CHAPTER 3 COMPARISON OF RHEOLOGICAL PROPERTIES OF CRUDE AROUND THE WORLD

CHAPTER 3 COMPARISON OF RHEOLOGICAL PROPERTIES OF CRUDE AROUND THE WORLD 3.1 INTRODUCTION Crude oil varies in colour from nearly colourless to tar black, and in viscosity from close to that of water to almost solid. In fact, there are more than 300 different types of crude oil produced around the world, all of which have different characteristics. Two of the most important characteristics are density (or viscosity) and sulphur content.(burcik, 1957). High-quality crude oils are characterised by low density (light) and low sulphur content (sweet) and are typically more expensive than their heavy and sour counterparts (Pirson, 1977). This reflects the fact that light crude oils produce more higher-value products (such as gasoline, jet fuel and diesel) than medium or heavy density crudes, while sweet crude oils require less processing than sour crudes (since sulphur is a harmful pollutant that needs to be removed to meet air quality standards). When a barrel of crude oil is refined, around 40 50 per cent is used to produce petrol (gasoline), with the remainder better suited to producing products such as diesel, heating oils and jet fuel (kerosene), heavy bitumen, as well as the petrochemicals used to produce dyes, synthetic detergents and plastics as shown in Fig. 3.1. The precise proportions depend on the quality of the particular crude oil (as well as the specification of the refinery), with differences in the prices of the various grades of crude oil influenced by differences in demand for the various end products as well as by the supply of the different grades of crude oil A Barrel of Crude Oil 50 40 30 20 10 0 Petrol Destillate Jet Fuel Liquid petroleum gases Other Fig. 3.1 Percent Composition for a Barrel of Crude Oil 51

API density (conceived by American Petroleum Institute) is used in the Anglo Saxon system to express crude oil density. A liquid, the API degree of which is 10 API, at a temperature amounting to 15 C, has a density equal to 1.00 (i.e. that of water, 1 kg/liter) at the same temperature. A density equal to 22 API at 15 C is equivalent to 0.9218 density at 15 C, and 35 API at 15 C is equivalent to 0.8498 density at 15 C. The lower limit of conventional crude oil is generally placed at 15 API. Fig. 3.2: Comparison of Sulphur Content & API Gravity of Crude Oils Across Different Reservoirs Generally, we talk about heavy crude oil less than 20 API, medium crude oil 20-30 API and light crude oil beyond this figures, but these boundaries vary according to the countries. The lightest crude oils are most required by refiners because they give directly numerous light layouts with high value (diesel oil, gasoline, naphtha). Conversely, heavy crude oils give more products, such as bitumen and residual fuel, that have either to be sold as they are at low price, or to be converted into lighter layouts, particularly by hydrocracking (hydrogen addition). The sulfur content varies considerably from a well to another, so from a commercial blend to another, from 0.03 % to 5 % approx. shown in Fig.3.2. Sulphur is a 52

polluting agent that refiners have to extract (at least in countries having laws against acid rains). Then, it reduces the crude oil value. Generally, the limit between sweet crude oil and sour crude oil is 1.5 % sulphur. A crude oil may be: -VLSC (Very Low Sulphur Content) -LSC (Low Sulphur Content) -MSC (Medium Sulphur Content) -HSC (High Sulphur Content) -VHSC (Very High Sulphur Content) Apart from these two main ranges, there are numerous other quality criteria, i.e. viscosity, acidity, ratios between types of hydrocarbons (cyclical or not, saturated or not) and nitrogen contents, heavy metals contents, salts contents, and so on (Whitson, 1983). The crude oil price depends, in major part, on its chemical and physical characteristics. So, a crude oil HSC (High Sulphur Content) has a lower price than a crude oil LSC (Low Sulphur Content), a naphthenic crude oil is more onerous because this crude oil, after reforming, will give a lot of aromatic products with high octane index, serving as a basis to produce regular gas and premium gas. If kerosene fraction of crude oil is abundant and if its freezing point is very low, for example - 54 C, this crude oil is more onerous because kerosene acts as a basis in the production of Jet A1, fuel for planes. 53

Fig. 3.3 Comparison of sulphur content & API Gravity of crude oils across the globe The price of a given crude oil is then fixed according to the initial well and to their containers, but also to crudes oils serving as a reference (Brent, WTI, Arabian Light, Minas, and so on). A given crude oil, according to its quality and to its markets distances gets a price differential compared to the reference crude oil. This differential is most often negative, as crude oils acting as a reference are high quality crude oils and available near consumption places. And also, it varies according to the market. 3.2 CRUDE OIL RHEOLOGY & CHARACTERIZATION Change in temperature of crude oil may change the behaviour of crude oil from Newtonian to non-newtonian where the viscous stresses are not linearly proportional to the rate of deformation over time. The type of non-newtonian behaviour exhibited by waxy crude resembles the Bingham plastic behaviour where a minimum amount of stress called as yield stresss or Gel strength, required for the fluid to be in motion. The expression for Bingham plastic behaviour can be expressed as: 54

Where, - Shear stress at any time. - Initial shear stress. - Shear rate. As the behaviour of waxy crude oil may be even non-linear and follow the characteristics more complex than Bingham plastic flow model. Such an expression can be further extended as: According to Herschel-Bulkley (1926), if, the fluid behaves as solid. k is consistency index, n is flow index. For flow index (n) less than 1 implies that the fluid is shear thinning and for flow index greater than 1 implies that fluid is shear thickening. Crude oil characterization has long been an area of concern in refining; however, the need to identify the chemical nature of crude has gained importance in upstream operations. Traditionally, this has been done by simply stating the crude oil gravity, but more information is required to understand the oil well enough to estimate the volume in the reservoir and its recoverability (Watson and Nelson, 1935). 3.3 REGIONAL TRENDS IN CRUDE OIL COMPOSITION During the last 60 years, several correlations have been proposed for determining pressure-volume-temperature (PVT) properties. The most widely used correlations treat the oil and gas phases as a two-component system. Only the pressure, temperature, specific gravity, and relative amount of each component are used to characterize the oil s PVT properties. Crude oil systems from various oil-producing regions of the world were used in the development of the correlations. These crude oils can exhibit regional trends in chemical composition, placing them into one of the following groups i.e. paraffinic (P), naphthenic (N), or aromatic (A). Comparison of Sulphur content & API Gravity of crude oils among different countries is shown in Fig. 3.4. 55

Fig. 3.4 Comparison of sulphur content & API Gravity of crude oils among different countries 3.4 CLASSIFICATION OF PETROLEUM CONSTITUENTS A classification system and nomenclature commonly used in the petroleum industry describes components as belonging to the paraffinic (P), naphthenic (N), or aromatic (A) fractions (Allen and Roberts, 1982). These are often referred to jointly as PNA. Paraffins This class includes n-alkanes and i-alkanes that consist of chains of hydrocarbon segments (-CH 2-, -CH 3 ) connected by single bonds. Methane (CH 4 ) is the simplest paraffin and the most common compound in petroleum reservoir fluids. The majority of components present in solid wax deposits are high-molecular-weight paraffins. Naphthenes This class includes the cycloalkanes, which are hydrocarbons similar to paraffins but contain one or more cyclic structures. The elements of the cyclic structures are joined by single bonds. Naphthenes make up a large part of microcrystalline waxes. 56

THUND14X(Am ANASR06X(Ame PZFLR14X(Angola) MONDO14X(An KISSJ10U(Angola) SAXBT14X(Ango AZRLT13F(Azerb CLAKBL13(Cana TNOVA14(Cana DOBA15B(Chad) TRITN07B(Mala EBOK14(Nigeria) USAN14X(Nigeria) QUAIB14X(Nige ORMNL10X(Nor GRANE14F(Nor VOLVE11X(Nor GLFKB07X(Norw STATBL03(Norw KUTUBL14(Papu UPZAK12Z(Saud ANS11U(UK) BRENT14X(UK) Paraffins, Naphthenes, Aromatics Aromatics This class includes all compounds that contain one or more ring structures similar to benzene (C 6 H 6 ). The carbon atoms in the ring structure are connected by six identical bonds that are intermediate between single and double bonds, which are referred to as: Hybrid bonds Aromatic double bonds Benzene bonds Because of the differences in composition, correlations developed from regional samples, predominantly of one chemical base, may not provide satisfactory results when applied to crude oils from other regions (Riazi and Daubert, 1980). A Comparison of Paraffin, Napthenes and Aromatics is shown in the Fig. 3.5. below: 60.0 50.0 40.0 30.0 20.0 10.0 0.0 Paraffins, vol % Naphthenes, vol % Aromatics (FIA), vol % Fig. 3.5 Comparison of Paraffin s, Naphthalene s & Aromatics across 46 reservoirs throughout the globe 3.5 CLASSIFICATION OF HYDROCARBONS BASED ON STRUCTURE Hydrocarbons are classified according to the structure of the molecule (Burcik, 1957). Paraffin hydrocarbons are characterized by open or straight chains joined by single bonds. Examples are: Methane 57

Ethane Propane Decane Isomers of these compounds, which contain branched chains, are also included as paraffins. The first four members of the series are gaseous at room temperature and pressure. Compounds ranging from pentane (C 5 H 12 ) through heptadecane (C 17 H 36 ) are liquids, while the heavier members are colourless, wax-like solids. Unsaturated hydrocarbons, which consist of olefins, diolefins, and acetylenes, have double and triple bonds in the molecule. These compounds are highly reactive and are not normally present to any great extent in crude oil. Naphthene hydrocarbons are ringed molecules and are also called cycloparaffins. These compounds, like the paraffins, are saturated and very stable. They make up a second primary constituent of crude oil. Aromatic hydrocarbons are also cyclic but are derivatives of benzene. The rings are characterized by alternating double bonds and, in contrast to olefins, are quite stable, though not as stable as paraffins. Crude oils are complex mixtures of these hydrocarbons. Oils containing primarily paraffin hydrocarbons are called paraffinbased or paraffinic. Traditional examples are Pennsylvania grade crude oils. Naphthenic-based crudes contain a large percentage of cycloparaffins in the heavy components. Examples of this type of crude come from the US midcontinent region. Highly aromatic crudes are less common but are still found around the world. Crude oils tend to be a mixture of paraffins-naphthenes-aromatics, with paraffins and naphthenes the predominant species (Pirson, 1977). 3.6 DOMINANT CHARACTERISTICS OF CRUDE 3.6.1 Characterisation Factor, K uop The dominant characteristics of the crude are assessed by the measuring the following properties. Boiling profile (ASTM D 86) API Gravity The characterization factor K UOP was introduced by research personnel from the Universal Oil Products Company. The characterization factor K UOP (or KW) was 58

Kuito (Angola) Barrow Island(Asia) Seria (waxy)(bolivia) Leduc(Canada) Barco (light)(colombia) Duri(Indonesia) Agha Jari(Iran) Naranjos(Mexico) Escravos(Nigeria) N'Kossa(Republic of Nanhai Light(South Santa Maria(U.S.A) Talco(U.S.A) West Texas(U.S.A) Salt Creek(U.S.A) Louden(U.S.A) Scurry County(U.S.A) Chase(U.S.A) La Rosa(Venezuela) Santa Rosa(Venezuela) KW defined for pure components using only their boiling point & densities and it is represented as K UOP = 1.8T 1/3 /S Where, T being the boiling temperature (Kelvin) and S being the standard specific gravity (15.6 o C/15.6 o C). The K UOP values for the pure hydrocarbons investigated are as follows. 13 for paraffins 12 for hydrocarbons whose chain and ring weights are equivalent 11 for naphthenes 10 for pure aromatics A Comparison of Characterisation factor for the Crudes across the World Crudes is shown below in Fig. 3.6. below: 0 API 70.0 60.0 50.0 40.0 30.0 20.0 10.0 0.0 13.00 12.50 12.00 11.50 11.00 10.50 10.00 Fig. 3.6 Trend of API gravity w.r.t characterization factors across various reservoirs across the globe To extend the applicability of the characterization factor to the complex mixtures of hydrocarbon found in petroleum fractions, it was necessary to introduce the concept of a mean average boiling point temperature to petroleum cut. This is calculated from distillation curves, either ASTM or TBP. The Volume Average Boiling Point (VABP) 59

is derived from the cut point temperature for 10, 20, 50, 70, 80, or 90 % for the sample in question. In the above formula, VABP replaces the boiling point for the pure component. The following temperatures have been defined. For a crude oil using its TBP distillation (given as volume) Volume average boiling point: T= (T 20 + T 50 +T 80 )/3 For a petroleum cut using its ASTM distillation curve, Volume average boiling point: T= (T 10 + 2T 50 +T 90 )/4 Where T 20 is the temperature at which 20% of the sample has been distilled and likewise T 50, T 80 and T 90. In this manner, the K UOP of petroleum cut can be calculated quickly from readily available data, i.e. the specific gravity and the distillation curve. The K UOP value is between 10 & 13 and defines the chemical nature of the cut, as it will be for the pure components. The characterization factor is extremely valuable and widely used in refining. Many nomograms are currently available correlating K UOP with API gravity and one such nomogram is currently used for assessing the dominant characteristics of crude oil. 3.6.2 Correlation Index (CI) The classification of crude base can also be done on the basis of its correlation index. Correlation index value of crude oil from 0-15 indicates that the crude is predominantly paraffinic; 15-50 indicates predominance of either naphthene or mixture of paraffin, naphthene and aromatic and above 50 indicates predominance of aromatic character. 3.7 DEPOSITION POTENTIAL 3.7.1 Asphaltene The Asphaltene deposition potential is assessed by measuring the following properties. 60

Asphaltene (n-heptane insoluble) SARA distribution Asphaltenes do not dissolve in crude oil but exist as a colloidal suspension. They are soluble in aromatic compounds such as xylene, but will precipitate in the presence of light paraffinic compounds such as pentane. The Asphaltenes are the heptane insoluble fraction of crude oil. The saturate, aromatic and resin components are separated using liquid chromatography. From the SARA data, the asphaltene/resin ratio and the Colloidal Instability Index (CII) of the oil is calculated. It has been reported that the oils containing 1:1 or greater weight ratio of resin to asphaltene are less subject to asphaltene deposition. The colloidal instability index considers a crude oil as a colloidal system made up of pseudo components saturates, aromatics, resins and asphaltenes. It is calculated as the ratio of the sum of saturates and asphaltenes fractions to the sum of aromatic and resin fractions. Oils with a CII of below 0.7 are considered stable while those with a CII of above 0.9 are considered very unstable. A CII of 0.7-0.9 is indicative of oil with moderate stability. The study of SARA distribution of the crude indicates the asphaltene deposition potential. The wax deposition potential of the crude is assessed by measuring the following physicochemical characteristics. Pour point Wax Content Carbon number profiling of crude Wax profiling Prediction of WAT and solid wax A combination of these properties affects the potential for Wax deposition. The more potential of wax deposition means severity of problem and measures required for removing / reduction of wax deposition. A proactive approach for predicting wax deposition potential can help in reducing the wax deposition problems. Various studies related to pour point, wax content, carbon number profiling, wax profiling and WAT can help towards wax deposition potential. There are different methods used for generating this data from different experiments through different standards available. Data generated over a period of time can help in creating a database on fields and thus giving information on wad deposition planning and prevention. 61

BJAA BR-11 BR-31 BR-38 BR-46 BR-53 CMPG CMPG ELAA KP-1 KH-6 KH-8 KH-12 KH-17 KH-22 KH-22 KH-26 KG-5 NR-5 NR-7 UR-2 Density Specific Gravity WAX (%) Resin_Asphatene % A Comparison of Wax, Resin and Asphaltene for Some West Indian Reservoirs is given in Fig. 3.7. below: 45 40 35 30 25 20 15 10 5 0 Wax (%Wt/Wt) Resin (%Wt/Wt) Asphaltene (%Wt/Wt) 25 20 15 10 5 0 Fig. 3.7Comparisons of Wax, Resin & Asphaltene for some West Indian reservoirs A Comparison of Density & Specific gravity and API with pour point is given in Fig. 3.8. below: 1.0 1.0 0.9 0.9 0.8 0.8 Density at 15 C ( g/cc) 0.7 Specific Gravity at 60/60 F 0.7 0.6 1.0 0.9 0.8 0.7 0.6 0.5 0.4 0.3 0.2 0.1 0.0 Fig. 3.8 Comparison of Density & Specific gravity of some North East Indian wells Comparison of API Pur point of some North East Indian wells is shown in Fig. 3.9. below: 62

BJAA BR-11 BR-31 BR-38 BR-46 BR-53 CMPG CMPG ELAA KP-1 KH-6 KH-8 KH-12 KH-17 KH-22 KH-22 KH-26 KG-5 NR-5 NR-7 UR-2 0 API, Pour Point 60.0 50.0 40.0 30.0 20.0 10.0 API Gravity (degree) Pour Point ( C) 0.0 Fig. 3.9 Comparison of API & Pour point of some North East Indian wells 3.7.2 Resins Resins and asphaltenes are the colored and black components found in oil and are made up of relatively high-molecular-weight, polar, polycyclic, aromatic ring compounds. Pure asphaltenes are non-volatile, dry, solid, black powders, while resins are heavy liquids or sticky solids with the same volatility as similarly sized hydrocarbons. High-molecular-weight resins tend to be red in colour, while lighter resins are less colored. Resins are readily soluble in oil (Pirson, 1977; Allen and Roberts, 1982). 3.8 FULL COMPONENT CHARACTERIZATION No crude oil has ever been completely separated into its individual components, although many components can be identified. Despite this complexity, several properties relevant to petroleum engineers can be determined from black oil PVT correlations. 3.9 SARA CLASSIFICATION OF PETROLEUM CONSTITUENTS FOR SOME INDIAN CRUDES The components of the heavy fraction of a petroleum fluid can be separated into four groups: Saturates Aromatics, Resins and Asphaltenes (SARA). A Comparison of Crude with Respect to Asphaltenes, Resins and Wax for some North East Indian Crude Oil is placed in Fig. 3.10. below: 63

BJAA BR-11 BR-31 BR-38 BR-46 BR-53 CMPG-5 CMPG-8 ELAA KP-1 KH-6 KH-8 KH-12 KH-17 KH-22 KH-22 KH-26 KG-5 NR-5 NR-7 UR-2 Asphaltene, Resin, Wax 35.0 30.0 25.0 20.0 15.0 10.0 5.0 0.0 Asphaltene Resin Wax Fig. 3.10 Comparison of Wax, Resin & Asphaltene for some North East Indian wells Saturates include all hydrocarbon components with saturated (singlebonded) carbon atoms. These are the n-alkanes, i-alkanes, and cycloalkanes (naphthenes). Aromatics include benzene and all the derivatives composed of one or more benzene rings. Resins are components with a highly polar end group and long alkane tails. The polar end group is composed of aromatic and naphthenic rings and often contains heteroatoms such as oxygen, sulfur, and nitrogen. Pure resins are heavy liquids or sticky solids. Asphaltenes are large highly polar components made up of condensed aromatic and naphthenic rings, which also contain heteroatoms. Pure asphaltenes are black, non-volatile powders. The experimental method used to determine the weight fractions of these groups is called SARA analysis (McCain, 1990). A comparison of API and pour point for some of the crude of Indian reservoirs is shown in Fig. 3.11. Light crude oil has an API gravity higher than 31 0. Medium crude oil has an API gravity between 22 0 and 31 0. Wax content varies from 12 to 23% in the crudes. 64

API gravity and pour point 40 35 30 25 20 15 10 5 30 25 18% 35 35 35 35 20% 20% 30 30 11% 37 35 32 36 36 36 32 22% 23% 15 15% 12% 50% 45% 40% 35% 30% 25% 20% 15% 10% 5% Wax % Pour Point API 0 0% Field Fig. 3.11Comparison of API and pour point for some Indian reservoirs 3.10 TRANSPORT PROPERTIES The transport property of the crude is assessed by measuring the following properties. Viscosity at different temperature at constant shear rate Viscosity at different shear rate at constant temperature 3.11 API GRAVITY The petroleum industry uses API gravity as the preferred gravity scale, which is related to specific gravity as Where, - Specific gravity of oil - API gravity of oil 65

KLL-404 Kalol-35 KLL-470 KL-49 LM-108 Kalol-702 Kalol-407 GGS VII(K) K-525 KL-441 Wadu-35 Paliyad Motera-38 AM-104 AMD-124 MYLJ-10 NGM-47 NGM-160 Wasna-47 NDJ-90 Wadsar-02 Wamaj-11 S.Kadi-161 JHL-94 JH-54 Viraj-19-A LM-163 Halisa-02 G-131 G-60 THUND14X(America) ANASR06X(America) PZFLR14X(Angola) MONDO14X(Angola) KISSJ10U(Angola) SAXBT14X(Angola) AZRLT13F(Azerbaijan) CLAKBL13(Canada) TNOVA14(Canada) DOBA15B(Chad) TRITN07B(Malaysia) EBOK14(Nigeria) USAN14X(Nigeria) QUAIB14X(Nigeria) ORMNL10X(Norway) GRANE14F(Norway) VOLVE11X(Norway) GLFKB07X(Norway) STATBL03(Norway) KUTUBL14(Papul New Guinea) UPZAK12Z(Saudi Arabia) ANS11U(UK) BRENT14X(UK) API Gravity for some of Crudes around the world is shown in Fig. 3.12. below: 0 API 70.0 60.0 50.0 40.0 30.0 20.0 10.0 0.0 API Gravity Fig. 3.12Comparison of API gravity of 46 reservoirs across the globe The API ranges from as low as 20 degrees to as high as 60 degrees. A comparison of API and pour point for some of the Crude of Indian reservoirs is shown in Fig. 3.13. below: 0 API & Pour Point 60 50 40 30 20 10 0 API Gravity Pour Point C Fig. 3.13 Comparison of API gravity & Pour point for some West Indian reservoirs 3.12 CHARACTERIZATION FACTOR Whitson (1983) has suggested use of the characterization factor as a means of further characterizing crude oils and components. Watson and Nelson (1933) 66

introduced a ratio between the mean average boiling point and specific gravity that could be used to indicate the chemical nature of hydrocarbon fractions and, therefore, could be used as a correlative factor. Characterization factors are calculated with Watson et al. (1935) 3.13 USE OF CHARACTERIZATION FACTOR Characterization factors are useful because they remain reasonably constant for chemically similar hydrocarbons. A characterization factor of 12.5 or greater indicates a hydrocarbon compound predominantly paraffinic in nature. Lower values of this factor indicate hydrocarbons with more naphthenic or aromatic components. Highly aromatic hydrocarbons exhibit values of 10.0 or less; therefore, the Watson characterization factor provides a means of determining the paraffinicity of a crude oil. Using work from Riazi and Daubert (1980), Whitson (1983) developed the following relationship in terms of molecular weight and specific gravity. γ o = oil specific gravity γ API = oil API gravity K w = Watson characterization factor, R 1/3 T b = mean average boiling point temperature, T, R M o = oil molecular weight, m, lbm/lbmmol 3.14 COMPARISON OF DIFFERENT RHEOLOGICAL PROPERTIES AROUND THE WORLD Watson characterization factors for selected pure components classify crude oil as paraffins, naphthenes or aromatics. The characterization factor values provide insight into their use. 67

Crude oils typically have characterization factors ranging from 11 to 12.5. Datawas derived from assay data available in the public domain. It samples crudes from around the world and can be used to provide insight into PVT behaviour on a regional basis. The properties of the heptanes-plus fraction in the stock tank crude oil are an additional source that can provide insight into the Watson characterization factor. It is important to account for the lighter paraffin components found in the oil to arrive at the characterization factor for the entire crude. 68

REFERENCES 1. Allen, T.O. and Roberts, A.P., 1982, Production Operations: Well Completions, Workover, and Stimulation, Second Edition, Vol. 2. Tulsa, Oklahoma: Oil and Gas Consultants International. 2. Burcik, E.J., 1957, Properties of Petroleum Reservoir Fluids, Chap. 1. New York: John Wiley & Sons. 3. McCain, W.D. Jr. 1990, The Properties of Petroleum Fluids, Second Edition, Tulsa, Oklahoma: PennWell Publishing Company. 4. Pirson, S.J., 1977, Oil Reservoir Engineering, PP 303 304, Huntington, New York: Robert E. Krieger Publishing. 5. Riazi, M.R. and Daubert, T.E., 1980, Simplify Property Predictions. Hydrocarbon Processing., Vol. 59 (No. 3), PP 115 116. 6. Watson, K.M. and Nelson, E.F., 1933, Improved Methods for Approximating Critical and Thermal Properties of Petroleum. Industrial and Engineering Chemistry Vol. 25, PP 880. 7. Watson, K.M., Nelson, E.F. and Murphy, G.B., 1935, Characterization of Petroleum Fractions. Industrial and Engineering Chemistry, Vol. 7, PP 1460 1464. 8. Whitson, C.H., 1983, Characterizing Hydrocarbon plus Fractions, SPE 12233- PA, SPE Journal Vol. 23 (No. 4), PP 683-694, http://dx.doi.org/10.2118/1233- PA 9. Various reports & analysis of Company. 69