore and grain volumes Vp Vb

iii)

(2-5)

Vp Vg

Vp

(2-6)

Porosity from grain and bulk volumes Vp Vb

Vb

Vg Vb

(2-7)

It must be noticed that the two volumes used to determine the porosity must be for the same sample. For example, if the bulk and grain volumes are used to determine

according

to Eq. (2-7) and if the bulk volume of a uniform sample is determined by measuring the sample dimensions while the grain volume of the sample is to be determined by crushing the sample and finding the volume of the grains, care must be taken not to loose any of the grains.

2-1-1-Absolute and Effective Porosity: Some of the pores in a rock may be sealed off from other pores by cementing materials. These pores, although present and contribute to the porosity as defined earlier, do not allow passage or withdrawal of fluids. If the total pores whether connected or unconnected are considered in determining porosity, the total or absolute porosity is obtained. On the other hand if only the interconnected pores are considered, the effective porosity will result. The difference between absolute and effective porosity is known and the dead porosity.

2-2-Laboratory Measurements of Porosity: As indicated before it is necessary to determine two of the three volumes (bulk, grain and pore) to estimate the porosity. Sometimes the bulk and grain densities may be used instead of bulk and grain volumes. Depending on the method used, either absolute or effective porosity will result.


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2-2-1-Determination of Bulk Volume:

2-2-1-1-By Measuring the Dimensions: For a regularly shaped sample, the bulk volume is found by measuring the dimensions of the sample. For a cylindrical sample with diameter D and length L, the bulk volume is given by: Vb = ( /4) D2 L

(2-8)

For a sample with rectangular cross section Vb = a x b x L

(2-9)

A sliding caliper is used to measure the dimensions. Different reading are usually taken for the diameter and length and the average values are used.

2-2-1-2-By Russel Volumeter: In this case a sample must by saturated completely with a non-reacative fluid or coated by paraffin wax and then placed in the volumeter Figure. (2-1). The difference in the fluid level before and after the sample gives the bulk volume of the sample. If the sample is coated the volume of the coating material must be found and subtracted from the reading. This obtained by noting the weight of the coating wax which is the difference between the weight of the sample before and after coating and dividing it by the density of the wax.


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Figure. (2-1) Russel Volumeter

2-2-1-3-Gravimetric (Loss of Weight) Method: A coated sample is weighed suspended in air and then suspended in a liquid (water or kerosene). The difference in weight is the buoyancy force which is equal to the volume of displaced fluid multiplied by the density of the fluid. Since the volume of the displaced fluid is the same as the volume of immersed solid, then: volume of coated sample = (W1 – W2) /


(2-10)

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Where: W1

= weight in air

W2

= weight in liquid = density of liquid

The volume of the coating material must be found and subtracted as explained earlier.

2-2-1-4-By Mercury Pycnometer: A special steel pycnometer is used Figure.( 2-2). It is first filled with mercury. The top is removed and the sample placed at the mercury surface. The top is then pressed down allowing excess mercury to overflow into a beaker. The excess mercury is then collected and its volume determined in a graduated cylinder. For more accuracy, the mercury may be weighed and the volume determined by dividing the weight of mercury by its density.

Figure.( 2-2) :Mercury Pycnometer:

2-2-1-5-By Mercury Pump: When a rock has a small fraction of void space, it is difficult to measure porosity by the mentioned methods.At this case, mercury injection is used. The principle consists of


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forcing mercury under relatively high pressure in the rock pores. A pressure gauge is attached to the cylinder for reading pressure under which measuring fluid is forced into the pores. Figure. (2-.3b) shows a typical curve from the mercury injection method. The volume of mercury entering the core sample is obtained from the device with accuracy up to 0.01 cm3.

Figure (2-3): Mercury injection pump (a) and porosity through mercury injection (b).

The pump consists of a core chamber, pump cylinder with piston and wheel, scales and gauges Figure. (2-3). First mercury is brought to a fixed mark above the sample chamber and the pump is brought to zero reading. The piston is removed withdrawing mercury from the chamber. The sample is then placed in the chamber and mercury is brought back to the fixed mark. The reading of the pump scale gives the bulk volume of the sample.

Notes: 1-In the loss of weight method, if a saturated sample is used instead of a coated sample, the grain volume of the sample is obtained. 2-The Russel volumeter may be used in the same way described to determine the grain volume of a crushed sample.


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3-If the weight of a dry clean sample is determined before coating or saturating the sample, the bulk density of the sample is found from the measured bulk volume.

Bulk density ( b)

weight of dry sample bulk volum e of sample

(2-11)

2-2-2-Determination of Grain Volume: 2-2-2-1-By Russel Volumeter: A part of a clean (extracted) dry sample is crushed into individual grains. The grains are weighed by analytical balance and the volume is determined by Russel volumeter as in the case of bulk volume determination.

2-2-2-2-By Pycnometer: A glass pycnometer (Fig. 1-4) is used. The pycnometer is weighed empty and then filled with water (or kerosene). The crushed sample is weighed then placed in the empty pycometer and the weight is determined. Finally the pyconometer with the grains in it is completed with water until it is completely filled and the total weight is determined. The grain volume is then calculated as follows:

Vg

W1

(W2

W0 ) W3

(2-12)

where, W1 = weight of pycnometer filled with fluid W0 = weight of empty pycnometer W2 = weight of pycnometer + grain W3 = weight of pycnometer + grain + fluid = density of fluid

Notes: 1. (W2 – W0) is the weight of the crushed grains. This is more accurate than the use of the weight of the grains before placing in pycnometer because some grains may be lost.


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2. The same method can be used to determine the bulk volume of a coated or fully saturated sample. 3. The grain volume of a sample (uncrushed) can also be obtained by Russel Volumeter or the pycnometer methods provided the sample is unsaturated (dry) and enough time is allowed for the fluid to penetrate the pores of the sample before the readings are taken.

2-2-2-3-Loss of Weight Method: The weight of a dry clean sample W1 is determined. The sample is then fully saturated with a non-reactive liquid. The weight of the sample suspended in the liquid W2 is then determined. The difference (loss) of weight is divided by the density of the liquid to find the grain volume of the sample.

Vg = (W1 – W2) /

(2-13)

The grain volume determined by this method is the effective grain volume which includes any pores that are sealed off. Porosity calculated using this method will be the effective porosity.

2-2-2-4-Gas Expansion Method: Many porosimeters are designed to use the principle of Boyle’s law of gas expansion to determine the grain volume. The idea is to allow the remaining volume of a chamber in which a core is placed (V1 – Vg) at pressure P1 to expand by an additional volume V2 and read the final pressure P2 (Fig. 1-5). From Boyle’s Law (at constant temperature). (V1 – Vg) P1 = (V1 – Vg + V2) P2

(2-14)

knowing V1, V2, P1 and P2 allows the calculation of grain volume Vg. Vg = V1 – [(P2 / (P1 – P2)] V2


(2-15)

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Note: If we know the weight of the dry clean sample for which the grain volume is determined, the grain density can be calculated by:

g

weight of dry sample grain volu me of sample

(2-16)

The helium porosimeter uses the principle of gas expansion, as described by Boyle’s law. A known volume (reference cell volume) of helium gas, at a predetermined pressure, is isothermally expanded into a sample chamber. After expansion, the resultant equilibrium pressure is measured. This pressure depends on the volume of the sample chamber minus the rock grain volume, and then the porosity can be calculated.

2-2-3-Pore Volume Determination: 2-2-3-1-Saturation Method: A dry clean sample is weighed and placed in a suction flask with two connections to a vacuum pump and a seperatory funnel (Fig. 1-6). First the valve is closed and vacuum is applied. After sufficient vacuum is reached the vacuum pump is shut off, the valve to the funnel is opened and the liquid is allowed to saturate the sample. The sample is kept immersed in the liquid for sometime to allow complete saturation. The saturated sample is drained from excess liquid and weighed. The pore volume is then calculated as: Vp = (W2 – W1) /

(2-17)

where, W2 = weight of saturated sample W1 = weight of dry sample = density of saturating fluid A wetting non-reactive liquid must be used. Kerosene or tetrachlorethane are usually used.


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2-2-3-2-Mercury Injection Method: The mercury pump described in bulk volume determination is also used for pore volume determination. After a dry sample is placed in the core chamber and the bulk volume is determined, pressure is applied by moving the piston clockwise allowing mercury to enter the pores of the sample. Pressure vs. volume of injected mercury is recorded until a pressure of 1000 psia is reached. The final volume reading gives the pore volume of the sample. Notes: 1. Macropores and fractures can be detected by a flat curve at the start where increase in volume is noted without appreciable rise in pressure (Fig. 1-7). 2. Capillary pressure curves can be calculated from the same experiment.

2-2-3-3-Washburn Bunting Method: This method is based on liberating the air from the pores of the sample by creating vacuum. This is achieved by first raising the mercury level above the sample while the valve is open, closing the valve and then lowering the mercury reservoir Figure( 2-4) so that the mercury falls below the sample in the chamber. The collected air is measured under atmospheric pressure by raising the mercury reservoir until the mercury level is the same in the two sides. Air is then allowed to escape and the process is repeated until no more air is extruded. The total volume of air (under atmospheric pressure) is recorded.


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Figure (2-4): Washburn –Bunting type The experiment is first run without a sample to determine the volume of air adsorbed on the glass surface of the apparatus. This volume is subtracted from the total air volume obtained before to get the pore volume of the sample.

2-2-3-4-Gas Expansion Method: The mercury pump (with a vacuum) gauge is used. After the bulk volume is determined and mercury fills the chamber but does not penetrate the sample, the air in the pores is allowed to expand by withdrawing the mercury from the chamber. If the volume of mercury withdrawn is V which is read on the pump scale then from Boyle’s Law :


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Vp P1 = (Vp + V) P2

(2-18)

so Vp = V[(P2 / (P1 – P2)]

(2-19)

where, P2 is the final pressure read on the vacuum gauge and P1 is initial pressure (atmospheric) It is clear that if P2 = ½ P1 then Vp = V.

(2-20)

So the pore volume would be equal to the volume of mercury withdrawn from the chamber to reduce the pressure in the chamber to half its original (atmospheric) value. All the methods measuring pore volume yield effective porosity. The methods are based on either the extraction of a fluid from the rock or the introduction of a fluid into the pore spaces of the rock. One of the most used methods is the helium technique, which employs Boyle’s law. The helium gas in the reference cell isothermally expands into a sample cell. After expansion, the resultant equilibrium pressure is measured.

Figure (2-4):The Helium porosimeter apparatus The schematic diagram of the helium porosimeter shown in Figure(2-4) has a reference volume V1, at pressure p1, and a matrix cup with unknown volume V2, and initial pressure


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p2. The reference cell and the matrix cup are connected by tubing; the system can be brought to equilibrium when the core holder valve is opened, allowing determination of the unknown volume V2 by measuring the resultant equilibrium pressure p. (Pressure p1 and p2 are controlled by the operator; usually p1 = 100 and p2 = 0 psig). When the core holder valve is opened, the volume of the system will be the equilibrium volume V, which is the sum of the volumes V1 and V2. Boyle’s law is applicable if the expansion takes place isothermally. Thus the pressure-volume products are equal before and after opening the core holder valve: P1V1 +P2V2

= P(V1+V2)

(2-21)

Solving the equation for the unknown volume, V2: V2

=

(P-P1)V1

(2-22)

P2-P1 Since all pressures in equation (5.4) must be absolute and it is customary to set p1 = 100 psig and p2 = 0 psig, Eq. (5.4) may be simplified as follows: V2

=

V1(100-P)

(2-23)

P where V2 in cm3 is the unknown volume in the matrix cup, and V1 in cm3 is the known volume of the reference cell. p in psig is pressure read directly from the gauge. 3-3-Conclusions and recommendations: Helium has advantages over other gases because: (1) its small molecules rapidly penetrated small pores, (2) it is inert and does not adsorb on rock surfaces as air may do, (3) helium can be considered as an ideal gas (i.e., z = 1.0) for pressures and temperatures usually employed in the test, and (4) helium has a high diffusivity and therefore affords a useful means for determining porosity of low permeability rocks.


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Permeability measurement by using gas and liquid Permeability (K) 3-1-Introduction The permeability of rock is the ability of that rock to transmit fluids through it. So the permeability is a measure of the production potential of formation. The higher the permeability of a reservoir rock in a well the more the production the could be realized from that well. The product (k×h) where k is the permeability and h is the thickness is known as the formation capacity. While porosity depends on the fraction of bulk volume occupied by pores regardless of the size of the individual pores, the permeability largly depends on the size of the different pores (pore size and pore size distribution). The larger the pore size in a rock, the higher will be the permeability of that rock. Shales, for example, have a very high porosity (50%) while their permeability is very low because of their very small pores. On the other hand

fractured limestone have very small porosity while their permeability is very high

because of the large fractured. Mathematically, the permeability is defined by means of Darcy law which gives the flow rate of an incompressible fluid in a linear homogeneous porous system by: Q=

KA P µ L

(3-1)

Where, Q = flow rate, cm3/sec A = cross-sectional area, cm2 P = pressure drop, atom L = length, cm µ = fluid viscosity, cp k = permeability, Darcy


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It is therefore obvious that the permeability of a rock is equal to the flow rate of a fluid of 1 cp viscosity in a sample of 1cm2 cross-sectional area under a pressure gradient of 1 atom/cm. Usually the permeability is given in millidarcies, where 1 darcy=1000 md.

Because some liquid may react with the rock matrix it is more convenient to use gas (air) in permeability measurement. Since gases are compressible, eq. (3.1) is not applicable. For ideal gas flow: Q=K A (P12 –P22)

(3-2)

2µLP

Where, P is the pressure at which the flow rate Q is measured. It can be shown that if Q is measured at the mean pressure Pm= [(P1+P2)/2] then : Qm =K A

P

(3-3)

µL 3-2- Absolute, Effective and Relative Permeability:

If a single fluid is flowing alone in a porous medium, the permeability calculated by Eq. (3.1) – (3.3) is known as absolute permeability. In other words it is the permeability at 100% saturation of a given fluid. If more than one fluid are present in the pore space, the permeability. It is clear that the effective permeability is less than or equal to the absolute permeability and is a function of the fluid saturation as well as the absolute permeability of the rock. The relative permeability is the ratio of the effective permeability to the absolute permeability and is a function of the fluid saturation only.

3-3-Air and liquid permeability:

At high pressure, gas molecules become close to each other and the mean free path of the gas approaches the diameter of pores. In this case the phenomena of gas slippage occurs and the


30


permeability to the gas is reduced. At very high pressures, the gas permeability Kg approaches that of liquid permeability KL. according to klinkenberg: Kg

=

K L ( 1+

b ) Pm

(3.4)

Where, Pm is the mean pressure [(P1+P2)/2]. It is clear that a plot of Kg Vs. 1/Pm gives a straight line with slope b and intercept KL Figure (3-1). This phenomena of gas permeability dependence on mean pressure is known as the "klinkenberg effect".

Figure (3-1): Variation in gas permeability with mean pressure and type of gas. 3-4-Radial Flow For radial flow of incompressible fluids: Q= 2

K h (Pe -Pw) µ ln (re/rw)

( 3-5)

Where the same units as in Eq. (3.1) are used. For the radial flow of ideal gas, Eq. (3.5) may be used with Qm measured at the mean pressure [(Pe + Pw) /2] instead of Q.


31


3-5-Laboratory Determination of absolute permeability: A cylindrical core (plug) is usually used. The dimensions of the core (diameter and length) are measured by a sliding vernier. The core is placed in a rubber sleeve (early models use brass cylinders and the core is fitted using sealing wax) and inserted in the core holder of the permeameter Figure(3-2).

Figure (3-2): Schematic diagram of permeameter Permeability is measured by passing a fluid of known viscosity through a core sample of measured dimensions and then measuring flow rate and pressure drop. Various techniques are used for permeability measurements of cores, depending on sample dimensions and shape, degree of consolidation, type of fluid used, ranges of confining and fluid pressure applied, and range of permeability of the core Air or liquid is passed through the core and the pressure is measured by pressure gauges at the inlet and outlet faces of the core (usually the pressure is atmospheric at the outlet). The flow rate measured by a suitable device (rotometer or wet test meter).Different flow rates are Dr.Eng.Mostafa M.Kinawy

32


usually used and the corresponding pressure drop is recorded. If gas is used, the flow rate is calculated at the mean pressure using ideal gas law: Qm Pm

=

Qout Pout

(3-6)

The permeability is the calculated using Eq. (3.1) or (3.3). A plot of Q vs. P will show whether the flow is still in the laminar (viscous) range where Darcy Law is applicable Figure. (3-3a) and (3-3b)

Figure (3-3): (a) : Plot of experimental results for calculation of permeability from equation k = QµL/(P1-P2) ,(b) : Plot of experimental results for calculation of permeability from equation k =2QbµLPb/A(P12-P22)


33


Experiment #3 Permeability measurement by using air Description: The constant head permeameter with the Hassler cell is used to measure the air permeability. Apparatus: The apparatus used is illustrated in figure (3-4)

Figure (3-4) :Gas Permeameter Procedure: The measured air permeability is influenced by the mean pressure Pm of the core. A cylindrical core (plug) is usually used. The dimensions of the core (diameter and length) are measured by a sliding vernier. The core is placed in a rubber sleeve (early models use brass cylinders and the core is fitted using sealing wax) and inserted in the core holder of the permeameter Figure (3-4). Or Figure (3-6). Air or liquid is passed through the core and the


34


pressure is measured by pressure gauges at the inlet and outlet faces of the core (usually the pressure is atmospheric at the outlet). The flow rate measured by a suitable device (rotometer or wet test meter). Different flow rates are usually used and the corresponding pressure drop is recorded. If gas is used, the flow rate is calculated at the mean pressure using ideal gas law Air viscosity as a function of temperature is shown in Figure (3-5). Four measurements of air permeability will be taken at different pressures. It is important to keep the P constant, because the air flow at the core sample must be laminar. It is best to have relative little pressure difference, P. To avoid turbulent flow, use a maximal P = 0.2 bar. Results and Calculation: 1. Calculate air permeability from Equation (3-2) 2. Plot k versus 1/Pm and calculate kL. 3. Calculate Klinkenberg constant b.


35


Figure (3-5): Gas viscosity as a function of temperature.

Figure (3-6):Hassler type core holder


36


Experiment #4 Permeability measurement by using liquid (water) Description: The objective of this experiment is to measure the absolute permeability of water using a method based on the Darcy theory. Apparatus: The apparatus used is illustrated in figure (4-1)

Figure (4-1): Liquid Permeameter

Procedure: 1. Weight a dry Berea plug Wdry, measure its diameter D and length L, with caliper. Saturate the core with 36 g/l NaCl brine and weigh the plug, Wsat. 2. Mount the core in core holder. 3. Measure three flow rates under three driving pressures: 0.6, 0.8, 1.0, or 1.2 bar. Each measurement collects water production Vw, in T = 60 seconds. 4. Plot a line through the three P-Vw data in a grid paper. Calculate the absolute permeability kab.


37


Calculations and report: Core No.: D: L: Wdry: Wsat:

cm cm gm gm.

Conclusions and recommendations Permeability is measured by passing a fluid of known viscosity through a core sample of measured dimensions and then measuring flow rate and pressure drop. Various techniques are used for permeability measurements of cores, depending on sample dimensions and shape, degree of consolidation, type of fluid used, ranges of confining and fluid pressure applied, and range of permeability of the core.


38


Experiment #5 Fluid saturations measurement by extraction method. 5-1 -Theory (Introduction). Fluid saturation is defined as the ratio of the volume of fluid in a given core sample to the pore volume of the sample: Sw = Vw Vp

So = Vo Vp

Sw +So +Sg =

Sg =

1

Vg Vp

(5-1)

(5-2)

where Vw, Vo, Vg and Vp are water, oil, gas and pore volumes respectively and Sw, So and Sg are water, oil and gas saturations. Note that fluid saturation may be reported either as a fraction of total porosity or as a fraction of effective porosity. Since fluid in pore spaces that are not interconnected can not be produced from a well, the saturations are more meaningful if expressed on the basis of effective porosity. The weight of water collected from the sample is calculated from the volume of water by the relationship: Ww =

w

Vw

(5-3)

where w is water density in g/cm3. The weight of oil removed from the core may be computed as the weight of liquid less weight of water: Wo = WL -Ww

(5-4)

where WL is the weight of liquids removed from the core sample in gram. Oil volume may then be calculated as Wo/

w.

Pore volume Vp is determined by a porosity measurement,and

oil and water saturation may be calculated by Eq. (5.1). Gas saturation can be determined using Eq. (5.2 5-2- Saturation Determination, Dean-Stark Distillation Method : 5-2-1-Apparatus The Dean-Stark distillation provides a direct determination of water content. The oil and


39


water area extracted by dripping a solvent, usually toluene or a mixture of acetone and chloroform, over the plug samples. In this method, the water and solvent are vaporized, recondensed in a cooled tube in the top of the apparatus and the water is collected in a calibrated chamber Figure (5-1).

Figure (5-1): The Dean-Stark distillation apparatus 5-2-2-Description: The objective of the experiment is to determine the oil, water and gas saturation of a core sample. 5-2-3-Procedure: 1. Weigh a clean, dry thimble. Use tongs to handle the thimble. 2. Place the cylindrical core plug inside the thimble, then quickly weigh the thimble and sample.


40


3. Fill the extraction flask two-thirds full with toluene. Place the thimble with sample into the long neck flask. 4. Tighten the ground joint fittings, but do not apply any lubricant for creating tighter joints. Start circulating cold water in the condenser. 5. Turn on the heating jacket or plate and adjust the rate of boiling so that the reflux from the condenser is a few drops of solvent per second. The water circulation rate should be adjusted so that excessive cooling does not prevent the condenser solvent from reaching the core sample. 6. Continue the extraction until the solvent is clear. Change solvent if necessary. 7. Read the volume of collected water in the graduated tube. Turn off the heater and cooling water and place the sample into the oven (from 1050C to 1200C), until the sample weight does not change. The dried sample should be stored in a desiccater. 8. Obtain the weight of the thimble and the dry core. 9. Calculate the loss in weight WL, of the core sample due to the removal of oil and water. 10. Measure the density of a separate sample of the oil. 11. Calculate the oil, water and gas saturations after the pore volume Vp of the sample is determined. 5-2-4-Data and calculations: Sample No:

Porosity:

Where Worg: Weight of original saturated sample Wdry: Weight of desaturated and dry sample

5-2-4-1-Equations: WL= Worg - Wdry Wo= WL - Ww


41

PGE 363 :Reservoir Engineering Laboratory Manual Vb = Vp =

(D/2)2 l Vb

where D and L are diameter and length of the core sample, respectively.


42


Experiment #6 Fluid saturations measurement by retort method. 6-1-Theory: The theories of the formation of oil reservoirs consider that oil traps (structural or stratigraphic)

originally were filled with water of marine origin. The oil and/or gas is

believed to have entered the trap, displacing the water to some original reservoir saturation (the connate water saturation). Thus, a petroleum reservoir normally contains both petroleum hydrocarbons and water occupying the same, or adjacent, pores. Quantitative evaluation of the fluids is necessary for reservoir characterization. The retort distillation is divided into two parts: (1) as the rock is first heated (to approximately 400'F or 204OC), water and all but the heaviest fraction of the oil present in the sample are vaporized; and (2) in the second stage of heating, the temperature is raised to about 1 100°F (593°C) and the hydrocarbons remaining in the sample are vaporized, or cracked by the heat and removed as a vapor. Part of this vapor is condensable and part is not. Generally the process of cracking leaves a carbon residue within the core. Therefore, the amount of oil recovered by retort distillation is less than the amount of oil in the core. Thus, the intense heat removes water of crystallization from the clays and other hydrated minerals present in the core. The amount of water obtained is slightly greater than the amount of free water in the pores because of the added water of crystallization. Empirical correction factors (obtained from retorting cores containing known amounts of oil) are used to correct for the retorting errors. The correction factors are defined as

follows: Co = fraction of oil left in the rock as coke, with respect to the total oil C, = amount of excess water recovered due to dehydration (removal recovered. of water of crystallization) with respect to the dry mass of the sand The fluids produced by the retort are collected in the centrifuge tubes, which then may be centrifuged to separate the oil and water for accurate volumetric measurements.Because the oil is less dense than the water, it will separate to the top of the liquid column in the centrifuge tubes. An emulsion (a


43


fine mixture of oil in water) will form in the centrifuge tubes between the oil and water that cannot be separated by the centrifuge. As a first approximation, one can assume that the emulsion is composed of 80% water and 20% oil, by volume. If better results are obtained by changing the water/oil ratio of the emulsion, one should do so. 6-2-Retort Apparatus: The retort apparatus is illustrated in figures (6-1) and (6-2). 1-Retort assembly

2-Graduated centrifuge tubes

porosimeter

5-Oven-dried sandstone

3-Analytical balance

4-Oil injection

6-Saturated sandstone

Figure (6-1) : Retort apparatus


44


Figure ( 6-2 ): Retort distillation apparatus

6-2-2-Retort Specimen: 1. Obtain core samples from the instructor. 2. Determine the bulk volume of the core sample by measurement with a caliper or using an oil or mercury

porosimeter (Experiment No. 8).

3. Obtain the mass of the core sample.


45


4. Place the sample in the retort cylinder and screw the lid on (hand-tight only).

6-2-3-Retort Caliberation: 1. Crush part of the dried sandstone to half-centimer fragments.

2. Place the fragments into the retort receptacle to within one-half inch of the top and pack them in tightly.

3. Using a pipette, slowly drip 6 ml of oil and 4 ml of water over the crushed rock. The centrifuge tube should be under the retort to catch any flow.

6-3-Retorting Procedure: 1. Start circulating water through the condensers. 2. Plug in both retorts.

3. After 45 minutes, prop the circulating hoses upright. Fill them with water and close the water valve. 4. Thirty (30) minutes later, drain all of the water from the condensers.

5. Fifteen (15) minutes later, unplug the retorts. 6. Cool the retorted samples. DO NOT PLACE THE RETORTED SAMPLES ON WAXED PAPER. Record the dry mass of the samples. 7. Centrifuge the tubes containing the fluids and record the total fluid volumes obtained in: ( 1 ) the calibration retort and (2) the sample retort

.


46


Experiment #7 Capillary pressure by porous plate method Capillary Pressure 7-1-Theory (Introduction). Capillary pressure is the difference in pressure between two immiscible fluids across a curved interface at equilibrium. Curvature of the interface is the consequence of preferential wetting of the capillary walls by one of the phases. Figure (7-1) illustrates various wetting conditions. In Figure (7-1-)a, two immiscible fluids are shown in contact with a capillary. The water wets the walls of the capillary, but the oil is non-wetting and is resting on a thin film of the wetting fluid. The pressure within the non-wetting fluid is greater than the pressure in the wetting fluid and, consequently, the interface between the fluids is curved convex with respect to the non-wetting fluid. The capillary pressure is defined as the pressure difference between the non-wetting and wetting phases:

Pc = Pnw - Pw

(7-1)

In Figure 5.lb, the two fluids wet the walls of the capillary to the same extent, and the pressure of each fluid is the same. Therefore, the interface between the immiscible fluids is straight across (-90") and the capillary pressure is equal to zero. If the pressure in the water is greater than in the oil, the curvature of the interface is directed into the oil and the capillary pressure is positive Figure (7-1) The radii of curvature between water and oil in the pores of the rock are functions of wettability, saturations of water and oil, pore geometry, mineralogy of the pore walls, and the saturation history of the system. Therefore, the radii of curvature and contact angle vary from one pore to another, and the average macroscopic properties of the rock sample apply *

7-2-Measurement of capillary pressure using porous plate method:

The derivation of capillary pressure equations thus far has been based on a single uniform capillary tube. Porous geologic materials, however, are composed of interconnected pores of Dr.Eng.Mostafa M.Kinawy

47


various sizes. In addition, the wettability of the pore surfaces varies from point to point within the rock due to the variation in the mixture of minerals in contact with the fluids. This leads to variation of the capillary pressure as a function of fluid saturation and an overall mean description of the rock wettability. Hydrocarbon reservoirs were initially saturated with water, which was displaced by migrating hydrocarbons. The water accumulated in the geologic structure and formed a trap for the oil, thus producing a petroleum reservoir. This process can be repeated in the laboratory by displacing water from a core with a gas or oil. The pressure required for the equilibrium displacement of the wetting phase (water) with the non-wetting gas or oil is the water drainage capillary pressure, which is recorded as a function of the water saturation. The porous plate method is the most accurate measurement of capillary pressure in homogeneous and heterogeneous cores. Several plugs can be measured at a time. The limitation is that the capillary discontinuity may distort the results.

7-2-1-Apparatus: The apparatus used is shown in (Figure 7-2).

7-2-2-Procedure:

Water saturated samples for air-water or oil-water tests and oil saturated cores for air-oil tests are placed on a semi-permeable diaphragm, and a portion of the contained liquid is displaced with the appropriate fluid of air or oil. A schematic diagram of an apparatus for performing such tests is seen in Figure. (7-2). It consists of a cell for imposing pressure, a semipermeable diaphragm C, manometer for recording pressure M, and a measuring burette for measuring produced volumes. During measurement, the pressure is increased in steps and final equilibrium produced volumes of the wetting phase are recorded for each step. The porous plate method is slow and one full curve may take up to 40 days or more to obtain. However, equipment needed for this method is simple and inexpensive and the work needed is limited to some volume reading during the process. Several samples may be run in one chamber. Then the samples have to be removed in order to weigh them separately between


48


each pressure increase. Preferably, one and one sample should be run in an assembly of onesample cells. Then it is not necessary to decrease pressure between each reading.

Figure (7-1) : Various wetting conditions that may exist for water and oil in contact in a capillary, using the contact angle method. 7-2-3-Calculations and report: 1. Calculate and fill the data form. 2. Plot capillary pressure curve (Sw-Pc) and pore size histogram (distribution).


49


Where: Pc(i) = capillary pressure of ith measurement, cm of water, reading of U-manometer Wwet = core weight of ith measurement, g Sw(i) = (Wwet(i)-Wdry)/Wwater, ith water saturation of Pc(i) Wwater = Wsat-Wdry, g r(i) = 2_g-w/Pc(i), radius corresponding to Pc(i) g-w =

70.0 dynes/cm, interfacial tension of gas-water

Pc(i) = 981.Hwater, dynes/cm2 W(i)/Wwater = (Wwet(i-1)-Wwet(i))/Wwater, fraction of the capillaries of r(i) in total pore Volume

Figure (7-2) : Porous Plate method assembly


50


This method is regarded as the standard method against which all other methods are compared. Routinely only the drainage curve is measured, but with appropriate modifications the imbibition curve may be determined in the same manner. The weakness, as with all the other methods, is the transformation of data to reservoir conditions.


51


Experiment #8 Capillary pressure by mercury injection method 8-1-Theory (Introduction). CapilIary pressure curves for rocks have been determined by mercury injection and withdrawal because the method is simple to conduct and rapid. The data can be used to determine the pore size distribution, to study the behavior of capillary pressure curves, and to infer characteristics of pore geometry.

The mercury injection method has two disadvantages: (1) after mercury is injected into a core, it cannot be used for any other tests because the mercury cannot be safely removed, and (2) mercury vapor is toxic, so strict safety precautions must be followed when using mercury.

8-2-Apparatus: To conduct a test, a core is cleaned, dried, and the pore volume and permeability are

determined. If liquids are used in the core, it is dried once more before the capillary pressure is determined. The core is placed in the sample chamber of the mercury injection equipment Figure

(8-1). The sample chamber is evacuated, and incremental quantities of mercury are injected while the pressure required for injection of each increment is recorded. The incremental pore volumes of mercury injected are plotted as a function of the injection pressure to obtain the injection capillary pressure curve (Figure 8-2), curve 1).


52


Figure (8-1) :Equipment for mercury injection Capillary pressure measurement .

Figure (8-2): Mercury-gas capillary pressure curves showing the initial injection curve with its threshold pressure and the hysteresis loop. Note that very high pressures are required for mercury injection.


53


8-3-Procedure: The test specimen is evacuated and mercury is injected in increments into the core at increasing pressure levels. When the entry pressure is reached, one can easily determine the bulk volume of the core. A mercury injection apparatus is schematically shown in Figure. (81). The equipment consists basically of a mercury injection pump, a sample holder cell with a window for observing constant mercury level, manometers, vacuum pump, and a pressurized gas reservoir. In this method the mercury injected is calculated as a percentage of pore volume and related to pressure. A practical pressure limit on most equipment is about 15-25 MPa, but equipment for 150 MPa also exists.

Two important advantages are gained with the mercury injection method: (1) the time for determining a complete curve is reduce to less than one hour, and (2) the range of pressure is increased compared with the other methods. However, this method is a destructive method and it is difficult to transform the results to reservoir conditions because of the highly unrealistic fluid system and the uncertainty of wetting of mercury-solid. Using mercury-air as the fluid-pair, one will not obtain the irreducible saturation as when displacing water with air.


54


Experiment #9 Resistivity Measurements of Fluid-Saturated Rocks

9-1-Theory (Introdution):

The objective of this experiment is to measure the main electrical properties of porous rock like water resistivity, formation factor, tortuosity, cementation factor, resistivity index and saturation exponent.

Figure(9-1):: The electrical circuit of resistance measurements. 9-2-Procedure: Resistance measurements in our laboratory are a ratio of voltage decrease method, that is the ratio of voltage decrease between a reference resistor and a sample (to be measured) in series Figure (9-1) . Then, the resistance of the sample is calculated and the resistivity of the sample can be developed when the size of the sample is known.


55


9-3-Calculations and report: 1. Calculate water resistivity, Rw Equation:


56


Experiment #10 Grain size distribution measurement 10-1-Introduction: One of the methods used for determining grain size distribution is sieve analysis. After the grain size distribution has been determined, the depositional history of the rock may be inferred from graphical analysis of the grain size distribution. The distribution of sizes of the grains in sediments is related to: (1) the availability of different sizes of particles in the parent matter from which the grains are derived, and (2) the processes operating where the sediments were deposited, particularly the competency of fluid

flow (in other words, the history of sedimentary processes). Measurement of the grain size distribution will yield a plot of the cumulative mass percent (frequency) of ranges of grain sizes versus the PHI-scale used for particles size notation, the surface area of the rock per unit of pore volume and of bulk volume, and the surface area per unit of grain volume of the sediment. In general, the procedure is to carefully crush the rock with an impact crusher (not a grinder) to obtain individual grains. A set of sieve trays is assembled with the finest screens at the bottom Figure (10-1). In sieve analysis, it is assumed that the grains caught on the individual screens have sizes that are smaller than the openings of the screen above and larger than the screen that they are resting on. The amount of sand caught on each screen in the stack is weighed and, as a first approximation, the average grain diameter is assumed to be equal to the average of the screen opening sizes between which it was trapped. The second assumption that is applied is that the mineral grains are spherical in shape. With these assumptions, several statistical analyses can be made. The relationship between the surface area and volume of a sphere is as follows: SA (sphere) V(sphere)

=

d2 d3 6

=

6 d

10-1

where: SA(sphere) =

Surface area of a sphere.

V(sphere) = Volume of a sphere.


57


The average surface of the grains is taken as the sum of the surface areas determined for the sand caught on each screen size. This surface area is based on the average grain diameter. Summing up the calculated surface area for each of the sieve screens is performed as follows: =

VithSC

=

x 6 dithSC

MithSC sd

Stotal =

Vtotal

x

6 dithSC ( Stotal )

10-2

x

10-3

Vtotal

where: dithSC = diameter of the ith screen sd

= density of the sand

Stotal = total surface area of the sample VithSC =

Vtotal =

volume collected on the ith screen total grain volume of the sample

MithSC = mass (‘grams) collected on the ith screen.

The surface area of a porous medium does not quantify the value; instead, the surface area must be a function of the volume of material in which it was contained (cm2/cm3). Smaller particles packed in a unit volume have much more surface area than do larger particles filling the same space. The surface area of a porous medium can be expressed in three ways based on the three rock volumes (pore volume, grain volume and bulk volume). The surface areas are defined as follows: SBV = surface area per unit bulk volume of the porous medium

SMG = surface area per unit volume of the mineral grains comprising the porous medium. Spv = surface area per unit volume of pore space within the porous medium.

The three surface area expressions are related through the definition of porosity (the ratio of the pore volume to the bulk volume), thus:

The expression for calculating the surface area per unit volume of mineral grains (SMG) from sieve analysis data may be derived as follows:


58


The standard size classifications for sedimentary particles are listed in Table 10-1.

10-2-Apparatus and equipments: The apparatus used for analysis of the grain size distribution of the sediments is shown in figure (10-1). 10-2-1-Equipments: Analytical balance Rock crushing instrument Mortar and pestle Sieves Mechanical shaker for stacked sieves

Figure (10-1): Assembly of sieve trays (finest screens at the bottom) for analysis of the grain size distribution of the sediments. Dr.Eng.Mostafa M.Kinawy

59


10-3-Sieve analysis procedure: 1. Using a sledgehammer, break a clastic rock sample into pieces approximately 1 in. in diameter. 2. Crush the 1-in. pieces in the rock crusher and collect the crushed rock in a mortar.

3. Crush the sample into grains using the mortar and pestle. Do not crush the individual grains by using a rotary motion of the pestle. Separate the grains by using a back and forth motion.

4. Obtain a crushed sample of about 200 g. 5. Clean each of the sieves using a bristle brush (brush from the bottom).

6. Strike the sieve on the outside of the rim 2 to 3 times to loosen grains that are tightly trapped between the screen openings. It may not be possible to remove all of them. 7. Assemble the sieve on the shaker with the pan on the bottom and the coarsest of the screens on the top. 8. Pour the weighed, crushed sample of sand into the top sieve (be careful not to spill any of the sample).

9. Place the cover on the top sieve, tighten the stack of sieves onto the shaker, and shake the assembly for 5 minutes. Place any grains left on the top sieve into the mortar and re-crush them. (Consult the lab instructor about this.) Return the crushed grains to the top sieve. 10. Shake the assembly for 15 minutes. A modification of the procedure at this point is to separate the sample into two new series of sieves for thorough sorting with additional shaking for 20 minutes. If the sample is not to be separated, continue shaking for an additional 10 minutes and then proceed with the weighing. 1 1. Weigh the contents of each sieve individually on an analytical balance and complete the sample calculation as follows:


Table (10-1)

60



61


Experiment #11 Determination of bubble point pressure of crude oil 11-1-Introduction Samples for study of reservoir crude oil may be obtained either by bottom hole sampling or recombining surface separator liquid and gas samples . A high pressure cell is used for experimental determination of " bubble point " pressure . The cell is equipped with glass window to permit visual observation of the sample under test . Constant temperature is maintained into the cell . Constant temperature oil bath or devices for controlling of temperature at which the experiment is made are furnished with the cell . The sample is transferred from sample bottle to the cell .The transfer apparatus is shown in Figure (11-1). In the presence of mercury , the change of oil and gas in the due to any pressure variation under constant temperature is a function of compressibility of mercury into the cell

Sometime it is difficult to trace the bubble through the cell's window . Then we find out the bubble point pressure with the help of a graph plotted pressure versus volume . The pressure is gradually reduced in the cell and volume at different pressure are tabulated . The pressure in the cell is reduced as low as 50 psi . The point when the curve takes a sharp turn is the bubble point and the corresponding pressure is the bubble point pressure.

11-2- Procedure: Transfer the reservoir sample from the sample bottle to the PVT cell represented in Figure (11-2). described hereunder : 1 - Fill the mercury pump ( 5 ) with mercury and increase the pressure more than the bubble point pressure ( i.e. reference pressure ) . 2 – increase the pressure in other pump ( 1 ) to a pressure equal to the pressure in pump ( 5 ) . Then close valve ( 7 ) and take pump reading at room temperature . 3 – equalize the pressure in gauge ( 2 ) , cell and gauge ( 12 ) . 4 – open the valves ( 7 ) , ( 8 ) and ( 9 ) . Start injecting mercury from pump ( 5 ) to the sample bottle ( 4 ) and at the same time withdraw mercury from cell ( 3 ) to pump ( 1) keeping the pressure of the overall system equal .


62


Figure (11-1) :Sample transfer apparatus


63


Figure (11-2): PVT cell 5 – Close valve ( 8 ) and ( 7 ) and then take pump ( 1 ) reading bring the pressure down to reference pressure . 6 – Volume of the sample collected into the cell is the difference between the two reading of the pump ( 1 ) . Correction is made to this volume at room temperature . Now reduce the pressure in the cell gradually and while reducing the pressure keep watching the cell window . When a bubble of the gas is witnessed through the cell window read the gauge ( 2 ) pressure . This pressure is the bubble point pressure . 11-3-Precautions: 1 – Before filling the cell with mercury make sure that the connections between the pump , the gauges , the cell and other pump are very well sealed and evacuated thoroughly . 2 – Clean all the system with carbon tetrachloride . 3 – Every volume reading should be corrected .


64


Experiment #12 Oil formation volume factor and Gas formation volume factor 12-1-Introduction Subsurface sample of oil reservoir has dissolved gasses in it. These gases separate out of the sample at atmospheric conditions . Using flash equilibrium separation the following properties of reservoir are investigated using related calculations 1. oil formation volume factor; 2. solution gas oil ratio. 3. gas formation volume factor. 12-2- Principle of Apparatus: A bottom hole or recombination sample is expanded from above its bubble point pressure into a chamber under controlled back pressure and temperature. The gas liberated is measured with a gas meter at atmospheric conditions while the liquid volume is read in the separator. 12-3-Apparatus : The apparatus used is shown in figures (12-1) and (12-2).

12-4-Procedure: 1. connect the pressurized sample to the inlet valve of the separator. 2. close drain and inlet valve , turn regulator valves to "off". Open atmospheric by-pass valve. 3. hook up temperaure jacket lines , if required , and circulate fluid arround chamber. A thermometer is provided for temperature monitoring. 4. charge the pressurized sample contained in the sample bottle to the top inlet valve, maintaining pressure with mercury pump. 5. expand the sample into the separator by opening the inlet valve . charge 10 to 20 cc to purge the system.


65


Figure (12-1):Flash equilibrium separator

Figure (12-2): Flow Diagram, Flash Equilibrium Separator

6. close the inlet valve and let the liquid settle down at the bottom 7. open the gasometer inlet valve to allow the separator gas enter in the gas chamber.


66


8. take initial reading on mercury pump and the gas meter. 9. drain the oil by opening the outlet valve of the separator. Measure its volume and its weight. 10. place the evacuated gas balloon in the line up stream of the meter so that weight of the gas can be determined. 12-5-observation: Separator conditions , atmospheric Weight of evacuated gas balloon (TARE)

=

grams

Weight of Tare +dry air

=

grams:

Weight of Tare + gas

=

grams

Charge pressure

Mercury pump & atm. Temp.

Psia

reservoir fluid

1. 2. Volume of the stock tank oil =

cc

Weight of the stock tank oil

cc

=

12-6-Calculation procedure: Gas gravity =

Weight of the gas Weight of the air

Oil formation volume factor= Volume at bubble point and reservoir temperature Volume of stock tank oil Volume correction =

Volume at bubble point and reservoir temperature Volume at charge conditions

Gas oil ratio

=

Volume of gas , cc

cc/cc

Volume of STO ,cc or

5.615 x cc /cc

= SCF/BBL

,STO @ atmospheric conditions

weight of flash gas = (ft)3 (sp.gr. of gas x molecular weight of air) =

gm

molar gas volume (ft3/#mol)


67


Total weight = wt .of S.T.O. + wt .of flash gas

=

Density (gm/cc) @ bubble point and reservoir temperature =

gm :

total weight gms Volume @ bubble point and reservoir temperature


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Experiment #13 Oil viscosity measurement 13-1-Introduction (Throry): Gain a basic knowledge of the techniques used to measure viscosity. Rheology is the study of the change in form and flow of matter in terms of elasticity, viscosity and plasticity. A clear understanding of the rheological properties of fluids is vital in many fields of science and engineering. The purpose of this lab is to introduce you to the different techniques and approaches to measure viscosity experimentally. Viscosity is the measure of the internal friction of fluid. This internal friction is caused when a layer of fluid moves in relation to another layer. The greater the friction, the greater the amount of force required to cause this movement. This movement is known as shear.

Figure (13-1): Deformation of a liquid under the action of a tangential force. To define viscosity more precisely, let’s take a look at figure (13-1) . Two parallel planes of fluid of equal area “A” are separated by a distance dx and are moving at different speeds V1, V2. The force required to maintain the difference in speed is proportional to the difference in speed through the liquid.

where: is known as the viscosity, usually in units of centipoises or Pa.s. dv / dx is the shear rate. Describes the shearing the fluid experiences when the layers move with respect of each other. Units in reciprocal second, sec-1.


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F/A is the force per unit area required for the shearing. This is known as the shear stress and it has units of pressure. Therefore, we can define viscosity as:

13-1-1-Newtonian fluids: A Newtonian fluid is characterized by having a constant viscosity at a given temperature. This is normally the case for water and most oils. A plot of shear rate versus shear stress would show a constant slope, figure (13-2). This is the simplest and easiest fluids to measure in the lab.

Figure (13-2): Shear rate versus Shear stress for a newtonian fluid

13-1-2-Non Newtonian fluids A non-newtonian fluid is characterized by not having an unique value for viscosity. That is, the relationship stress rate/shear rate is not constant. The viscosity of these fluids will depend on the shear rate applied. There are several types of non-newtonian fluid behavior that we can observe in the lab. The most common are shown in figure 3.


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13-1-2-1-Pseudo plastic fluids : these are fluids like paints and emulsions, there is a decrease in viscosity as the shear rate increases. Also known as shear thinning fluids. 13-1-2-2-Dilatant fluids: these are fluids that increase their viscosity as the shear rate increases. Examples are cement slurries, candy mixtures, corn startch in water. Also known as shear thickening fluids. 13-1-2-3-Plastic fluids: These fluids will behave like solids under static conditions. They will start to flow only when certain amount of pressure is applied. Examples are tomato catsup and silly putty. `

Figure (13-3): Shear rate versus Shear Stress for different types of fluids 13-2-Instruments to measure rheological properties Most instruments designed to measure viscosity can be classified in two general categories: tube type and rotational type. Figure 4 shows the different types of instruments available. The selection of a particular instrument must be based on the type of analysis required and the characteristics of the fluid to be tested. For example, rotational methods are generally more appropriate for non-newtonian fluids, while glass capillary viscometers are only suitable for Newtonian fluids. In this lab, we will use one instrument viscometer .


to measure viscosity: the Ruska Rolling Ball

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13.2.1. Falling Ball Viscometer An instrument commonly used for determining viscosity of a liquid is the falling (orrolling) ball viscometer Figure (13-4) and (13-5), which is based on Stoke’s law for a sphere falling in a fluid under effect of gravity. A polished steel ball is dropped into a glass tube of a somewhat larger diameter containing the liquid, and the time required for the ball to fall at constant velocity through a specified distance between reference marks is recorded. The following equation is used µ = t ( b- f) K

13-1

where: µ = absolute viscosity,cp t =falling time, s b

= density of the ball ,gm/cm3

f

= density of fluid at measuring temperature,gm/cm3

K = ball constant. The ball constant K is not dimensionless, but involves the mechanical equivalent of heat. The rolling ball viscometer will give good results as long as the fluid flow in the tube remains in the laminar range. In some instruments of this type both pressure and temperature may be controlled.

Figure (13-4): Ruska falling ball viscometer.


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Figure (13-5): Schematic diagram of the falling ball viscometer. 13-3-Apparatus The Ruska rolling ball viscometer shown in figure (13-4) is used to determine the viscosity of bottom hole and surface samples at elevated temperatures and pressures, up to 10,000 psi and 300 °F. This instrument operates on the rolling ball principle, where the roll time of a ¼ inch diameter ball is used to obtain viscosity data. The viscosity is calculated as

where : viscosity K: constant ball : fliud :

Density of the ball Density of the fluid

t: roll back time The driving force in this instrument is the difference in density between the fluid and the ball. At a fixed temperature, the difference in ball and fluid density will be constant. The viscosity


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will be directly proportional to the roll back time. The constant of the viscometer must be determined by previous calibration using a liquid of known viscosity. 13-4-Operating Procedure: 1) choose the correct ball size. If the fluid viscosity is estimated to be between 0 and 5 cP, a 0.252 or 0.248 inch diameter ball should be used. Above 25 cP, the 0.234 inch diameter ball will be appropriate 2) Clean the test assemblywith kerosene and vent air to ensure the chamber is free of dust. 3) Place the ball in the bottom of the empty measuring barrel. 4) Evacuate the test assembly. This is done by opening the vacuum pump valve at the lower end of the unit and closing the charging valve. 5) Charge the test sample fluid in the viscometer. The vacuum valve shold be closed while the high pressure charging valve is reopened. 6) Rock the test assembly to obtain a single phase sample. The presence of gas bubbles inside the chamber can prevent the ball from moving freely and stop the experiment completely. 7) Set the temperature of the viscosimeter to the desired value. Allow 3 hours for the temperature to estabilize. 8) Bring the ball to the hold position, by rotating the test unit 180 degrees. 9) Turn on the coil and switch to HOLD. The yellow light must be on 10) Rotate the assembly to the desired angle (70°, 45°, or 23°), this will depend on how viscous the fluid is. 11) Switch to FALL. The green light must be on. The ball is released and the time to travel is displayed. When the ball hits the bottom, a sound alarm will be triggered. 12) Calculate the viscosity by using equation 4. with the appropriate values for the constant. These values will be provided to you in the lab.


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References 1- Experimental

Reservoir

Engineering Laboratory Work Book ,O. Torsæter M. Abtahi

Department of Petroleum engineering and Applied Geophysics ,Norwegian University of Science and Technology ,January, 2003 2- Applied Reservoir Engineering ,Volume 1 ,Charles R. Smith G. W. Tracy R. Lance Farrar OGCI Publications Oil & Gas Consultants International, Inc. Tulsa, 1992 3- Petrophysics Theory and Practice of Measuring Reservoir Rock and Fluid Transport Properties Djebbar Tiab and Erle C. Donaldson Copyright @ 2004, Elsevier, Inc. All rights reserved. Second edition. 4- Petroleum Reservoir Engineering Physical PropertiesJames W. Amyx Daniel M. Bass, JR. Robert L. Whiting ,The Agricultural and Mechanical College of Texas ,Copyright © 1960 by the McGraw-Hill Book Company, Inc. Reissued 1988 by the McGraw-Hill Book Company, Inc.


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